KMI Exhibit 99.1 KMP 2002 Financial Statements and Notes

EX-99.1 9 kmiex991.htm KMP 2002 FINANCIAL STATEMENTS AND NOTES KMI Exhibit 99.1 KMP 2002 Financial Statements and Notes

Exhibit 99.1

INDEX TO FINANCIAL STATEMENTS

Page
----
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

Report of Independent Accountants................................... 90

Consolidated Statements of Income for the years ended
December 31, 2002, 2001, and 2000.................................. 91

Consolidated Statements of Comprehensive Income for the years
ended December 31, 2002, 2001, and 2000............................ 92

Consolidated Balance Sheets as of December 31, 2002 and 2001....... 93

Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001, and 2000.................................. 94

Consolidated Statements of Partners' Capital for the years ended
December 31, 2002, 2001, and 2000.................................. 95

Notes to Consolidated Financial Statements.......................... 96

<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS

To the Partners of
Kinder Morgan Energy Partners, L.P.

In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Kinder
Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December
31, 2002 and 2001, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Partnership's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

As discussed in Note 8 to the consolidated financial statements, the Partnership
changed its method of accounting for goodwill and other intangible assets
effective January 1, 2002.

As discussed in Note 14 to the consolidated financial statements, the
Partnership changed its method of accounting for derivative instruments and
hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Houston, Texas
February 21, 2003

90
<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31,
2002 2001 2000
------- -------- --------
(In thousands except per
unit amounts)
Revenues
Natural gas sales................. $2,740,518 $1,627,037 $ 10,196
Services.......................... 1,272,640 1,161,643 726,462
Product sales and other........... 223,899 157,996 79,784
---------- ---------- ----------
4,237,057 2,946,676 816,442
---------- ---------- ----------
Costs and Expenses
Gas purchases and other costs of
sales........................... 2,704,295 1,657,689 124,641
Operations and maintenance........ 379,827 356,654 164,379
Fuel and power.................... 86,413 73,188 43,216
Depreciation and amortization..... 172,041 142,077 82,630
General and administrative........ 118,857 109,293 64,427
Taxes, other than income taxes.... 51,326 43,947 21,588
---------- --------- ----------
3,512,759 2,382,848 500,881
---------- --------- ----------

Operating Income.................... 724,298 563,828 315,561

Other Income (Expense)
Earnings from equity investments.. 89,258 84,834 71,603
Amortization of excess cost of
equity investments.............. (5,575) (9,011) (8,195)
Interest, net..................... (176,460) (171,457) (93,284)
Other, net........................ 1,698 1,962 14,584
Minority Interest................... (9,559) (11,440) (7,987)
--------- ---------- -----------

Income Before Income Taxes.......... 623,660 458,716 292,282
Income Taxes........................ 15,283 16,373 13,934
--------- ---------- -----------

Net Income.......................... $608,377 $442,343 $278,348
========= ========= ==========

Calculation of Limited Partners'
Interest in Net Income:
Net Income.......................... $608,377 $442,343 $278,348
Less: General Partner's interest in
Net Income.......................... (270,816) (202,095) (109,470)
--------- --------- ---------
Limited Partners' interest in Net
Income.............................. $337,561 $240,248 $168,878
========= ========= =========

Basic Limited Partners' Net Income
per Unit:........................... $ 1.96 $ 1.56 $ 1.34
========= ========= =========

Diluted Limited Partners' Net Income
per Unit:........................... $ 1.96 $ 1.56 $ 1.34
========= ========= =========
Weighted Average Number of Units used
in Computation of Limited Partners'
Net Income per Unit:
Basic............................. 172,017 153,901 126,212
========= ========= =========

Diluted........................... 172,186 154,110 126,300
========= ========= =========

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

91
<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31,
2002 2001 2000
------- ------- ------
(In thousands)

Net Income............................... $608,377 $442,343 $ 278,348
Cumulative effect transition adjustment.. -- (22,797) --
Change in fair value of derivatives used
for hedging purposes................. (116,560) 35,162 --
Reclassification of change in fair value
of derivatives to net income......... 7,477 51,461 --
--------- --------- ---------
Comprehensive Income..................... $499,294 $ 506,169 $ 278,348
======== ========== =========

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

<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31,
--------------------------
2002 2001
--------- ----------
(Dollars in thousands)

ASSETS
Current Assets
Cash and cash equivalents............. $ 41,088 $ 62,802
Accounts and notes receivable
Trade.............................. 457,583 215,860
Related parties.................... 17,907 52,607
Inventories
Products........................... 4,722 2,197
Materials and supplies............. 7,094 6,212
Gas imbalances........................ 25,488 15,265
Gas in underground storage............ 11,029 18,214
Other current assets.................. 104,479 194,886
----------- ----------
669,390 568,043
------- ----------
Property, Plant and Equipment, net...... 6,244,242 5,082,612
Investments............................. 311,044 440,518
Notes receivable........................ 3,823 3,095
Goodwill................................ 856,940 546,734
Other intangibles, net.................. 17,324 16,663
Deferred charges and other assets....... 250,813 75,001
---------- -----------
TOTAL ASSETS............................ $8,353,576 $6,732,666
========== ===========

LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities
Accounts payable
Trade................................. $ 373,368 $ 111,853
Related parties....................... 43,742 9,235
Current portion of long-term debt........ - 560,219
Accrued interest......................... 52,500 34,099
Deferred revenues........................ 4,914 2,786
Gas imbalances........................... 40,092 34,660
Accrued other liabilities................ 298,711 209,852
---------- -----------
813,327 962,704
---------- -----------
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding........................... 3,659,533 2,237,015
Market value of interest rate swaps 166,956 (5,441)
---------- -----------
3,826,489 2,231,574
Deferred revenues........................ 25,740 29,110
Deferred income taxes.................... 30,262 38,544
Other long-term liabilities and
deferred credits....................... 199,796 246,464
---------- ----------
4,082,287 2,545,692
---------- ----------
Commitments and Contingencies (Notes 13
and 16)
Minority Interest.......................... 42,033 65,236
---------- ----------
Partners' Capital
Common Units (129,943,218 and 129,855,018
units issued and outstanding at
December 31, 2002 and 2001,
respectively)............................ 1,844,553 1,894,677

Class B Units (5,313,400 and 5,313,400
units issued and outstanding at
December 31, 2002 and 2001,
respectively)............................. 123,635 125,750

i-Units (45,654,048 and 30,636,363
units issued and outstanding at
December 31, 2002 and 2001,
respectively)............................. 1,420,898 1,020,153
General Partner........................... 72,100 54,628
Accumulated other comprehensive income.... (45,257) 63,826
----------- ----------
3,415,929 3,159,034
TOTAL LIABILITIES AND PARTNERS' CAPITAL. $8,353,576 $6,732,666
=========== ==========

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

93
<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,
----------------------------------
2002 2001 2000
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities
Net income............................ $ 608,377 $ 442,343 $ 278,348
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization....... 172,041 142,077 82,630
Amortization of excess cost of
equity investments................. 5,575 9,011 8,195
Earnings from equity investments.... (89,258) (84,834) (71,603)
Distributions from equity investments 77,735 68,832 47,512
Changes in components of working
capital:
Accounts receivable............... (177,240) 174,098 6,791
Other current assets.............. (7,583) 22,033 (6,872)
Inventories....................... (1,713) 22,535 (1,376)
Accounts payable.................. 288,712 (183,179) (8,374)
Accrued liabilities............... 26,232 (47,692) 26,479
Accrued taxes..................... 2,379 8,679 (1,302)
Rate refunds settlement............. (100) (100) (52,467)
Other, net.......................... (35,462) 7,358 (6,394)
----------- ----------- -----------
Net Cash Provided by Operating
Activities........................... 869,695 581,161 301,567
----------- ----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets.............. (908,511) (1,523,454) (1,008,648)
Additions to property, plant and
equipment for expansion and
maintenance projects............... (542,235) (295,088) (125,523)
Sale of investments, property, plant
and equipment, net of removal
costs.............................. 13,912 9,043 13,412
Acquisitions of investments......... (1,785) -- (79,388)
Contributions to equity investments. (10,841) (2,797) (375)
Other............................... (1,420) (6,597) 2,956
----------- ----------- -----------
Net Cash Used in Investing Activities. (1,450,880) (1,818,893) (1,197,566)
----------- ----------- -----------
Cash Flows From Financing Activities
Issuance of debt.................... 3,803,414 4,053,734 2,928,304
Payment of debt..................... (2,985,322) (3,324,161) (1,894,904)
Loans to related party.............. -- (17,100) --
Debt issue costs.................... (17,006) (8,008) (4,298)
Proceeds from issuance of common
units.............................. 1,586 4,113 171,433
Proceeds from issuance of i-units... 331,159 996,869 --
Contributions from General Partner.. 3,353 11,716 7,434
Distributions to partners:
Common units...................... (306,590) (268,644) (194,691)
Class B units..................... (12,540) (8,501) --
General Partner................... (253,344) (181,198) (91,366)
Minority interest................. (9,668) (14,827) (7,533)
Other, net.......................... 4,429 (2,778) 887
----------- ----------- -----------
Net Cash Provided by Financing
Activities........................... 559,471 1,241,215 915,266
----------- ----------- -----------
Increase (Decrease) in Cash and Cash
Equivalents.......................... (21,714) 3,483 19,267
Cash and Cash Equivalents, beginning
of period............................ 62,802 59,319 40,052
----------- ----------- -----------
Cash and Cash Equivalents, end of
period............................... $41,088 $62,802 $59,319
=========== =========== ===========
Noncash Investing and Financing
Activities:
Assets acquired by the issuance of $ -- $ -- $ 179,623
units..............................
Assets acquired by the assumption of
liabilities........................ 213,861 293,871 333,301
Supplemental disclosures of
cash flow information:
Cash paid during the year for
Interest (net of capitalized
interest).......................... 161,840 165,357 88,821
Income taxes........................ 1,464 2,168 1,806

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

94
<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

2002 2001 2000
----------------------- --------------------- ------------------------
Units Amount Units Amount Units Amount
--------- ---------- --------- ---------- --------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Common Units:
Beginning Balance.................. 129,855,018 $ 1,894,677 129,716,218 $ 1,957,357 118,274,274 $ 1,759,142
Net income......................... -- 254,934 -- 203,559 -- 168,878
Units issued as consideration in the
acquisition of assets or
Businesses....................... -- -- -- -- 2,428,344 53,050
Units issued for cash.............. 88,200 1,532 138,800 2,405 9,013,600 170,978
Distributions...................... -- (306,590) -- (268,644) -- (194,691)
Ending Balance..................... 129,943,218 1,844,553 129,855,018 1,894,677 129,716,218 1,957,357

Class B Units:
Beginning Balance.................. 5,313,400 125,750 5,313,400 125,961 -- --
Net income......................... -- 10,427 -- 8,335 -- --
Units issued as consideration in the
acquisition of assets or
Businesses....................... -- -- -- -- 5,313,400 125,961
Units issued for cash.............. -- (2) -- (44) -- --
Distributions...................... -- (12,540) -- (8,502) -- --
Ending Balance..................... 5,313,400 123,635 5,313,400 125,750 5,313,400 125,961

i-Units:
Beginning Balance.................. 30,636,363 1,020,153 -- -- -- --
Net income......................... -- 72,200 -- 28,354 -- --
Units issued for cash.............. 12,478,900 328,545 29,750,000 991,799 -- --
Distributions...................... 2,538,785 -- 886,363 -- -- --
Ending Balance..................... 45,654,048 1,420,898 30,636,363 1,020,153 -- --

General Partner:
Beginning Balance.................. -- 54,628 -- 33,749 -- 15,656
Net income......................... -- 270,816 -- 202,095 -- 109,470
Units issued as consideration in the
acquisition of assets or
Businesses....................... -- -- -- -- -- (11)
Units issued for cash.............. -- -- -- (18) -- --
Distributions...................... -- (253,344) -- (181,198) -- (91,366)
Ending Balance..................... -- 72,100 -- 54,628 -- 33,749

Accumulated other comprehensive income:
Beginning Balance.................. -- 63,826 -- -- -- --
Cumulative effect transition adj... -- -- -- (22,797) -- --
Change in fair value of derivatives
used for hedging purposes........ -- (116,560) -- 35,162 -- --
Reclassification of change in fair
value of derivatives to net
Income........................... -- 7,477 -- 51,461 -- --
Ending Balance..................... -- (45,257) -- 63,826 -- --

Total Partners' Capital.............. 180,910,666 $ 3,415,929 165,804,781 $ 3,159,034 135,029,618 $ 2,117,067

The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>

95
<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

General

Kinder Morgan Energy Partners, L.P., the "Partnership", is a Delaware limited
partnership formed in August 1992. We own and manage a diversified portfolio of
energy transportation and storage assets. We provide services to our customers
and create value for our unitholders primarily through the following activities:

o transporting, storing and processing refined petroleum products;

o transporting, storing and selling natural gas;

o transporting and selling carbon dioxide for use in, and selling crude
oil produced from, enhanced oil recovery operations; and

o transloading, storing and delivering a wide variety of bulk, petroleum and
petrochemical products at terminal facilities located across the United
States.

We focus on providing fee-based services to customers, avoiding commodity
price risks and taking advantage of the tax benefits of a limited partnership
structure. We trade on the New York Stock Exchange under the symbol "KMP" and
presently conduct our business through four reportable business segments:

o Products Pipelines;

o Natural Gas Pipelines;

o CO2 Pipelines; and

o Terminals.

For more information on our reportable business segments, see Note 15.

Kinder Morgan, Inc.

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. KMI
trades on the New York Stock Exchange under the symbol "KMI" and is one of
the largest energy transportation and storage companies in the United States,
operating, either for itself or on our behalf, more than 30,000 miles of
natural gas and products pipelines. It also has significant retail
distribution, electric generation and terminal assets. At December 31, 2002,
KMI and its consolidated subsidiaries owned, through its general and limited
partner interests, an approximate 19.2% interest in us. As a result of
owning this significant interest in us, KMI receives a substantial portion of
its earnings from returns on this investment.

Kinder Morgan Management, LLC

Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. It is referred to as "KMR" in this report. Our
general partner owns all of KMR's voting securities and, pursuant to a
delegation of control agreement, our general partner delegated to KMR, to the
fullest extent permitted under Delaware law and our partnership agreement, all
of its power and authority to manage and control our business and affairs,
except that KMR cannot take certain specified actions without the approval of
our general partner. Under

96
<PAGE>

the delegation of control agreement, KMR manages and controls our business
and affairs and the business and affairs of our operating limited partnerships
and their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, KMR's activities are limited to being a limited partner in,
and managing and controlling the business and affairs of us, our operating
limited partnerships and their subsidiaries.

In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares to the public in
an initial public offering. KMR's shares were initially issued at a price of
$35.21 per share, less commissions and underwriting expenses, and the shares
trade on the New York Stock Exchange under the symbol "KMR". Substantially all
of the net proceeds from the offering were used to buy i-units from us. The
i-units are a separate class of limited partner interests in us and are issued
only to KMR. When it purchased i-units from us, KMR became a limited partner in
us. At December 31, 2002, KMR and its consolidated subsidiary owned
approximately 25.2% of our outstanding limited partner units. KMR receives all
of its earnings from returns on this investment.

2. Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior years have been reclassified to conform to the current
presentation.

Our consolidated financial statements were prepared in accordance with
accounting principles generally accepted in the United States. Certain amounts
included in or affecting our financial statements and related disclosures must
be estimated, requiring us to make certain assumptions with respect to values or
conditions which cannot be known with certainty at the time the financial
statements are prepared.

The preparation of our financial statements in conformity with generally
accepted accounting principles requires our management to make estimates and
assumptions that affect:

o the amounts we report for assets and liabilities;

o our disclosure of contingent assets and liabilities at the date of the
financial statements; and

o the amounts we report for revenues and expenses during the reporting
period.

Therefore, the reported amounts of our assets and liabilities, revenues and
expenses and associated disclosures with respect to contingent assets and
obligations are necessarily affected by these estimates. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with experts and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates. Any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.

In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others.

Cash Equivalents

We define cash equivalents as all highly liquid short-term investments with
original maturities of three months or less.

97
<PAGE>

Accounts Receivables

Our policy for determining an appropriate allowance for doubtful accounts
varies according to the type of business being conducted and the customers being
served. An allowance for doubtful accounts is charged to expense monthly,
generally using a percentage of revenue or receivables, based on a historical
analysis of uncollected amounts, adjusted as necessary for changed circumstances
and customer-specific information. When specific receivables are determined to
be uncollectible, the reserve and receivable are relieved. The following tables
show the balance in the allowance for doubtful accounts and activity for the
years ended December 31, 2002, 2001 and 2000.

Valuation and Qualifying Accounts
(In thousands)

Year Ended December 31, 2002
----------------------------------------------------------------
Additions Additions
Balance at charged to charged to Balance at
beginning costs and other end of
of Period expenses accounts(1) Deductions(2) period
---------- ---------- ----------- ------------- ----------
Allowance for
Doubtful
Accounts..... $ 7,556 $ 822 $ 4 $ (290) $ 8,092
----------

(1)Additions represent the allowance recognized when we acquired IC Terminal
Holdings Company and Consolidated Subsidiaries.

(2)Deductions represent the write-off of receivables and the revaluation of the
allowance account.

Year Ended December 31, 2001
----------------------------------------------------------------
Additions Additions
Balance at charged to charged to Balance at
beginning costs and other end of
of Period expenses accounts(1) Deductions(2) period
---------- ---------- ----------- ------------- ----------
Allowance for
Doubtful
Accounts..... $ 4,151 $ 3,641 $ 1,362 $(1,598) $ 7,556
----------

(1)Additions represent the allowance recognized when we acquired CALNEV Pipe
Line LLC and Kinder Morgan Liquids Terminals LLC, as well as transfers from
other accounts.

(2)Deductions represent the write-off of receivables and the revaluation of the
allowance account.

Year Ended December 31, 2000
----------------------------------------------------------------
Additions Additions
Balance at charged to charged to Balance at
beginning costs and other end of
of Period expenses accounts(1) Deductions(2) period
---------- ---------- ----------- ------------- ----------
Allowance for
Doubtful
Accounts..... $ 6,717 $ -- $ 2,718 $(5,284) $ 4,151
----------

(1)Additions represent the allowance recognized when we acquired our Natural
Gas Pipelines.

(2)Deductions represent the write-off of receivables and the revaluation of the
allowance account.

In addition, at December 31, 2002, our balance of Accrued other current
liabilities in the accompanying consolidated balance sheet included
approximately $38.7 million related to customer prepayments.

Inventories

Our inventories of products consist of natural gas liquids, refined petroleum
products, natural gas, carbon dioxide and coal. We report these assets at the
lower of weighted-average cost or market. We report materials and supplies at
the lower of cost or market.

98
<PAGE>

Property, Plant and Equipment

We state property, plant and equipment at its acquisition cost. We expense
costs for maintenance and repairs in the period incurred. The cost of property,
plant and equipment sold or retired and the related depreciation are removed
from our balance sheet in the period of sale or disposition. We compute
depreciation using the straight-line method based on estimated economic lives.
Generally, we apply composite depreciation rates to functional groups of
property having similar economic characteristics. The rates range from 2.0% to
12.5%, excluding certain short-lived assets such as vehicles.

Our exploration and production activities are accounted for under the
successful efforts method of accounting. Under this method, costs of productive
wells and development dry holes, both tangible and intangible, as well as
productive acreage are capitalized and amortized on the unit-of-production
method. Proved developed reserves are used in computing units-of-production
rates for drilling and development costs, and total proved reserves are used for
depletion of leasehold costs. The basis for units-of-production rate
determination is by field. We charge the original cost of property sold or
retired to accumulated depreciation and amortization, net of salvage and cost of
removal. We do not include retirement gain or loss in income except in the case
of significant retirements or sales.

We review for the impairment of long-lived assets whenever events or
changes in circumstances indicate that our carrying amount of an asset may not
be recoverable. We would recognize an impairment loss when estimated future cash
flows expected to result from our use of the asset and its eventual disposition
is less than its carrying amount.

On January 1, 2002, we adopted Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" and we
now evaluate the impairment of our long-lived assets in accordance with this
Statement. This statement retains the requirements of SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of", however, this statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
the cost to sell it. Furthermore, the scope of discontinued operations is
expanded to include all components of an entity with operations of the entity in
a disposal transaction. The adoption of SFAS No. 144 has not had an impact on
our business, financial position or results of operations. In practice, the
composite life may not be determined with a high degree of precision, and hence
the composite life may not reflect the weighted average of the expected useful
lives of the asset's principal components.

Equity Method of Accounting

We account for investments in greater than 20% owned affiliates, which we do
not control, by the equity method of accounting. Under this method, an
investment is carried at our acquisition cost, plus our equity in undistributed
earnings or losses since acquisition.

Excess of Cost Over Fair Value

Effective January 1, 2002, we adopted SFAS No. 141, "Business Combinations"
and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141
supercedes Accounting Principles Board Opinion No. 16 and requires that all
transactions fitting the description of a business combination be accounted for
using the purchase method and prohibits the use of the pooling of interests for
all business combinations initiated after June 30, 2001. The Statement also
modifies the accounting for the excess of cost over the fair value of net assets
acquired as well as intangible assets acquired in a business combination. The
provisions of this Statement apply to all business combinations initiated after
June 30, 2001, and all business combinations accounted for by the purchase
method that are completed after July 1, 2001. In addition, this Statement
requires disclosure of the primary reasons for a business combination and the
allocation of the purchase price paid to the assets acquired and liabilities
assumed by major balance sheet caption.

SFAS No. 142 supercedes Accounting Principles Board Opinion No. 17 and
requires that goodwill no longer be amortized, but instead should be tested, at
least on an annual basis, for impairment. A benchmark assessment of potential
impairment must also be completed within six months of adopting SFAS No. 142.
After the first six

99
<PAGE>

months, goodwill will be tested for impairment annually or as changes in
circumstances require. SFAS No. 142 applies to any goodwill acquired in a
business combination completed after June 30, 2001. Other intangible assets are
to be amortized over their useful life and reviewed for impairment in accordance
with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets". An intangible asset with an indefinite useful life can no
longer be amortized until its useful life becomes determinable. In addition,
this Statement requires disclosure of information about goodwill and other
intangible assets in the years subsequent to their acquisition that was not
previously required. Required disclosures include information about the changes
in the carrying amount of goodwill from period to period and the carrying amount
of intangible assets by major intangible asset class.

These accounting pronouncements required that we prospectively cease
amortization of all intangible assets having indefinite useful economic lives.
Such assets, including goodwill, are not to be amortized until their lives are
determined to be finite. In addition, a recognized intangible asset with an
indefinite useful life and goodwill should be tested for impairment annually or
on an interim basis if events or circumstances indicate that the fair value of
the asset has decreased below its carrying value. We completed this initial
transition impairment test in June 2002 and determined that our goodwill and
such intangible assets were not impaired as of January 1, 2002.

Prior to January 1, 2002, we amortized the excess cost over the underlying
net asset book value of our equity investments using the straight-line method
over the estimated remaining useful lives of the assets in accordance with
Accounting Principles Board Opinion No. 16 "Business Combinations". We amortized
this excess for undervalued depreciable assets over a period not to exceed 50
years and for intangible assets over a period not to exceed 40 years. For our
consolidated affiliates, we reported amortization of excess cost over fair value
of net assets (goodwill) as amortization expense in our accompanying
consolidated statements of income. For our investments accounted for under the
equity method, we reported amortization of excess cost on investments as
amortization of excess cost of equity investments in our accompanying
consolidated statements of income.

Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was approximately $716.6 million as of December 31, 2002
and $546.7 million as of December 31, 2001. Such amounts are included within
goodwill on our accompanying consolidated balance sheets. Our total unamortized
excess cost over underlying fair value of net assets accounted for under the
equity method was approximately $140.3 million as of December 31, 2002 and
December 31, 2001. Per our adoption of SFAS No. 142, the December 31, 2002
balance is included within goodwill on our accompanying consolidated balance
sheet and the December 31, 2001 balance is included within investments on our
accompanying consolidated balance sheet.

In addition to our annual impairment test, we periodically reevaluate the
amount at which we carry the excess of cost over fair value of net assets of
businesses we acquired, as well as the amortization period for such assets, to
determine whether current events or circumstances warrant adjustments to our
carrying value and/or revised estimates of useful lives in accordance with
Accounting Principles Board Opinion No. 18 "The Equity Method of Accounting for
Investments in Common Stock". At December 31, 2002, we believed no such
impairment had occurred and no reduction in estimated useful lives was
warranted.

For more information on our acquisitions, see Note 3. For more information on
our investments, see Note 7.

Revenue Recognition

We recognize revenues for our pipeline operations based on delivery of actual
volume transported or minimum obligations under take-or-pay contracts. We
recognize bulk terminal transfer service revenues based on volumes loaded. We
recognize liquids terminal tank rental revenue ratably over the contract period.
We recognize liquids terminal through-put revenue based on volumes received or
volumes delivered depending on the customer contract. Liquids terminal minimum
take-or-pay revenue is recognized at the end of the contract year or contract
term depending on the terms of the contract. We recognize transmix processing
revenues based on volumes processed or sold, and if applicable, when title has
passed. We recognize energy-related product sales revenues based on delivered
quantities of product.

Capitalized Interest

We capitalize interest expense during the new construction or upgrade of
qualifying assets. Interest expense

100
<PAGE>

capitalized in 2002, 2001 and 2000 was $5.8 million, $3.1 million and $2.5
million, respectively.

Unit-Based Compensation

SFAS No. 123, "Accounting for Stock-Based Compensation", encourages, but does
not require, entities to adopt the fair value method of accounting for stock or
unit-based compensation plans. As allowed under SFAS No. 123, we apply
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations in accounting for common unit options
granted under our common unit option plan. Accordingly, compensation expense is
not recognized for common unit options unless the options are granted at an
exercise price lower than the market price on the grant date. Pro forma
information regarding changes in net income and per unit data, if the accounting
prescribed by SFAS No. 123 had been applied, is not material. No compensation
expense has been recorded since the options were granted at exercise prices
equal to the market prices at the date of grant. For more information on
unit-based compensation, see Note 13.

Environmental Matters

We expense or capitalize, as appropriate, environmental expenditures that
relate to current operations. We expense expenditures that relate to an existing
condition caused by past operations, which do not contribute to current or
future revenue generation. We do not discount environmental liabilities to a net
present value and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, our recording of these accruals coincides with our
completion of a feasibility study or our commitment to a formal plan of action.

We utilize both internal staff and external experts to assist us in
identifying environmental issues and in estimating the costs and timing of
remediation efforts. Often, as the remediation evaluation and effort progresses,
additional information is obtained, requiring revisions to estimated costs.
These revisions are reflected in our income in the period in which they are
reasonably determinable. In December 2002, after a thorough 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 $0.3 million non-recurring reduction in environmental expense and
in our overall accrued environmental liability, and we included this amount
within Other, net in the accompanying Consolidated Statement of Income for 2002.
The $0.3 million income item resulted from the necessity of properly adjusting
and realigning our environmental expenses and accrued liabilities between our
reportable business segments, specifically between our Products Pipelines and
our Terminals business segments. The $0.3 million reduction in environmental
expense resulted in a $15.7 million non-recurring loss to our Products Pipelines
business segment and a $16.0 million non-recurring gain to our Terminals
business segment.

Legal

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

Pension

We are required to make assumptions and estimates regarding the accuracy of
our pension investment returns. Specifically, these include:

o our investment return assumptions;

o the significant estimates on which those assumptions are based; and

101
<PAGE>

o the potential impact that changes in those assumptions could have on our
reported results of operations and cash flows.

We consider our overall pension liability exposure to be minimal in relation
to the value of our total consolidated assets and net income. However, in
accordance with SFAS No. 87, "Employers' Accounting for Pensions", a component
of our net periodic pension cost includes the return on pension plan assets,
including both realized and unrealized changes in the fair market value of
pension plan assets.

A source of volatility in pension costs comes from this inclusion of
unrealized or market value gains and losses on pension assets as part of the
components recognized as pension expense. To prevent wide swings in pension
expense from occurring because of one-time changes in fund values, SFAS No. 87
allows for the use of an actuarial computed "expected value" of plan asset gains
or losses to be the actual element included in the determination of pension
expense. The actuarial derived expected return on pension assets not only
employs an expected rate of return on plan assets, but also assumes a
market-related value of plan assets, which is a calculated value that recognizes
changes in fair value in a systematic and rational manner over not more than
five years. As required, we disclose the weighted average expected long-run rate
of return on our plan assets, which is used to calculate our plan assets'
expected return. For more information on our pension disclosures, see Note 10.

Gas Imbalances and Gas Purchase Contracts

We value gas imbalances due to or due from interconnecting pipelines at the
lower of cost or market. Gas imbalances represent the difference between
customer nominations and actual gas receipts from and gas deliveries to our
interconnecting pipelines under various Operational Balancing Agreements.
Natural gas imbalances are settled in cash or made up in-kind subject to the
pipelines' various terms.

Minority Interest

As of December 31, 2002, minority interest consists of the following:

o the 1.0101% general partner interest in our operating partnerships;

o the 0.5% special limited partner interest in SFPP, L.P.;

o the 50% interest in Globalplex Partners, a Louisiana joint venture owned
50% and controlled by Kinder Morgan Bulk Terminals, Inc.;

o the approximate 32% interest in MidTex Gas Storage Company, L.L.P., a Texas
limited liability partnership owned approximately 68% and controlled by
Kinder Morgan Texas Pipeline L.P. and its consolidated subsidiaries; and

o the 33 1/3% interest in International Marine Terminals, a Louisiana
partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P.
"C".

Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do
not directly pay federal income tax. Our taxable income or loss, which may vary
substantially from the net income or net loss we report in our consolidated
statement of income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of our net assets for financial
and tax reporting purposes cannot be readily determined as we do not have access
to information about each partner's tax attributes in the Partnership.

Some of our corporate subsidiaries and corporations in which we have an
equity investment do pay federal and state income taxes. Deferred income tax
assets and liabilities for certain operations conducted through corporations are
recognized for temporary differences between the assets and liabilities for
financial reporting and tax purposes. Changes in tax legislation are included in
the relevant computations in the period in which such changes are

102
<PAGE>

effective. Deferred tax assets are reduced by a valuation allowance for the
amount of any tax benefit not expected to be realized.

Comprehensive Income

Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income", requires that enterprises report a total for
comprehensive income. For each of the years ended December 31, 2002 and 2001,
the only difference between our net income and our comprehensive income was the
unrealized gain or loss on derivatives utilized for hedging purposes. There was
no difference between our net income and our comprehensive income for the year
ended December 31, 2000. For more information on our risk management activities,
see Note 14.

Net Income Per Unit

We compute Basic Limited Partners' Net Income per Unit by dividing 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 potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.

Two-for-one Common Unit Split

On July 18, 2001, KMR, the delegate of our general partner, approved a
two-for-one unit split of its outstanding shares and our outstanding common
units representing limited partner interests in us. The common unit split
entitled our common unitholders to one additional common unit for each common
unit held. Our partnership agreement provides that when a split of our common
units occurs, a unit split on our Class B units and our i-units will be effected
to adjust proportionately the number of our Class B units and i-units. The
issuance and mailing of split units occurred on August 31, 2001 to unitholders
of record on August 17, 2001. All references to the number of KMR shares, the
number of our limited partner units and per unit amounts in our consolidated
financial statements and related notes, have been restated to reflect the effect
of the split for all periods presented.

Risk Management Activities

We utilize energy derivatives for the purpose of mitigating our risk
resulting from fluctuations in the market price of natural gas, natural gas
liquids, crude oil and carbon dioxide. In addition, we enter into interest rate
swap agreements for the purpose of hedging the interest rate risk associated
with our fixed rate debt obligations. Prior to December 31, 2000, our accounting
policy for these activities was based on a number of authoritative
pronouncements including SFAS No. 80, "Accounting for Futures Contracts". Our
new policy, which is based on SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", became effective on January 1, 2001.

Effective January 1, 2001, we adopted SFAS No. 133, as amended by SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No.133" and No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities". SFAS No. 133
established accounting and reporting standards requiring that every derivative
financial instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, SFAS
No. 133 allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.

Furthermore, if the derivative transaction qualifies for and is designated as
a normal purchase and sale, it is exempted from the fair value accounting
requirements of SFAS No. 133 and is accounted for using traditional accrual
accounting. Our derivatives that hedge our commodity price risks involve our
normal business activities, which include the sale of natural gas, natural gas
liquids, oil and carbon dioxide, and these derivatives have been designated as
cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives
that hedge

103
<PAGE>

exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. The ineffective portion of the gain or loss is reported in earnings
immediately. See Note 14 for more information on our risk management activities.

3. Acquisitions and Joint Ventures

During 2000, 2001 and 2002, we completed the following significant
acquisitions. Each of the acquisitions was accounted for under the purchase
method and the assets acquired and liabilities assumed were recorded at their
estimated fair market values as of the acquisition date. The results of
operations from these acquisitions are included in our consolidated financial
statements from the date of acquisition.

Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc.

Effective January 1, 2000, we acquired all of the shares of the capital stock
of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. We paid an
aggregate consideration of approximately $31.0 million, including 1,148,344
common units, approximately $0.8 million in cash and the assumption of
approximately $7.0 million in liabilities. The Milwaukee terminal is located on
nine acres of property leased from the Port of Milwaukee. Its major cargoes are
coal, bulk de-icing salt and fertilizer. The Dakota terminal, located in St.
Paul, Minnesota, primarily handles bulk de-icing salt and grain products.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Common units issued.................... $23,319
Cash paid, including transaction costs 757
Liabilities assumed.................... 6,960
-------
Total purchase price................... $31,036
=======
Allocation of purchase price:
Current assets......................... $ 1,764
Property, plant and equipment.......... 15,201
Goodwill............................... 14,071
-------
$31,036
=======

Kinder Morgan CO2 Company, L.P.

Effective April 1, 2000, we acquired the remaining 78% limited partner
interest and the 2% general partner interest in Shell CO2 Company, Ltd. from
Shell for approximately $212.1 million and the assumption of approximately $37.1
million of liabilities. We renamed the limited partnership Kinder Morgan CO2
Company, L.P., and going forward from April 1, 2000, we have included its
results as part of our consolidated financial statements under our CO2 Pipelines
business segment. As is the case with all of our operating partnerships, we own
a 98.9899% limited partner interest in KMCO2 and our general partner owns a
direct 1.0101% general partner interest.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $212,081
Liabilities assumed................... 37,080
--------
Total purchase price.................. $249,161
========
Allocation of purchase price:
Current assets........................ $ 51,870
Property, plant and equipment......... 230,332
Goodwill.............................. 45,751
Equity investments.................... (79,693)(a)
Deferred charges and other assets..... 901
--------
$249,161
========

104
<PAGE>

(a) Represents reclassification of our original 20% equity investment in Shell
CO2 Company, L.P. of ($86.7) million and our allocation of purchase price to the
equity investment purchased in our acquisition of Shell CO2 Company, L.P. of
$7.0 million.

Devon Energy

Effective June 1, 2000, KMCO2 acquired significant interests in carbon
dioxide pipeline assets and oil-producing properties from Devon Energy
Production Company L.P. for $53.4 million. Included in the acquisition was an
approximate 81% equity interest in the Canyon Reef Carriers CO2 Pipeline, an
approximate 71% working interest in the SACROC oil field, and minority interests
in the Sharon Ridge unit and the Reinecke unit. All of the assets and properties
are located in the Permian Basin of West Texas.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $53,435
-------
Total purchase price.................. $53,435
=======
Allocation of purchase price:
Property, plant and equipment......... $53,435
-------
$53,435
=======

Buckeye Refining Company, LLC

On October 25, 2000, we acquired Kinder Morgan Transmix, LLC, formerly
Buckeye Refining Company, LLC, which owns and operates transmix processing
plants in Indianola, Pennsylvania and Wood River, Illinois and other related
transmix assets. As consideration for the purchase, we paid Buckeye
approximately $37.3 million for property, plant and equipment plus approximately
$8.4 million for net working capital and other items. We also assumed
approximately $11.5 million of liabilities.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $45,696
Liabilities assumed................... 11,462
-------
Total purchase price.................. $57,158
=======
Allocation of purchase price:
Current assets........................ $19,862
Property, plant and equipment......... 37,289
Deferred charges and other assets..... 7
-------
$57,158
=======

Cochin Pipeline

Effective November 3, 2000, we acquired from NOVA Chemicals Corporation an
undivided 32.5% interest in the Cochin Pipeline System for approximately $120.5
million. On June 20, 2001, we acquired an additional 2.3% ownership interest
from Shell Canada Limited for approximately $8.1 million. In January 2002, we
purchased an additional 10% ownership interest from NOVA Chemicals Corporation
for approximately $29 million. The January 2002 transaction was made effective
December 31, 2001. We now own approximately 44.8% of the Cochin Pipeline System
and the remaining interests are owned by subsidiaries of BP Amoco and
ConocoPhillips. We record our proportional share of joint venture revenues and
expenses and cost of joint venture assets with respect to the Cochin Pipeline
System as part of our Products Pipelines business segment.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $157,613
--------
Total purchase price.................. $157,613
========
Allocation of purchase price:
Property, plant and equipment......... $157,613
--------
$157,613
========

105
<PAGE>

Delta Terminal Services LLC

Effective December 1, 2000, we acquired all of the shares of the capital
stock of Delta Terminal Services LLC, formerly Delta Terminal Services, Inc.,
for approximately $118.1 million and the assumption of approximately $18.0
million of liabilities. The acquisition includes two liquid bulk storage
terminals in New Orleans, Louisiana and Cincinnati, Ohio.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $118,112
Liabilities assumed................... 17,976
--------
Total purchase price.................. $136,088
========
Allocation of purchase price:
Current assets........................ $ 1,137
Property, plant and equipment......... 70,610
Goodwill.............................. 64,304
Deferred charges and other assets..... 37
--------
$136,088
========

MKM Partners, L.P.

On December 28, 2000, we announced that KMCO2 had entered into a definitive
agreement to form a joint venture with Marathon Oil Company in the southern
Permian Basin of West Texas. The joint venture holds a nearly 13% interest in
the SACROC unit and a 49.9% interest in the Yates Field unit. The joint venture
was formed on January 1, 2001 and named MKM Partners, L.P. As of December 31,
2000, we paid $34.2 million plus committed 30 billion cubic feet of carbon
dioxide for our 7.5% interest in the Yates field unit. In January 2001, we
contributed our interest in the Yates field unit together with an approximate 2%
interest in the SACROC unit in return for a 15% interest in the joint venture.
In January 2001, Marathon Oil Company purchased an approximate 11% interest in
the SACROC unit from KMCO2 for $6.2 million. Marathon Oil Company then
contributed this interest in the SACROC unit and its 42.4% interest in the Yates
field unit for an 85% interest in the joint venture. Going forward from January
1, 2001, we accounted for this investment under the equity method of accounting.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $34,163
-------
Total purchase price.................. $34,163
=======
Allocation of purchase price:
Equity investments.................... $34,163
-------
$34,163
=======

2000 Kinder Morgan, Inc. Asset Contributions

Effective December 31, 2000, we acquired $621.7 million of assets from KMI.
We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp. (both of
which were converted to single-member limited liability companies), the Casper
and Douglas natural gas gathering and processing systems, a 50% interest in
Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services, LLC.
As consideration for these assets, we paid to KMI $192.7 million in cash and
approximately $156.3 million in units, consisting of 1,280,000 common units and
5,313,400 Class B units. We also assumed liabilities of approximately $272.7
million. The purchase price for the transaction was determined by the boards of
directors of KMI and our general partner based on pricing principles used in the
acquisition of similar assets. This transaction was approved unanimously by the
independent directors of our general partner, with the benefit of advice of
independent legal and financial advisors, including a fairness opinion from the
investment banking firm A.G. Edwards & Sons, Inc.

106
<PAGE>

Our purchase price and our allocation to assets acquired and liabilities assumed
was as follows (in thousands):

Purchase price:
Common and Class B units issued....... $156,305
Cash paid, including transaction costs 192,677
Liabilities assumed................... 272,718
--------
Total purchase price.................. $621,700
========
Allocation of purchase price:
Current assets........................ $255,320
Property, plant and equipment......... 137,145
Intangible-leasehold Value............ 179,390
Equity investments.................... 45,225
Deferred charges and other assets..... 4,620
--------
$621,700
========

Colton Transmix Processing Facility

Effective December 31, 2000, we acquired the remaining 50% interest in the
Colton Transmix Processing Facility from Duke Energy Merchants for approximately
$11.2 million and the assumption of approximately $1.8 million of liabilities.
We now own 100% of the Colton facility. Prior to our acquisition of the
controlling interest in the Colton facility, we accounted for our ownership
interest in the Colton facility under the equity method of accounting.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $11,233
Liabilities assumed................... 1,788
-------
Total purchase price.................. $13,021
=======
Allocation of purchase price:
Current assets........................ $ 4,465
Property, plant and equipment......... 8,556
-------
$13,021
=======

Domestic Pipelines and Terminals Businesses from GATX

During the first quarter of 2001, we acquired GATX Corporation's domestic
pipeline and terminal businesses. The acquisition included:

o Kinder Morgan Liquids Terminals LLC (formerly GATX Terminals
Corporation), effective January 1, 2001;

o Central Florida Pipeline LLC (formerly Central Florida Pipeline
Company), effective January 1, 2001; and

o CALNEV Pipe Line LLC (formerly CALNEV Pipe Line Company), effective March
30, 2001.

KMLT's assets then included 12 terminals, located across the United States,
which stored approximately 35.6 million barrels of refined petroleum products
and chemicals. Five of the terminals are included in our Terminals business
segment, and the remaining assets are included in our Products Pipelines
business segment. Central Florida Pipeline LLC consists of a 195-mile pipeline
transporting refined petroleum products from Tampa to the growing Orlando,
Florida market. CALNEV Pipe Line LLC consists of a 550-mile refined petroleum
products pipeline originating in Colton, California and extending into the
growing Las Vegas, Nevada market. The pipeline interconnects in Colton with our
Pacific operations' West Line pipeline segment. Our purchase price was
approximately $1,233.4 million, consisting of $975.4 million in cash, $134.8
million in assumed debt and $123.2 million in assumed liabilities.

107
<PAGE>

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $ 975,428
Debt assumed.......................... 134,746
Liabilities assumed................... 123,246
----------
Total purchase price.................. $1,233,420
==========
Allocation of purchase price:
Current assets........................ $ 32,364
Property, plant and equipment........ 928,736
Deferred charges and other assets.... 4,785
Goodwill............................. 267,535
----------
$1,233,420
==========

Pinney Dock & Transport LLC

Effective March 1, 2001, we acquired all of the shares of the capital stock
of Pinney Dock & Transport LLC, formerly Pinney Dock & Transport Company, for
approximately $51.7 million. The acquisition includes a bulk product terminal
located in Ashtabula, Ohio on Lake Erie. The facility handles iron ore, titanium
ore, magnetite and other aggregates. Our purchase price consisted of
approximately $41.7 million in cash and approximately $10.0 million in assumed
liabilities.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $41,674
Liabilities assumed................... 10,055
-------
Total purchase price.................. $51,729
=======
Allocation of purchase price:
Current assets........................ $ 1,970
Property, plant and equipment......... 32,467
Deferred charges and other assets..... 487
Goodwill.............................. 16,805
-------
$51,729
=======

Bulk Terminals from Vopak

Effective July 10, 2001, we acquired certain bulk terminal businesses, which
were converted or merged into six single-member limited liability companies,
from Koninklijke Vopak N.V. (Royal Vopak) of The Netherlands. Acquired assets
included four bulk terminals. Two of the terminals are located in Tampa, Florida
and the other two are located in Fernandina Beach, Florida and Chesapeake,
Virginia. As a result of the acquisition, our bulk terminals portfolio gained
entry into the Florida market. Our purchase price was approximately $44.3
million, consisting of approximately $43.6 million in cash and approximately
$0.7 million in assumed liabilities.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $43,622
Liabilities assumed................... 700
-------
Total purchase price.................. $44,322
=======
Allocation of purchase price:
Property, plant and equipment......... $44,322
=======

Kinder Morgan Texas Pipeline

Effective July 18, 2001, we acquired, from an affiliate of Occidental
Petroleum Corporation, K M Texas Pipeline, L.P., a partnership that owned a
natural gas pipeline system in the State of Texas. Prior to our acquisition of
this natural gas pipeline system, these assets were leased and operated by
Kinder Morgan Texas Pipeline, L.P., a business unit included in our Natural Gas
Pipelines business segment. As a result of this acquisition, we will be released
from lease payments of $40 million annually from 2002 through 2005 and $30
million annually from 2006

108
<PAGE>

through 2026. The acquisition included 2,600 miles of pipeline that primarily
transports natural gas from south Texas and the Texas Gulf Coast to the greater
Houston/Beaumont area. In addition, we signed a five-year agreement to supply
approximately 90 billion cubic feet of natural gas to chemical facilities owned
by Occidental affiliates in the Houston area. Our purchase price was
approximately $326.1 million and the entire cost was allocated to property,
plant and equipment. We merged K M Texas Pipeline, L.P. into Kinder Morgan Texas
Pipeline, L.P. on August 1, 2002.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $359,059
Release SFAS No. 13 deferred credit
previously held...................... (32,918)
---------
Total purchase price................. $326,141
========
Allocation of purchase price:
Property, plant and equipment........ $326,141
--------
$326,141

Note: These assets were previously leased from a third party under an
operating lease. The released Statement of Financial Accounting Standards No.
13, "Accounting for Leases" deferred credit relates to a deferred credit
accumulated to spread non-straight line operating lease rentals over the period
expected to benefit from those rentals.

The Boswell Oil Company

Effective August 31, 2001, we acquired from The Boswell Oil Company three
terminals located in Cincinnati, Ohio; Pittsburgh, Pennsylvania; and Vicksburg,
Mississippi. The Cincinnati and Pittsburgh terminals handle both liquids and
dry-bulk materials. The Vicksburg terminal is a break-bulk facility, primarily
handling paper and steel products. As a result of the acquisition, we continued
the expansion of our bulk terminal businesses and entered new markets. Our
purchase price was approximately $22.4 million, consisting of approximately
$18.0 million in cash, a $3.0 million one-year note payable and approximately
$1.4 million in assumed liabilities.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $18,035
Note payable.......................... 3,000
Liabilities assumed................... 1,364
-------
Total purchase price.................. $22,399
=======
Allocation of purchase price:
Current assets........................ $ 1,658
Property, plant and equipment......... 9,867
Intangibles-Contract Rights........... 4,000
Goodwill.............................. 6,874
-------
$22,399
=======

The $6.9 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.

Liquids Terminals from Stolt-Nielsen

In November 2001, we acquired certain liquids terminals in Chicago,
Illinois and Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc.,
Stolthaven Chicago Inc. and Stolt-Nielsen Transportation Group, Ltd. As a
result of the acquisition, we expanded our liquids terminals businesses into
strategic markets. The Perth Amboy facility provides liquid chemical and
petroleum storage and handling, as well as dry-bulk handling of salt and
aggregates, with liquid capacity exceeding 2.3 million barrels annually. We
closed on the Perth Amboy, New Jersey portion of this transaction on November
8, 2001. The Chicago terminal handles a wide variety of liquid chemicals
with a working capacity in excess of 0.7 million barrels annually. We closed
on the Chicago, Illinois portion of this transaction on November 29, 2001.
Our purchase price was approximately $70.8 million, consisting of
approximately $44.8 million in cash, $25.0 million in assumed debt and $1.0
million in assumed liabilities.

109
<PAGE>

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $44,838
Debt assumed.......................... 25,000
Liabilities assumed................... 1,000
-------
Total purchase price.................. $70,838
=======
Allocation of purchase price:
Property, plant and equipment......... $70,763
Goodwill.............................. 75
-------
$70,838
=======

The $0.1 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.

Interests in Snyder and Diamond M Plants

On November 14, 2001, we announced that KMCO2 had purchased Mission
Resources Corporation's interests in the Snyder Gasoline Plant and Diamond M
Gas Plant. In December 2001, KMCO2 purchased Torch E&P Company's interest in
the Snyder Gasoline Plant and entered into a definitive agreement to purchase
Torch's interest in the Diamond M Gas Plant. We paid approximately $20.9
million for these interests. All of these assets are located in the Permian
Basin of West Texas. As a result of the acquisition, we increased our
ownership interests in both plants, each of which process gas produced by the
SACROC unit. The acquisition expanded our carbon dioxide-related operations
and complemented our working interests in oil-producing fields located in
West Texas. Currently, we own an approximate 22% ownership interest in the
Snyder Gasoline Plant and a 51% ownership interest in the Diamond M Gas
Plant. The acquired interests are included as part of our CO2 Pipelines
business segment.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $20,872
-------
Total purchase price.................. $20,872
=======
Allocation of purchase price:
Property, plant and equipment......... $20,872
-------
$20,872
=======

Kinder Morgan Materials Services LLC

Effective January 1, 2002, we acquired all of the equity interests of
Kinder Morgan Materials Services LLC for approximately $8.9 million and the
assumption of approximately $3.3 million of liabilities, including long-term
debt of $0.4 million. Kinder Morgan Materials Services LLC currently
operates more than 60 transload facilities in 20 states. The facilities
handle dry-bulk products, including aggregates, plastics and liquid
chemicals. The acquisition of Kinder Morgan Materials Services LLC expanded
our growing terminal operations and is part of our Terminals business segment.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $ 8,916
Debt assumed.......................... 357
Liabilities assumed................... 2,967
-------
Total purchase price.................. $12,240
=======
Allocation of purchase price:
Current assets........................ $ 879
Property, plant and equipment......... 11,361
-------
$12,240
=======

110
<PAGE>

66 2/3% Interest in International Marine Terminals

Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals, referred to herein as IMT, from Marine Terminals
Incorporated. Effective February 1, 2002, we acquired an additional 33 1/3%
interest in IMT from Glenn Springs Holdings, Inc. Our combined purchase
price was approximately $40.5 million, including the assumption of $40
million of long-term debt. IMT is a partnership that operates a bulk
terminal site in Port Sulphur, Louisiana. This terminal is a multi-purpose
import and export facility, which handles approximately 8 million tons
annually of bulk products including coal, petroleum coke, iron ore and
barite. The acquisition complements our existing bulk terminal assets. IMT
is part of our Terminals business segment.

Our purchase price and our allocation to assets acquired, liabilities
assumed and minority interest was as follows (in thousands):

Purchase price:
Cash received, net of transaction costs $(3,781)
Debt assumed........................... 40,000
Liabilities assumed.................... 4,249
--------
Total purchase price................... $40,468
========
Allocation of purchase price:
Current assets......................... $6,600
Property, plant and equipment.......... 31,781
Deferred charges and other assets...... 139
Minority interest...................... 1,948
-------
$40,468
=======

Kinder Morgan Tejas

Effective January 31, 2002, we acquired all of the equity interests of
Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc.,
for an aggregate consideration of approximately $881.5 million, consisting of
$727.1 million in cash and the assumption of $154.4 million of liabilities.
Tejas Gas, LLC consists primarily of a 3,400-mile natural gas intrastate
pipeline system that extends from south Texas along the Mexico border and the
Texas Gulf Coast to near the Louisiana border and north from near Houston to
east Texas. The acquisition expands our natural gas operations within the
State of Texas. The acquired assets are referred to as Kinder Morgan Tejas
in this report and are included in our Natural Gas Pipelines business segment.

The allocation of our purchase price to the assets and liabilities of
Kinder Morgan Tejas is preliminary, pending final purchase price adjustments
that should be made in the first quarter of 2003. The total purchase price
increased $49.0 million in the fourth quarter of 2002 due to adjustments in
the amount of assumed liabilities related primarily to gas purchase
contracts. Due to the seasonality of certain gas purchase activities, we
were not able to determine the fair value of these contracts until the fourth
quarter of 2002. This pre-acquisition contingency was appropriately recorded
during the allocation period specified by SFAS No. 141, "Business
Combinations". The allocation of our purchase price was based on an
independent appraisal of fair market values as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $727,094
Liabilities assumed................... 154,455
--------
Total purchase price.................. $881,549
========
Allocation of purchase price:
Current assets........................ $ 56,496
Property, plant and equipment,
including cushion gas ............... 674,147
Goodwill ............................. 150,906
========
$881,549
========

The $150.9 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.

Milwaukee Bagging Operations

Effective May 1, 2002, we purchased a bagging operation facility adjacent
to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase
enhances the operations at our Milwaukee terminal, which is capable

111
<PAGE>

of handling up to 150,000 tons per year of fertilizer and salt for
de-icing and livestock purposes. The Milwaukee bagging operations are
included in our Terminals business segment.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands)

Purchase price:
Cash paid, including transaction costs $ 8,500
-------
Total purchase price.................. $ 8,500
=======
Allocation of purchase price:
Current assets........................ $ 40
Property, plant and equipment......... 3,140
Goodwill.............................. 5,320
-------
$8,500
=======

The $5.3 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.

Trailblazer Pipeline Company

On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68
million. We now own 100% of Trailblazer Pipeline Company. During the first
quarter of 2002, we paid $12.0 million to CIG Trailblazer Gas Company, an
affiliate of El Paso Corporation, in exchange for CIG's relinquishment of its
rights to become a 7% to 8% equity owner in Trailblazer Pipeline Company in
mid-2002. Trailblazer Pipeline Company is an Illinois partnership that owns
and operates a 436-mile natural gas pipeline system that traverses from
Colorado through southeastern Wyoming to Beatrice, Nebraska. Trailblazer
Pipeline Company has a current certificated capacity of 846 million cubic
feet per day of natural gas.

Our purchase price and our allocation to assets acquired, liabilities
assumed and minority interest was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $80,125
-------
Total purchase price.................. $80,125
=======
Allocation of purchase price:
Property, plant and equipment......... $41,739
Goodwill.............................. 15,000
Minority interest..................... 23,386
-------
$80,125
=======

The $15.0 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.

Owensboro Gateway Terminal

Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. As of December
31, 2002, we have paid approximately $7.2 million and established a $0.5
million liability for final purchase price settlements. The facility is one
of the nation's largest storage and handling points for bulk aluminum. The
terminal also handles a variety of other bulk products, including petroleum
coke, lime and de-icing salt. The terminal is situated on a 92-acre site
along the Ohio River, and the purchase expands our presence along the river,
complementing our existing facilities located near Cincinnati, Ohio and
Moundsville, West Virginia. The acquired terminal is now called the
Owensboro Gateway Terminal and is included in our Terminals business segment.

112
<PAGE>

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $7,140
Purchase price reserve................ 500
Liabilities assumed................... 11
------
Total purchase price.................. $7,651
======
Allocation of purchase price:
Current assets........................ $ 42
Property, plant and equipment......... 4,265
Intangibles-agreements................ 54
Goodwill.............................. 3,290
------
$7,651
======

The $3.3 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.

IC Terminal Holdings Company

Effective September 1, 2002, we acquired all of the shares of the capital
stock of IC Terminal Holdings Company from the Canadian National Railroad.
Our purchase price was approximately $17.8 million, consisting of $17.6
million and the assumption of $0.2 million in liabilities. The acquisition
includes the former ICOM marine terminal in St. Gabriel, Louisiana. The St.
Gabriel facility features 400,000 barrels of liquids storage capacity and a
related pipeline network that serves one of the fastest growing petrochemical
production areas in the country. The acquisition further expands our
terminal businesses along the Mississippi River. The acquired terminal will
be referred to as the Kinder Morgan St. Gabriel terminal and will be included
in our Terminals business segment.

Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):

Purchase price:
Cash paid, including transaction costs $17,572
Liabilities assumed................... 253
-------
Total purchase price.................. $17,825
=======
Allocation of purchase price:
Current assets........................ $ 46
Property, plant and equipment......... 14,430
Investment in ICPT, LLC............... 1,785
Non-current note receivable........... 1,350
Deferred charges and other assets..... 214
-------
$17,825
=======

Pro Forma Information

The following summarized unaudited Pro Forma Consolidated Income Statement
information for the twelve months ended December 31, 2002 and 2001, assumes
the 2002 and 2001 acquisitions and joint ventures had occurred as of January
1, 2001. 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
the 2002 and 2001 acquisitions and joint ventures as of January 1, 2001 or
the results which will be attained in the future. Amounts presented below
are in thousands, except for the per unit amounts:

Pro Forma Year Ended
December 31,
------------------------
2002 2001
---------- ----------
(Unaudited)
Revenues........................... $4,510,960 $5,275,551
Operating Income................... 729,564 609,439
Income before extraordinary charge. 632,171 519,980
Net Income......................... 616,888 502,487
Basic and diluted Limited Partners'
Net Income per unit............... $ 1.93 $ 1.60

113

<PAGE>

Acquisitions Subsequent to December 31, 2002

Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk facilities at major
ports along the East Coast and in the southeastern United States. The
acquisition also includes the purchase of certain assets that provide
stevedoring services at these locations. The cost of the acquisition will be
approximately $31.3 million. On December 31, 2002, we paid $29.9 million for
the Rudolph acquisition and this amount is included with Other current assets
on our accompanying balance sheet. We expect to pay the remaining
approximate amount of $1.4 million during the first quarter of 2003. The
acquired operations serve various terminals located at the ports of New York
and Baltimore, along the Delaware River in Camden, New Jersey, and in Tampa
Bay, Florida. Combined, these facilities transload nearly four million tons
annually of products such as fertilizer, iron ore and salt. The acquisition
expands our growing terminals business segment and complements certain of our
existing terminal facilities and will be included in our Terminals business
segment.

4. New Accounting Pronouncements

On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No. 143 requires companies to record a
liability relating to the retirement and removal of assets used in their
business. The liability is initially recorded at its fair value, and the
relative asset value is increased by the same amount. Over the life of the
asset, the liability will be accreted to its future value and eventually
extinguished when the asset is taken out of service. The provisions of this
statement are effective for fiscal years beginning after June 15, 2002. With
respect to our Natural Gas Pipelines and Products Pipelines business segments,
we have certain surface facilities that are required to be dismantled and
removed, with certain site reclamation to be performed. While, in general, our
right-of-way agreements do no require us to remove pipe or otherwise perform
remediation upon taking the pipeline permanently out of service, some
right-of-way agreements do provide for these actions. With respect to our CO2
Pipelines business segment, we generally are required to plug our oil production
wells when removed from service and we anticipate recording a liability for such
obligation. Our Terminals business segment has entered into certain facility
leases which require removal of improvements upon expiration of the lease term.
We anticipate recording a liability for such obligation. For the Natural Gas
Pipelines and Products Pipelines business segments, we expect that we will be
unable to reasonably estimate and record liabilities for the majority of our
obligations that fall under the provisions of this statement because we cannot
reasonably estimate when such obligations would be settled. For the CO2
Pipelines and Terminals business segments, the effect of adopting SFAS No. 143
is not material to the consolidated financial statements.

In April 2002, the Financial Accounting Standards Board issued SFAS No.
145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13, and Technical Corrections". This Statement eliminates the
current requirement that gains and losses on debt extinguishment must be
classified as extraordinary items in the income statement. Instead, such
gains and losses will be classified as extraordinary items only if they are
deemed to be unusual and infrequent, in accordance with the current GAAP
criteria for extraordinary classification. In addition, SFAS No. 145
eliminates an inconsistency in lease accounting by requiring that
modifications of capital leases that result in reclassification as operating
leases be accounted for consistent with sale-leaseback accounting rules.
This Statement also contains other nonsubstantive corrections to
authoritative accounting literature. The changes related to debt
extinguishment will be effective for fiscal years beginning after May 15,
2002, and the changes related to lease accounting will be effective for
transactions occurring after May 15, 2002. Adoption of this Statement will
not have any immediate effect on our consolidated financial statements. We
will apply this guidance prospectively.

In June 2002, the Financial Accounting Standards Board issued SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities",
which addresses accounting for restructuring and similar costs. SFAS No. 146
supersedes previous accounting guidance, principally Emerging Issues Task
Force Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for
restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF No. 94-3,
a liability for an exit cost was recognized at the date of the company's
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS
No. 146 may affect the timing of recognizing future restructuring costs as
well as the amounts recognized.

114
<PAGE>

In November 2002, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others". This interpretation of Financial Accounting Standards Board
Statements No. 5, 57 and 107, and rescission of FIN No. 34 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has
issued. It also clarifies that a guarantor is required to recognize, at the
inception of a guarantee, a liability for the fair value of the obligation
undertaken in issuing the guarantee. This interpretation incorporates,
without change, the guidance in FIN No. 34, "Disclosure of Indirect
Guarantees of Indebtedness of Others", which is being superceded. The
initial recognition and initial measurement provisions of FIN No. 45 are
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements in this interpretation are
effective for financial statements of interim or annual periods after
December 15, 2002, and have been adopted. For more information, see Note 13.

In December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation - Transition and Disclosure".
This amendment to SFAS No. 123, "Accounting for Stock-Based Compensation",
provides alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, this statement amends the disclosure requirements of SFAS No. 123
to require disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the effect
of the method used on reported results. The provisions of this statement are
effective for financial statements of interim or annual periods after
December 15, 2002. Early application of the disclosure provisions is
encouraged, and earlier application of the transition provisions is
permitted, provided that financial statements for the 2002 fiscal year have
not been issued as of the date the statement was issued.

5. Income Taxes

Components of the income tax provision applicable to continuing operations
for federal and state taxes are as follows (in thousands):

Year Ended December 31,
-------------------------------
2002 2001 2000
--------- --------- ---------
Taxes currently payable:
Federal................ $15,855 $ 9,058 $10,612
State.................. 3,116 1,192 1,416
Foreign................ 147 - -
--------- ------- -------
Total.................. 19,118 10,250 12,028
Taxes deferred:
Federal................ (3,280) 5,366 1,627
State.................. (555) 757 279
--------- ------- -------
Total.................. (3,835) 6,123 1,906
--------- ------- -------
Total tax provision..... $15,283 $16,373 $13,934
========= ======= ========
Effective tax rate..... 2.4% 3.5% 4.8%

The difference between the statutory federal income tax rate and our
effective income tax rate is summarized as follows:

Year Ended December 31,
----------------------------
2002 2001 2000
--------- -------- ---------
Federal income tax rate................ 35.0% 35.0% 35.0%
Increase (decrease) as a result of:
Partnership earnings not subject to
tax................................. (35.0)% (35.0)% (35.0)%
Corporate subsidiary earnings subject
to tax.............................. 0.6% 1.3% 0.6%
Income tax expense attributable to
corporate equity earnings........... 1.6% 1.8% 4.1%
State taxes.......................... 0.2% 0.4% 0.1%
Effective tax rate..................... 2.4% 3.5% 4.8%

115
<PAGE>

Deferred tax assets and liabilities result from the following (in
thousands):

December 31,
----------------
2002 2001
------- -------
Deferred tax assets:
Book accruals.................... $ 97 $ 404
Net Operating Loss/Alternative
minimum tax credits............. 3,556 1,846
------- -------
Total deferred tax assets.......... 3,653 2,250
Deferred tax liabilities:
Property, plant and equipment.... 33,915 40,794
------- -------
Total deferred tax liabilities..... 33,915 40,794
------- -------
Net deferred tax liabilities....... $30,262 $38,544
======= =======

We had available, at December 31, 2002, approximately $1.4 million of
alternative minimum tax credit carryforwards, which are available
indefinitely, and $2.1 million of net operating loss carryforwards, which
will expire between the years 2003 and 2022. We believe it is more likely
than not that the net operating loss carryforwards will be utilized prior to
their expiration; therefore, no valuation allowance is necessary.

6. Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

December 31,
-------------------
2002 2001
-------- --------
Natural gas, liquids and carbon dioxide
pipelines............................... $2,544,987 $2,246,930
Natural gas, liquids and carbon dioxide
pipeline station equipment.............. 2,801,729 2,168,924
Coal and bulk tonnage transfer, storage
and services............................ 281,713 214,040
Natural gas and transmix processing...... 98,094 97,155
Other.................................... 292,881 217,245
Accumulated depreciation and depletion... (452,408) (302,012)
----------- -----------
5,566,996 4,642,282
Land and land right-of-way............... 340,507 283,878
Construction work in process............. 336,739 156,452
----------- -----------
$6,244,242 $5,082,612
=========== ===========

Depreciation and depletion expense charged against property, plant and
equipment consists of the following (in thousands):

2002 2001 2000
-------- -------- -------
Depreciation and
depletion expense........ $171,461 $126,641 $79,740

7. Investments

Our significant equity investments at December 31, 2002 consisted of:

o Plantation Pipe Line Company (51%);

o Red Cedar Gathering Company (49%);

o MKM Partners, L.P. (15%);

o Thunder Creek Gas Services, LLC (25%);

o Coyote Gas Treating, LLC (Coyote Gulch) (50%);

o Cortez Pipeline Company (50%); and

o Heartland Pipeline Company (50%).

116
<PAGE>

On April 1, 2000, we acquired the remaining 80% ownership interest in
Shell CO2 Company, Ltd. and renamed the entity Kinder Morgan CO2 Company,
L.P. On December 31, 2000, we acquired the remaining 50% ownership interest
in the Colton Transmix Processing Facility. Due to these acquisitions, we no
longer report these two investments under the equity method of accounting.
In addition, we had an equity investment in International Marine Terminals
(33 1/3%) for one month of 2002. We acquired an additional 33 1/3% interest
in International Marine Terminals effective February 1, 2002, and after this
date, the financial results of IMT were no longer reported under the equity
method.

We own approximately 51% of Plantation Pipe Line Company, and an affiliate
of ExxonMobil owns the remaining approximate 49%. Each investor has an equal
number of directors on Plantation's board of directors, and board approval is
required for certain corporate actions that are considered participating
rights. Therefore, we do not control Plantation Pipe Line Company, and we
account for our investment under the equity method of accounting.

On January 1, 2001, Kinder Morgan CO2 Company, L.P. acquired our 15%
interest in MKM Partners, L.P., a joint venture with Marathon Oil Company in
the southern Permian Basin of West Texas. The joint venture consists of a
nearly 13% interest in the SACROC unit and a 49.9% interest in the Yates oil
field. We account for our 15% investment in the joint venture under the
equity method of accounting because our ownership interest includes 50% of
the joint venture's general partner interest, and the ownership of this
general partner interest gives us the ability to exercise significant
influence over the operating and financial policies of the joint venture.

We acquired our investment in Cortez Pipeline Company as part of our KMCO2
acquisition. We acquired our investments in Coyote Gas Treating, LLC and
Thunder Creek Gas Services, LLC from KMI on December 31, 2000. Please refer
to Note 3 for more information on our acquisitions.

On January 1, 2002, we adopted SFAS No. 142 and, accordingly, we reclassed
the $140.3 million representing the balance, on that date, of our total
unamortized excess cost over underlying fair value of net assets accounted
for under the equity method from our investments to our goodwill.

Our total investments consisted of the following (in thousands):

December 31,
--------------------
2002 2001
--------- ---------
Plantation Pipe Line Company............. $126,024 $217,473
Red Cedar Gathering Company.............. 64,459 99,484
MKM Partners, L.P........................ 60,795 58,633
Thunder Creek Gas Services, LLC.......... 36,921 30,159
Coyote Gas Treating, LLC................. 2,344 16,323
Cortez Pipeline Company.................. 10,486 9,599
Heartland Pipeline Company............... 5,459 5,608
All Others............................... 4,556 3,239
-------- --------
Total Equity Investments................. $311,044 $440,518
======== ========

Our earnings from equity investments were as follows (in thousands):

Year Ended December 31,
---------------------------
2002 2001 2000
-------- -------- --------
Plantation Pipe Line Company.......... $26,426 $25,314 $31,509
Cortez Pipeline Company............... 28,154 25,694 17,219
Red Cedar Gathering Company........... 19,082 18,814 16,110
MKM Partners, L.P..................... 8,174 8,304 --
Coyote Gas Treating, LLC.............. 2,651 2,115 --
Thunder Creek Gas Services, LLC....... 2,154 1,629 --
Heartland Pipeline Company............ 998 882 1,581
Shell CO2 Company, Ltd................ -- -- 3,625
Coltonn Transmix Processing Facility.. -- -- 1,815
Trailblazer Pipeline Company.......... -- -- (24)
All Others............................ 1,619 2,082 (232)
-------- -------- --------
Total................................. $89,258 $84,834 $71,603
======== ======== ========
Amortization of excess costs.......... $(5,575) $(9,011) $(8,195)
======== ======== ========
117
<PAGE>

Summarized combined unaudited financial information for our significant
equity investments is reported below (in thousands; amounts represent 100% of
investee financial information):

Year Ended December 31,
----------------------------
Income Statement 2002 2001 2000
-------------------------------- -------- -------- --------
Revenues........................... $505,602 $449,259 $399,335
Costs and expenses................. 309,291 280,100 276,000
Earnings before extraordinary items 196,311 169,159 123,335
Net income......................... 196,311 169,159 123,335

December 31,
-------------------
Balance Sheet 2002 2001
-------------------- --------- ---------
Current assets.......... $ 83,410 $ 101,015
Non-current assets...... 1,101,057 1,079,053
Current liabilities..... 243,636 242,438
Non-current liabilities. 374,132 392,739
Partners'/owners' equity 566,699 544,891

8. Intangibles

Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141 "Business Combinations" and Statement of Financial
Accounting Standards No. 142 "Goodwill and Other Intangible Assets". These
accounting pronouncements require that we prospectively cease amortization of
all intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined
to be finite. A recognized intangible asset with an indefinite useful life
should be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below
its carrying value. We completed this initial transition impairment test in
June 2002 and determined that our goodwill was not impaired as of January 1,
2002.

Our intangible assets include goodwill, lease value, contracts and
agreements. We acquired our intangible lease value as part of our
acquisition of Kinder Morgan Texas Pipeline, L.P. on December 31, 2000 from
KMI. In our July 2001 acquisition of K M Texas Pipeline, L.P., we acquired
the leased pipeline asset from Occidental Petroleum and our operating lease
was terminated. We then allocated the balance of the Kinder Morgan Texas
Pipeline, L.P. intangible lease value between goodwill and property.

All of our intangible assets having definite lives are being amortized on
a straight-line basis over their estimated useful lives. SFAS Nos. 141 and
142 also require that we disclose the following information related to our
intangible assets still subject to amortization and our goodwill (in
thousands):

December 31,
-----------------
2002 2001
--------- ---------
Goodwill.................. $876,839 $566,633
Accumulated amortization.. (19,899) (19,899)
--------- ---------
Goodwill.................. 856,940 546,734
Lease value............... 6,124 6,124
Contracts and other....... 11,580 10,739
Accumulated amortization.. (380) (200)
--------- ---------
Other intangibles, net 17,324 16,663
--------- ---------
Total intangibles, net $874,264 $563,397
========= =========

118
<PAGE>

Changes in the carrying amount of goodwill for the twelve months ended
December 31, 2002 are summarized as follows (in thousands):

<TABLE>
<CAPTION>
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
--------- ----------- --------- --------- -----
<S> <C> <C> <C> <C> <C>
Balance at Dec. 31, 2000 $ - $ - $ 50,324 $107,746 $158,070
Goodwill acquired 267,816 87,452 (2,999) 46,359 398,628
Goodwill dispositions, net - - - - -
Amortized to expense (5,051) - (1,224) (3,689) (9,964)
Impairment losses - - - - -
------------- ----------- ------------ --------- ---------
Balance at Dec. 31, 2001 $ 262,765 $ 87,452 $ 46,101 $150,416 $546,734
============= =========== ============ ========= =========
Transfer from investments 86,276 54,054 - - 140,330
Goodwill acquired 417 165,906 - 3,553 169,876
Goodwill dispositions, net - - - - -
Impairment losses - - - - -
------------- ----------- ------------ --------- ---------
Balance at Dec. 31, 2002 $ 349,458 $ 307,412 $ 46,101 $ 153,969 $ 856,940
============= =========== ============ ========= =========
</TABLE>

Amortization expense on intangibles, including amortization of excess
intangible costs of equity investments, consists of the following (in
thousands):
2002 2001 2000
------ ------ ------
Goodwill............ $ - $13,416 $5,460
Lease value......... 140 4,999 140
Contracts and other. 40 60 40
----- ------- ------
Total amortization.. $ 180 $18,475 $5,640
===== ======= ======

Our weighted average amortization period for our intangible assets is
approximately 41 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
Year Expense
---- -------
2003 $180
2004 $180
2005 $180
2006 $180
2007 $180

Had SFAS No. 142 been in effect prior to January 1, 2002, our reported
limited partners' interest in net income and net income per unit would have
been as follows (in thousands, except per unit amounts):

Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
Reported limited partners' interest in
net income $ 337,561 $ 240,248 $ 168,878
Add: limited partners' interest in
goodwill amortization -- 13,280 5,405
--------- --------- ---------
Adjusted limited partners' interest in
net income $ 337,561 $ 253,528 $ 174,283
========= ========= =========
Basic limited partners' net income per
unit:
Reported net income $ 1.96 $ 1.56 $ 1.34
Goodwill amortization -- 0.09 0.04
--------- --------- ---------
Adjusted net income $ 1.96 $ 1.65 $ 1.38
========= ========= =========

Diluted limited partners' net income
per unit:
Reported net income $ 1.96 $ 1.56 $ 1.34
Goodwill amortization
-- 0.09 0.04
--------- --------- ---------
Adjusted net income $ 1.96 $ 1.65 $ 1.38
========= ========= =========

9. Debt

Our debt and credit facilities as of December 31, 2002, consisted
primarily of:

o a $530 million unsecured 364-day credit facility due October 14, 2003;

119
<PAGE>

o a $445 million unsecured three-year credit facility due October 15, 2005;

o $37.1 million of Series F First Mortgage Notes due December 2004 (our
subsidiary, SFPP, L.P. is the obligor on the notes);

o $200 million of 8.00% Senior Notes due March 15, 2005;

o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal
District Revenue Bonds due March 15, 2006 (our 66 2/3% owned
subsidiary, International Marine Terminals, is the obligor on the
bonds);

o $250 million of 5.35% Senior Notes due August 15, 2007;

o $30 million of 7.84% Senior Notes, with a final maturity of July 2008
(our subsidiary, Central Florida Pipe Line LLC, is the obligor on the
notes);

o $250 million of 6.30% Senior Notes due February 1, 2009;

o $250 million of 7.50% Senior Notes due November 1, 2010;

o $700 million of 6.75% Senior Notes due March 15, 2011;

o $450 million of 7.125% Senior Notes due March 15, 2012;

o $25 million of New Jersey Economic Development Revenue Refunding Bonds
due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals
LLC, is the obligor on the bonds);

o $87.9 million of Industrial Revenue Bonds with final maturities ranging
from September 2019 to December 2024 (our subsidiary, Kinder Morgan
Liquids Terminals LLC, is the obligor on the bonds);

o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder
Morgan Operating L.P. "B", is the obligor on the bonds);

o $300 million of 7.40% Senior Notes due March 15, 2031;

o $300 million of 7.75% Senior Notes due March 15, 2032;

o $500 million of 7.30% Senior Notes due August 15, 2033; and

o a $975 million short-term commercial paper program (supported by our
credit facilities, the amount available for borrowing under our credit
facilities is reduced by our outstanding commercial paper borrowings).

None of our debt or credit facilities are subject to payment acceleration
as a result of any change to our credit ratings. However, the margin that we
pay with respect to LIBOR based borrowings under our credit facilities is
tied to our credit ratings.

Our outstanding short-term debt at December 31, 2002, consisted of:

o $220 million of commercial paper borrowings;

o $37.1 million under the SFPP, L.P. 10.7% First Mortgage Notes;

o $5 million under the Central Florida Pipeline LLC Notes; and

o $2.8 million in other borrowings.

We intend and have the ability to refinance our $264.9 million of
short-term debt on a long-term basis under our

120
<PAGE>

unsecured long-term credit facility. Accordingly, such amounts have been
classified as long-term debt in our accompanying consolidated balance sheet.
Currently, we do not anticipate any liquidity problems. The weighted average
interest rate on all of our borrowings was approximately 5.015% during 2002
and 6.965% during 2001.

Credit Facilities

On December 31, 2000, we had two credit facilities, a $300 million
unsecured five-year credit facility expiring on September 29, 2004, and a
$600 million unsecured 364-day credit facility expiring on October 25, 2001.
On December 31, 2000, the outstanding balance under our five-year credit
facility was $207.6 million and the outstanding balance under our 364-day
credit facility was $582 million.

During the first quarter of 2001, we obtained a third unsecured credit
facility, in the amount of $1.1 billion, expiring on December 31, 2001. The
credit facility was used to support the increase in our commercial paper
program to $1.7 billion for our acquisition of the GATX businesses. The
terms of this credit facility were substantially similar to the terms of the
other two facilities. Upon issuance of additional senior notes on March 12,
2001, this short-term credit facility was reduced to $500 million. During
the second quarter of 2001, we terminated this $500 million credit facility,
which was scheduled to expire on December 31, 2001. On October 25, 2001, our
364-day credit facility expired and we obtained a new $750 million unsecured
364-day credit facility expiring on October 23, 2002. The terms of this
credit facility were substantially similar to the terms of the expired
facility. There were no borrowings under either credit facility at December
31, 2001.

On February 21, 2002, we obtained a third unsecured 364-day credit
facility, in the amount of $750 million, expiring on February 20, 2003. The
credit facility was used to support the increase in our commercial paper
program to $1.8 billion for our acquisition of Tejas Gas, LLC, and the terms
of this credit facility were substantially similar to the terms of our other
two credit facilities. Upon issuance of additional senior notes in March
2002, this short-term credit facility was reduced to $200 million.

In August 2002, upon the completion of our i-unit equity sale, we
terminated, under the terms of the agreement, our $200 million unsecured
364-day credit facility that was due February 20, 2003. On October 16, 2002,
we successfully renegotiated our bank credit facilities by replacing our $750
million unsecured 364-day credit facility due October 23, 2002 and our $300
million unsecured five-year credit facility due September 29, 2004 with two
new credit facilities. Our current facilities include:

o a $530 million unsecured 364-day credit facility due October 14, 2003;
and

o a $445 million unsecured three-year credit facility due October 15, 2005.

Our credit facilities are with a syndicate of financial institutions.
Wachovia Bank, National Association is the administrative agent under both
credit facilities. The terms of our two credit facilities are substantially
similar to the terms of our previous credit facilities. Interest on the two
credit facilities accrues at our option at a floating rate equal to either:

o the administrative agent's base rate (but not less than the Federal
Funds Rate, plus 0.5%); or

o LIBOR, plus a margin, which varies depending upon the credit rating of
our long-term senior unsecured debt.

Our credit facilities include the following restrictive covenants as of
December 31, 2002:

o requirements to maintain certain financial ratios:

o total debt divided by earnings before interest, income taxes,
depreciation and amortization for the preceding four quarters may not
exceed 5.0;

o total indebtedness of all consolidated subsidiaries shall at no time
exceed 15% of consolidated indebtedness;

o tangible net worth as of the last day of any fiscal quarter shall not
be less than $2,100,000,000; and

121
<PAGE>

o consolidated indebtedness shall at no time exceed 62.5% of total
capitalization;

o limitations on entering into mergers, consolidations and sales of assets;

o limitations on granting liens; and

o prohibitions on making any distribution to holders of units if an event
of default exists or would exist upon making such distribution.

There were no borrowings under either credit facility at December 31,
2002. The amount available for borrowing under our credit facilities is
reduced by:

o a $23.7 million letter of credit that supports Kinder Morgan Operating
L.P. "B"'s tax-exempt bonds;

o a $28 million letter of credit entered into on December 23, 2002 that
supports Nassau County, Florida Ocean Highway and Port Authority tax
exempt bonds (associated with the operations of our bulk terminal
facility located at Fernandina Beach, Florida); and

o our outstanding commercial paper borrowings.

Our new three-year credit facility also permits us to obtain bids for
fixed rate loans from members of the lending syndicate.

Senior Notes

On March 12, 2001, we closed a public offering of $1.0 billion in
principal amount of senior notes, consisting of $700 million in principal
amount of 6.75% senior notes due March 15, 2011 at a price to the public of
99.705% per note, and $300 million in principal amount of 7.40% senior notes
due March 15, 2031 at a price to the public of 99.748% per note. In the
offering, we received proceeds, net of underwriting discounts and
commissions, of approximately $693.4 million for the 6.75% notes and $296.6
million for the 7.40% notes. We used the proceeds to pay for our acquisition
of Pinney Dock & Transport LLC (see Note 3) and to reduce our outstanding
balance on our credit facilities and commercial paper borrowings.

On March 14, 2002, we closed a public offering of $750 million in
principal amount of senior notes, consisting of $450 million in principal
amount of 7.125% senior notes due March 15, 2012 at a price to the public of
99.535% per note, and $300 million in principal amount of 7.75% senior notes
due March 15, 2032 at a price to the public of 99.492% per note. In the
offering, we received proceeds, net of underwriting discounts and
commissions, of approximately $445.0 million for the 7.125% notes and $295.9
million for the 7.75% notes. We used the proceeds to reduce our outstanding
balance on our commercial paper borrowings.

On March 22, 2002, we paid $200 million to retire the principal amount of
our Floating Rate senior notes that matured on that date. We borrowed the
necessary funds under our commercial paper program.

Under an indenture dated August 19, 2002, and a First Supplemental
Indenture dated August 23, 2002, we completed a private placement of $750
million in debt securities. The notes consisted of $500 million in principal
amount of 7.30% Senior Notes due August 15, 2033 and $250 million in
principal amount of 5.35% Senior Notes due August 15, 2007. In the offering,
we received proceeds, net of underwriting discounts and commissions, of
approximately $494.7 million for the 7.30% notes and $248.3 million for the
5.35% notes. The proceeds were used to reduce the borrowings under our
commercial paper program. On November 18, 2002, we exchanged these notes
with substantially identical notes that were registered under the Securities
Act of 1933.

122
<PAGE>

At December 31, 2002, our unamortized liability balance due on the various
series of our senior notes was as follows (in millions):

8.0% senior notes due March 15, 2005 $ 199.8
5.35% senior notes due August 15, 2007 249.8
6.3% senior notes due February 1, 2009 249.5
7.5% senior notes due November 1, 2010 248.8
6.75% senior notes due March 15, 2011 698.3
7.125% senior notes due March 15, 2012 448.1
7.4% senior notes due March 15, 2031 299.3
7.75% senior notes due March 15, 2032 298.5
7.3% senior notes due August 15, 2033 499.0
--------
Total $3,191.1
========

Interest Rate Swaps

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
December 31, 2002, we have entered into interest rate swap agreements with a
notional principal amount of $1.95 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt
obligations.

These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. These swaps also meet the conditions required to
assume no ineffectiveness under SFAS No. 133 and, therefore, we have
accounted for them using the "shortcut" method prescribed for fair value
hedges by SFAS No. 133. 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. At
December 31, 2002, we recognized an asset of $167.0 million for the net fair
value of our swap agreements and we included this amount with Deferred
charges and other assets on the accompanying balance sheet. At December 31,
2001, we recognized a liability of $5.4 million for the net fair value of our
swap agreements and we included this amount with Other long-term liabilities
and deferred Credits on the accompanying balance sheet. For more information
on our risk management activities, see Note 14.

Commercial Paper Program

On December 31, 2000, our commercial paper program provided for the
issuance of up to $600 million of commercial paper. On that date, we had $52
million of commercial paper outstanding with an interest rate of 7.02%.
During the first quarter of 2001, we increased our commercial paper program
to provide for the issuance of an additional $1.1 billion of commercial
paper. We entered into a $1.1 billion unsecured 364-day credit facility to
support this increase in our commercial paper program, and we used the
program's increase in available funds to close on the GATX acquisition.

In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares representing
limited liability company interests with limited voting rights to the public
in an initial public offering. Its shares were issued at a price of $35.21
per share, less commissions and underwriting expenses, and it used
substantially all of the net proceeds from that offering to purchase i-units
from us. After commissions and underwriting expenses, we received net
proceeds of approximately $996.9 million for the issuance of 29,750,000
i-units to KMR. We used the proceeds from the i-unit issuance to reduce the
borrowings under our commercial paper program.

Also during the second quarter of 2001, after the issuance of additional
senior notes on March 12, 2001 and the issuance of i-units in May 2001, we
decreased our commercial paper program back to $600 million. On October 17,
2001, we increased our commercial paper program to $900 million. As of
December 31, 2001, we had $590.5 million of commercial paper outstanding with
an interest rate of 2.6585%.

On February 21, 2002, our commercial paper program increased to provide
for the issuance of up to $1.8 billion of commercial paper. We entered into
a $750 million unsecured 364-day credit facility to support this increase in
our

123
<PAGE>

commercial paper program, and we used the program's increase in available
funds to close on the Tejas acquisition. After the issuance of additional
senior notes on March 14, 2002, we reduced our commercial paper program to
$1.25 billion.

On August 6, 2002, KMR issued in a public offering, an additional
12,478,900 of its shares, including 478,900 shares upon exercise by the
underwriters of an over-allotment option, at a price of $27.50 per share,
less commissions and underwriting expenses. The net proceeds from the
offering were used to buy i-units from us. After commissions and
underwriting expenses, we received net proceeds of approximately $331.2
million for the issuance of 12,478,900 i-units. We used the proceeds from
the i-unit issuance to reduce the borrowings under our commercial paper
program and, in conjunction with our issuance of additional i-units and as
previously agreed upon under the terms of our credit facilities, we reduced
our commercial paper program to provide for the issuance of up to $975
million of commercial paper as of December 31, 2002. On December 31, 2002,
we had $220.0 million of commercial paper outstanding with an average
interest rate of 1.58%.

The borrowings under our commercial paper program were used to finance
acquisitions made during 2001 and 2002. The borrowings under our commercial
paper program reduce the borrowings allowed under our credit facilities.

SFPP, L.P. Debt

At December 31, 2002, the outstanding balance under SFPP, L.P.'s Series F
notes was $37.1 million. The annual interest rate on the Series F notes is
10.70%, the maturity is December 2004, and interest is payable semiannually
in June and December. We expect to repay the Series F notes prior to
maturity as a result of SFPP, L.P. taking advantage of certain optional
prepayment provisions without penalty in 1999 and 2000. We expect to pay the
remaining $37.1 million balance in December 2003. Additionally, the Series F
notes may be prepaid in full or in part at a price equal to par plus, in
certain circumstances, a premium. We agreed as part of the acquisition of
SFPP, L.P.'s operations (which constitute a significant portion of our
Pacific operations) not to take actions with respect to $190 million of SFPP,
L.P.'s debt that would cause adverse tax consequences for the prior general
partner of SFPP, L.P. The Series F notes are collateralized by mortgages on
substantially all of the properties of SFPP, L.P. The Series F notes contain
certain covenants limiting the amount of additional debt or equity that may
be issued by SFPP, L.P. and limiting the amount of cash distributions,
investments, and property dispositions by SFPP, L.P. We do not believe that
these restrictions will materially affect distributions to our partners.

Kinder Morgan Liquids Terminals LLC Debt

Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC
(see Note 3). As part of our purchase price, we assumed debt of $87.9
million, consisting of five series of Industrial Revenue Bonds. The bonds
consist of the following:

o $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September
1, 2019;

o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,
2022;

o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September
1, 2022;

o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,
2023; and

o $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,
2024.

In November 2001, we acquired a liquids terminal in Perth Amboy, New
Jersey from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation
Group, Ltd. (see Note 3). As part of our purchase price, we assumed $25.0
million of Economic Development Revenue Refunding Bonds issued by the New
Jersey Economic Development Authority. These bonds have a maturity date of
January 15, 2018. Interest on these bonds is computed on the basis of a year
of 365 or 366 days, as applicable, for the actual number of days elapsed
during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a
360-day year consisting of twelve 30-day months during a Term Rate Period.
As of December 31, 2002, the interest rate was 1.05%. We have an outstanding
letter of credit issued by Citibank in the amount of $25.3 million that
backs-up the $25.0 million principal amount of the bonds and $0.3

124
<PAGE>

million of interest on the bonds for up to 42 days computed at 12% on a
per annum basis on the principal thereof.

Central Florida Pipeline LLC Debt

Effective January 1, 2001, we acquired Central Florida Pipeline LLC (see
Note 3). As part of our purchase price, we assumed an aggregate principal
amount of $40 million of Senior Notes originally issued to a syndicate of
eight insurance companies. The Senior Notes have a fixed annual interest
rate of 7.84% with repayments in annual installments of $5 million beginning
July 23, 2001. The final payment is due July 23, 2008. Interest is payable
semiannually on January 1 and July 23 of each year. At December 31, 2002,
Central Florida's outstanding balance under the Senior Notes was $30.0
million.

CALNEV Pipe Line LLC Debt

Effective March 30, 2001, we acquired CALNEV Pipe Line LLC (see Note 3).
As part of our purchase price, we assumed an aggregate principal amount of
$6.8 million of Senior Notes originally issued to a syndicate of five
insurance companies. The Senior Notes had a fixed annual interest rate of
10.07%. In June 2001, we prepaid the balance outstanding under the Senior
Notes, plus $0.9 million for interest and a make-whole premium, from cash on
hand.

Trailblazer Pipeline Company Debt

Credit Facility

At December 31, 2000, Trailblazer Pipeline Company had a $10 million
borrowing under an intercompany account payable in favor of KMI. In January
2001, Trailblazer Pipeline Company entered into a 364-day revolving credit
agreement with Credit Lyonnais New York Branch, providing for loans up to $10
million. The borrowings were used to pay the account payable to KMI. The
agreement was to expire on December 27, 2001, and provided for an interest
rate of LIBOR plus 0.875%. Pursuant to the terms of the revolving credit
agreement with Credit Lyonnais New York Branch, Trailblazer Pipeline Company
partnership distributions were restricted by certain financial covenants.

On June 26, 2001, Trailblazer Pipeline Company prepaid the balance
outstanding under its Senior Secured Notes using a new two-year unsecured
revolving credit facility with a bank syndication. The new facility, as
amended August 24, 2001, provided for loans of up to $85.2 million and had a
maturity date of June 29, 2003. The agreement provided for an interest rate
of LIBOR plus a margin as determined by certain financial ratios. Pursuant
to the terms of the revolving credit facility, Trailblazer Pipeline Company
partnership distributions were restricted by certain financial covenants. On
June 29, 2001, Trailblazer Pipeline Company paid the $10 million outstanding
balance under its 364-day revolving credit agreement and terminated that
agreement. At December 31, 2001, the outstanding balance under Trailblazer
Pipeline Company's two-year revolving credit facility was $55.0 million, with
a weighted average interest rate of 2.875%, which reflects three-month LIBOR
plus a margin of 0.875%. In July 2002, we paid the $31.0 million outstanding
balance under Trailblazer's revolving credit facility and terminated the
facility.

Senior Notes

On September 23, 1992, pursuant to the terms of a Note Purchase Agreement,
Trailblazer Pipeline Company issued and sold an aggregate principal amount of
$101 million of Senior Secured Notes to a syndicate of fifteen insurance
companies. The Senior Secured Notes had a fixed annual interest rate of
8.03% and the $20.2 million balance as of December 31, 2000 was to be repaid
in semiannual installments of $5.05 million from March 1, 2001 through
September 1, 2002, the final maturity date. Interest was payable
semiannually in March and September. Trailblazer Pipeline Company provided
collateral for the notes principally by an assignment of certain Trailblazer
Pipeline Company transportation contracts, and pursuant to the terms of this
Note Purchase Agreement, Trailblazer Pipeline Company's partnership
distributions were restricted by certain financial covenants. Effective
April 29, 1997, Trailblazer Pipeline Company amended the Note Purchase
Agreement. This amendment allowed Trailblazer Pipeline Company to include
several additional transportation contracts as collateral for the notes,
added a limitation on the amount of additional money that Trailblazer
Pipeline Company could borrow and relieved Trailblazer

125
<PAGE>

Pipeline Company from its security deposit obligation. On June 26, 2001,
Trailblazer Pipeline Company prepaid the $15.2 million balance outstanding
under the Senior Secured Notes, plus $0.8 million for interest and a
make-whole premium, using its new two-year unsecured revolving credit
facility.

Kinder Morgan Operating L.P. "B" Debt

The $23.7 million principal amount of tax-exempt bonds due 2024 were
issued by the Jackson-Union Counties Regional Port District. These bonds
bear interest at a weekly floating market rate. During 2002, the
weighted-average interest rate on these bonds was 1.39% per annum, and at
December 31, 2002, the interest rate was 1.59%. We have an outstanding
letter of credit issued under our credit facilities that supports our
tax-exempt bonds. The letter of credit reduces the amount available for
borrowing under our credit facilities.

International Marine Terminals Debt

As of February 1, 2002, we owned a 66 2/3% interest in International
Marine Terminals partnership (see Note 3). The principal assets owned by IMT
are dock and wharf facilities financed by the Plaquemines Port, Harbor and
Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port
Facilities Revenue Refunding Bonds (International Marine Terminals Project)
Series 1984A and 1984B. The bonds mature on March 15, 2006. The bonds are
backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002,
an Amended and Restated Letter of Credit Reimbursement Agreement relating to
the letters of credit in the amount of $45.5 million was entered into by IMT
and KBC Bank. In connection with that agreement, we agreed to guarantee the
obligations of IMT in proportion to our ownership interest. Our obligation
is approximately $30.3 million for principal, plus interest and other fees.

Maturities of Debt

The scheduled maturities of our outstanding debt, excluding market value
of interest rate swaps, at December 31, 2002, are summarized as follows (in
thousands):

2003......... $264,937
2004......... 5,018
2005......... 204,836
2006......... 45,019
2007......... 254,863
Thereafter... 2,884,860
---------
Total........ $3,659,533
==========

Of the $264.9 million scheduled to mature in 2003, we intend and have the
ability to refinance the entire amount on a long-term basis under our
existing credit facilities.

Fair Value of Financial Instruments

The estimated fair value of our long-term debt, excluding market value of
interest rate swaps, is based upon prevailing interest rates available to us
at December 31, 2002 and December 31, 2001 and is disclosed below.

Fair value as used in SFAS No. 107 "Disclosures About Fair Value of
Financial Instruments" represents the amount at which an instrument could be
exchanged in a current transaction between willing parties.

December 31, 2002 December 31, 2001
--------------------- ----------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
-------- ---------- -------- ----------
(In thousands)
Total Debt $3,659,533 $4,475,058 $2,797,234 $3,094,530

10. 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

126
<PAGE>

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.

The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Employee Benefit Plan for
Employees of Hall-Buck Marine Services Company and the benefits under this
plan were based primarily upon years of service and final average pensionable
earnings. Benefit accruals were frozen as of December 31, 1998 for the
Hall-Buck plan. Effective December 31, 2000, the Hall-Buck plan, along with
the K N Energy, Inc. Retirement Plan for Bargaining Employees, was merged
into the K N Energy, Inc. Retirement Plan for Non-Bargaining employees, with
the Non-Bargaining Plan being the surviving plan. The merged plan was
renamed the Kinder Morgan, Inc. Retirement Plan.

SFPP's post-retirement benefit plan is frozen and no additional
participants may join the plan.

Net periodic benefit costs and weighted-average assumptions for these
plans include the following components (in thousands):

2002 2001 2000
---------- ---------- ---------------------
Other Other Other
Post- Post- Post-
retirement retirement Pension retirement
Benefits Benefits Benefits Benefits
---------- ---------- -------- ----------
Net periodic benefit cost
Service cost............. $ 165 $ 120 $ -- $ 46
Interest cost............ 906 804 145 755
Expected return on plan
assets................... -- -- (170) --
Amortization of prior
service cost............ (545) (545) -- (493)
Actuarial gain........... -- (27) -- (290)
------- ------- ------ -------
Net periodic benefit cost $ 526 $ 352 $ (25) $ 18
======= ======= ====== =======

Additional amounts
recognized
Curtailment (gain) loss $ -- $ -- $ -- $ --
Weighted-average
assumptions as of
December 31:
Discount rate............ 6.50% 7.00% 7.5% 7.75%
Expected return on plan
assets.................. -- -- 8.5% --
Rate of compensation
increase................ 3.9% -- -- --

Information concerning benefit obligations, plan assets, funded status and
recorded values for these plans follows (in thousands):

2002 2001
--------------- ---------------
Other Other
Post-retirement Post-retirement
Benefits Benefits
--------------- ---------------
Change in benefit obligation
Benefit obligation at Jan. 1...... $ 13,368 $ 10,897
Service cost...................... 165 120
Interest cost..................... 906 804
Participant contributions......... 143 --
Amendments........................ (493) --
Actuarial (gain) loss............. (264) 2,350
Benefits paid from plan assets.... (550) (803)
--------- ---------
Benefit obligation at
Dec. 31.......................... $ 13,275 $ 13,368
========= =========

Change in plan assets
Fair value of plan assets
at Jan. 1........................ $ -- $ --
Actual return on plan assets...... -- --
Employer contributions............ 407 803
Participant contributions......... 143 --
Benefits paid from plan assets.... (550) (803)
--------- ---------
Fair value of plan assets
at Dec. 31....................... $ -- $ --
========= =========

127
<PAGE>

2002 2001
--------------- ---------------
Other Other
Post-retirement Post-retirement
Benefits Benefits
--------------- ---------------
Funded status.................... $(13,275) $(13,368)
Unrecognized net acturiral
(gain) loss..................... 729 993
Unrecognized prior
service (benefit)............... (1,059) (1,111)
Adj. for 4th qtr.
employer contributions........... 105 --
--------- ---------
Prepaid (accrued) benefit
cost............................ $(13,500) $(13,486)
========= =========

In 2001, SFPP modified benefits associated with its post-retirement
benefit plan. This plan amendment resulted in a $2.5 million increase in its
benefit obligation for 2001. The unrecognized prior service credit is
amortized on a straight-line basis over the remaining expected service to
retirement (2.5 years). For measurement purposes, a 11% annual rate of
increase in the per capita cost of covered health care benefits was assumed
for 2003. The rate was assumed to decrease gradually to 5% by 2009 and
remain at that level thereafter.

Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A 1% change in assumed health
care cost trend rates would have the following effects:

1-Percentage 1-Percentage
Point Increase Point Decrease
-------------- --------------
Effect on total of service and
interest cost components............. $ 106 $ (89)
Effect on postretirement benefit
obligation........................... $1,148 $ (974)

Multiemployer Plans and Other Benefits

As a result of acquiring several terminal operations, primarily our
acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we
participate in several multi-employer pension plans for the benefit of
employees who are union members. We do not administer these plans and
contribute to them in accordance with the provisions of negotiated labor
contracts. Other benefits include a self-insured health and welfare
insurance plan and an employee health plan where employees may contribute for
their dependents' health care costs. Amounts charged to expense for these
plans were $1.3 million for the year ended 2002 and $0.6 million for the year
ended 2001.

We assumed River Consulting, Inc.'s (a consolidated affiliate of Kinder
Morgan Bulk Terminals) savings plan under Section 401(k) of the Internal
Revenue Code. This savings plan allowed eligible employees to contribute up
to 10% of their compensation on a pre-tax basis, with us matching 2.5% of the
first 5% of the employees' wage. Matching contributions are vested at the
time of eligibility, which is one year after employment. Effective January
1, 1999, we merged this savings plan into the retirement savings plan of our
general partner (see next paragraph).

The Kinder Morgan Savings Plan, formerly the Kinder Morgan Retirement
Savings Plan, permits all full-time employees of KMGP Services Company, Inc.
and KMI to contribute 1% to 50% of base compensation, on a pre-tax basis,
into participant accounts. In addition to a mandatory contribution equal to
4% of base compensation per year for most plan participants, KMGP Services
Company, Inc. and KMI may make discretionary contributions in years when
specific performance objectives are met. Certain employees' contributions
are based on collective bargaining agreements. Our mandatory contributions
are made each pay period on behalf of each eligible employee. Any
discretionary contributions are made during the first quarter following the
performance year. All contributions, including discretionary contributions,
are in the form of KMI stock that is immediately convertible into other
available investment vehicles at the employee's discretion. In the first
quarter of 2003, no discretionary contributions were made to individual
accounts for 2002. The total amount charged to expense for our Savings Plan
was $5.6 million during 2002. All contributions, together with earnings
thereon, are immediately vested and not subject to forfeiture. Participants
may direct the investment of their contributions into a variety of
investments. Plan assets are held and distributed pursuant to a trust
agreement.

Effective January 1, 2001, employees of KMGP Services Company, Inc. and
KMI became eligible to participate in a new Cash Balance Retirement Plan.
Certain employees continue to accrue benefits through a career-pay formula,
"grandfathered" according to age and years of service on December 31, 2000,
or collective bargaining arrangements. All other employees will accrue
benefits through a personal retirement account in the new Cash Balance
Retirement Plan. Employees with prior service and not grandfathered convert
to the Cash Balance

128
<PAGE>

Retirement Plan and will be credited with the current fair value of any
benefits they have previously accrued through the defined benefit plan. We
will then begin contributions on behalf of these employees equal to 3% of
eligible compensation every pay period. In addition, discretionary
contributions are made to the plan based on our and KMI's performance. In the
first quarter of 2002, an additional 1% discretionary contribution was made to
individual accounts. No additional contributions were made for 2002 performance.
Interest will be credited to the personal retirement accounts at the 30-year
U.S. Treasury bond rate in effect each year. Employees become fully vested in
the plan after five years, and they may take a lump sum distribution upon
termination of employment or retirement.

11. Partners' Capital

At December 31, 2002, our partners' capital consisted of:

o 129,943,218 common units;

o 5,313,400 Class B units; and

o 45,654,048 i-units.

Together, these 180,910,666 units represent the limited partners' interest
and an effective 98% economic interest in the Partnership, exclusive of our
general partner's incentive distribution. Our general partner has an
effective 2% interest in the Partnership, excluding our general partner's
incentive distribution. At December 31, 2002, our common unit total
consisted of 116,987,483 units held by third parties, 11,231,735 units held
by KMI and its consolidated affiliates (excluding our general partner); and
1,724,000 units held by our general partner. Our Class B units were held
entirely by KMI and our i-units were held entirely by KMR.

At December 31, 2001, our Partners' capital consisted of:

o 129,855,018 common units;

o 5,313,400 Class B units; and

o 30,636,363 i-units.

Our total common units outstanding at December 31, 2001, consisted of
110,071,392 units held by third parties, 18,059,626 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units
held by our general partner. Our Class B units were held entirely by KMI and
our i-units were held entirely by KMR.

All of our Class B units were issued 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. We initially issued 29,750,000 i-units in
May 2001. The 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, and controlling and managing the
business and affairs of, the Partnership, our operating partnerships and our
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

129
<PAGE>

equal. Furthermore, 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 the same value
as 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 related cash but will
retain the cash and use the cash 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 937,658 i-units on November 14,
2002. These additional i-units distributed were based on the $0.61 per unit
distributed to our common unitholders on that date. For the year ended
December 31, 2002, KMR received distributions of 2,538,785 i-units. These
additional i-units distributed were based on the $2.36 per unit distributed
to our common unitholders during 2002.

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. For the years ended December 31, 2002, 2001 and 2000, we
declared distributions of $2.435, $2.15 and $1.7125, respectively, per unit.
Our distributions to unitholders for 2002, 2001 and 2000 required incentive
distributions to our general partner in the amount of $267.4 million, $199.7
million and $107.8 million, respectively. The increased incentive
distributions paid for 2002 over 2001 and 2001 over 2000 reflect the increase
in amounts distributed per unit as well as the issuance of additional units.

On January 15, 2003, we declared a cash distribution for the quarterly
period ended December 31, 2002, of $0.625 per unit. This distribution was
paid on February 14, 2003, to unitholders of record as of January 31, 2003.
Our common unitholders and Class B unitholders received cash. KMR, our sole
i-unitholder, received a distribution in the form of additional i-units based
on the $0.625 distribution per common unit. The number of i-units
distributed was 858,981. For each outstanding i-unit that KMR held, a
fraction of an i-unit was issued. The fraction was determined by dividing:

o $0.625, the cash amount distributed per common unit

o $33.219, the average of KMR's limited liability shares' closing market
prices from January 14-28, 2003, the ten consecutive trading days
preceding the date on which the shares began to trade ex- dividend under
the rules of the New York Stock Exchange.

This February 14, 2003 distribution required an incentive distribution to
our general partner in the amount of $72.5 million. Since this distribution
was declared after the end of the quarter, no amount is shown in the December
31, 2002 balance sheet as a Distribution Payable.

12. Related Party Transactions

General and Administrative Expenses

KMGP Services Company, Inc. provides employees and KMR, through its wholly
owned subsidiary, Kinder Morgan Services LLC, provides centralized payroll
and employee benefits services to us, our operating partnerships

130
<PAGE>

and subsidiaries, Kinder Morgan G.P., Inc. and KMR (collectively, the
"Group"). Employees of KMGP Services Company, Inc. are assigned to work for
one or more members of the Group. The direct costs of all compensation,
benefits expenses, employer taxes and other employer expenses for these
employees are allocated and charged by Kinder Morgan Services LLC to the
appropriate members of the Group, and the members of the Group reimburse
Kinder Morgan Services LLC for their allocated shares of these direct costs.
There is no profit or margin charged by Kinder Morgan Services LLC to the
members of the Group. The administrative support necessary to implement
these payroll and benefits services is provided by the human resource
department of KMI, and the related administrative costs are allocated to
members of the Group in accordance with existing expense allocation
procedures. The effect of these arrangements is that each member of the
Group bears the direct compensation and employee benefits costs of its
assigned or partially assigned employees, as the case may be, while also
bearing its allocable share of administrative costs. Pursuant to our limited
partnership agreement, we provide reimbursement for our share
of these administrative costs and such reimbursements will be accounted for
as described above.

The named executive officers of our general partner and KMR and some other
employees that provide management or services to both KMI and the Group are
employed by KMI. Additionally, other KMI employees assist in the operation
of our Natural Gas Pipeline assets formerly owned by KMI. These KMI
employees' expenses are allocated without a profit component between KMI and
the appropriate members of the Group.

Partnership Distributions

Kinder Morgan G.P., Inc.

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

o its 1.0101% direct general partner ownership interest (accounted for as
minority interest in the consolidated financial statements of the
Partnership); and

o its 0.9899% ownership interest indirectly owned via its 1% ownership
interest in the Partnership.

At December 31, 2002, our general partner owned 1,724,000 common units,
representing approximately 0.95% of our outstanding limited partner units.
Our partnership agreement requires that we distribute 100% of available cash
as defined in our partnership agreement to our partners within 45 days
following the end of each calendar quarter in accordance with their
respective percentage interests. Available cash consists generally of all of
our cash receipts, including cash received by our operating partnerships,
less cash disbursements and net additions to reserves (including any reserves
required under debt instruments for future principal and interest payments)
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 or fractions of i-units. For
each outstanding i-unit, a fraction of an i-unit will be issued. The
fraction is calculated by dividing the amount of cash being distributed per
common unit by the average market price of KMR's limited liability shares
over the ten consecutive trading days preceding the date on which the shares
begin to trade ex-dividend under the rules of the New York Stock Exchange.
The cash equivalent of distributions of i-units will be treated as if it had
actually been distributed, including for purposes of determining the
distributions to our general partner and calculating available cash for
future periods. We will not distribute the related cash but will retain the
cash and use the cash in our business.

131
<PAGE>

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

Available cash for each quarter is distributed as follows;

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.

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 declared
incentive distributions for the years ended December 31, 2002, 2001 and 2000
were $267.4 million, $199.7 million and $107.8 million, respectively.

Kinder Morgan, Inc.

KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the
sole stockholder of our general partner. At December 31, 2002, KMI directly
owned 6,523,650 common units and 5,313,400 Class B units, indirectly owned
6,432,085 common units owned by its consolidated affiliates, including our
general partner and owned 13,511,726 KMR shares, representing an indirect
ownership interest of 13,511,726 i-units. Together, these units represent
approximately 17.6% of our outstanding limited partner units. Including both
its general and limited partner interests in us, at the 2002 distribution
level, KMI received approximately 51% of all quarterly distributions from us,
of which approximately 40% is attributable to its general partner interest
and 11% is attributable to its limited partner interest. The actual level of
distributions KMI will receive in the future will vary with the level of
distributions to the limited partners determined in accordance with our
partnership agreement.

Kinder Morgan Management, LLC

KMR, our general partner's delegate, remains the sole owner of our
45,654,048 i-units.

Asset Acquisitions

2000 Kinder Morgan, Inc. Asset Contributions

Effective December 31, 2000, we acquired over $621.7 million of assets
from KMI. As consideration for these assets, we paid to KMI $192.7 million
in cash and approximately $156.3 million in units, consisting of 1,280,000
common units and 5,313,400 Class B units. We also assumed liabilities of
approximately $272.7 million. We acquired Kinder Morgan Texas Pipeline, L.P.
and MidCon NGL Corp. (both of which were converted to single-member limited
liability companies), the Casper and Douglas natural gas gathering and
processing systems, a 50% interest in Coyote Gas Treating, LLC and a 25%
interest in Thunder Creek Gas Services, LLC. The purchase price for the
transaction was determined by the boards of directors of KMI and our general
partner based on pricing principles used in the acquisition of similar
assets. The transaction was approved unanimously by the independent

132
<PAGE>

directors of our general partner, with the benefit of independent financial and
legal advisors, including a fairness opinion from the investment banking firm
A.G. Edwards & Sons, Inc.

Mexican Entity Transfer

In the fourth quarter of 2002, KMI transferred to us its interests in
Kinder Morgan Natural Gas de Mexico, S. de R.L. de C.V., hereinafter referred
to as KM Mexico. KM Mexico is the entity through which we are developing the
Mexican portion of our Mier-Monterrey natural gas pipeline that connects to
the southern tip of Kinder Morgan Texas Pipeline, L.P.'s intrastate pipeline,
hereinafter referred to the Monterrey Project. The Monterrey Project was
initially conceived at KMI in 1996 and between 1996 and 1998 KMI and its
subsidiaries paid, on behalf of KM Mexico, approximately $2.5 million in
connection with the Monterrey Project to explore the feasibility of and to
obtain permits for the Mexican portion of the project. Following 1998, the
Monterrey Project was dormant at KMI.

In December 2000, when KMI contributed to us Kinder Morgan Texas Pipeline,
L.P., the entity that had been primarily responsible for the Monterrey
Project, the Monterrey Project was still dormant (and thought likely to
remain dormant indefinitely). Consequently, KM Mexico was not contributed to
us at that time.

In 2002, Kinder Morgan Texas Pipeline, L.P. reassessed the Monterrey
Project and determined that the Monterrey Project was an economically
feasible project for us. Accordingly, KMI's Board of Directors on the one
hand, and KMR and our general partner's Boards of Directors on the other
hand, unanimously determined, respectively, that KMI should transfer KM
Mexico to us for approximately $2.5 million, the amount paid by KMI and its
subsidiaries, on KM Mexico's behalf, in connection with the Monterrey Project
between 1996 and 1998.

Operations

KMI or its subsidiaries operate and maintain for us the assets comprising
our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of
America, a subsidiary of KMI, operates Trailblazer Pipeline Company's assets
under a long-term contract pursuant to which Trailblazer Pipeline Company
incurs the costs and expenses related to NGPL's operating and maintaining the
assets. Trailblazer Pipeline Company provides the funds for capital
expenditures. NGPL does not profit from or suffer loss related to its
operation of Trailblazer Pipeline Company's assets.

The remaining assets comprising our Natural Gas Pipelines business segment
are operated under agreements between KMI and us. The agreements have
five-year terms and contain automatic five-year extensions. Pursuant to the
applicable underlying agreements, we pay KMI either a fixed amount or actual
costs incurred as reimbursement for the corporate general and administrative
expenses incurred in connection with the operation of these assets. The
amounts paid to KMI for corporate general and administrative costs, including
amounts related to Trailblazer Pipeline Company, were $13.3 million of fixed
costs and $2.8 million of actual costs incurred for 2002, and $9.5 million of
fixed costs and $3.2 million of actual costs incurred for 2001. Commencing in
2003, KMI will be operating additional pipeline assets, including our North
System and Cypress Pipeline, which are part of our Products Pipelines business
segment, as well as our Monterrey Pipeline, which is currently under
construction and will be part of our Natural Gas Pipelines business segment. We
estimate the total reimbursement to be paid to KMI in respect of all pipeline
assets operated by KMI and its subsidiaries for us for 2003 will be
approximately $19.7 million, which includes $14.4 million of fixed costs
(adjusted for inflation) and $5.3 million of actual costs. We believe the
amounts paid to KMI for the services they provided each year fairly reflect the
value of the services performed. However, due to the nature of the allocations,
these reimbursements may not have exactly matched the actual time and overhead
spent. We believe the agreed-upon amounts were, at the time the contracts were
entered into, a reasonable estimate of the corporate general and administrative
expenses to be incurred by KMI and its subsidiaries in performing such services.
We also reimburse KMI and its subsidiaries for operating and maintenance costs
and capital expenditures incurred with respect to these assets.

Other

We own a 50% equity interest in Coyote Gas Treating, LLC, referred to
herein as Coyote Gulch. Coyote Gulch is a joint venture, and El Paso Field
Services Company owns the remaining 50% equity interest. We are the managing
partner of Coyote Gulch. As of December 31, 2002, Coyote's balance sheet has
current notes payable to

133
<PAGE>

each partner in the amount of $17.1 million. These notes are due on June
30, 2003. At that time, the partners can either renew the notes or make
capital contributions which enable Coyote to payoff the existing notes.

Generally, KMR makes all decisions relating to the management and control
of our business. Our general partner owns all of KMR's voting securities and is
its sole managing member. KMI, through its wholly owned and controlled
subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our
general partner. Certain conflicts of interest could arise as a result of the
relationships among KMR, our general partner, KMI and us. The directors and
officers of KMI have fiduciary duties to manage KMI, including selection and
management of its investments in its subsidiaries and affiliates, in a manner
beneficial to the shareholders of KMI. In general, KMR has a fiduciary duty to
manage us in a manner beneficial to our unitholders. The partnership agreements
for us and our operating partnerships contain provisions that allow KMR to take
into account the interests of parties in addition to us in resolving conflicts
of interest, thereby limiting its fiduciary duty to our unitholders, as well as
provisions that may restrict the remedies available to unitholders for actions
taken that might, without such limitations, constitute breaches of fiduciary
duty. The partnership agreements provide that in the absence of bad faith by
KMR, the resolution of a conflict by KMR will not be a breach of any duties. The
duty of the directors and officers of KMI to the shareholders of KMI may,
therefore, come into conflict with the duties of KMR and its directors and
officers to our unitholders. The Conflicts and Audit Committee of KMR's board of
directors will, at the request of KMR, review (and is one of the means for
resolving) conflicts of interest that may arise between KMI or its subsidiaries,
on the one hand, and us, on the other hand.

13. Leases and Commitments

Operating Leases

We have entered into certain operating leases. Including probable
elections to exercise renewal options, the remaining terms on our leases
range from one to 41 years. Future commitments related to these leases at
December 31, 2002 are as follows (in thousands):
2003...................... $ 18,747
2004...................... 15,128
2005...................... 13,206
2006...................... 11,819
2007...................... 9,545
Thereafter................ 55,545
--------
Total minimum payments.... $123,990
========

We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $1.6 million. Total lease and rental
expenses, including related variable charges were $21.6 million for 2002,
$41.1 million for 2001 and $7.5 million for 2000.

Common Unit Option Plan

During 1998, we established a common unit option plan, which provides that
key personnel of KMGP Services Company, Inc. and KMI are eligible to receive
grants of options to acquire common units. The number of common units
available under the option plan is 500,000. The option plan terminates in
March 2008. As of December 31, 2002 and 2001, outstanding options for
261,600 and 379,400 common units had been granted to certain personnel with a
term of seven years at an average exercise price of approximately $17.30 per
unit. During 2002, 88,200 options were exercised at an average price of
$17.77 per unit. These options had an average fair market value of $34.24
per unit. During 2001, 55,200 options were exercised at an average price of
$17.52 per unit. These options had an average fair market value of $33.26
per unit. In addition, as of December 31, 2002, outstanding options for
20,000 common units, at an average exercise price of $20.58 per unit, had
been granted to two of Kinder Morgan G.P., Inc.'s three non-employee
directors. The options granted generally have a term of seven years, vest
40% on the first anniversary of the date of grant and 20% on each of the next
three anniversaries, and have exercise prices equal to the market price of
the common units at the grant date.

We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for common
unit options granted under our common unit option plan. Pro forma
information regarding changes in net income and per unit data, if the
accounting prescribed by Statement of Financial Accounting Standards No. 123
"Accounting for Stock Based Compensation," had been applied, is not

134
<PAGE>

material. No compensation expense has been recorded since the options
were granted at exercise prices equal to the market prices at the date of
grant.

Other

Effective January 17, 2002, our general partner entered into a retention
agreement with C. Park Shaper, an officer of our general partner and its
delegate. Pursuant to the terms of the agreement, Mr. Shaper obtained a $5
million personal loan guaranteed by us. Mr. Shaper was required to purchase
KMI common shares and our common units in the open market with the loan
proceeds. If he voluntarily leaves us prior to the end of five years, then
he must repay the entire loan. After five years, provided Mr. Shaper has
continued to be employed by our general partner, we and KMI will assume Mr.
Shaper's obligations under the loan. The agreement contains provisions that
address termination for cause, death, disability and change of control.

We have an Executive Compensation Plan for certain executive officers of
our general partner. We may, at our option and with the approval of our
unitholders, pay the participants in units instead of cash. Eligible awards
are equal to a percentage of an incentive compensation value, which is equal
to a formula based upon the cash distributions paid to our general partner
during the four calendar quarters preceding the date of redemption multiplied
by eight. The amount of these awards are accrued as compensation expense and
adjusted quarterly. Under the plan, no eligible employee may receive a grant
in excess of 2% of the incentive compensation value and total awards under
the plan may not exceed 10% of the incentive compensation value. The plan
terminates January 1, 2007, and any unredeemed awards will be automatically
redeemed. At December 31, 2002, there were no outstanding awards granted
under our Executive Compensation Plan.

Contingent Debt

Cortez Pipeline Company Debt

Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers
Pipeline Company - 13% owner) are required, on a 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 owners 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 owners further severally guarantee, on a percentage
basis, the obligations of the Cortez Pipeline Company owners under the
Throughput and Deficiency Agreement.

Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our guaranty obligations
jointly and severally through December 31, 2006 for Cortez Capital
Corporation's debt programs in place as of April 1, 2000.

At December 31, 2002, the debt facilities of Cortez Capital Corporation
consisted of:

o $115.7 million of Series D notes due May 15, 2013;

o a $175 million short-term commercial paper program; and

o a $175 million committed revolving credit facility due December 26, 2003
(to support the above-mentioned $175 million commercial paper program).

At December 31, 2002, Cortez Capital Corporation had $140.6 million of
commercial paper outstanding with an interest rate of 1.39%, the average
interest rate on the Series D notes was 6.9322% and there were no borrowings
under the credit facility.

135
<PAGE>

Plantation Pipeline Company Debt

On April 30, 1997, Plantation Pipeline Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation
Pipeline Company, severally guarantee this debt on a pro rata basis
equivalent to our respective 51% ownership interest. During 1999, this
agreement was amended to reduce the maturity date by three years. The $10
million is outstanding at December 31, 2002.

Red Cedar Gas Gathering Company Debt

In October 1998, Red Cedar Gas 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 secured by a first priority lien on the ownership
interests, including our 49% ownership interest, in Red Cedar Gas Gathering
Company. The Senior Notes are also guaranteed by us and the other owner of
Red Cedar Gas Gathering Company. The principal is to be repaid in seven
equal installments beginning on October 31, 2004 and ending on October 31,
2009, with any remainder due October 31, 2010. The $55 million is
outstanding at December 31, 2002.

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. A
letter of credit was issued as security for the Adjustable Demand Revenue
Bonds and was guaranteed by the parent company of Nassau Terminals, Inc., the
operator of the port facilities. In July 2002, we acquired Nassau Terminals,
Inc. 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.

At December 31, 2002 the outstanding principal amount of the Adjustable
Demand Revenue Bonds is $25 million. The bonds require principal repayments
of $5 million per year through 2008.

14. Risk Management

Hedging Activities

Certain of our business activities expose us to risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil
and carbon dioxide. Through KMI, we use energy financial instruments to
reduce our risk of changes in the prices of natural gas, natural gas liquids
and crude oil markets (and carbon dioxide to the extent contracts are tied to
crude oil prices) as discussed below. The fair value of these risk
management instruments reflects the estimated amounts that we would receive
or pay to terminate the contracts at the reporting date, thereby taking into
account the current unrealized gains or losses on open contracts. We have
available market quotes for substantially all of the financial instruments
that we use.

The energy risk management products that we use include:

o commodity futures and options contracts;

o fixed-price swaps; and

o basis swaps.

Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated
with:

136
<PAGE>

o pre-existing or anticipated physical natural gas, natural gas liquids
and crude oil sales;

o pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;

o natural gas purchases; and

o system use and storage.

Our risk management activities are only 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.

As a result of our adoption of SFAS No. 133, as discussed in Note 2, we
recorded a cumulative effect adjustment in other comprehensive income of
$22.8 million representing the fair value of our derivative financial
instruments utilized for hedging activities as of January 1, 2001. During
the year ended December 31, 2001, $16.6 million of this initial adjustment
was reclassified to earnings as a result of hedged sales and purchases during
the period. During 2001, we reclassified a total of $51.5 million to
earnings as a result of hedged sales and purchases during the period.

The gains and losses included in Accumulated other comprehensive income
will be reclassified into earnings as the hedged sales and purchases take
place. Approximately $42.5 million of the Accumulated other comprehensive
loss balance of $45.3 million representing unrecognized net losses on
derivative activities at December 31, 2002 is expected to be reclassified
into earnings during the next twelve months. During 2002, we reclassified
$7.5 million of the accumulated other comprehensive income balance of $63.8
million representing unrecognized net losses on derivative activities at
December 31, 2001 into earnings. For each of the years ended December 31,
2002 and 2001, we did not reclassify any gains or losses into earnings as a
result of the discontinuance of cash flow hedges due to a determination that
the forecasted transactions will no longer occur by the end of the originally
specified time period.

Purchases or sales of commodity contracts require a dollar amount to be
placed in margin accounts. In addition, through KMI, we are required to post
margins with certain over-the-counter swap partners. These margin
requirements are determined based upon credit limits and mark-to-market
positions. Our margin deposits associated with commodity contract positions
were $1.9 million at December 31, 2002 and $20.0 million on December 31,
2001. Our margin deposits associated with over-the-counter swap partners
were $0.0 million on December 31, 2002 and ($42.1) million on December 31,
2001.

We recognized a gain of $0.7 million during 2002 and a loss of $1.3
million during 2001 as a result of ineffective hedges. These amounts are
reported within the caption Operations and maintenance in the accompanying
Consolidated Statements of Income. For each of the years ended December 31,
2002 and 2001, we did not exclude any component of the derivative
instruments' gain or loss from the assessment of hedge effectiveness.

The differences between the current market value and the original physical
contracts value associated with our hedging activities are primarily
reflected as Other current assets and Accrued other current liabilities in
the accompanying consolidated balance sheets. At December 31, 2002, our
balance of $104.5 million of Other current assets included approximately
$57.9 million related to risk management hedging activities, and our balance
of $298.7 million of Accrued other current liabilities included approximately
$101.3 million related to risk management hedging activities. At December
31, 2001, our balance of $194.9 million of Other current assets included
approximately $163.7 million related to risk management hedging activities,
and our balance of $209.9 million of Accrued other current liabilities
included approximately $117.8 million related to risk management hedging
activities.

The remaining differences between the current market value and the
original physical contracts value associated with our hedging activities are
reflected as deferred charges or deferred credits in the accompanying
consolidated balance sheets. At December 31, 2002, our balance of $250.8
million of Deferred charges and other assets included

137
<PAGE>

approximately $5.7 million related to risk management hedging activities,
and our balance of $199.8 million of Other long-term liabilities and deferred
credits included approximately $8.5 million related to risk management
hedging activities. At December 31, 2001, our balance of $75.0 million of
Deferred charges and other assets included approximately $22.0 million
related to risk management hedging activities, and our balance of $246.5
million of Other long-term liabilities and deferred credits included
approximately $4.7 million related to risk management hedging activities.

Prior to 2001, we accounted for gain/loss on our over-the-counter swaps
and marked our open futures position to market value. Such items were
deferred on the balance sheet and reflected in current receivables, other
current assets, accrued other current liabilities, deferred charges or
deferred credits in our consolidated balance sheets. In all instances, these
deferrals are offset by the corresponding value of the underlying physical
transactions. In the event energy financial instruments are terminated prior
to the period of physical delivery of the items being hedged, the gains and
losses on the energy financial instruments at the time of termination remain
deferred until the period of physical delivery.

Given our portfolio of businesses as of December 31, 2002, our principal
uses of derivative financial instruments will be to mitigate the risk
associated with market movements in the price of energy commodities. Our net
short natural gas derivatives position primarily represents our hedging of
anticipated future natural gas purchases and sales. Our net short crude oil
derivatives position represents our crude oil derivative purchases and sales
made to hedge anticipated oil purchases and sales. In addition, crude oil
contracts have been sold to hedge anticipated carbon dioxide purchases and
sales that have pricing tied to crude oil prices. Finally, our net short
natural gas liquids derivatives position reflects the hedging of our
forecasted natural gas liquids purchases and sales. As of December 31, 2002,
the maximum length of time over which we have hedged our exposure to the
variability in future cash flows associated with commodity price risk is
through December 2007.

As of December 31, 2002, our commodity contracts and over-the-counter
swaps and options (in thousands) consisted of the following:

<TABLE>
<CAPTION>
Over the
Counter
Swaps and
Commodity Options
Contracts Contracts Total
--------- --------- --------
(Dollars in thousands)
<S> <C> <C> <C>
Deferred Net (Loss) Gain........................ $ (926) $ (49,323) $ (50,249)
Contract Amounts-- Gross........................ $ 117,778 $ 881,609 $ 999,387
Contract Amounts-- Net.......................... $ (862) $ (465,082) $ (465,944)

(Number of contracts(1))
Natural Gas
Notional Volumetric Positions: Long........... 1,439 5,208 6,647
Notional Volumetric Positions: Short.......... (1,028) (6,854) (7,882)
Net Notional Totals to Occur in 2003.......... 411 (1,391) (980)
Net Notional Totals to Occur in 2004 and Beyond -- (255) (255)
Crude Oil
Notional Volumetric Positions: Long........... 84 678 762
Notional Volumetric Positions: Short.......... (879) (18,457) (19,336)
Net Notional Totals to Occur in 2003.......... (795) (5,005) (5,800)
Net Notional Totals to Occur in 2004 and Beyond -- (12,774) (12,774)
Natural Gas Liquids
Notional Volumetric Positions: Long........... -- -- --
Notional Volumetric Positions: Short.......... -- (964) (964)
Net Notional Totals to Occur in 2003.......... -- (588) (588)
Net Notional Totals to Occur in 2004 and Beyond -- (376) (376)

</TABLE>
__________
(1) A term of reference describing a unit of commodity trading. One natural
gas contract equals 10,000 MMBtus. One crude oil or natural gas liquids
contract equals 1,000 barrels.

Our over-the-counter swaps and options are with a number of parties, each
of which has an investment grade credit rating. We both owe money and are
owed money under these financial instruments. At December 31, 2002, if all
parties owing us failed to pay us amounts due under these arrangements, our
credit loss would be $9.5 million.

138
<PAGE>

At December 31, 2002, our largest credit exposure to a single
counterparty was $4.2 million. In addition, 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.

During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as hedges under SFAS No. 133. Upon making
that determination, we:

o ceased to account for those derivatives as hedges;

o entered into new derivative transactions on substantially similar terms
with other counterparties to replace our position with Enron;

o designated the replacement derivative positions as hedges of the
exposures that had been hedged with the Enron positions; and

o recognized a $6.0 million loss (included with General and administrative
expenses in the accompanying Consolidated Statement of Operations for
2001) in recognition of the fact that it was unlikely that we would be
paid the amounts then owed under the contracts with Enron.

While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that additional losses will result from counterparty credit risk in
the future.

Interest Rate Swaps

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
December 31, 2002 and 2001, respectively, we were a party to interest rate
swap agreements with a notional principal amount of $1.95 billion and $900
million, respectively, for the purpose of hedging the interest rate risk
associated with our fixed and variable rate debt obligations.

As of December 31, 2002, a notional principal amount of $1.75 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 8.0% senior notes due March 15,
2005;

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 $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; and

o $400 million principal amount of our 7.30% senior notes due August 15,
2033.

These swap agreements have termination dates that correspond to the
maturity dates of the related series of senior notes, therefore, as of
December 31, 2002, the maximum length of time over which we have hedged our
exposure to the variability in future cash flows associated with interest
rate risk is through August 2033. 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 at March
15, 2009. The swap agreements related to our 7.75% senior notes and our
7.30%

139
<PAGE>

senior notes contain mutual cash-out provisions at the then-current
economic value every five years. These interest rate swaps have been
designated as fair value hedges as defined by SFAS No. 133. SFAS No. 133
designates derivatives that hedge a recognized asset or liability's exposure
to changes in their fair value as fair value hedges and the gain or loss on
fair value hedges are to be recognized in earnings in the period of change
together with the offsetting loss or gain on the hedged item attributable to
the risk being hedged. The effect of that accounting is to reflect in
earnings the extent to which the hedge is not effective in achieving
offsetting changes in fair value.

As of December 31, 2002, we also have swap agreements that effectively
convert the interest expense associated with $200 million of our variable
rate debt to fixed rate. The maturity dates of these swap agreements range
from September 2, 2003 to August 1, 2005. In the prior year, this hedge was
designated a fair value hedge on our $200 million Floating Rate Senior Notes,
which were retired in March 2002. Subsequent to the repayment of our
Floating Rate Senior Notes, the swaps were designated as a cash flow hedge of
the risk associated with changes in the designated benchmark interest rate
(in this case, one-month LIBOR) related to forecasted payments associated
with interest on an aggregate of $200 million of our portfolio of commercial
paper.

In addition, 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 for fair value
hedges by SFAS No. 133. 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 or fixed rate
payments under the swaps. Interest expense is accrued monthly and paid
semi-annually. At December 31, 2002, we recognized an asset of $179.1
million and a liability of $12.1 million for the $167.0 million net fair
value of our swap agreements, and we included these amounts with Deferred
charges and other assets and Other long-term liabilities and deferred credits
on the accompanying balance sheet. The offsetting entry to adjust the
carrying value of the debt securities whose fair value was being hedged was
recognized as Market value of interest rate swaps on the accompanying balance
sheet. At December 31, 2001, we recognized a liability of $5.4 million for
the net fair value of our swap agreements and we included this amount with
Other long-term liabilities and deferred credits on the accompanying balance
sheet, and again, the offsetting entry to adjust the carrying value of the
debt securities whose fair value was being hedged was recognized as Market
value of interest rate swaps on the accompanying balance sheet.

We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions only 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.

15. Reportable Segments

We divide our operations into four reportable business segments (see Note 1):

o Products Pipelines;

o Natural Gas Pipelines;

o CO2 Pipelines; and

o Terminals.

Each segment uses the same accounting policies as those described in the
summary of significant accounting policies (see Note 2). We evaluate
performance based on each segments' earnings, which exclude general and
administrative expenses, third-party debt costs, interest income and expense
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 of refined petroleum products, including gasoline, diesel
fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment
derives

140
<PAGE>

its revenues primarily from the sale, gathering, transmission and storage
of natural gas. Our CO2 Pipelines segment derives its revenues primarily
from the marketing and transportation of carbon dioxide used as a flooding
medium for recovering crude oil from mature oil fields and from the
production of crude oil from fields in the Permian Basin of West Texas. 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):

2002 2001 2000
---- ---- ----
Revenues
Products Pipelines............. $ 576,542 $ 605,392 $ 420,272
Natural Gas Pipelines.......... 3,086,187 1,869,315 174,187
CO2 Pipelines.................. 146,280 122,094 89,214
Terminals...................... 428,048 349,875 132,769
----------- ----------- -----------
Total consolidated revenues.... $4,237,057 $2,946,676 $ 816,442
=========== =========== ===========
Operating income
Products Pipelines............. $ 342,372 $ 298,991 $ 195,057
Natural Gas Pipelines.......... 253,498 171,899 97,349
CO2 Pipelines.................. 66,560 59,559 48,059
Terminals...................... 180,725 142,672 39,523
----------- ----------- -----------
Total segment operating income. 843,155 673,121 379,988
Corporate administrative
expenses..................... (118,857) (109,293) (64,427)
----------- ----------- -----------
Total consolidated operating
income........................ $ 724,298 $ 563,828 $ 315,561
=========== =========== ===========

Earnings from equity investments, net of
amortization of excess costs
Products Pipelines............ $ 25,717 $ 22,686 $ 29,105
Natural Gas Pipelines......... 23,610 21,156 14,975
CO2 Pipelines................. 34,311 31,981 19,328
Terminals..................... 45 -- --
----------- ----------- -----------
Consolidated equity earnings,
net of amortization.......... $ 83,683 $ 75,823 $ 63,408
=========== =========== ===========

Interest revenue
Products Pipelines.............. $ -- $ -- $ --
Natural Gas Pipelines........... -- -- --
CO2 Pipelines................... -- -- --
Terminals....................... -- -- --

----------- ----------- -----------
Total segment interest revenue.. -- -- --
----------- ----------- -----------
Unallocated interest revenue.... 1,819 4,473 3,818
----------- ----------- -----------
Total consolidated interest $ 1,819 $ 4,473 $ 3,818
revenue........................
=========== =========== ===========

Interest (expense)
Products Pipelines.............. $ -- $ -- $ --
Natural Gas Pipelines........... -- -- --
CO2 Pipelines................... -- -- --
Terminals....................... -- -- --
----------- ----------- -----------
Total segment interest (expense) -- -- --
----------- ----------- -----------
Unallocated interest (expense).. (178,279) (175,930) (97,102)
----------- ----------- -----------
Total consolidated interest $ (178,279) $ (175,930) $ (97,102)
(expense)......................
=========== =========== ===========

Other, net(a)
Products Pipelines.............. $ (14,000) $ 440 $ 10,492
Natural Gas Pipelines........... 36 749 744
CO2 Pipelines................... 112 547 741
Terminals....................... 15,550 226 2,607
----------- ----------- -----------
Total consolidated Other, net... $ 1,698 $ 1,962 $ 14,584
=========== =========== ===========

(a) 2002 amounts include non-recurring environmental expense adjustments
resulting in a $15.7 million loss to our Products Pipelines business
segment and a $16.0 million gain to our Terminals business segment.

141
<PAGE>

2002 2001 2000
---- ---- ----
Income tax benefit (expense)
Products Pipelines.............. $ (10,154) $ (9,653) $ (11,960)
Natural Gas Pipelines........... (378) -- --
CO2 Pipelines................... -- -- --
Terminals....................... (4,751) (6,720) (1,974)
----------- ----------- -----------
Total consolidated income tax
benefit (expense).............. $ (15,283) $ (16,373) $ (13,934)
=========== =========== ===========

Segment earnings
Products Pipelines.............. $ 343,935 $ 312,464 $ 222,694
Natural Gas Pipelines........... 276,766 193,804 113,068
CO2 Pipelines................... 100,983 92,087 68,128
Terminals....................... 191,569 136,178 40,156
----------- ----------- -----------
Total segment earnings.......... 913,253 734,533 444,046
Interest and corporate
administrative expenses(a)..... (304,876) (292,190) (165,698)
----------- ----------- -----------
Total consolidated net income... $ 608,377 $ 442,343 $ 278,348
=========== =========== ===========

(a) Includes interest and debt expense, general and administrative
expenses, minority interest expense and other insignificant items.

Assets at December 31
Products Pipelines............ $3,088,799 $3,095,899 $ 2,220,984
Natural Gas Pipelines......... 3,121,674 2,058,836 1,552,506
CO2 Pipelines................. 613,980 503,565 417,278
Terminals..................... 1,165,096 990,760 357,689
----------- ----------- -----------
Total segment assets.......... 7,989,549 6,649,060 4,548,457
Corporate assets(a)........... 364,027 83,606 76,753
----------- ----------- -----------
Total consolidated assets..... $8,353,576 $6,732,666 $4,625,210
=========== =========== ===========

(a) Includes cash, cash equivalents and certain unallocable deferred charges.

Depreciation and amortization
Products Pipelines............ $ 64,388 $ 65,864 $ 40,730
Natural Gas Pipelines......... 48,411 31,564 21,709
CO2 Pipelines................. 29,196 17,562 10,559
Terminals..................... 30,046 27,087 9,632
----------- ----------- -----------
Total consolidated depreciation
and amortization............. $ 172,041 $ 142,077 $ 82,630
=========== =========== ===========

Investments at December 31
Products Pipelines............ $ 133,927 $ 225,561 $ 231,651
Natural Gas Pipelines......... 103,724 146,566 141,613
CO2 Pipelines................. 71,283 68,232 9,559
Terminals..................... 2,110 159 59
----------- ----------- -----------
Total consolidated equity
investments.................. 311,044 440,518 382,882
Investment in oil and gas assets
to be contributed to joint
venture........................ -- -- 34,163
----------- ----------- -----------
$ 311,044 $ 440,518 $ 417,045
=========== =========== ===========

Capital expenditures
Products Pipelines............ $ 62,199 $ 84,709 $ 69,243
Natural Gas Pipelines......... 194,485 86,124 14,496
CO2 Pipelines................. 163,183 65,778 16,115
Terminals..................... 122,368 58,477 25,669
----------- ----------- -----------
Total consolidated capital
expenditures................. $ 542,235 $ 295,088 $ 125,523
=========== =========== ===========

Our total operating revenues are derived from a wide customer base. For
each of the years ended December 31, 2002 and 2001, one customer accounted
for more than 10% of our total consolidated revenues. Total transactions
within our Natural Gas Pipelines segment in 2002 with CenterPoint Energy
accounted for 15.6% of our total consolidated revenues during 2002. Total
transactions within our Natural Gas Pipelines and Terminals segment in 2001
with the Reliant Energy group of companies, including the entities which
became CenterPoint Energy in October 2002, accounted for 20.2% of our total
consolidated revenues during 2001. For the year ended December 31, 2000, no
revenues from transactions with a single external customer amounted to 10% or
more of our total consolidated revenues.

142
<PAGE>

16. Litigation and Other Contingencies

The tariffs charged for interstate common carrier pipeline transportation
for our pipelines are subject to rate regulation by the Federal Energy
Regulatory Commission, referred to herein as FERC, under the Interstate
Commerce Act. The Interstate Commerce Act requires, among other things, that
interstate petroleum products pipeline rates be just and reasonable and
non-discriminatory. Pursuant to FERC Order No. 561, effective January 1,
1995, interstate petroleum products pipelines are able to change their rates
within prescribed ceiling levels that are tied to an inflation index. FERC
Order No. 561-A, affirming and clarifying Order No. 561, expands the
circumstances under which interstate petroleum products pipelines may employ
cost-of-service ratemaking in lieu of the indexing methodology, effective
January 1, 1995. For each of the years ended December 31, 2002, 2001 and
2000, the application of the indexing methodology did not significantly
affect our tariff rates.

Federal Energy Regulatory Commission Proceedings

SFPP, L.P.

SFPP, L.P., referred to herein 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 involving shippers'
complaints regarding the interstate rates, as well as practices and the
jurisdictional nature of certain facilities and services, on our Pacific
operations' pipeline systems. Generally, the interstate rates on our Pacific
operations' pipeline systems are "grandfathered" under the Energy Policy Act
of 1992 unless "substantially changed circumstances" are found to exist. To
the extent "substantially changed circumstances" are found to exist, our
Pacific operations may be subject to substantial exposure under these FERC
complaints.

The complainants have alleged a variety of grounds for finding
"substantially changed circumstances." Applicable rules and regulations in
this field are vague, relevant factual issues are complex, and there is
little precedent available regarding the factors to be considered or the
method of analysis to be employed in making a determination of "substantially
changed circumstances". Given the relative newness of the grandfathering
standard under the Energy Policy Act and limited precedent, we cannot predict
how these allegations will be viewed by the FERC.

If "substantially changed circumstances" are found, SFPP rates previously
"grandfathered" under the Energy Policy Act will lose their "grandfathered"
status. If these rates are found to be unjust and unreasonable, shippers may
be entitled to a prospective rate reduction and a complainant may be entitled
to reparations for periods from the date of its complaint to the date of the
implementation of the new rates.

We currently believe that these FERC complaints seek approximately $197
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million.
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.

However, even if "substantially changed circumstances" are found to exist,
we believe that the resolution of these FERC complaints will be for amounts
substantially less than the amounts sought and that the resolution of such
matters will not have a material adverse effect on our business, financial
position or results of operations.

OR92-8, et al. proceedings. In September 1992, El Paso Refinery, L.P.
filed a protest/complaint with the FERC:

o challenging SFPP's East Line rates from El Paso, Texas to Tucson and
Phoenix, Arizona;

o challenging SFPP's proration policy; and

o seeking to block the reversal of the direction of flow of SFPP's
six-inch pipeline between Phoenix and Tucson.

143
<PAGE>

At various subsequent dates, the following other shippers on SFPP's South
System filed separate complaints, and/or motions to intervene in the FERC
proceeding, challenging SFPP's rates on its East and/or West Lines:

o Chevron U.S.A. Products Company;

o Navajo Refining Company;

o ARCO Products Company;

o Texaco Refining and Marketing Inc.;

o Refinery Holding Company, L.P. (a partnership formed by El Paso
Refinery's long-term secured creditors that purchased its refinery in
May 1993);

o Mobil Oil Corporation; and

o Tosco Corporation.

Certain of these parties also claimed that a gathering enhancement fee at
SFPP's Watson Station in Carson, California was charged in violation of the
Interstate Commerce Act.

The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al.,
and ruled that they are complaint proceedings, with the burden of proof on
the complaining parties. These parties must show that SFPP's rates and
practices at issue violate the requirements of the Interstate Commerce Act.

A FERC administrative law judge held hearings in 1996, and issued an
initial decision on September 25, 1997. The initial decision agreed with
SFPP's position that "changed circumstances" had not been shown to exist on
the West Line, and therefore held that all West Line rates that were
"grandfathered" under the Energy Policy Act of 1992 were deemed to be just
and reasonable and were not subject to challenge, either for the past or
prospectively, in the Docket No. OR92-8 et al. proceedings. SFPP's Tariff
No. 18 for movement of jet fuel from Los Angeles to Tucson, which was
initiated subsequent to the enactment of the Energy Policy Act, was
specifically excepted from that ruling.

The initial decision also included rulings generally adverse to SFPP on
such cost of service issues as:

o the capital structure to be used in computing SFPP's 1985 starting rate
base ;

o the level of income tax allowance; and

o the recovery of civil and regulatory litigation expenses and certain
pipeline reconditioning costs.

The administrative law judge also ruled that SFPP's gathering enhancement
service at Watson Station was subject to FERC jurisdiction and ordered SFPP
to file a tariff for that service, with supporting cost of service
documentation.

SFPP and other parties asked the FERC to modify various rulings made in
the initial decision. On January 13, 1999, the FERC issued its Opinion No.
435, which affirmed certain of those rulings and reversed or modified
others.

With respect to SFPP's West Line, the FERC affirmed that all but one of
the West Line rates are "grandfathered" as just and reasonable and that
"changed circumstances" had not been shown to satisfy the complainants'
threshold burden necessary to challenge those rates. The FERC further held
that the rate stated in Tariff No. 18 did not require rate reduction.
Accordingly, the FERC dismissed all complaints against the West Line rates
without any requirement that SFPP reduce, or pay any reparations for, any
West Line rate.

With respect to the East Line rates, Opinion No. 435 made several changes
in the initial decision's methodology for calculating the rate base. It held
that the June 1985 capital structure of SFPP's parent company at that time,

144
<PAGE>

rather than SFPP's 1988 partnership capital structure, should be used to
calculate the starting rate base and modified the accumulated deferred income
tax and allowable cost of equity used to calculate the rate base. It also
ruled that SFPP would not owe reparations to any complainant for any period
prior to the date on which that complainant's complaint was filed, thus
reducing by two years the potential reparations period claimed by most
complainants.

SFPP and certain complainants sought rehearing of Opinion No. 435 by the
FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for
review of Opinion No. 435 with the U.S. Court of Appeals for the District of
Columbia Circuit, all of which were either dismissed as premature or held in
abeyance pending FERC action on the rehearing requests.

On March 15, 1999, as required by the FERC's order, SFPP submitted a
compliance filing implementing the rulings made in Opinion No. 435,
establishing the level of rates to be charged by SFPP in the future, and
setting forth the amount of reparations that would be owed by SFPP to the
complainants under the order. The complainants contested SFPP's compliance
filing.

On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified
Opinion No. 435 in certain respects. It denied requests to reverse its
rulings that SFPP's West Line rates and Watson Station gathering enhancement
facilities fee are entitled to be treated as "grandfathered" rates under the
Energy Policy Act. It suggested, however, that if SFPP had fully recovered
the capital costs of the gathering enhancement facilities, that might form
the basis of an amended "changed circumstances" complaint.

Opinion No. 435-A granted a request by Chevron and Navajo to require that
SFPP's December 1988 partnership capital structure be used to compute the
starting rate base from December 1983 forward, as well as a request by SFPP
to vacate a ruling that would have required the elimination of approximately
$125 million from the rate base used to determine capital structure. It also
granted two clarifications sought by Navajo, to the effect that SFPP's return
on its starting rate base should be based on SFPP's capital structure in each
given year (rather than a single capital structure from the outset) and that
the return on deferred equity should also vary with the capital structure for
each year. Opinion No. 435-A denied the request of Chevron and Navajo that
no income tax allowance be recognized for the limited partnership interests
held by SFPP's corporate parent, as well as SFPP's request that the tax
allowance should include interests owned by certain non-corporate entities.
However, it granted Navajo's request to make the computation of interest
expense for tax allowance purposes the same as for debt return.

Opinion No. 435-A reaffirmed that SFPP may recover certain litigation
costs incurred in defense of its rates (amortized over five years), but
reversed a ruling that those expenses may include the costs of certain civil
litigation with Navajo and El Paso. It also reversed a prior decision that
litigation costs should be allocated between the East and West Lines based on
throughput, and instead adopted SFPP's position that such expenses should be
split equally between the two systems.

As to reparations, Opinion No. 435-A held that no reparations would be
awarded to West Line shippers and that only Navajo was eligible to recover
reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP
barred Navajo from obtaining reparations prior to November 23, 1993, but
allowed Navajo reparations for a one-month period prior to the filing of its
December 23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's
indexing methodology should be used in determining rates for reparations
purposes and made certain clarifications sought by Navajo.

Opinion No. 435-A denied Chevron's request for modification of SFPP's
prorationing policy. That policy required customers to demonstrate a need
for additional capacity if a shortage of available pipeline space existed.
SFPP's prorationing policy has since been changed to eliminate the
"demonstrated need" test.

Finally, Opinion No. 435-A directed SFPP to revise its initial compliance
filings to reflect the modified rulings. It eliminated the refund obligation
for the compliance tariff containing the Watson Station gathering enhancement
fee, but required SFPP to pay refunds to the extent that the initial
compliance tariff East Line rates exceeded the rates produced under Opinion
No. 435-A.

145
<PAGE>

In June 2000, several parties filed requests for rehearing of rulings made
in Opinion No. 435-A. Chevron and RHC both sought reconsideration of the
FERC's ruling that only Navajo is entitled to reparations for East Line
shipments. SFPP sought rehearing of the FERC's:

o decision to require use of the December 1988 partnership capital
structure for the period 1984-88 in computing the starting rate base;

o elimination of civil litigation costs;

o refusal to allow any recovery of civil litigation settlement payments;
and

o failure to provide any allowance for regulatory expenses in prospective
rates.

On July 17, 2000, SFPP submitted a compliance filing implementing the
rulings made in Opinion No. 435-A, together with a calculation of reparations
due to Navajo and refunds due to other East Line shippers. SFPP also filed a
tariff stating revised East Line rates based on those rulings.

ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of
Opinion No. 435-A in the U.S. Court of Appeals for the District of Columbia
Circuit. All of those petitions except Chevron's were either dismissed as
premature or held in abeyance pending action on the rehearing requests. On
September 19, 2000, the court dismissed Chevron's petition for lack of
prosecution, and subsequently denied a motion by Chevron for reconsideration
of that dismissal.

On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on
requests for rehearing and comments on SFPP's compliance filing. Based on
those rulings, the FERC directed SFPP to submit a further revised compliance
filing, including revised tariffs and revised estimates of reparations and
refunds.

Opinion No. 435-B denied SFPP's requests for rehearing, which involved the
capital structure to be used in computing starting rate base, SFPP's ability
to recover litigation and settlement costs incurred in connection with the
Navajo and El Paso civil litigation, and the provision for regulatory costs
in prospective rates. However, it modified the FERC's prior rulings on
several other issues. It reversed the ruling that only Navajo is eligible
to seek reparations, holding that Chevron, RHC, Tosco and Mobil are also
eligible to recover reparations for East Line shipments. It ruled, however,
that Ultramar is not eligible for reparations in the Docket No. OR92-8 et al.
proceedings.

The FERC also changed prior rulings that had permitted SFPP to use certain
litigation, environmental and pipeline rehabilitation costs that were not
recovered through the prescribed rates to offset overearnings (and potential
reparations) and to recover any such costs that remained by means of a
surcharge to shippers. Opinion No. 435-B required SFPP to pay reparations to
each complainant without any offset for unrecovered costs. It required SFPP
to subtract from the total 1995-1998 supplemental costs allowed under Opinion
No. 435-A any overearnings not paid out as reparations, and allowed SFPP to
recover any remaining costs from shippers by means of a five-year surcharge
beginning August 1, 2000. Opinion No. 435-B also ruled that SFPP would only
be permitted to recover certain regulatory litigation costs through the
surcharge, and that the surcharge could not include environmental or pipeline
rehabilitation costs.

Opinion No. 435-B directed SFPP to make additional changes in its revised
compliance filing, including:

o using a remaining useful life of 16.8 years in amortizing its starting
rate base, instead of 20.6 years;

o removing the starting rate base component from base rates as of August
1, 2001;

o amortizing the accumulated deferred income tax balance beginning in
1992, rather than 1988;

o listing the corporate unitholders that were the basis for the income tax
allowance in its compliance filing and certifying that those companies
are not Subchapter S corporations; and

146
<PAGE>

o "clearly" excluding civil litigation costs and explaining how it limited
litigation costs to FERC-related expenses and assigned them to
appropriate periods in making reparations calculations.

On October 15, 2001, Chevron and RHC filed petitions for rehearing of
Opinion No. 435-B. Chevron asked the FERC to clarify:

o the period for which Chevron is entitled to reparations; and

o whether East Line shippers that have received the benefit of
FERC-prescribed rates for 1994 and subsequent years must show that there
has been a substantial divergence between the cost of service and the
change in the FERC's rate index in order to have standing to challenge
SFPP rates for those years in pending or subsequent proceedings.

RHC's petition contended that Opinion No. 435-B should be modified on
rehearing, to the extent it:

o suggested that a "substantial divergence" standard applies to complaint
proceedings challenging the total level of SFPP's East Line rates
subsequent to the Docket No. OR92-8 et al. proceedings;

o required a substantial divergence to be shown between SFPP's cost of
service and the change in the FERC oil pipeline index in such subsequent
complaint proceedings, rather than a substantial divergence between the
cost of service and SFPP's revenues; and

o permitted SFPP to recover 1993 rate case litigation expenses through a
surcharge mechanism.

ARCO, Ultramar and SFPP filed petitions for review of Opinion No. 435-B
(and in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals
for the District of Columbia Circuit. The court consolidated the Ultramar
and SFPP petitions with the consolidated cases held in abeyance and ordered
that the consolidated cases be returned to its active docket.

On November 7, 2001, the FERC issued an order ruling on the petitions for
rehearing of Opinion No. 435-B. The FERC held that Chevron's eligibility for
reparations should be measured from August 3, 1993, rather than the September
23, 1992 date sought by Chevron. The FERC also clarified its prior ruling
with respect to the "substantial divergence" test, holding that in order to
be considered on the merits, complaints challenging the SFPP rates set by
applying the FERC's indexing regulations to the 1994 cost of service derived
under the Opinion No. 435 orders must demonstrate a substantial divergence
between the indexed rates and the pipeline's actual cost of service.
Finally, the FERC held that SFPP's 1993 regulatory costs should not be
included in the surcharge for the recovery of supplemental costs.

On November 20, 2001, SFPP submitted its compliance filing and tariffs
implementing Opinion No. 435-B and the FERC's November 7, 2001 order.
Motions to intervene and protest were subsequently filed by ARCO, Mobil
(which now submits filings under the name ExxonMobil), RHC, Navajo and
Chevron, alleging that SFPP:

o should have calculated the supplemental cost surcharge differently;

o did not provide adequate information on the taxpaying status of its
unitholders; and

o failed to estimate potential reparations for ARCO.

On December 7, 2001, Chevron filed a petition for rehearing of the FERC's
November 7, 2001 order. The petition requested the FERC to specify whether
Chevron would be entitled to reparations for the two year period prior to the
August 3, 1993 filing of its complaint.

On December 10, 2001, SFPP filed a response to those claims. On December
14, 2001, SFPP filed a revised compliance filing and new tariff correcting an
error that had resulted in understating the proper surcharge and tariff
rates.

147
<PAGE>

On December 20, 2001, the FERC's Director of the Division of Tariffs and
Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and
December 14, 2001 tariff filings because they were not made effective
retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for
rehearing of those orders by the FERC, on the ground that the FERC has no
authority to require retroactive reductions of rates filed pursuant to its
orders in complaint proceedings.

On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's
November 7, 2001 order in the U.S. Court of Appeals for the District of
Columbia Circuit. On January 8, 2002, the court consolidated those petitions
with the petitions for review of Opinion Nos. 435, 435-A and 435-B. On
January 24, 2002, the court ordered the consolidated proceedings to be held
in abeyance until the FERC acts on Chevron's request for rehearing of the
November 7, 2001 order.

Motions to intervene and protest the December 14, 2001 corrected
submissions were filed by Navajo, ARCO and ExxonMobil. Ultramar requested
leave to file an out-of-time intervention and protest of both the November
20, 2001 and December 14, 2001 submissions. On January 14, 2002, SFPP
responded to those filings to the extent they were not mooted by the orders
rejecting the tariffs in question.

On February 15, 2002, the FERC denied rehearing of the Director of the
Division of Tariffs and Rates Central's letter orders. On February 21, 2002,
SFPP filed a motion requesting that the FERC clarify whether it intended SFPP
to file a retroactive tariff or simply make a compliance filing calculating
the effects of Opinion No. 435-B back to August 1, 2000; in the event the
order was clarified to require a retroactive tariff filing, SFPP asked the
FERC to stay that requirement pending judicial review.

On April 8, 2002, SFPP filed a petition for review of the FERC's February
15, 2002 Order in the U.S. Court of Appeals for the District of Columbia
Circuit. BP West Coast Products, LLC (formerly ARCO); ExxonMobil; Tosco
Corporation; and Ultramar, Inc. and Valero Energy Corporation filed motions
to intervene in that proceeding. On April 9, 2002, the Court of Appeals
consolidated SFPP's petition with the petitions for review of the FERC's
prior orders and directed the parties "to file motions to govern future
proceedings" by May 9, 2002. Motions were filed by SFPP, RHC, Navajo,
Chevron and the "Indicated Parties" (BP West Coast Products, ExxonMobil,
Ultramar and Tosco). The FERC requested that the Court of Appeals continue
to hold the consolidated cases in abeyance pending the completion of
proceedings before the agency on rehearing.

On June 25, 2002, the Court of Appeals granted the ExxonMobil and Valero
Energy motions to intervene, and directed intervenors on the side of
petitioners to notify the court of that status and provide a statement of
issues to be raised. ExxonMobil filed a notice on July 2, 2002; Ultramar,
Inc. and Valero Energy on July 10, 2002. On July 12, 2002, SFPP responded to
the ExxonMobil notice in order to urge the Court of Appeals not to rely on
ExxonMobil's categorization of the issues and party alignments in allocating
briefing.

On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the
FERC's annual indexing adjustment. Motions to intervene and protest were
filed by Navajo and Chevron, contesting any indexing adjustment to the
litigation surcharge permitted by Opinion No. 435-B. On June 28, 2002, the
FERC's Director of the Division of Tariffs and Rates rejected Tariff No. 70
on the ground that the surcharge should not be indexed. On July 2, 2002,
SFPP filed FERC Tariff No. 73 to replace Tariff No. 70 in compliance with
that decision, which resulted in an average reduction from Tariff No. 70 of
approximately $.0002 per barrel.

On September 26, 2002, the FERC issued an order ruling on the protests
against SFPP's November 20, 2001 and December 14, 2001 compliance filings
implementing Opinion No. 435-B and the November 7, 2001 Order. The FERC held
that:

o SFPP must measure supplemental costs against the total amount of
reparations for the entire reparations period (as opposed to
year-by-year);

o SFPP will not be permitted to include in its supplemental costs
(a) litigation expenses incurred during 1999 and 2000 or (b) payments
made to Navajo and RHC to settle certain FERC litigation;

o the tariff surcharge collected by SFPP for all shipments between August
1, 2000 and December 1, 2001 is subject to refund; and

148

<PAGE>

o in calculating its tax allowance, SFPP must exclude the ownership
interest attributable to an entity that the FERC found to be a mutual
fund.

The FERC rejected the requests by Navajo, BP West Coast Products and
ExxonMobil to extend the period for which they are entitled to reparations
beyond the periods specified in prior orders.

The September 26, 2002 Order also ruled on SFPP's request for
clarification of the February 15, 2002 Order as to whether it was required to
make a retroactive tariff filing or rather a compliance filing calculating
the effects of Opinion No. 435-B beginning August 1, 2000. The FERC held
that SFPP was required to file a tariff retroactive to August 1, 2000. The
FERC did not rule on SFPP's alternative request for a stay. The FERC also
ruled on Chevron's request for rehearing of the November 7, 2001 Order,
clarifying that Chevron was eligible for reparations for shipments on the
East Line for the two years prior to the filing of its complaint.

On October 22, 2002, ExxonMobil filed a Request for Clarification or, in
the Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil
requested that the FERC clarify that ExxonMobil was eligible for reparations
for East Line rates.

On October 25, 2002, SFPP filed Tariff No. 75 implementing changes
required by the September 26, 2002 Order, and on October 28, 2002, SFPP
submitted a compliance filing pursuant to that order. Valero Marketing and
Supply Company filed a motion to intervene and protest regarding the
compliance filing and tariff, and Tosco Corporation protested the compliance
filing. Navajo Refining Company, L.P. moved to intervene in proceedings
relating to the tariff, and Chevron Products Company and Equilon Enterprises
LLC filed comments and related pleadings challenging the compliance filing
and seeking additional relief.

On January 29, 2003, the FERC issued an order accepting the October 28,
2002 compliance filing subject to the condition that SFPP recalculate gross
reparations in determining its per barrel surcharge and submit a revised
tariff reflecting that change within fifteen days of the order. The FERC
rejected all other challenges to that compliance filing.

Following the September 26, 2002 Order, several parties filed motions to
govern future proceedings with the U.S. Court of Appeals for the District of
Columbia Circuit. BP West Coast Products LLC and ExxonMobil (the "Indicated
Parties") and Valero Energy Corporation, Ultramar Inc. and Tosco Corporation
(the "Joint Parties") requested that the court return the petitions for
review to its active docket but sever the docket involving compliance filing
issues. The FERC filed a motion that did not take a definitive position on
whether the petitions for review should continue to be held in abeyance, but
noted that compliance filing issues were still pending before the FERC.
SFPP, Chevron, Navajo and RHC filed responses to the motions to govern future
proceedings. On December 6, 2002, the Court of Appeals granted the motion of
the "Indicated Parties" and "Joint Parties" to return the petitions for
review to the Court's active docket. The Court also severed the docket
relating to compliance filing issues and directed the parties to submit a
proposed briefing schedule and format. On January 6, 2003, SFPP and FERC
filed a joint briefing proposal, and the shipper parties jointly filed a
separate briefing proposal.

On October 18, 2002, Chevron filed a petition for review of Opinion Nos.
435, 435-A and 435-B in the U.S. Court of Appeals for the District of
Columbia Circuit. The Court of Appeals consolidated that petition with the
main docket on November 20, 2002. Tosco Corporation and BP West Coast
Products LLC moved to intervene in that docket, and those motions were
granted on December 10, 2002.

Petitions for review of the September 26, 2002 Order have been filed in
the U.S. Court of Appeals for the District of Columbia Circuit by Navajo, on
October 24, 2002, and by SFPP, on November 8, 2002. The Court consolidated
those petitions with the main docket on November 5, 2002 and November 12,
2002, respectively. Valero Marketing and Supply Company moved to intervene
in both dockets and Tosco Corporation moved to intervene in the docket for
the SFPP petition. On January 6, 2003, Valero Marketing and Supply Company
filed a motion to substitute itself for Ultramar Diamond Shamrock Corporation
in Ultramar's petition for review of Opinion No. 435-B. On January 21, 2003
SFPP filed a response, stating that it did not object to the proposed
substitution provided Valero Marketing and Supply Corporation was not
permitted to create or enlarge any claim for damages.

149
<PAGE>

On January 24, 2003, ConocoPhillips filed a motion to substitute itself
for Tosco Corporation in the consolidated dockets, and on January 27, 2003,
filed a similar motion in the severed docket relating to compliance filing
issues.

Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines
(Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were
subject to FERC's jurisdiction under the Interstate Commerce Act, and, if so,
claimed that the rate for that service was unlawful. Texaco sought to have
its claims addressed in the OR92-8 proceeding discussed above. Several other
West Line shippers filed similar complaints and/or motions to intervene. The
FERC consolidated all of these filings into Docket No. OR96-2 and set the
claims for a separate hearing. A hearing before an administrative law judge
was held in December 1996.

In March 1997, the judge issued an initial decision holding that the
movements on the Sepulveda pipelines were not subject to FERC jurisdiction.
On August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP
filed a tariff establishing the initial interstate rate for movements on the
Sepulveda pipelines at the preexisting rate of 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 that, while SFPP appeared to lack
market power in the Sepulveda origin market, a hearing was necessary to
permit the protesting parties to substantiate allegations that SFPP possesses
market power in the origin market. A hearing before a FERC administrative
law judge on this limited issue was held in February 2000.

On December 21, 2000, the FERC administrative law judge issued his initial
decision finding that SFPP possesses market power over the Sepulveda origin
market. The ultimate disposition of SFPP's application is pending before the
FERC.

Following the issuance of the initial decision in the Sepulveda case, the
FERC judge indicated an intention to proceed to consideration of the justness
and reasonableness of the existing rate for service on the Sepulveda
pipelines. On February 22, 2001, the FERC granted SFPP's motion to block
such consideration and to defer consideration of the pending complaints
against the Sepulveda rate until after FERC's final disposition of SFPP's
market rate application.

OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a
complaint at 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 Diamond Shamrock Corporation 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 the lines. SFPP answered each of
these complaints. FERC issued orders accepting the complaints and
consolidating them into one proceeding (Docket No. OR96-2, et al.), but
holding 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. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds
for their complaints to go forward to a hearing to assess whether any of the
challenged rates that are grandfathered under the Energy Policy Act will
continue to have such status and, if the grandfathered status of any rate is
not upheld, whether the existing rate is just and reasonable.

In August 2000, Navajo and RHC 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. In September 2000, FERC
accepted these new complaints and consolidated them with the ongoing
proceeding in Docket No. OR96-2, et al.

150
<PAGE>

A hearing in this consolidated proceeding was held from October 2001 to
March 2002. An initial decision by the administrative law judge is expected
in the first half of 2003.

OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the
OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along
with a motion to consolidate the complaint with the OR96-2 proceeding. On
May 21, 2002, the FERC dismissed Chevron's complaint and motion to
consolidate. Chevron filed a request for rehearing and on September 25,
2002, the FERC dismissed Chevron's rehearing request. In October 2002,
Chevron filed a request for rehearing of the FERC's September 25 order. The
FERC has indicated that it intends to rule on Chevron's request in February
2003. Chevron continues to participate in the OR96-2 proceeding as an
intervenor.

CALNEV Pipe Line LLC

We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides
interstate and intrastate transportation from an interconnection with SFPP at
Colton, California to destinations in and around Las Vegas, Nevada.

In April 2002, Chevron filed a complaint against CALNEV's interstate
rates, making allegations of unjust and unreasonable rates. CALNEV answered
Chevron's complaint on May 16, 2002, and Chevron moved for leave to respond
to CALNEV's answer on June 17, 2002.

In September of 2002, CALNEV and Chevron were able to reach a mutually
agreeable resolution of the disputed claims, and a settlement was executed.
In the settlement agreement, the parties agreed, among other things, that
for a period of five years, CALNEV would not seek a rate increase at the FERC
or the California Public Utilities Commission except as permitted under four
specific exceptions and that Chevron would not file complaints against
CALNEV's rates, provided it complies with such exceptions. On October 10,
2002, the FERC granted the parties' joint motion to dismiss the complaint
with prejudice.

Trailblazer Pipeline Company

As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at FERC on November 29, 2002. The filing
provides for a small rate decrease and also includes a number of non-rate
tariff changes. By an order issued December 31, 2002, FERC effectively
bifurcated the proceeding. The rate change was accepted to be effective on
January 1, 2003, subject to refund and a hearing. Most of the non-rate
tariff changes were suspended until June 1, 2003, subject to refund and a
technical conference procedure.

Trailblazer has sought rehearing of the FERC order with respect to the
refund condition on the rate decrease. The Indicated Shippers have sought
rehearing as to FERC acceptance of certain non-rate tariff provisions. A
prehearing conference on the rate issues was held on January 16, 2003. A
procedural schedule was established under which the hearing will commence on
October 8, 2003, if the case is not settled. Discovery has commenced as to
rate issues.

The technical conference on non-rate issues was held on February 6, 2003.
Those issues include:

o capacity award procedures;

o credit procedures;

o imbalance penalties; and

o the maximum length of bid terms considered for evaluation in the right
of first refusal process.

Initial and reply comments on these issues as discussed at the technical
conference are due March 7, 2003 and March 18, 2003, respectively.

151
<PAGE>

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 seek 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 a decision addressing the submitted matters is expected within
three to four months.

The CPUC has recently issued a resolution approving a 2001 request by SFPP
to raise its California rates to reflect increased power costs. The
resolution approving the requested rate increase also requires SFPP to submit
cost data for 2001, 2002, and 2003 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.

There is no way to quantify the potential extent to which the CPUC could
determine that SFPP's existing California rates are unreasonable or estimate
the amount of dollars potentially subject to refund as a consequence of the
CPUC resolution requiring the provision by SFPP of cost-of-service data.
SFPP believes that submission of the required, representative cost data
required by the CPUC will indicate that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.

We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position or results of operations.

FERC Order 637

Kinder Morgan Interstate Gas Transmission LLC

On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained
KMIGT's compliance plan to implement the changes required by FERC dealing
with the way business is conducted on interstate natural gas pipelines. All
interstate natural gas pipelines were required to make such compliance
filings, according to a schedule established by FERC. From October 2000
through June 2001, KMIGT held a series of technical and phone conferences to
identify issues, obtain input, and modify its Order 637 compliance plan,
based on comments received from FERC staff and other interested parties and
shippers. On June 19, 2001, KMIGT received a letter from FERC encouraging it
to file revised pro-forma tariff sheets, which reflected the latest
discussions and input from parties into its Order 637 compliance plan.

152
<PAGE>

KMIGT made such a revised Order 637 compliance filing on July 13, 2001.
The July 13, 2001 filing contained little substantive change from the
original pro-forma tariff sheets that KMIGT originally proposed on June 15,
2000. On October 19, 2001, KMIGT received an order from FERC, addressing its
July 13, 2001 Order 637 compliance plan. In the Order addressing the July
13, 2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed
to make several changes to its tariff, and in doing so, was directed that it
could not place the revised tariff into effect until further order of the
FERC. KMIGT filed its compliance filing with the October 19, 2001 Order on
November 19, 2001 and also filed a request for rehearing/clarification of the
FERC's October 19, 2001 Order on November 19, 2001. Several parties
protested the November 19, 2001 compliance filing. KMIGT filed responses to
those protests on December 14, 2001. At this time, it is unknown when this
proceeding will be finally resolved. The full impact of implementation of
Order 637 on the KMIGT system is under evaluation. We believe that these
matters will not have a material adverse effect on our business, financial
position or results of operations.

Separately, numerous petitioners, including KMIGT, have filed appeals of
Order 637 in the D.C. Circuit, potentially raising a wide array of issues
related to Order 637 compliance. Initial briefs were filed on April 6, 2001,
addressing issues contested by industry participants. Oral arguments on the
appeals were held before the court in December 2001. On April 5, 2002, the
D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The
D.C. Circuit remanded the FERC's decision to impose a 5-year cap on bids that
an existing shipper would have to match in the right of first refusal
process. The D.C. Circuit also remanded the FERC's decision to allow
forward-hauls and backhauls to the same point. Finally, the D.C. Circuit
held that several aspects of the FERC's segmentation policy and its policy on
discounting at alternate points were not ripe for review. The FERC requested
comments from the industry with respect to the issues remanded by the D.C.
Circuit. They were due July 30, 2002.

On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:

o eliminated the requirement of a 5-year cap on bid terms that an existing
shipper would have to match in the right of first refusal process, and
found that no term matching cap is necessary given existing regulatory
controls;

o affirmed FERC's policy that a segmented transaction consisting of both
a forwardhaul up to contract demand and a backhaul up to contract
demand to the same point is permissible; and

o accordingly required, under Section 5 of the NGA, pipelines that the
FERC had previously found must permit segmentation on their systems to
file tariff revisions within 30 days to permit such segmented
forwardhaul and backhaul transactions to the same point.

Trailblazer Pipeline Company

On August 15, 2000, Trailblazer Pipeline Company made a filing to comply
with FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing
reflected changes in:

o segmentation;

o scheduling for capacity release transactions;

o receipt and delivery point rights;

o treatment of system imbalances;

o operational flow orders;

o penalty revenue crediting; and

o right of first refusal language.

153
<PAGE>

On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637
compliance filing. FERC approved Trailblazer's proposed language regarding
operational flow orders and the right of first refusal, but required
Trailblazer to make changes to its tariff related to the other issues listed
above.

On November 14, 2001, Trailblazer made its compliance filing pursuant to
the FERC order of October 15, 2001. That compliance filing has been
protested. Separately, also on November 14, 2001, Trailblazer filed for
rehearing of that FERC order. These pleadings are pending FERC action.

Trailblazer anticipates no adverse impact on its business as a result of
the implementation of Order No. 637.

Standards of Conduct Rulemaking

On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between KMIGT, Trailblazer and their respective affiliates.
In addition, the Notice could be read to require separate staffing of KMIGT
and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties,
including KMIGT, have filed comment on the Proposed Standards of Conduct
Rulemaking. On May 21, 2002, FERC held a technical conference dealing with
the FERC's proposed changes in the Standard of Conduct Rulemaking. On June
28, 2002, KMIGT and numerous other parties flied additional written comments
under a procedure adopted at the technical conference. The Proposed
Rulemaking is awaiting further FERC action. We believe that these matters,
as finally adopted, will not have a material adverse effect on our business,
financial position or results of operations.

The FERC also issued a Notice of Proposed Rulemaking in Docket No.
RM02-14-000 in which it proposed new regulations for cash management
practices, including establishing limits on the amount of funds that can be
swept from a regulated subsidiary to a non-regulated parent company. Kinder
Morgan Interstate Gas Transmission LLC filed comments on August 28, 2002. We
believe that these matters, as finally adopted, will not have a material
adverse effect on our business, financial position or results of operations.

Southern Pacific Transportation Company Easements

SFPP and Southern Pacific Transportation Company are engaged in a judicial
reference 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
SPTC should be adjusted pursuant to existing contractual arrangements
(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).

Although SFPP received a favorable ruling from the trial court in May
1997, in September 1999, the California Court of Appeals remanded the case
back to the trial court for further proceeding. SFPP claims that the rent
payable for each of the years 1994 through 2004 should be approximately $4.4
million and SPTC claims it should be approximately $15.0 million. We believe
SPTC's position in this case is without merit and we have set aside reserves
that we believe are adequate to address any reasonably foreseeable outcome of
this matter. As of early-February 2003, the matter is currently in trial.

Carbon Dioxide Litigation

Kinder Morgan CO2 Company, L.P. directly or indirectly through its
ownership interest in the Cortez Pipeline Company, along with other entities,
is a defendant in several actions in which the plaintiffs allege that the
defendants undervalued carbon dioxide produced from the McElmo Dome field and
overcharged for transportation costs, thereby allegedly underpaying royalties
and severance tax payments. The plaintiffs, who are seeking monetary damages
and injunctive relief, are comprised of royalty, overriding royalty and small
share working interest owners who claim that they were underpaid by the
defendants. These cases are: CO2 Claims Coalition, LLC v. Shell Oil Co., et
al., No. 96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al.
v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00);
Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed
9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C.
Colo. filed 9/22/00); United

154
<PAGE>

States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220
(U.S.D.C. Colo. filed 6/13/00); Shell Western E&P Inc. v. Bailey, et al., No
98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al.
v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court,
Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil
Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed
3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43
(Colo. Dist. Ct. Montezuma County filed 3/21/98).

At a hearing conducted in the United States District Court for the
District of Colorado on April 8, 2002, the Court orally announced that it had
approved the certification of proposed plaintiff classes and approved a
proposed settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks,
Watson, Ainsworth and United States ex rel. Crowley cases. The Court entered
a written order approving the Settlement on May 6, 2002; plaintiffs counsel
representing Shores, et al. appealed the court's decision to the 10th Circuit
Court of Appeals. On December 26, 2002, the 10th Circuit Court of Appeals
affirmed in all respects the District Court's Order approving settlement.

Following the decision of the 10th Circuit, the Plaintiffs and Defendants
jointly filed motions to abate the Shell Western E&P Inc., Shores and First
State Bank of Denton cases in order to afford the parties time to discuss
potential settlement. These Motions were granted on February 6, 2003. In
the Celeste C. Grynberg case, the parties are currently engaged in discovery.

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. There are no further pretrial
proceedings at this time.

Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating
Company et al. v. Gas Pipelines, et al.)

Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999,
three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto,
filed a purported nationwide class action in the Stevens County, Kansas
District Court against some 250 natural gas pipelines and many of their
affiliates. The District Court is located in Hugoton, Kansas. Certain
entities we acquired in the Kinder Morgan Tejas acquisition are also
defendants in this matter. The Petition (recently amended) alleges a
conspiracy to underpay royalties, taxes and producer payments by the
defendants' undermeasurement of the volume and heating content of natural gas
produced from nonfederal lands for more than twenty-five years. The named
plaintiffs purport to adequately represent the interests of unnamed
plaintiffs in this action who are comprised of the nation's gas producers,
State taxing agencies and royalty, working and overriding owners. The
plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees from the defendants, jointly and
severally. This action was originally filed on May 28, 1999 in Kansas State
Court in Stevens County, Kansas as a class action against approximately 245
pipeline companies and their affiliates, including certain Kinder Morgan
entities. Subsequently, one of the defendants removed the action to Kansas
Federal District Court and the case was styled as Quinque Operating Company,
et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District
Court for the District of Kansas. Thereafter, we filed a motion with the
Judicial Panel for Multidistrict Litigation to consolidate this action for
pretrial purposes with the Grynberg False Claim Act cases referred to below,
because of common factual questions. On April 10, 2000, the MDL Panel
ordered that this case be consolidated with the Grynberg federal False Claims
Act cases discussed below. On January 12, 2001, the Federal District Court
of Wyoming issued an oral ruling remanding the case back to the State Court
in Stevens County, Kansas. The Court in Kansas has issued a case management
order addressing the initial phasing of the case. In this initial phase, the
court will rule on motions to dismiss (jurisdiction and sufficiency of
pleadings), and if the action is not dismissed, on class certification.
Merits discovery has been stayed.

155
<PAGE>

Recently, the defendants filed a motion to dismiss on grounds other than
personal jurisdiction, which was denied by the Court in August, 2002. The
Motion to Dismiss for lack of Personal Jurisdiction of the nonresident
defendants has been briefed and is awaiting decision. The current named
plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and Stixon
Petroleum, Inc. Quinque Operating Company has been dropped from the action
as a named plaintiff. On January 13, 2003, a motion to certify the class was
argued. A decision on this moton is pending.

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 Claim 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. Discovery is now underway to determine issues related to the
Court's subject matter jurisdiction, arising out of the False Claim Act.

Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et al.

Mel R. Sweatman and Paz Gas Corporation vs. Gulf Energy Marketing, LLC, et
al. On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortuous interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to
be shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder
Morgan Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this
action eliminated profit on Kinder Morgan Tejas, a portion of which Mr.
Sweatman and Paz Gas Corporation claim they are entitled under an agreement
with a subsidiary of ours acquired in the Tejas Gas acquisition. We have
filed a motion to remove the case from venue in Dewitt County, Texas to
Harris County, Texas, and our motion was denied in a venue hearing in
November 2002.

In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an
alleged commercial bribery committed by us, Gulf Energy Marketing, and
Intergen inasmuch as we, in our role as acquirer of Kinder Morgan Tejas,
allegedly paid Intergen to non-renew the underlying Entex contracts belonging
to the Tejas/Paz joint venture. Moreoever, new and distinct allegations of
breach of fiduciary and bribery of a fiduciary are also raised in this
amended petition for the first time.

Based on the information available to date and our preliminary
investigation, we believe this suit is without merit and we intend to defend
it vigorously.

Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy,
Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company,
Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P.,
Houston Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875
(District Court, Wharton County Texas).

On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional
defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc.,
Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The
First Amended Complaint purports to bring a class action on behalf of those
Texas residents who purchased natural gas for residential purposes from the
so-called "Reliant Defendants" in Texas at any time during the period
encompassing "at least the last ten years."

156
<PAGE>

The Complaint alleges that Reliant Energy Resources Corp., by and through
its affiliates, has artificially inflated the price charged to residential
consumers for natural gas that it allegedly purchased from the non-Reliant
defendants, including the above-listed Kinder Morgan entities. The Complaint
further alleges that in exchange for Reliant Energy Resources Corp.'s
purchase of natural gas at above market prices, the non-Reliant defendants,
including the above-listed Kinder Morgan entities, sell natural gas to Entex
Gas Marketing Company 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, violations of the Texas Deceptive Trade Practices Act, and violations
of the Texas Utility Code against some or all of the Defendants, and civil
conspiracy against all of the defendants, and seeks relief in the form of,
inter alia, actual, exemplary and statutory damages, civil penalties,
interest, attorneys' fees and a constructive trust ab initio on any and all
sums which allegedly represent overcharges by Reliant and Reliant Energy
Resources Corp.

On November 18, 2002, the Kinder Morgan defendants filed a Motion to
Transfer Venue and, Subject Thereto, Original Answer to the First Amended
Complaint. The parties are currently engaged in preliminary discovery.
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.

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"); and 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").

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 have filed a Notice of
Appeal to the United States Court of Appeals for the 9th Circuit, which
appeal is currently pending.

On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz 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 Complaint on the grounds that it also fails to state a claim upon
which relief can be granted. This motion is currently pending before the
court.

Based on the information available to date and our preliminary
investigation, we believe that the claims against us in the Snyder and Galaz
matters are without merit and intend to defend against them vigorously.

Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover
potential

157
<PAGE>

liability, and that these matters will not have a material adverse effect
on our business, financial position or results of operations.

Walter Chandler v. Plantation Pipe Line Company

On October 2, 2001, the jury rendered a verdict against Plantation Pipe
Line Company in the case of Walter Chandler v. Plantation Pipe Line Company.
The jury awarded the plaintiffs a total of $43.8 million. The judge reduced
the award to $42.6 million due to a prior settlement with the plaintiffs by a
third party.

This case was filed in April 1997 by the landowner (Evelyn Chandler Trust)
and two residents of the property (Buster Chandler and his son, Clay
Chandler). The suit was filed against Chevron, Plantation and two
individuals. The two individuals were later dismissed from the suit.
Chevron settled with the plaintiffs in December 2000. The property and
residences are directly across the street from the location of a former
Chevron products terminal. The Plantation pipeline system traverses the
Chevron terminal property. The suit alleges that gasoline released from the
terminal and pipeline contaminated the groundwater under the plaintiffs'
property. As noted above, a current remediation effort is taking place among
Chevron, Plantation and Alabama Department of Environmental Management.

In addition to the Chandler case, in 1998 and 1999, other entities and
individuals living in close proximity to the Chandlers filed lawsuits against
Plantation, Chevron and an environmental consulting firm, CH2MHill, alleging
property damage and personal injuries from groundwater contaminated with
petroleum hydrocarbons. In February 2003, Plantation settled, through a
confidential settlement, all of these lawsuits as well as the Chandler
litigation. Plantation believes that the settlement of these lawsuits and
the Chandler litigation will not have a material adverse effect on its
business, financial position or results of operations.

Marion County, Mississippi Litigation

In 1968, Plantation discovered a release from its 12-inch pipeline in
Marion County, Mississippi. The pipeline was immediately repaired. In 1998
and 1999, 62 lawsuits were filed on behalf of 263 plaintiffs in the Circuit
Court of Marion County, Mississippi. The majority of the claims are based on
alleged exposure from the 1968 release, including claims for property damage
and personal injury. Plantation has resolved some of the lawsuits but
lawsuits by 236 of the plaintiffs are still pending. Although a trial date
has not been set for any of the remaining cases, it is anticipated that a
trial on a portion of the lawsuits will be scheduled in 2003. Plantation
believes that the ultimate resolution of these Marion County, Mississippi
cases will not have a material effect on its business, financial position or
results of operations.

Environmental Matters

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, 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 regulations, risks of additional costs and
liabilities are inherent in pipeline and terminal 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 the following governmental proceedings
related to compliance with environmental regulations associated with our
assets and have established a reserve to address the costs associated with
the cleanup:

o one cleanup ordered by the United States Environmental Protection Agency
related to ground water contamination in the vicinity of SFPP's storage
facilities and truck loading terminal at Sparks, Nevada;

158
<PAGE>

o several ground water hydrocarbon remediation efforts under
administrative orders issued by the California Regional Water Quality
Control Board and two other state agencies;

o groundwater and soil remediation efforts under administrative orders
issued by various regulatory agencies on those assets purchased from
GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV
Pipe Line LLC and Central Florida Pipeline LLC; and

o a ground water remediation effort taking place between Chevron,
Plantation Pipe Line Company and the Alabama Department of Environmental
Management.

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.

Furthermore, our review of assets related to Kinder Morgan Interstate Gas
Transmission LLC indicates possible environmental impacts from petroleum and
used oil releases into the soil and groundwater at nine sites. Additionally,
our review of assets related to Kinder Morgan Texas Pipeline indicates
possible environmental impacts from petroleum releases into the soil and
groundwater at six sites. Further delineation and remediation of any
environmental impacts from these matters will be conducted. Reserves have
been established to address the closure of these issues.

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 or results of
operations. We have recorded a total reserve for environmental claims in the
amount of $52.7 million at December 31, 2002. As of December 31, 2002, we
were not able to reasonably estimate when the eventual settlements of these
claims will occur.

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 or results of operations.

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. In addition, since many of our assets are subject to
regulation, we are subject to potential future changes in applicable rules
and regulations that may have an adverse effect on our business, financial
position or results of operations.

17. Quarterly Financial Data (unaudited)

Basic Diluted
Operating Operating Net Income Net Income
Revenues Income Net Income per Unit per Unit
--------- --------- ---------- ---------- ----------
(In thousands, except per unit amounts)
<S> <C> <C> <C> <C> <C>
2002
First Quarter..... $ 803,065 $ 165,856 $ 141,433 $ 0.48 $ 0.48
Second Quarter.... 1,090,936 172,347 144,517 0.48 0.48
Third Quarter..... 1,121,320 189,403 158,180 0.50 0.50
Fourth Quarter.... 1,221,736 196,692 164,247 0.50 0.50
2001
First Quarter..... $1,028,645 $ 138,351 $ 101,667 $ 0.45 $ 0.45
Second Quarter.... 735,755 138,596 104,226 0.36 0.36
Third Quarter..... 638,544 144,892 115,792 0.37 0.37
Fourth Quarter.... 543,732 141,989 120,658 0.40 0.40

</TABLE>

159