Kinder Morgan, Inc. 2002 Form 10-K

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QZ3z4KpDEH1SdLqWBNzyAHUNa7bUnCshsoBsDX+BdaQS6j9iIx6+SxJxxJB/ELcV rN/Cob+TK8jK1wegWdw1Gg== 0000054502-03-000002.txt : 20030226 0000054502-03-000002.hdr.sgml : 20030226 20030226123331 ACCESSION NUMBER: 0000054502-03-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030226 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KINDER MORGAN INC CENTRAL INDEX KEY: 0000054502 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [4923] IRS NUMBER: 480290000 STATE OF INCORPORATION: KS FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-06446 FILM NUMBER: 03580367 BUSINESS ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 1000 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 3039144752 MAIL ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 1000 CITY: HUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: KN ENERGY INC DATE OF NAME CHANGE: 19920430 FORMER COMPANY: FORMER CONFORMED NAME: KANSAS NEBRASKA NATURAL GAS CO INC DATE OF NAME CHANGE: 19830403 FORMER COMPANY: FORMER CONFORMED NAME: K N ENERGY INC DATE OF NAME CHANGE: 19920703 10-K 1 kmi10k2002.htm KINDER MORGAN, INC. 2002 FORM 10-K Kinder Morgan, Inc. 2002 Form 10-K

Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-K

[X]

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

For the fiscal year ended December 31, 2002
or

[ ]

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

For the transition period from _____to_____

Commission File Number 1-6446
kminc.gif (5069 bytes)
Kinder Morgan, Inc.
(Exact name of registrant as specified in its charter)

Kansas		48-0290000
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices, including zip code)

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

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

Title of each class		Name of each exchange on which registered
Common stock, par value $5 per share Preferred share purchase rights Purchase Obligation of Kinder Morgan Management, LLC shares		New York Stock Exchange New York Stock Exchange New York Stock Exchange

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

Preferred stock, Class A $5 cumulative series

(Title of class)

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2):
Yes [X] No [ ]

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $3,633,920,424 at June 28, 2002.

The number of shares outstanding of the registrant's common stock, $5 par value, as of January 31, 2003 was 121,933,618 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Part III of this report incorporates by reference specific portions of the Registrant's Proxy Statement relating to its 2003 Annual Meeting of Stockholders.

KINDER MORGAN, INC. AND SUBSIDIARIES
CONTENTS

			Page Number
	PART I
Items 1 and 2:	Business and Properties		3-17
		Overview	5
		Natural Gas Pipeline Company Of America	6
		TransColorado Gas Transmission Company	8
		Kinder Morgan Retail	10
		Power and Other	11
		Regulation	13
		Environmental Regulation	15
		Risk Factors	15
Item 3:	Legal Proceedings		17
Item 4:	Submission of Matters to a Vote of Security Holders		18
	Executive Officers of the Registrant		18-20

	PART II

Item 5:	Market for Registrant's Common Equity and Related Stockholder
	Matters		21
Item 6:	Selected Financial Data		22-23
Item 7:	Management's Discussion and Analysis of Financial Condition and
	Results of Operations		24-54
		General	24
		Critical Accounting Policies and Estimates	26
		Consolidated Financial Results	29
		Results Of Operations	31
		Natural Gas Pipeline Company Of America	32
		TransColorado Pipeline	34
		Kinder Morgan Retail	35
		Power and Other	36
		Kinder Morgan Texas Pipeline	38
		Other Income and (Expenses)	38
		Income Taxes - Continuing Operations	39
		Discontinued Operations	39
		Liquidity and Capital Resources	40
		Cash Flows	42
		Litigation and Environmental	47
		Regulation	48
		Risk Management	48
		Recent Accounting Pronouncements	51
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk		55
Item 8:	Financial Statements and Supplementary Data		56-107
Item 9:	Changes in and Disagreements With Accountants on Accounting and
	Financial Disclosure		107

	PART III
Item 10:	Directors and Executive Officers of the Registrant		107-108
Item 11:	Executive Compensation		108
Item 12:	Security Ownership of Certain Beneficial Owners and Management
	and Related Stockholder Matters		108
Item 13:	Certain Relationships and Related Transactions		108
Item 14:	Controls and Procedures		108

	PART IV
Item 15:	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		108-113

Signatures			114
Certifications			115-116

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

PART I

Items 1. and 2. Business and Properties.

In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation, incorporated on May 18, 1927, formerly known as K N Energy, Inc.) and its consolidated subsidiaries. All volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute and at 60 degrees Fahrenheit and, in most instances, are rounded to the nearest major multiple. In this report, the term "MMcf" means million cubic feet, the term "Bcf" means billion cubic feet and the term "MMBtus" means million British Thermal Units ("Btus"). Natural gas liquids consist of ethane, propane, butane, iso-butane and natural gasoline. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes.

We make available free of charge on or through our Internet website, at http://www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

(A) General Development of Business

We are one of the largest energy storage and transportation companies in the United States, operating, either for ourselves or on behalf of Kinder Morgan Energy Partners, L.P., over 30,000 miles of natural gas and petroleum products pipelines. We own and operate (i) Natural Gas Pipeline Company of America, a major interstate natural gas pipeline system with approximately 9,700 miles of pipelines and associated storage facilities and (ii) TransColorado Gas Transmission Company, a 300-mile interstate natural gas pipeline in western Colorado and northwest New Mexico. We own interests in and operate a retail natural gas distribution business serving approximately 240,000 customers in Colorado, Nebraska and Wyoming. We have constructed, currently operate and, in some cases, own natural gas-fired electric generation facilities. These businesses are discussed in detail in the next section of this report. Our common stock is traded on the New York Stock Exchange under the symbol "KMI." Our executive offices are located at 500 Dallas, Suite 1000, Houston Texas 77002 and our telephone number is (713) 369-9000.

In addition to the businesses described above, we own the general partner of, and have a significant limited partner interest in, Kinder Morgan Energy Partners, the largest publicly traded pipeline limited partnership in the United States in terms of market capitalization and the owner and operator of the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Kinder Morgan Energy Partners owns and/or operates a diverse group of assets used in the transportation, storage and processing of energy products, including refined petroleum products pipeline systems with more than 10,000 miles of products pipeline and 32 associated terminals. Kinder Morgan Energy Partners owns over 15,000 miles of natural gas transportation pipelines, plus natural gas gathering and storage facilities. Kinder Morgan Energy Partners also owns or operates approximately 50 liquid and bulk terminal facilities and over 60 rail transloading facilities located throughout the United States, handling over 60 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 35 million barrels for refined petroleum products, chemicals and other liquid products. In addition, Kinder Morgan Energy Partners owns Kinder Morgan CO₂ Company, L.P., which transports, markets and produces carbon dioxide for use in enhanced oil recovery operations primarily in the Permian Basin of West Texas. Additional information concerning

the business of Kinder Morgan Energy Partners is contained in Kinder Morgan Energy Partners' 2002 Annual Report on Form 10-K.

In the initial public offering, 10 percent of Kinder Morgan Management's shares were purchased by us, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which is consolidated in our financial statements) purchased by the public created an additional minority interest on our balance sheet of $892.7 million at the time of the transaction. The earnings recorded by Kinder Morgan Management that are attributable to its shares held by the public are reported as "minority interest" in our consolidated statements of operations. On August 6, 2002, Kinder Morgan Management closed the issuance and sale of 12,478,900 limited liability shares in an underwritten public offering. The net proceeds of approximately $328.6 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. We did not purchase any of the offered shares. In addition, during 2002, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $3.4 million. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management's 2002 Annual Report on Form 10-K.

At December 31, 2002, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management, LLC we owned, approximately 31.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 13.0 million common units, 5.3 million Class B units and 13.5 million i-units, represent approximately 17.6 percent of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2 percent interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 19.2 percent of Kinder Morgan Energy Partners' total equity interests at December 31, 2002. We receive quarterly distributions on the i-units owned by Kinder Morgan Management in additional i-units and distributions on our other units in cash.

approximately 51% of all quarterly distributions made by Kinder Morgan Energy Partners, of which approximately 40% is attributable to our general partner interest and 11% is attributable to our limited partner interest. The actual level of distributions we will receive in the future will vary with the level of distributable cash determined in accordance with Kinder Morgan Energy Partners' partnership agreement.

We reflect our investment in Kinder Morgan Energy Partners under the equity method of accounting and, accordingly, report our share of Kinder Morgan Energy Partners' earnings as "Equity in Earnings" in our Consolidated Statement of Operations in the period in which such earnings are reported by Kinder Morgan Energy Partners.

On October 7, 1999, we completed the acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and the sole stockholder of the general partner of Kinder Morgan Energy Partners. To effect that acquisition, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan (Delaware). Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan (Delaware), was named our Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc.

(B) Financial Information about Segments

Note 20 of the accompanying Notes to Consolidated Financial Statements contains financial information about our business segments.

(C) Narrative Description of Business

Overview

We are an energy and related services provider. Our principal business segments are: (1) Natural Gas Pipeline Company of America and affiliated companies, a major interstate natural gas pipeline and storage system, (2) TransColorado Pipeline, an interstate natural gas pipeline located in western Colorado and northwest New Mexico, in which we increased our ownership interest from 50 percent to 100 percent effective October 1, 2002, (3) Kinder Morgan Retail, the regulated sale of natural gas to residential, commercial and industrial customers and non-utility sales of natural gas to certain utility customers under the Choice Gas Program, a program that allows utility customers to choose their natural gas provider and (4) Power and Other, the operation and, in prior periods, construction of natural gas-fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments. Natural gas transportation, storage and retail sales accounted for approximately 93%, 90% and 96% of our consolidated revenues in 2002, 2001 and 2000, respectively. The operations of Kinder Morgan Energy Partners, a significant limited partnership equity-method investee in which we also hold the general partner interest, include (i) liquids and refined petroleum products pipelines, (ii) transportation and storage of natural gas, (iii) carbon dioxide production and transportation and (iv) bulk and liquids terminals. Our equity in the earnings of Kinder Morgan Energy Partners, net of the associated amortization, constituted approximately 65%, 40% and 21% of our income from continuing operations before interest and income taxes in 2002, 2001 and 2000, respectively. The following table gives our segment earnings for each of the last two years, our earnings attributable to our investment in Kinder Morgan Energy Partners and the percent of the combined total each represents. As described in "Management's Discussion and Analysis of Financial Condition and Results of Operations", at December 31, 2000, we transferred certain assets to Kinder Morgan Energy Partners. In 1999, we discontinued our wholesale natural gas marketing, non-energy retail marketing services and natural gas gathering and processing businesses. Notes 5 and 20 of the accompanying Notes to Consolidated Financial Statements contain additional information on asset sales and our business

segments. As discussed following, certain of our operations are regulated by various federal and state entities.

	Year Ended December 31,
	2002		2001
	Amount	% of Total	Amount	% of Total
	(Dollars in thousands)
Investment in Kinder Morgan Energy Partners:
Equity in Earnings, Net of Kinder Morgan
Management, LLC Minority Interest	$338,504		$253,524
Amortization of Equity-method Goodwill	-		(25,644)
	338,504	41.70%	227,880	32.94%
Natural Gas Pipeline Company of America	359,911	44.33%	346,569	50.09%
TransColorado Pipeline	12,648	1.56%	(5,268)	(0.76%)
Kinder Morgan Retail	64,056	7.89%	56,696	8.19%
Power and Other	36,673	4.52%	65,983	9.54%
Total	$811,792	100.00%	$691,860	100.00%
	========	=======	========	=======

Natural Gas Pipeline Company of America

During 2002, Natural Gas Pipeline Company of America's segment earnings of $359.9 million represented 44% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 59% of our income from continuing operations before interest and income taxes. Through Natural Gas Pipeline Company of America we own and operate approximately 9,700 miles of interstate natural gas pipelines, storage fields, field system lines and related facilities, consisting primarily of two major interconnected natural gas transmission pipelines terminating in the Chicago metropolitan area. The system is powered by 57 compressor stations in mainline and storage service having an aggregate of approximately 0.8 million horsepower. Natural Gas Pipeline Company of America's system has over 1,700 points of interconnection with 34 interstate pipelines, 19 intrastate pipelines, a number of gathering systems, and over 60 local distribution companies and other end users, thereby providing significant flexibility in the receipt and delivery of natural gas. Natural Gas Pipeline Company of America's Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 3,900 miles of mainline and various small-diameter pipelines. The other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,400 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by Natural Gas Pipeline Company of America's approximately 700-mile Amarillo/Gulf Coast pipeline.

Natural Gas Pipeline Company of America provides transportation and storage services to third-party natural gas distribution utilities, marketers, producers, industrial end users and other shippers. Pursuant to transportation agreements and Federal Energy Regulatory Commission tariff provisions, Natural Gas Pipeline Company of America offers its customers firm and interruptible transportation, storage and no-notice services, and interruptible park and loan services. Under Natural Gas Pipeline Company of America's tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported, including a fuel charge collected in kind. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. Reservation and commodity charges are both based upon geographical location and time of year. Under firm no-notice service, customers pay a reservation charge for the right to have up to a specified volume of natural gas delivered but, unlike with firm transportation service, are able to meet their peaking requirements without making specific nominations. Natural Gas Pipeline Company of America has the authority to negotiate rates with customers as long as it has first offered service to those customers under its reservation and commodity charge rate structure. Natural Gas Pipeline Company of America's revenues have historically been higher in the first and fourth quarters of the year, reflecting higher

system utilization during the colder months. During the winter months, Natural Gas Pipeline Company of America collects higher transportation commodity revenue, higher interruptible transportation revenue, winter-only capacity revenue and higher peak rates on certain contracts.

Natural Gas Pipeline Company of America's principal delivery market area encompasses the states of Illinois, Indiana and Iowa and secondary markets in portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural Gas Pipeline Company of America is the largest transporter of natural gas to the Chicago market and we believe that its cost of service is very competitive in the region. In 2002, Natural Gas Pipeline Company of America delivered an average of 1.67 trillion Btus per day of natural gas to this market. Given its strategic location at the center of the North American pipeline grid, we believe that Chicago is likely to continue to be a major natural gas trading hub for the rapidly growing markets in the Midwest and Northeast.

Substantially all of Natural Gas Pipeline Company of America's pipeline capacity is committed under firm transportation contracts ranging from one to five years. Approximately 69% of the total transportation volume committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts in effect on January 1, 2003 had remaining terms of less than three years. Natural Gas Pipeline Company of America continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts. Nicor Gas Company, Peoples Gas Light and Coke Company, and Northern Indiana Public Service Company (NIPSCO) are Natural Gas Pipeline Company of America's three largest customers. Contracts representing 41% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 1, 2003 are scheduled to expire during 2003. As of February 18, 2003, 47% of Natural Gas Pipeline Company of America's long-term contracted firm transport capacity as of January 1, 2003 that was scheduled to expire during 2003 had been recontracted or terms had been agreed to for rollover with the same customers, and certain other of that capacity had been sold to other customers.

Natural Gas Pipeline Company of America is one of the nation's largest natural gas storage operators with approximately 600 Bcf of total natural gas storage capacity, 220 Bcf of working gas capacity and up to 4.0 Bcf per day of peak deliverability from its storage facilities, which are located near the markets it serves. Natural Gas Pipeline Company of America owns and operates eight underground storage fields in four states. These storage assets complement its pipeline facilities and allow it to optimize pipeline deliveries and meet peak delivery requirements in its principal markets. Natural Gas Pipeline Company of America provides firm and interruptible gas storage service pursuant to storage agreements and tariffs. Firm storage customers pay a monthly demand charge irrespective of actual volumes stored. Interruptible storage customers pay a monthly charge based upon actual volumes of gas stored.

Natural Gas Pipeline Company of America is a 50% joint venture partner in the Horizon Pipeline Company. Nicor-Horizon, a subsidiary of Nicor Inc. is the other joint venture partner. The Horizon Pipeline Company completed and placed into service its new $82 million natural gas pipeline in northern Illinois on May 11, 2002. This newly constructed pipeline is being operated by Natural Gas Pipeline Company of America as an interstate pipeline company under the authority of the Federal Energy Regulatory Commission. Horizon's natural gas pipeline consists of 28 miles of newly constructed 36-inch diameter pipe, the lease of capacity in 42 miles of existing pipeline from Natural Gas Pipeline Company of America, and newly installed natural gas compression facilities. Horizon Pipeline Company can transport up to 380 MMcf of natural gas per day from near Joliet into McHenry County in Illinois, connecting the emerging supply hub at Joliet with the northern part of the Nicor Gas distribution system and an existing Natural Gas Pipeline Company of America pipeline.

Natural Gas Pipeline Company of America completed and placed into service a lateral extension of its pipeline system from Centralia, Illinois to East St. Louis, Illinois in August 2002. This lateral extension

consists of approximately 50 miles of 24-inch pipeline with an initial capacity of approximately 300,000 MMBtus per day.

Competition: Natural Gas Pipeline Company of America competes with other transporters of natural gas in virtually all of the markets it serves and, in particular, in the Chicago area, which is the northern terminus of Natural Gas Pipeline Company of America's two major pipeline segments and its largest market. These competitors include both interstate and intrastate natural gas pipelines and, historically, most of the competition has been from such pipelines with supplies originating in the United States. In recent years, Natural Gas Pipeline Company of America has also faced competition from additional pipelines carrying Canadian produced natural gas into the Chicago market. The most recent example is the Alliance Pipeline, which began service during the 2000-2001 heating season. The additional pipeline capacity into the Chicago market has increased competition for transportation into the area while, at the same time, new pipelines, such as Vector Pipeline, have been constructed for the specific purpose of transporting gas from the Chicago area to other markets, generally further north and further east. The overall impact of the increased pipeline capacity into the Chicago area, combined with additional take-away capacity and the increased demand in the area, has created a situation that remains dynamic with respect to the ultimate impact on individual transporters such as Natural Gas Pipeline Company of America.

Natural Gas Pipeline Company of America also faces competition with respect to the natural gas storage services it provides. Natural Gas Pipeline Company of America has storage facilities in both market and supply areas, allowing it to offer varied storage services to customers. It faces competition from independent storage providers as well as storage services offered by other natural gas pipelines and local natural gas distribution companies.

The competition faced by Natural Gas Pipeline Company of America with respect to its natural gas transportation and storage services is generally price-based, although there is also a significant component related to the variety, flexibility and the reliability of services offered by others. Natural Gas Pipeline Company of America's extensive pipeline system, with access to diverse supply basins and significant storage assets in both the supply and market areas, causes it to be a strong competitor in many situations but customers still have alternative sources for their requirements. In addition, due to the price-based nature of much of the competition faced by Natural Gas Pipeline Company of America, its proven ability to be a low-cost provider is an important factor in its success in acquiring and retaining customers. Additional competition for storage services could result from the utilization of currently underutilized storage facilities or from conversion of existing storage facilities from one use to another. In addition, existing competitive storage facilities could, in some instances, be expanded.

TransColorado Gas Transmission Company

During 2002, TransColorado Gas Transmission Company's segment earnings of $12.6 million represented approximately 2% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 2% of our income from continuing operations before interest and income taxes. Through TransColorado Gas Transmission Company, referred to as TransColorado Pipeline, we own and operate approximately 300 miles of interstate natural gas pipelines on the Western Slope of Colorado and Northwestern New Mexico. The system is powered by 2 compressor stations in mainline service having an aggregate of approximately 10 thousand horsepower. TransColorado Pipeline's system, which extends from approximately 30 miles east of Meeker, Colorado to Bloomfield, New Mexico, has 17 points of interconnection with 5 interstate pipelines, 1 intrastate pipeline, 2 gathering systems, and 2 local distribution companies, thereby providing relatively significant flexibility in the receipt and delivery of natural gas. Gas flowing south through the pipeline moves onto the El Paso, Transwestern and Southern Trail pipeline systems. The

TransColorado Pipeline receives gas from two coal seam natural gas treating plants located in the San Juan Basin of Colorado and from pipeline and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. This pipeline was a 50/50 joint venture with Questar Corp. until we bought Questar's interest effective October 1, 2002, thus becoming the sole owner. As a result, our consolidated financial statements include TransColorado Pipeline's results as a 50/50 equity method investment prior to October 1, 2002 and on a 100% basis as a consolidated subsidiary thereafter.

TransColorado Pipeline provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers. Pursuant to transportation agreements and Federal Energy Regulatory Commission tariff provisions, TransColorado Pipeline offers its customers firm and interruptible transportation and interruptible park and loan services. Under TransColorado Pipeline's tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. The underlying reservation and commodity charges are assessed pursuant to a "postage stamp" maximum recourse rate structure. TransColorado Pipeline has the authority to negotiate rates with customers as long as it has first offered service to those customers under its reservation and commodity charge rate structure. TransColorado Pipeline's revenues have historically been higher during the second and third quarters of the year, resulting from two factors: (i) winter heating market loads to the north of TransColorado Pipeline and (ii) summer air conditioning market loads to the south of TransColorado Pipeline.

TransColorado Pipeline acts principally as a feeder pipeline system from the developing natural gas supply basins on the Western Slope of Colorado into the interstate natural gas pipelines that lead away from the Blanco Hub area of New Mexico. TransColorado Pipeline is the largest transporter of natural gas from the Western Slope supply basins of Colorado and provides a competitively attractive outlet for that developing natural gas resource. In 2002, TransColorado Pipeline transported an average of 420 billion Btus per day of natural gas from these supply basins. TransColorado Pipeline provides a strategically important link between the underdeveloped gas supply resources on the Western Slope of Colorado and the greater southwestern United States marketplace.

TransColorado Pipeline's pipeline capacity is currently fully subscribed through October of 2004. Beyond October of 2004, approximately 80% of TransColorado Pipeline's pipeline capacity is committed under firm transportation contracts that extend through year-end 2007. TransColorado Pipeline is actively pursuing full contract subscription through 2007 and beyond.

On January 21, 2003, we announced the start of an open season seeking shipper interest for a proposal to expand capacity on the TransColorado Pipeline system. This expansion project would include additional compression and line-looping infrastructure to increase capacity on the existing TransColorado Pipeline mainline, which currently has capacity of approximately 300,000 Dekatherms per day, by as much as 150,000 Dekatherms per day. As part of this open season, we are also seeking shipper support for an extension of the TransColorado Pipeline system with a capacity of 750,000 Dekatherms per day. As designed, this 36-inch diameter pipeline would extend from TransColorado Pipeline's existing southern terminus in the Blanco Hub area to a point near Window Rock in Apache County, Arizona, where it would connect to Kinder Morgan Energy Partners' proposed Silver Canyon Pipeline. This proposed extension would also provide new interconnects with El Paso Natural Gas Company and Transwestern Pipeline Company. Whether or not either or both expansions are actually built will depend on a number of factors, including shipper support. We will not build either project in the absence of firm contracts to support the capital expenditures.

Competition: TransColorado Pipeline competes with other transporters of natural gas in each of the natural gas supply basins it serves. These competitors include both interstate and intrastate natural gas

pipelines and natural gas gathering systems. TransColorado Pipeline is the most recent interstate pipeline entrant into each of the competitive supply markets of the Paradox, Piceance and San Juan Basins of western Colorado. Notwithstanding, we believe that TransColorado Pipeline generally is looked upon favorably by shippers because it provides distinct advantages of larger system capacity and more direct access to market outlet than its competitors.

TransColorado Pipeline's shippers compete for market share with shippers drawing upon gas production facilities within the New Mexico portion of the San Juan Basin. TransColorado Pipeline has phased its past construction and expansion efforts to coincide with the ability of the interstate pipeline grid at Blanco, New Mexico to accommodate greater natural gas volumes. The overall San Juan Basin gas production base had been a perennial factor restricting the growth pace of TransColorado Pipeline's transport from the central Rockies natural gas supply basins. The San Juan Basin enjoyed prolific natural gas production growth related to coal seam gas development during the 1990's that hampered TransColorado Pipeline's ability to implement its full project before 1999. Natural gas production from the San Juan Basin peaked during the first quarter of 2000 and has since declined on an overall basis by 10%. TransColorado Pipeline's transport concurrently ramped up over that period such that TransColorado Pipeline now enjoys a growing share of the outlet from the San Juan Basin to the southwestern United States marketplace.

Historically, the competition faced by TransColorado Pipeline with respect to its natural gas transportation services has generally been based upon the price differential between the San Juan and Rocky Mountain basins. The pending Kern River Gas Transmission expansion project slated for completion during the secondquarter of 2003 is generally anticipated to reduce that price differential. However, given the increased number of direct connections to production facilities in the Piceance and Paradox basins and the aggressive gas supply development in each of those basins, we believe that TransColorado Pipeline's transport business will be less susceptible to changes in the price differential in the future.

Kinder Morgan Retail

During 2002, Kinder Morgan Retail's segment earnings of $64.1 million represented 8% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 11% of our income from continuing operations before interest and income taxes. As of December 31, 2002, through Kinder Morgan Retail, our retail natural gas distribution business served approximately 240,000 customers in Colorado, Nebraska and Wyoming through more than 10,500 miles of distribution and transmission pipelines, underground storage fields, field system lines and related facilities. Our intrastate pipelines, distribution facilities and retail natural gas sales in Colorado and Wyoming are subject to the regulatory authority of each state's utility commission. In Nebraska, retail natural gas sales rates for residential and small commercial customers are regulated by each municipality served.

Kinder Morgan Retail's operations in Nebraska, Wyoming and northeastern Colorado serve areas that are primarily rural and agricultural where natural gas is used primarily for space heating, crop irrigation, grain drying and processing of agricultural products. In much of Nebraska, the winter heating load is balanced by irrigation requirements in the summer and grain drying requirements in the fall. Kinder Morgan Retail's operations in western Colorado serve the fast-growing resort and associated service areas, and rural communities. These areas are characterized primarily by natural gas use for space heating, with historical annual growth rates of 6-8%. Kinder Morgan Retail operations include non-jurisdictional products and services, including the sale of natural gas in Kinder Morgan Retail's Choice Gas programs and natural gas-related equipment and services.

To support Kinder Morgan Retail's business, underground storage facilities are used to provide natural gas for load balancing and peak system demand. Storage services for Kinder Morgan Retail's natural gas distribution services are provided by (i) three facilities in Wyoming owned by Kinder Morgan, Inc., (ii) one facility in Colorado owned by Rocky Mountain Natural Gas Company, a wholly owned subsidiary of Kinder Morgan, Inc. and (iii) one facility located in Nebraska, which is owned by Kinder Morgan Energy Partners. The peak natural gas withdrawal capacity available for Kinder Morgan Retail's business is approximately 83 MMcf per day.

Kinder Morgan Retail's natural gas distribution business relies on both the intrastate pipelines it operates and third-party pipelines for transportation and storage services required to serve its markets. The natural gas supply requirements for Kinder Morgan Retail's natural gas distribution business are met through contract purchases from third-party suppliers.

Through Rocky Mountain Natural Gas Company in Colorado, Kinder Morgan Retail provides transportation services to natural gas producers, shippers and industrial customers. Kinder Morgan Retail provides storage services in Wyoming to its customers from its three storage fields, Oil Springs, Bunker Hill and Kirk Ranch, which combined have 29.7 Bcf of total storage capacity, 11.7 Bcf of working gas capacity, and up to 37 MMcf per day of peak withdrawal capacity. Rocky Mountain Natural Gas Company operates the Wolf Creek storage facility, which has 10.1 Bcf of total storage capacity, 2.7 Bcf of working gas capacity and provides 18 MMcf per day of withdrawal capacity for peak day use by its sales customers in Colorado.

Competition: The Kinder Morgan Retail natural gas distribution business segment operates in areas with varying service area rules, including state utility commission exclusively certificated service areas, non-exclusive municipal franchises and competitive areas. Limited competitive natural gas distribution pipelines exist within these service areas. The primary competition for Kinder Morgan Retail's products is from alternative fuels such as electric power and propane for heating use, and electric power, propane and diesel fuel for agriculture use. Kinder Morgan Retail provides natural gas utility services based upon cost-of-service regulation in most of its service areas.

Kinder Morgan Retail currently provides unbundled natural gas services in Nebraska and Wyoming under Choice Gas Programs. The Choice Gas Program allows competing commodity natural gas providers to sell natural gas to approximately 70% of its total customers at present. In the unbundled areas, Kinder Morgan Retail competes as one of four or five natural gas marketing companies to provide the customer with natural gas commodity offerings. Kinder Morgan Retail currently provides the natural gas commodity for 66% of the end use customers in the unbundled areas.

Power and Other

Power and Other's 2002 earnings before a charge to reduce the carrying value of certain of its assets represented less than 5% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 6% of our income from continuing operations before interest and income taxes. Kinder Morgan Power has designed, developed and constructed power projects and currently operates electric generation facilities as an independent power producer. Kinder Morgan Power is, primarily, a fee-for-service business that developed power projects for the benefit of long-term, off-take customers. These customers take the commodity benefits and risks in the marketplace and have paid Kinder Morgan Power a fee for developing and constructing and, in one case, a customer currently pays Kinder Morgan Power a fee for operating these facilities. Kinder Morgan Power's customers include power marketers, power generation companies and utilities. Kinder Morgan has decided to cease its power development activities as discussed following.

In 1998, Kinder Morgan Power acquired interests in the Thermo Companies, which provided us with our first electric generation assets as well as knowledge and expertise with General Electric Company jet engines (LMs) configured in a combined cycle mode. Through the Thermo Companies, Kinder Morgan Power has interests in three independent natural gas-fired LM projects in Colorado with an aggregate of 380 megawatts of electric generation capacity. Kinder Morgan Power used the LM knowledge to develop its proprietary "Orion" technology. We expect to make an additional investment in the Thermo Companies in 2003 as discussed under "Power and Other" within "Management's Discussion and Analysis of Financial Condition and Results of Operations."

In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant southeast of Little Rock, Arkansas, utilizing Kinder Morgan Power's Orion technology. Effective July 1, 2002, construction and testing of the 550-megawatt Wrightsville, Arkansas power generation facility were completed by Kinder Morgan Power and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville power facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Kinder Morgan Power has an investment in the project company, comprised primarily of preferred stock. Kinder Morgan Power expects to invest approximately $12 million in the Wrightsville power facility, during the first half of 2003, to meet its original equity commitment to the project and for operating cash deficiencies. Natural gas transportation service for the plant is provided by Natural Gas Pipeline Company of America.

On February 20, 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading agreed to supply natural gas to and market capacity for 16 years for a 550-megawatt natural gas-fired Orion technology electric power plant in Jackson, Michigan. Effective July 1, 2002, construction and testing of the Jackson, Michigan 550-megawatt power generation facility were completed by Kinder Morgan Power and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power Company made a preferred investment in Triton Power Company LLC valued at approximately $105 million; (ii) Triton Power Company LLC, through its wholly owned subsidiary, Triton Power Michigan LLC, entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC, and (iii) we received full payment of our $104.4 million construction note receivable. Williams Energy Marketing and Trading supplies all natural gas to and purchases all power from the power plant under a 16-year tolling agreement with Triton Power Michigan LLC.

Competition: During the period in which Kinder Morgan Power was developing natural gas-fired power generation facilities, its competitors were other companies that developed and constructed similar

facilities. Currently, with respect to the Thermo entities, Kinder Morgan Power does not directly face competition with respect to the sale of the power generated, as it is sold to the local electric utility under long-term contracts. With respect to its investments in the Jackson, Michigan and Wrightsville, Arkansas facilities, the principal impacts of competition are on the profitability of the facility, generally affecting the seller of the power being generated. To the extent that these parties are affected by competition from other sellers of power in their market areas, however, the value of our investment could also be affected.

Regulation

Interstate Transportation and Storage Services

Under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy Act of 1978, the Federal Energy Regulatory Commission regulates both the performance of interstate transportation and storage services by interstate natural gas pipeline companies, and the rates charged for such services. As used in this report, FERC refers to the Federal Energy Regulatory Commission.

With the adoption of FERC Order No. 636, the FERC required interstate natural gas pipelines that perform open access transportation under blanket certificates to "unbundle" or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies, whether such natural gas is purchased from the pipeline or from other merchants such as marketers or producers. Each interstate natural gas pipeline must now separately state the applicable rates for each unbundled service.

We are also subject to the requirements of FERC Order Nos. 497, et seq., and 566, et. seq., the Marketing Affiliate Rules, which prohibit preferential treatment by an interstate natural gas pipeline of its marketing affiliates and govern, in particular, the provision of information by an interstate natural gas pipeline to its marketing affiliates. On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10 in which it proposed new rules governing the interaction between an interstate gas pipeline and its affiliates. If adopted as proposed, the Notice of Proposed Rulemaking could be read to limit communication between our interstate pipeline businesses, including Natural Gas Pipeline Company of America and TransColorado Gas Transmission Company, and their affiliates. The Notice could also be read to require separate staffing of our interstate pipeline businesses and their affiliates, which, if applied, could significantly increase costs for these functions. On December 20, 2001, Natural Gas Pipeline Company of America and Kinder Morgan Interstate Gas Transmission LLC, as well as numerous other parties, jointly submitted their comments on the Notice of Proposed Rulemaking. In May 2002, the FERC held a technical conference on the proposed rulemaking. The FERC to date has not acted on the proposal.

The Pipeline Safety Improvement Act of 2002 was signed into law on December 17, 2002, providing guidelines in the areas of testing, education, training and communication. The Act requires pipeline companies to perform integrity tests on pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within 10 years of the date of enactment and must perform subsequent integrity tests on a seven year cycle. At least 50 percent of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing will consist of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition, within one year of the law's enactment, pipeline companies must implement a qualification program to make certain that employees are properly trained, using criteria the U.S. Department of Transportation is responsible for providing. Natural Gas Pipeline Company of America

estimates that the average annual incremental expenditure associated with the Pipeline Safety Improvement Act of 2002 will be approximately $8 million to $10 million dollars.

Intrastate Transportation and Sales

We operate an intrastate pipeline in Colorado, Rocky Mountain Natural Gas Company, which is regulated by the Colorado Public Utilities Commission as a public utility in regard to its natural gas transportation and sales services within the state. Rocky Mountain also performs certain natural gas transportation services in interstate commerce pursuant to Section 311 of the Natural Gas Policy Act of 1978. The Colorado Public Utilities Commission regulates the rates, terms, and conditions of natural gas sales and transportation services performed by public utilities in the state of Colorado.

During 2002 our intrastate pipeline in Wyoming, Northern Gas Company, was merged into Kinder Morgan, Inc. and is now operated as part of our retail distribution business in Wyoming pursuant to approvals received from the Wyoming Public Service Commission.

The operations of our intrastate pipeline business are affected by FERC rules and regulations issued pursuant to the Natural Gas Act and the Natural Gas Policy Act. Of particular importance are regulations that allow increased ability to provide interstate transportation services without the necessity of obtaining prior FERC authorization for each transaction. A key element of the program is nondiscriminatory access, under which a regulated pipeline must agree, under certain conditions, to transport natural gas for any party requesting such service.

Retail Natural Gas Distribution Services

Our intrastate pipelines and local natural gas distribution businesses in Colorado and Wyoming are under the regulatory authority of each respective state's utility commission. In Nebraska, retail natural gas sales rates for residential and small commercial customers are regulated by the municipality served.

In certain of the incorporated communities in which we provide retail natural gas services, we operate under franchises granted by the applicable municipal authorities. The duration of these franchises varies. In unincorporated areas, our natural gas utility services are not subject to municipal franchise. We have been issued various certificates of public convenience and necessity by the regulatory commissions in Colorado and Wyoming authorizing us to provide natural gas utility services within certain incorporated and unincorporated areas of those states.

We emerged as a leader in providing for customer choice in early 1996, when the Wyoming Public Service Commission issued an order allowing us to bring competition to 10,500 residential and commercial customers. In November 1997, we announced a similar plan to give residential and small commercial customers in Nebraska a choice of natural gas suppliers. This program, the Nebraska Choice Gas program, became effective June 1, 1998. As of December 31, 2002, the plan had been adopted by 178 of 181 communities, representing approximately 91,000 customers served by us in Nebraska. Effective June 1, 2002 the Choice Gas program was extended to all Wyoming end use customers, subject to further review by the Wyoming Public Service Commission. The programs have succeeded in providing a choice of suppliers, competitive prices, and new products and services, while maintaining reliability and security of supply. Kinder Morgan Retail continues to provide all services other than the natural gas commodity supply in these programs, and competes with other suppliers in offering nonregulated natural gas supplies to retail customers.

Environmental Regulation

Our operations and properties are subject to extensive and evolving federal, state and local laws and regulations governing the release or discharge of regulated materials into the environment or otherwise relating to environmental protection or human health and safety. We have an environmental compliance program, and we believe that our operations are in substantial compliance with applicable environmental laws and regulations. This program focuses on compliance with state and federal regulations relating to the Clean Air Act, the Clean Water Act, RCRA and solid waste issues and other related and applicable environmental regulations. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often costly to comply with and onerous. Failure to comply with applicable environmental laws may result in substantial administrative, civil, and criminal penalties or injunctions that would restrict operations or require future compliance, damage awards against the Company, or other mandatory or consensual measures or liabilities. These laws and regulations can also impose liability for remedial costs on the owner or operator of properties or the generators of materials, regardless of fault. Moreover, a trend in environmental law is towards stricter standards, stricter enforcement, and more restrictions on operations. This trend and other developments in environmental law may result in significant cost and liabilities for us.

We had an established environmental reserve at December 31, 2002 of approximately $15.5 million, to address remediation issues associated with approximately 35 projects. These projects include several ground water and soil hydrocarbon remediation efforts under the jurisdiction and direction of various state agencies. Many of these remediation efforts are the result of historic releases from non-operating sites. Additionally, we are addressing impacts at several locations from the historic use of mercury and polychlorinated biphenyls. We believe that costs for environmental remediation and separately ongoing compliance with applicable environmental regulations will not have a material adverse effect on our cash flows, financial position or results of operations or materially diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, the discovery of circumstances or conditions currently unforeseen by us, or that the development of new facts or conditions will not cause us to incur significant unanticipated costs and liabilities.

Risk Factors

We are highly dependent upon the earnings and distributions of Kinder Morgan Energy Partners. For 2002, approximately 65% of our income from continuing operations before interest and income taxes was attributable to our general and limited partner interests in Kinder Morgan Energy Partners (before reduction for the minority interest in Kinder Morgan Management). A significant decline in Kinder Morgan Energy Partners' earnings and/or cash distributions would have a corresponding negative impact on us. For more information on the earnings and cash distributions, please see Kinder Morgan Energy Partners' 2002 Annual Report on Form 10-K.

Competition could ultimately lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation capacity at favorable rates. For 2002, approximately 59% of our income from continuing operations before interest and income taxes was attributable to the results of operations of Natural Gas Pipeline Company of America, an interstate pipeline that is a major supplier to the Chicago, Illinois area. In recent periods, interstate pipeline competitors of Natural Gas Pipeline Company of America have constructed or expanded pipeline capacity into the Chicago area, although additional take-away capacity has also been constructed. To the extent that an excess of supply into this market area is created and persists, Natural Gas Pipeline Company of America's ability to recontract for expiring transportation capacity at favorable rates could be impaired. Contracts representing 41% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 1, 2003 are scheduled to expire during 2003.

3.	Our large amount of floating rate debt makes us vulnerable to increases in interest rates. At December 31, 2002, we had approximately $1.75 billion of debt subject to floating interest rates. Should interest rates increase significantly, our earnings would be adversely affected.

4.	The rates we charge shippers on our pipeline systems are subject to regulatory approval and oversight. While there are currently no material proceedings challenging the rates on any of our pipeline systems, regulators and shippers on these pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. We can provide no assurance that we will not face challenges to the rates we receive on our pipeline systems in the future.
5.	Sustained periods of weather inconsistent with normal in areas served by our natural gas transportation and distribution operations can create volatility in our earnings. Weather-related factors such as temperature and rainfall at certain times of the year affect our earnings in our natural gas transportation and retail natural gas distribution businesses. Sustained periods of temperatures and rainfall that differ from normal can create volatility in our earnings.
6.	Proposed rulemaking by the Federal Energy Regulatory Commission or other regulatory agencies having jurisdiction could adversely impact our income and operations. For example, on September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10. The proposed rule would expand the FERC's current standards of conduct to include a regulated transmission provider and all of its energy affiliates. It is not known whether the FERC will issue a final rule in this docket and, if it does, whether as a result we could incur increased costs and increased difficulty in our operations. Generally speaking, new regulations or different interpretations of existing regulations applicable to our assets could have a negative impact on our business, financial condition and results of operations.
7.	Environmental regulation and liabilities could result in increased operating and capital costs. Our business operations are subject to federal, state and local laws and regulations relating to environmental protection, pollution and human health and safety. For example, if an accidental leak or spill occurs from our pipelines or at our storage or other facilities, we may have to pay a significant amount to clean up the leak or spill, pay for government penalties, address natural resource damages, compensate for human exposure, install costly pollution control equipment, or a combination of these and other measures. The resulting costs and liabilities could negatively affect our level of earnings and cash flow. In addition, emission controls required under federal and state environmental laws could require significant capital expenditures at our facilities. The impact of environmental standards or future environmental measures could increase our costs significantly. Since the costs of environmental regulation are already significant, additional or stricter regulation or enforcement could negatively affect our business. We own or operate numerous properties that have been used for many years in connection with pipeline activities. While we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been released on our properties or on other properties where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose management and disposal of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws such as the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, which impose joint and several liability without regard to fault or the legality of the original conduct. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

The distressed financial condition of some of our customers could have an adverse impact on us in the event these customers are unable to pay us for the services we provide. Some of our customers are experiencing severe financial problems. The bankruptcy of one or more of them, or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

Increased regulatory requirements relating to the integrity of our pipelines will require us to spend additional money to comply with these requirements. Through our regulated pipeline subsidiaries, we are subject to extensive laws and regulations related to pipeline integrity. For example, recent federal legislation signed into law in December 2002 includes new guidelines for the U.S. Department of Transportation and pipeline companies in the areas of testing, education, training and communication. Compliance with existing and recently executed regulations requires significant expenditures. Additional laws and regulations that may be enacted in the future could significantly increase the amount of these expenditures.

Other

Amounts we spent during 2002, 2001, and 2000 on research and development activities were not material. We employed 5,390 people at December 31, 2002, including employees of our indirect subsidiary KMGP Services Company, Inc., who are dedicated to the operations of Kinder Morgan Energy Partners.

We are of the opinion that we generally have satisfactory title to the properties owned and used in our businesses, subject to the liens for current taxes, liens incidental to minor encumbrances, and easements and restrictions which do not materially detract from the value of such property or the interests therein or the use of the properties in our businesses. We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people's land for a period of time.

(D) Financial Information About Geographic Areas

All but an insignificant amount of our assets and operations are located in the continental United States of America.

Item 3.

Legal Proceedings.

The reader is directed to Note 10(B) of the accompanying Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Item 4.

Submission of Matters to a Vote of Security Holders

None

Executive Officers of the Registrant

(A) Identification and Business Experience of Executive Officers

Set forth below is certain information concerning our executive officers. All officers serve at the discretion of the board of directors.

Name	Age	Position
Richard D. Kinder	58	Director, Chairman and Chief Executive Officer
Michael C. Morgan	34	Director and President
C. Park Shaper	34	Vice President, Treasurer and Chief Financial Officer
David D. Kinder	28	Vice President, Corporate Development
Joseph Listengart	34	Vice President, General Counsel and Secretary
Deborah A. Macdonald	51	President, Natural Gas Pipelines
James E. Street	46	Vice President, Human Resources and Administration
Daniel E. Watson	44	President, Retail

Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder is also a director of Baker Hughes Incorporated. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc.

Michael C. Morgan is President of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Morgan was elected to each of these positions in July 2001. He was also elected Director of Kinder Morgan, Inc. in January 2003. Mr. Morgan served as Vice President - Strategy and Investor Relations of Kinder Morgan Management, LLC from February 2001 to July 2001. He served as Vice President - - Strategy and Investor Relations of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. from January 2000 to July 2001. He served as Vice President - Corporate Development of Kinder Morgan G.P., Inc. from February 1997 to January 2000. Mr. Morgan was the Vice President, Corporate Development of Kinder Morgan, Inc. from October 1999 to January 2000. From August 1995 until February 1997, Mr. Morgan was an associate with McKinsey & Company, an international management consulting firm. In 1995, Mr. Morgan received a Masters in Business Administration from the Harvard Business School. From March 1991 to June 1993, Mr. Morgan held various positions, including Assistant to the Chairman, at PSI Energy, Inc. Mr. Morgan received a Bachelor of Arts in Economics and a Masters of Arts in Sociology from Stanford University in 1990.

C. Park Shaper is Director, Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and Vice President, Treasurer and Chief Financial Officer of Kinder Morgan, Inc. Mr. Shaper was elected Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its formation in February 2001. He has served as Treasurer of Kinder Morgan, Inc. since April 2000 and Vice President and Chief Financial Officer of Kinder Morgan, Inc. since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000. From June 1999 to December 1999, Mr. Shaper was President and Director of Altair Corporation, an enterprise focused on the distribution of web-based investment research for the financial services industry. He served as Vice President and Chief Financial Officer of First Data Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997 to June 1999. From 1995 to 1997, he was a consultant with The Boston Consulting Group. He received a Masters of Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University.

David D. Kinder is Vice President, Corporate Development of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Kinder was elected Vice President, Corporate Development of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. in October 2002. He served as manager of corporate development for Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. from January 2000 to October 2002. He served as an associate in the corporate development group of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. from February 1999 to January 2000. From June 1996 to February 1999, Mr. Kinder was in the analyst and associate program at Enron Corp. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.

Joseph Listengart is Vice President, General Counsel and Secretary of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of Kinder Morgan, Inc. in October 1999. Mr. Listengart was elected Kinder Morgan G.P., Inc.'s Secretary in November 1998 and became an employee of Kinder Morgan G.P., Inc. in March 1998. From March 1995 through February 1998, Mr. Listengart worked as an attorney for Hutchins, Wheeler & Dittmar, a Professional Corporation. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990.

Deborah A. Macdonald is President, Natural Gas Pipelines of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. She was elected as President, Natural Gas Pipelines in June 2002. She also holds the title of President of Natural Gas Pipeline Company of America, Kinder Morgan, Inc.'s largest subsidiary. Ms. Macdonald has served as President of Natural Gas Pipeline Company of America since the merger of Kinder Morgan, Inc. in October 1999. Prior to joining Kinder Morgan, Ms. Macdonald worked as Senior Vice President of legal affairs for Aquila Energy Company from January 1999 to October 1999, and was engaged in a private energy consulting practice from June 1996 to December 1999. Ms. Macdonald received her Juris Doctor, summa cum laude, from Creighton University in May 1980 and received a Bachelors degree, magna cum laude, from Creighton University in December 1972.

James E. Street is Vice President, Human Resources and Administration of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in August 1999. From October 1996 to August 1999, Mr. Street was Senior Vice President, Human Resources and Administration for Coral Energy, a subsidiary of Shell Oil Company. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.

Daniel E. Watson is President, Retail for Kinder Morgan, Inc. Mr. Watson was elected President, Retail in October 1999. Mr. Watson also holds the title of President of Rocky Mountain Natural Gas Company, a Kinder Morgan, Inc. subsidiary. He has served as President, Rocky Mountain Natural Gas Company since October 1999. Between October 1999 and June 2002, Mr. Watson served as President of Northern Gas Company, another Kinder Morgan, Inc. subsidiary prior to its merger into Kinder Morgan, Inc. Prior to our acquisition of Kinder Morgan (Delaware), Inc. Mr. Watson held the position of Group Vice President and General Manager for our gas distribution and intrastate pipelines from April 1997 to October 1999. From July 1990 to April 1997 he held various natural gas supply and marketing positions for us. Mr. Watson received a Bachelor of Science degree in Geological Engineering in December, 1979, and a Bachelor of Science degree in Mining Engineering in May 1980, from the South Dakota School of Mines and Technology.

(B) Involvement in Certain Legal Proceedings

None.

PART II

Item 5.

Market for Registrant's Common Equity and Related Stockholder Matters

Our common stock is listed for trading on the New York Stock Exchange under the symbol "KMI." Dividends paid and the price range of our common stock by quarter for the last two years are provided below.

Market Price Per Share Data


2002

2001


Low

High

Low

High

   Quarter Ended:

      March 31
$36.810

$57.500

$42.875

$60.000

      June 30
$37.110

$52.620

$50.250

$59.970

      September 30
$33.100

$44.020

$46.220

$57.570

      December 31
$30.050

$42.980

$46.950

$57.130




Dividends Paid Per Share

2002

2001

   Quarter Ended:

      March 31
$0.05

$0.05

      June 30
$0.05

$0.05

      September 30
$0.10

$0.05

      December 31
$0.10

$0.05



   Stockholders of Record as of January 31, 2003
38,600 (approximately)

There were no sales of unregistered equity securities during the period covered by this report.

Item 6.

Selected Financial Data

Five-Year Review
Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2002	2001	2000	1999¹	1998²
	(In thousands except per share amounts)
Operating Revenues	$1,015,255	$1,054,907	$2,678,956	$1,834,094	$1,659,171
Gas Purchases and Other Costs of Sales	311,224	339,301	1,925,971	1,052,654	833,427
Gross Margin	704,031	715,606	752,985	781,440	825,744
Other Operating Expenses	467,364³	331,287	357,842	485,738	430,052
Operating Income	236,667	384,319	395,143	295,702	395,692
Other Income and (Expenses)⁴	208,412	22,917	(87,977)	(81,151)	(172,787)
Income From Continuing Operations Before Income Taxes	445,079	407,236	307,166	214,551	222,905
Income Taxes	135,912	168,601	123,017	79,124	82,710
Income From Continuing Operations	309,167	238,635	184,149	135,427	140,195
Loss From Discontinued Operations, Net of Tax	(4,986)	-	(31,734)	(395,319)	(77,984)
Income (Loss) Before Extraordinary Item	304,181	238,635	152,415	(259,892)	62,211
Extraordinary Item - Loss on Early
Extinguishment of Debt, Net of Income Taxes	(1,456)	(13,565)	-	-	-
Net Income (Loss)	302,725	225,070	152,415	(259,892)	62,211
Less-Preferred Dividends	-	-	-	129	350
Less-Premium Paid on Preferred Stock Redemption	-	-	-	350	-
Earnings (Loss) Available for Common Stock	$ 302,725	$ 225,070	$ 152,415	$ (260,371)	$ 61,861
	==========	==========	==========	==========	==========

Basic Earnings (Loss) Per Common Share:
Continuing Operations	$ 2.53	$ 2.07	$ 1.62	$ 1.68	$ 2.19
Discontinued Operations	(0.04)	-	(0.28)	(4.92)	(1.22)
Extraordinary Item - Loss on Early Extinguishment of Debt	(0.01)	(0.12)	-	-	-
Total Basic Earnings (Loss) Per Common Share	$ 2.48	$ 1.95	$ 1.34	$ (3.24)	$ 0.97
	==========	==========	==========	==========	==========

Number of Shares Used in Computing Basic Earnings (Loss) Per Common Share	122,184	115,243	114,063	80,284	64,021
	==========	==========	==========	==========	==========

Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$ 2.50	$ 1.97	$ 1.61	$ 1.68	$ 2.17
Discontinued Operations	(0.04)	-	(0.28)	(4.92)	(1.21)
Extraordinary Item - Loss on Early Extinguishment of Debt	(0.01)	(0.11)	-	-	-
Total Diluted Earnings (Loss) Per Common Share	$ 2.45	$ 1.86	$ 1.33	$ (3.24)	$ 0.96
	==========	==========	==========	==========	==========

Number of Shares Used in Computing Diluted Earnings (Loss) Per Common Share	123,402	121,326	115,030	80,358	64,636
	==========	==========	==========	==========	==========

Dividends Per Common Share	$ 0.30	$ 0.20	$ 0.20	$ 0.65	$ 0.76
	==========	==========	==========	==========	==========

Capital Expenditures⁵	$ 174,953	$ 124,171	$ 85,654	$ 92,841	$ 120,881
	==========	==========	==========	==========	==========

¹	Reflects the acquisition of Kinder Morgan (Delaware), Inc. on October 7, 1999.
²	Reflects the acquisition of MidCon Corp. on January 30, 1998.
³	Includes a $135.4 million charge to reduce the carrying value of power assets; see Note 6 of the accompanying Notes to Consolidated Financial Statements.
⁴	Includes significant impacts from sales of assets. See Note 1 (O) of the accompanying Notes to Consolidated Financial Statements.
⁵	Capital Expenditures shown are for continuing operations only.

Five-Year Review (Continued)
Kinder Morgan, Inc. and Subsidiaries

	As of December 31,
	2002		2001		2000		1999		1998
	(In thousands except per share amounts)
Total Assets	$10,102,750		$9,513,121		$8,396,678		$9,393,834		$9,623,779
	===========		==========		==========		==========		==========

Capitalization:
Common Equity	$ 2,354,997	37%	$2,259,997	39%	$1,777,624	39%	$1,649,615	32%	$1,219,043	25%
Preferred Stock	-	-	-	-	-	-	-	-	7,000	-
Preferred Capital
Trust Securities	275,000	4%	275,000	5%	275,000	6%	275,000	5%	275,000	6%
Minority Interests	967,802	15%	817,513	14%	4,910	-	9,523	-	63,354	1%
Long-term Debt¹	2,852,181	44%	2,409,798	42%	2,478,983	55%	3,293,326	63%	3,300,025	68%
Total Capitalization	$ 6,449,980	100%	$5,762,308	100%	$4,536,517	100%	$5,227,464	100%	$4,864,422	100%
	===========	===	==========	===	==========	===	==========	===	==========	===

Book Value Per
Common Share	$ 19.35		$ 18.24		$ 15.53		$ 14.64		$ 17.77
	===========		==========		==========		==========		==========

Excluding the market value of interest rate swaps. See Note 15 of the accompanying Notes to Consolidated Financial Statements.

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, referred to in the following discussion as "SFAS 142." SFAS 142, which superceded Accounting Principles Board Opinion No. 17, Intangible Assets, addresses financial accounting and reporting for (1) intangible assets acquired individually or with a group of other assets (but not those acquired in a business combination) at acquisition and (2) goodwill and other intangible assets subsequent to their acquisition. SFAS 142 is required to be applied starting with fiscal years beginning after December 15, 2001. We adopted SFAS 142 effective January 1, 2002.

Had the provisions of SFAS 142 been in effect during the periods prior to January 1, 2002 presented above, goodwill amortization would have been eliminated, increasing net income and associated per share amounts as follows:

	Year Ended December 31,
	2002	2001	2000	1999	1998
	(In thousands, except per share amounts)
Reported Income (Loss) Before Extraordinary Item	$304,181	$238,635	$152,415	$(259,892)	$ 62,211
Add Back: Goodwill Amortization,
Net of Related Tax Benefit	-	16,198	17,368	5,449	292
Adjusted Income (Loss) Before Extraordinary Item	304,181	254,833	169,783	(254,443)	62,503
Extraordinary Item	(1,456)	(13,565)	-	-	-
Adjusted Net Income (Loss)	$302,725	$241,268	$169,783	$(254,443)	$ 62,503
	========	========	========	=========	========
Reported Earnings per Diluted Share	$ 2.45	$ 1.86	$ 1.33	$ (3.24)	$ 0.96
	========	========	========	=========	========
Earnings per Diluted Share, as Adjusted	$ 2.45	$ 1.99	$ 1.48	$ (3.17)	$ 0.97
	========	========	========	=========	========

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations.

General

In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes. Specifically, as discussed in Notes 4, 5 and 8 of the accompanying Notes to Consolidated Financial Statements, we have engaged in acquisitions (including the October 1999 acquisition of Kinder Morgan (Delaware), Inc., the indirect owner of the general partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded master limited partnership, referred to in this report as "Kinder Morgan Energy Partners"), and divestitures (including the discontinuance of certain lines of business and the transfer of certain assets to Kinder Morgan Energy Partners) that may affect comparisons of financial position and results of operations between periods.

Business Strategy

Our business strategy is to: (i) focus on fee-based energy transportation and storage assets that are core to the energy infrastructure of growing markets, (ii) increase utilization of existing assets while controlling costs, (iii) make selected incremental acquisitions, (iv) maximize the benefits of our financial structure as discussed following and (v) continue to align employee and shareholder incentives.

During 1999, we implemented plans to dispose of our non-core businesses and as of December 31, 2000, we effectively completed the disposition of these assets and operations, all as more fully described in Note 8 of the accompanying Notes to Consolidated Financial Statements. The cash proceeds from these dispositions were largely used to retire debt, contributing to the reduction in outstanding indebtedness during 2000.

In addition to sales of non-core assets to third parties, we made significant contributions of assets to Kinder Morgan Energy Partners at the end of 1999 and the end of 2000 that, in total, had over $1 billion of fair market value. By contributing assets to Kinder Morgan Energy Partners that are accretive to its earnings and cash flow, we receive fair market value in the contribution transaction, while still maintaining an indirect interest in the earnings and cash flows of the assets through our limited and general partner interests in Kinder Morgan Energy Partners.

In addition to distributions received on our limited partner interests and our Kinder Morgan Management shares as discussed above, we also receive an incentive distribution from Kinder Morgan

Energy Partners as a result of our ownership of the general partner interest in Kinder Morgan Energy Partners. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to unit holders exceed specified target levels as set forth in Kinder Morgan Energy Partners' partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit. Including both our general and limited partner interests in Kinder Morgan Energy Partners, at the 2002 distribution level, we received approximately 51% of all quarterly distributions made by Kinder Morgan Energy Partners, of which approximately 40% is attributable to our general partner interest and 11% is attributable to our limited partner interest. The actual level of distributions we will receive in the future will vary with the level of distributable cash determined in accordance with Kinder Morgan Energy Partners' partnership agreement.

After the dispositions discussed above, our remaining businesses constitute four business segments. Our largest business segment and our primary source of operating income is Natural Gas Pipeline Company of America, which owns and operates a major interstate natural gas pipeline system that runs from natural gas producing areas in West Texas and the Gulf of Mexico to its principal market area of Chicago, Illinois. In accordance with our strategy to increase operational focus on core assets, we have worked toward renewing existing agreements and entering into new agreements to fully utilize the transportation and storage capacity of Natural Gas Pipeline Company of America's system. As a result, Natural Gas Pipeline Company of America sold virtually all of its capacity through the 2002-2003 winter season. Natural Gas Pipeline Company of America continues to pursue opportunities to connect its system to power generation facilities and, in addition, has extended its system to East St. Louis, Illinois.

Our other business segments consist of (i) our TransColorado Pipeline system, a 300-mile natural gas pipeline and related facilities extending from approximately 30 miles east of Meeker, Colorado to Bloomfield, New Mexico, (ii) our retail distribution of natural gas to approximately 240,000 customers in Colorado, Wyoming and Nebraska and (iii) our investment in, and, in some cases, operation of, electric power generation facilities. The TransColorado Pipeline system receives gas from two coal seam natural gas treating plants located in the San Juan Basin of Colorado and from pipeline and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. We purchased the remaining 50 percent interest in the TransColorado Pipeline that we did not already own from Questar Corp. in the fourth quarter of 2002 and have announced plans to expand and extend the system (see "TransColorado Pipeline" following and Note 10 of the accompanying Notes to Consolidated Financial Statements). Our retail natural gas distribution operations are located, in part, in areas where significant growth is occurring and we expect to participate in that growth through increased natural gas demand. Our power segment owns interests in and, in some cases, operates power generation facilities and continues to hold preferred investments in two gas-fired power plants constructed by us and placed into operation in 2002. During the fourth quarter of 2002, we announced that we were discontinuing our power development activities and we revalued certain of our power assets. See "Power and Other" following and Note 6 of the accompanying Notes to Consolidated Financial Statements.

With respect to financial strategy, it is our intention to maintain a relatively conservative capital structure that provides flexibility and stability. During 2002, we utilized cash that we generated from operations to fund capital expenditures, increase our ownership of the TransColorado Pipeline to 100 percent and to reacquire approximately $144 million of our common stock (pursuant to a previously

announced $450 million stock buyback program). At December 31, 2002, our total debt to total capital was approximately 48%, down from over 70% in late 1999, with approximately 50% of our debt subject to floating interest rates.

We believe that we will continue to benefit from accretive acquisitions and business expansions, primarily by Kinder Morgan Energy Partners. Kinder Morgan Energy Partners has a multi-year history of making accretive acquisitions, which benefit us through our limited and general partner interests. This acquisition strategy is expected to continue, with the availability of potential acquisition candidates being driven by consolidation in the energy industry, as well as realignment of asset portfolios by major energy companies, although we can provide no assurance that such acquisitions will occur in the future. In addition, we expect to expand, within strict guidelines as to risk, rate of return and timing of cash flows, both Natural Gas Pipeline Company of America's and TransColorado Pipeline's pipeline systems and acquire natural gas retail distribution properties that fit well with our current profile.

It is our intention to carry out the above strategy, modified as necessary to reflect changing economic and other circumstances. However, as discussed under "Risk Factors" elsewhere in this report, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure 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 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.

In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for our natural gas distribution deliveries for which meters have not yet been read, 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.

In our retail natural gas distribution business, because we read customer meters on a cycle basis, we are required to estimate the amount of revenue earned as the end of each period for which service has been rendered but meters have not yet been read. We have available historical information for these meters and, together with weather-related data that affects natural gas demand, we are able to make reliable estimates. In our natural gas pipeline businesses, we are similarly required to make estimates for services rendered but for which actual metered volumes are not available at reporting dates. As with our retail natural gas distribution business, we have historical data available to assist us in the estimation process, but the variations in volume are greater, introducing a larger possibility of error. We believe our estimates, which are corrected to reflect actual metered volumes in the next accounting month, provide acceptable approximations of the actual revenue earned during any period, especially given that the majority of our revenues in the pipeline business are derived from demand charges, which do not vary with the actual amount of gas transported.

During the periods in which we were constructing power plants we utilized the percentage of completion method to determine what portion of our overall construction fee had been earned. We utilized the services of third-party engineering firms to help us estimate the progress being made on each project, but any such process requires subjective judgments. Any errors in this estimation process could have resulted in revenues being reported before or after they were actually earned. Increases or decreases in revenues resulting from revisions to these estimates were recorded in the period in which the facts that gave rise to the revision became known.

With respect to the amount of income or expense we recognize in association with our pension and retiree medical plans, we must make a number of assumptions with respect to both future financial conditions (for example, medical costs, returns on fund assets and market interest rates) as well as future actions by plan participants (for example, when they will retire and how long they will live after retirement). Most of these assumptions have relatively minor impacts on the overall accounting recognition given to these plans but two assumptions in particular, the discount rate and the assumed long-term rate of return on fund assets, can have significant effects on the amount of expense recorded and liability recognized. At year-end 2002, we utilized an expected long-term return of 9.0% on pension and retiree medical fund assets. This return is predicated on the fact that, historically over long periods of time, widely traded large-cap equity securities have provided a return of approximately 10%, while fixed income securities have provided a return of approximately 6%. At December 31, 2002, our pension fund assets portfolio consisted of approximately 63.9% equity, 32.3% debt and 3.8% cash and cash equivalents, indicating that a long-term expected return would be approximately 8.5% if the investments were made in the broad indexes. Since our pension funds are actively managed by professional managers who provide this service for a fee, we expect to earn a premium of 0.75% to 1.5% on the equity portion of our portfolio and 0.25% to 0.50% on the fixed income portion, over and above the fees we pay our money managers. Thus, on a weighted basis, we would expect to earn a premium of 0.6% to 1.12% due to active management. Our historical premium over a balanced index was 1.44%, 7.08% and 1.46% for the latest 1-year, 3-year and 5-year periods, respectively. Therefore, using the low end of the range for the expected active management premium, we arrive at an overall expected return of 9.08%, which we have lowered slightly to 9% for purposes of making the pension fund calculations. The discount rate, which is intended to reflect a current settlement rate and is used to value the liabilities associated with these plans, was reduced from 7.25% at year-end 2001 to 7.0% at year-end 2002, reflecting a similar decrease in the yields of high-grade corporate bonds which are the benchmark reference for this rate assumption. While we believe these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of pension and retiree medical funding, (i) a change of 1% in the long-term return assumption would change our annual pension and retiree medical expense by $1.6 million and $0.7 million, respectively, in comparison to that recorded in 2002 and (ii) a 1% change in the discount rate would change our projected pension benefit obligation and our accumulated postretirement benefit obligation by $20.6 million and $9.5 million, respectively, compared to those balances as of December 31, 2002.

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. These estimates are affected by the choice of remediation methods as well as the expected timing and length of the effort. 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.

We are subject to litigation 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 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.

We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In addition, we do business in a number of states with differing laws concerning how income subject to each state's tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

As discussed under "Risk Management" elsewhere herein, we enter into derivative contracts (natural gas futures, swaps and options) solely for the purpose of mitigating risks that accompany our normal business activities, including interest rates and the price of natural gas and associated transportation. We account for these derivative transactions as hedges in accordance with the authoritative accounting guidelines, marking the derivatives to market at each reporting date, with the unrealized gains and losses either recognized as part of comprehensive income or, in the case of interest rate swaps, as a valuation adjustment to the underlying debt. Any inefficiency in the performance of the hedge is recognized in income currently and, ultimately, the financial results of the hedge are recognized concurrently with the financial results of the underlying hedged item. All but an insignificant amount of our natural gas related derivatives are for terms of 18 months or less, allowing us to utilize widely available, published forward pricing curves in determining all of our appropriate market values. Our interest rate swaps are similar in nature to many other such financial instruments and are valued for us by commercial banks with expertise in such valuations.

Consolidated Financial Results

	Year Ended December 31,
	2002	2001	2000
	(In thousands except per share amounts)
Operating Revenues	$1,015,255	$1,054,907	$2,678,956
	==========	==========	==========
Gross Margin¹	$ 704,031	$ 715,606	$ 752,985
	==========	==========	==========
General and Administrative Expenses	$ 73,496	$ 73,319	$ 59,799
	==========	==========	==========
Operating Income	$ 236,667²	$ 384,319	$ 395,143
Other Income and (Expenses)	208,412	22,917	(87,977)
Income Taxes	135,912	168,601	123,017
Income from Continuing Operations	309,167	238,635	184,149
Loss on Disposal of Discontinued Operations	(4,986)	-	(31,734)
Extraordinary Item - Loss on Early
Extinguishment of Debt	(1,456)	(13,565)	-
Net Income	$ 302,725	$ 225,070	$ 152,415
	==========	==========	==========

Total Diluted Earnings Per Common Share	$ 2.45	$ 1.86	$ 1.33
Loss on Disposal of Discontinued Operations	(0.04)	-	(0.28)
Extraordinary Item - Loss on Early
Extinguishment of Debt	(0.01)	(0.11)	-
Income from Continuing Operations Per Diluted Share	2.50	1.97	1.61
Revaluation of Power Investments	(0.68)	-	-
Income Tax Adjustments	0.34	-	-
Other, Including Major Asset Sales³	(0.01)	0.01	0.32
	$ 2.85	$ 1.96	$ 1.29
	==========	==========	==========

¹	Gross margin equals total operating revenues less gas purchases and other costs of sales.
²	Includes a charge of $134.5 million to reduce the carrying value of certain power assets as discussed under "Power and Other" following.
³	Incidental asset sales are included in business segment earnings. Results under this caption include (i) in 2002, net asset sale gains of $0.05 and an accrual for losses under gas purchase contracts of $(0.06), (ii) in 2001, net asset sale gains of $0.08, a litigation reserve increase of $(0.05) and a loss due to a derivative counterparty default of $(0.02) and (iii) in 2000, net asset sale gains of $0.32.

Our income from continuing operations increased from $238.6 million in 2001 to $309.2 million in 2002, an increase of $70.6 million (29.6%). This increase is comprised of a decrease of $147.7 million in operating income, an increase of $185.5 in net other income and expenses and a decrease of $32.7 million in income tax expense. Following is a discussion of items affecting operating income and other income and expenses. Please refer to the individual business segment discussions included elsewhere herein for additional information regarding business segment results. Refer to the headings "Other Income and (Expenses)," "Income Taxes - Continuing Operations" and "Discontinued Operations" included elsewhere herein for additional information regarding these items.

Our results for 2002, in comparison to 2001, reflect a decrease of $39.7 million (3.8%) in operating revenues, a decrease of $11.6 million (1.6%) in gross margin and a decrease of $147.7 million (38.4%) in operating income. The decrease in operating revenues and gross margin was principally attributable to decreased revenues in our Power and Other segment, partially offset by increased revenues in our Natural Gas Pipeline Company of America segment (see the individual business segment discussions for additional information). Operating income was negatively impacted in 2002, relative to 2001, by (i) decreased earnings from our Power and Other business segment, including a $134.5 million charge in 2002 to revalue certain investments (see "Power and Other" following), (ii) a $12.7 million charge in 2002 related to certain long-term natural gas purchase contracts (see Note 1(M) of the accompanying Notes to Consolidated Financial Statements) and (iii) an increase of $5.0 million in general and

administrative expenses, exclusive of a 2001 charge related to Enron Corp. (see below). This increase in general and administrative expenses was principally attributable to increased employee benefit costs. These negative impacts were partially offset by (i) increased earnings from our Natural Gas Pipeline Company of America, TransColorado Pipeline and Kinder Morgan Retail business segments and (ii) the fact that 2001 results included a $5.0 million loss resulting from nonperformance by a derivative counterparty (Enron Corp.), see Note 15 of the accompanying Notes to Consolidated Financial Statements.

Below the operating income line, net other income and expenses increased from income of $22.9 million in 2001 to income of $208.4 million in 2002, an increase of $185.5 million. This increase reflected (i) increased equity in earnings of Kinder Morgan Energy Partners in 2002 due, in part, to the strong performance from the assets held by Kinder Morgan Energy Partners and the cessation of amortization of equity-method goodwill related to this investment due to the adoption of SFAS No. 142 (see Note 1(N) of the accompanying Notes to Consolidated Financial Statements) and (ii) decreased 2002 interest expense reflecting lower 2002 interest rates and borrowed balances. These positive impacts were partially offset by (i) a $19.0 million increase in minority interest expense in 2002, principally attributable to the minority interests in Kinder Morgan Management, LLC and (ii) a $9.7 million decrease in net gains from asset sales in 2002 (see Note 1(P) of the accompanying Notes to Consolidated Financial Statements).

Our results for 2001, in comparison to 2000, reflect a decrease of $1.6 billion (60.6%) in operating revenues, a decrease of $37.4 million (5.0%) in gross margin and a decrease of $10.8 million (2.7%) in operating income. These declines are attributable to the fact that consolidated results for 2000 include the results of Kinder Morgan Texas Pipeline, L.P., referred to in this report as "Kinder Morgan Texas Pipeline" (operating revenues, gross margin and operating income before corporate charges of $1.7 billion, $81.3 million and $29.3 million, respectively), which was contributed to Kinder Morgan Energy Partners effective December 22, 2000. If the results of Kinder Morgan Texas Pipeline are excluded from 2000 results, the comparison of results from 2001 to 2000 reflects increases of $122.7 million (4.6%), $43.2 million (5.7%) and $13.9 million (3.5%) in operating revenues, gross margin and operating income, respectively. These increases represent improved results at each of our business segments, with Kinder Morgan Retail making the largest contribution to increased revenues and Power and Other making the largest contribution to the increases in gross margin and operating income. General and administrative expenses increased by $12.3 million from 2000 to 2001 principally as a result of (i) increased costs for employee benefits and (ii) a $5.0 million loss in 2001 resulting from nonperformance by a derivative counterparty as discussed above.

Below the operating income line, the improved results for 2001, relative to 2000, were principally due to (i) an increase of $138.5 million in equity in the earnings in Kinder Morgan Energy Partners in 2001, net of amortization of excess investment and (ii) a decrease of $27.0 million in 2001 net interest expense. The favorable variance created by these impacts was partially offset by (i) $12.6 million of increased 2001 minority interest (due to the sale of Kinder Morgan Management shares) and (ii) a reduction of approximately $39.1 million in net gains from assets sales in 2001.

For 2003, earnings attributable to our investment in Kinder Morgan Energy Partners are expected to increase by approximately 15% due to, among other factors, the improved performance of existing assets. However, there are factors beyond the control of Kinder Morgan Energy Partners that may affect its results, including developments in the regulatory arena and as yet unforeseen competitive developments or acquisitions.

Diluted earnings per share increased from $1.86 in 2001 to $2.45 in 2002, an increase of $0.59 or 31.7% reflecting, in addition to the financial and operating impacts discussed preceding, an increase of 2.1

million (1.7%) in average shares outstanding. Excluding the $(0.04) impact of discontinued operations in 2002 and the $(0.01) and $(0.11) impact of extraordinary losses in 2002 and 2001, respectively, diluted earnings per share from continuing operations increased from $1.97 in 2001 to $2.50 in 2002, an increase of $0.53 or $26.9%. After adjusting for the 2002 $(0.68) revaluation of power assets, the 2002 $0.34 favorable income tax adjustment and other non-recurring items aggregating $(0.01) in each respective year, diluted earnings per share increased from $1.96 in 2001 to $2.85 in 2002, an increase of $0.89 or 45.4%.

Results of Operations

We manage our various businesses by, among other things, allocating capital and monitoring operating performance. This management process includes dividing the company into business segments so that performance can be effectively monitored and reported for a limited number of discrete businesses. Currently, we manage and report our operations in the following business segments:

Business Segment	Business Conducted	Referred to As:

Natural Gas Pipeline Company of America and certain affiliates	The ownership and operation of a major interstate natural gas pipeline and storage system	Natural Gas Pipeline Company of America
TransColorado Gas Transmission Company	The ownership and operation of an interstate natural gas pipeline system in Colorado and New Mexico	TransColorado Pipeline
Retail Natural Gas Distribution	The regulated sale and transportation of natural gas to residential, commercial and industrial customers (including a small distribution system currently being built-out in Hermosillo, Mexico) and the non-regulated sales of natural gas to certain utility customers under the Choice Gas program	Kinder Morgan Retail
Power Generation and Other	The operation and, in previous periods, construction of natural gas-fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments	Power and Other

In previous periods, we owned and operated other lines of business, which we discontinued during 1999. Our direct investment in the natural gas transmission and storage business decreased significantly as a result of (i) the December 31, 1999 contribution to Kinder Morgan Energy Partners of Kinder Morgan Interstate Gas Transmission LLC and (ii) the December 22, 2000 contribution to Kinder Morgan Energy Partners of Kinder Morgan Texas Pipeline. In each case, the transaction was unanimously approved by our independent directors with the benefit of independent legal advice and a fairness opinion from Merrill Lynch. The results of operations of these two businesses are included in our financial statements

until their disposition. In the fourth quarter of 2002, as further discussed under "Power and Other" following, we decided to discontinue the development portion of our power generation business and decreased the carrying value of certain of our power assets. TransColorado Gas Transmission Company was a 50/50 joint venture with Questar Corp. until we became sole owner by purchasing Questar Corp.'s interest effective October 1, 2002. Results of operations for this segment include our 50% share of TransColorado Pipeline's earnings recognized under the equity method of accounting prior to October 2002 and consolidated results at the 100% level thereafter.

The accounting policies we apply in the generation of business segment information are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that (i) certain items below the "Operating Income" line are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners and certain insignificant international investees, are included in segment results. These equity method earnings are included in "Other Income and (Expenses)" in our Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not allocated to individual business segments and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value. As necessary for comparative purposes, we have reclassified prior period results and balances to conform to the current presentation.

Following are operating results by individual business segment (before intersegment eliminations), including explanations of significant variances between the periods presented.

Natural Gas Pipeline Company of America

	Year Ended December 31,
	2002	2001	2000
	(In thousands except systems throughput)
Operating Revenues	$ 699,998	$ 646,804	$ 622,002
	===========	===========	===========

Gross Margin	$ 539,149	$ 515,360	$ 510,586
	===========	===========	===========

Segment Earnings	$ 359,911	$ 346,569	$ 344,405
	===========	===========	===========

Systems Throughput (Trillion Btus)	1,480.5	1,398.9	1,459.3
	===========	===========	===========

Natural Gas Pipeline Company of America's segment earnings increased by $13.3 million, or 3.8%, from 2001 to 2002. Operating results for 2002 were positively affected, relative to 2001, by (i) increased margins from natural gas transportation and storage services, including operational natural gas sales and (ii) the inclusion of earnings from our equity investment in Horizon Pipeline Company, which was placed into service during the second quarter of 2002. These positive impacts were partially offset by (i) increased operations and maintenance expenses attributable to transmission mains and underground storage facilities, (ii) increased depreciation expense due to the addition of new facilities, principally the extension of our system to East St. Louis, Illinois, (iii) increased ad valorem taxes and (iv) the fact that 2001 results include $6.3 million of pre-tax gains from incidental asset sales. Although systems throughput increased in 2002, this increase did not have a significant impact on revenues or segment earnings due to the fact that transportation revenues are derived primarily from "demand" contracts in which shippers pay a fee to reserve a set amount of system capacity for their use.

Natural Gas Pipeline Company of America's segment earnings increased by $2.2 million, or 0.6%, from 2000 to 2001. Operating results for 2001 were positively affected, relative to 2000, by (i) increased natural gas transportation and storage margins and (ii) a $4.7 million increase in pre-tax gains from incidental asset sales in 2001. These positive impacts were partially offset by (i) increased operations and maintenance expenses, primarily attributable to the higher costs of electric power for compression, (ii) increased ad valorem taxes and (iii) the fact that 2000 results include a $3.3 million refund of previously expensed transportation charges from an unaffiliated interstate pipeline.

Substantially all of Natural Gas Pipeline Company of America's pipeline capacity is committed under firm transportation contracts ranging from one to five years. Under these contracts, over 90% of the revenues are derived from a demand charge and, therefore, are collected regardless of the volume of gas actually transported. The principal impact of the actual level of gas transported is on fuel recoveries, which are received in-kind as volumes move on the system. Approximately 69% of the total transportation volume committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts in effect on January 1, 2003 had remaining terms of less than three years. Contracts representing 41% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 1, 2003 are scheduled to expire during 2003. Natural Gas Pipeline Company of America continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts. As of February 18, 2003, 47% of Natural Gas Pipeline Company of America's long-term contracted firm transport capacity as of January 1, 2003 that was scheduled to expire during 2003 had been recontracted or terms had been agreed to for rollover with the same customers, and certain other of that capacity had been sold to other customers. Nicor Gas and Peoples Energy, two local gas distribution companies in the Chicago, Illinois area, are Natural Gas Pipeline Company of America's two largest customers.

For 2003, we currently expect that Natural Gas Pipeline Company of America will experience 4-5% growth in segment earnings in comparison to 2002. This increase in earnings is expected to be derived primarily from (i) the impact of having a full year of earnings from the Horizon Pipeline and the East St. Louis expansion project, (ii) incremental earnings from the North Lansing storage expansion project, expected to be in service in the spring of 2003 and (iii) new electric power generation load. However, as discussed following, there are factors beyond our control that can affect our results, including developments in the regulatory arena and as yet unforeseen competitive developments. Accordingly, our actual future results may differ significantly from our projections.

Our principal exposure to market variability is related to the variation in natural gas prices and basis differentials, which can affect gross margins in our Natural Gas Pipeline Company of America segment. "Basis differential" is a term that refers to the difference in natural gas prices between two locations or two points in time. These price differences can be affected by, among other things, natural gas supply and demand, available transportation capacity, storage inventories and deliverability, prices of alternative fuels and weather conditions. In recent periods, additional competitive pressures have been generated in Midwest natural gas markets due to the introduction and planned introduction of pipeline capacity to bring additional supplies of natural gas into the Chicago market area, although incremental pipeline capacity to take gas out of the area has also been constructed. We have attempted to reduce our exposure to this form of market variability by pursuing long-term, fixed-rate type contract agreements to utilize the capacity on Natural Gas Pipeline Company of America's system. In addition, as discussed under "Risk Management" elsewhere in this document and in Note 15 of the accompanying Notes to Consolidated Financial Statements, we utilize a comprehensive risk management program to mitigate our exposure to changes in the market price of natural gas and associated transportation.

The majority of Natural Gas Pipeline Company of America's system is subject to rate regulation under the jurisdiction of the Federal Energy Regulatory Commission. Currently, there are no material

proceedings challenging the rates on any of our pipeline systems. Nonetheless, 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 future challenges to the rates we receive for services on our pipeline systems.

TransColorado Pipeline

	Year Ended December 31,
	2002	2001	2000
	(In thousands except systems throughput)
Operating Revenues	$ 7,818	$ -	$ -
	=========	=========	=========

Gross Margin	$ 7,818	$ -	$ -
	=========	=========	=========

Segment Earnings (Losses)	$ 12,648	$ (5,268)	$ (10,336)
	=========	=========	=========

Systems Throughput (Trillion Btus)	155.8	103.1	90.3
	=========	=========	=========

TransColorado Pipeline was a 50/50 joint venture with Questar Corp. until we bought Questar's interest effective October 1, 2002, thus becoming the sole owner. As a result, TransColorado Pipeline's results shown above reflect our 50% equity interest in its earnings prior to October 1, 2002 and 100% of its results on a consolidated basis thereafter. The significant improvements in TransColorado Pipeline's operating results from 2000 to 2001 and from 2001 to 2002, apart from the change in our ownership, result from the increased demand and associated increased throughput on the system. This increased demand has resulted from the incremental natural gas production available in the Rocky Mountain basins that form the principal supply area for TransColorado Pipeline and the limited pathways for this natural gas to get to markets both east and west of these production areas. As a result of this increased demand and associated increased basis differentials, TransColorado Pipeline has sold out its firm available capacity through October 2004.

On January 21, 2003, we announced the start of an open season seeking shipper interest and commitments for a proposal to expand capacity on the TransColorado system. This expansion project would include additional compression and line-looping infrastructure to increase capacity on the existing TransColorado mainline, which currently has capacity of approximately 300,000 Dekatherms per day, by as much as 150,000 Dekatherms per day. As part of this open season, we are also seeking shipper support for an extension of the TransColorado system with a capacity of 750,000 Dekatherms per day. As designed, this 36-inch diameter pipeline would extend from TransColorado Pipeline's existing southern terminus in the Blanco Hub area to a point near Window Rock in Apache County, Arizona, where it would connect to Kinder Morgan Energy Partners' proposed Silver Canyon Pipeline. This proposed extension would also feature new interconnects with El Paso Natural Gas Company and Transwestern Pipeline Company. Whether or not either or both expansions are actually built will depend on a number of factors, including shipper support. We will not build either project in the absence of firm contracts to support the capital expenditures.

For 2003, we currently expect that TransColorado Pipeline will experience 24-28% growth in segment earnings in comparison to 2002. This earnings increase is expected to be driven by a full year of 100% ownership and increased demand for capacity on the TransColorado system and basis differentials for the year which will exceed those experienced in 2002 for the reasons discussed above. However, these market factors are largely beyond our control and, as discussed following, TransColorado Pipeline is subject to federal regulation. Accordingly, its actual future results may differ significantly from our projections.

The majority of TransColorado's system is subject to rate regulation under the jurisdiction of the Federal Energy Regulatory Commission. Currently, there are no material proceedings challenging the rates on any of our pipeline systems. Nonetheless, 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. TransColorado Pipeline is also subject to market variability in natural gas prices and basis differentials. Please refer to the discussion of basis differentials under the heading "Natural Gas Pipeline Company of America" in this Item.

Kinder Morgan Retail

	Year Ended December 31,
	2002	2001	2000
	(In thousands except systems throughput)
Operating Revenues	$ 259,748	$ 290,344	$ 235,208
	===========	===========	===========

Gross Margin	$ 113,223	$ 112,669	$ 101,950
	===========	===========	===========

Segment Earnings	$ 64,056	$ 56,696	$ 47,705
	===========	===========	===========

Systems Throughput (Trillion Btus)	42.4	42.0	44.0
	===========	===========	===========

Kinder Morgan Retail's segment earnings increased by $7.4 million, or 13.0%, from 2001 to 2002. These operating results were positively impacted in 2002, relative to 2001, by (i) margins derived from the fourth quarter 2001 acquisition of natural gas distribution facilities from Citizens Communications Company, as described following, (ii) strong demand during irrigation season, (iii) the addition of new customers in existing service territories and (iv) a $1.6 million ad valorem tax refund in 2002 from an affiliated shipper. The decrease in operating revenues was principally due to lower natural gas prices (a component of the overall sales rate) in 2002 than in 2001 and was offset by lower costs for natural gas purchases. The increase in 2002 gross margins was partially offset by higher operations, maintenance and depreciation expenses in 2002 principally attributable to the newly acquired facilities.

Kinder Morgan Retail's segment earnings increased by $9.0 million, or 18.8%, from 2000 to 2001. These operating results were positively impacted in 2001, relative to 2000, by (i) continued successful risk management of gas supply needs, which has reduced, but not eliminated, weather-related volatility in earnings (refer to the heading "Risk Management" in this Item for a more detailed discussion of our risk management strategy), (ii) improved 2001 results from our retail gas distribution properties in Mexico and (iii) the inclusion, in 2001 results, of income from the Wolf Creek storage system. These positive impacts were partially offset by higher operating expenses in 2001 resulting from overall system expansion. The increase in operating revenues in 2001 was principally due to higher natural gas prices in 2001 than in 2000 and was offset by higher costs for natural gas purchases.

During the fourth quarter of 2001, Kinder Morgan Retail successfully completed the acquisition of natural gas distribution facilities from Citizens Communications Company for approximately $11 million in cash and assumed liabilities. The natural gas distribution assets serve approximately 13,400 residential, commercial and agricultural customers in Bent, Crowley, Otero, Archuleta, La Plata and Mineral Counties in Colorado.

For 2003, we currently expect that Kinder Morgan Retail will experience approximately 2% growth in segment earnings. With a stable base of earnings due to regulated business, supplemented by a weather hedging program, increased earnings are expected to derive largely from the addition of new customers in existing service territories, especially certain high-growth areas in Colorado. However, as discussed

following, there are factors beyond our control that can affect our results, including developments in the regulatory arena, currently unforeseen competitive developments and weather-related impacts outside our hedging program. Accordingly, our actual future results may differ significantly from our projections.

A significant portion of Kinder Morgan Retail's business is subject to rate regulation by various state and local jurisdictions in Colorado, Wyoming and Nebraska. There are currently no material proceedings challenging the base rates on any of our intrastate pipeline or distribution systems. Nonetheless, there can be no assurance that we will not face future challenges to the rates we receive for these services. Kinder Morgan Retail is also subject to market variability in natural gas prices and basis differentials. Please refer to the discussion of basis differentials under the heading "Natural Gas Pipeline Company of America" in this Item.

Power and Other

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Operating Revenues	$ 47,784	$ 119,832	$ 74,232
	===========	===========	===========

Gross Margin	$ 43,841	$ 87,577	$ 59,123
	===========	===========	===========

Segment Earnings¹	$ 36,673	$ 65,983	$ 37,222
	===========	===========	===========

¹	Excludes, in 2002, the $134.5 million charge recorded in the fourth quarter to reduce the carrying value of certain assets. This charge is discussed below.

Results for this segment in 2002 include only the results of our Power business unit. Excluding the operating results of the Wattenberg facilities that were sold in 2001 as discussed below, segment revenues, gross margin and segment earnings decreased by $9.1 million, $8.7 million and $8.1 million, respectively, from 2001 to 2002. Power's reduced 2002 earnings reflect, as expected, lower 2002 power plant development fees. The reduction in 2002 development fees was partially offset by (i) increased fees received for operating power plants and (ii) decreased 2002 amortization charges as a result of newly adopted rules regarding amortization of goodwill (see Note 1(N) of the accompanying Notes to Consolidated Financial Statements). Operating results of the Power and Other segment for 2001 included $62.9 million of revenue, $35.0 million of gross margin and $21.2 million of segment earnings resulting from our operating agreement with Kerr-McGee Gathering LLC (formerly HS Resources, Inc.), which agreement concluded upon the sale of our Wattenberg natural gas facilities to Kerr-McGee effective December 28, 2001.

Power and Other's segment earnings increased by $28.8 million (77.3%) from 2000 to 2001. Operating results for 2001 were positively impacted, relative to 2000, by (i) $16.8 million of increased power plant development fee revenues from the development of the Wrightsville, Arkansas and Jackson, Michigan power plants, (ii) increased equity in the earnings of Thermo Cogeneration Partnership, (iii) $1.9 million of increased earnings from our agreements with Kerr-McGee Gathering LLC (formerly HS Resources, Inc.), and (iv) the fact that 2000 results include $2.3 million of losses related to the disposition of certain of our power turbine purchase agreements. These positive impacts were partially offset by (i) increased operations and maintenance expenses in 2001 related to power plant site development and (ii) the fact that 2000 results included $0.8 million of pre-tax gains from asset sales.

Effective July 1, 2002, construction and testing of the Jackson, Michigan 550-megawatt power generation facility were completed and commercial operations commenced. Concurrently with

commencement of commercial operations, (i) Kinder Morgan Power Company, our wholly owned subsidiary, made a preferred investment in Triton Power Company LLC valued at approximately $105 million; (ii) Triton Power Company LLC, through its wholly owned affiliate, Triton Power Michigan LLC, entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC; and (iii) we received full payment of our $104.4 million construction note receivable. Our preferred equity interest has no management or voting rights, but does retain certain protective rights, and is entitled to a cumulative return, compounded monthly, of 9.0% per annum. No income is expected in 2003 from this preferred investment. We account for this investment under the cost method, under which earnings are recognized as cash is received.

Also effective July 1, 2002, construction and testing of the 550-megawatt Wrightsville, Arkansas power generation facility were completed and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville power facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Kinder Morgan Power Company made and retains a preferred investment in the project company. No income is expected in 2003 from this investment. In addition, Kinder Morgan Power Company advanced approximately $16.7 million to the electricity transmission carrier and the project company, which is scheduled to be repaid with interest over the next several years. Our preferred equity interest has no management or voting rights, but does retain certain protective rights, and provides for a cumulative preferred dividend return that escalates over time from 6.3% to 8.8%. We account for this investment under the cost method, under which earnings are recognized as cash is received.

During 2002, we noted that a number of factors had negatively affected Power's business environment and certain of its current operations. These factors, which are currently expected to continue in the near to intermediate term, include (i) volatile and generally declining prices for wholesale electric power in certain markets, (ii) cancellation and/or postponement of the construction of a number of new power generation facilities, (iii) difficulty in obtaining air permits with acceptable operating conditions and constraints and (iv) a marked deterioration in the financial condition of a number of participants in the power generating and marketing business, including participants in the two newly constructed power plants in Jackson, Michigan and Wrightsville, Arkansas. During the fourth quarter of 2002, after completing an analysis of these and other factors to determine their impact on the market value of these assets and the prospects for this business in the future, we (i) determined that we would no longer pursue power development activities and (ii) recorded a $134.5 million pre-tax charge ($83.4 million after tax, or $0.68 per diluted common share) to reduce the carrying value of our investments in (i) sites for future power plant development, (ii) power plants and (iii) turbines and associated equipment (see Note 6 of the accompanying Notes to Consolidated Financial Statements). In recent months, the cash flows generated by the Wrightsville project company have not been adequate to service the associated debt. If this continues, it could have an adverse effect on our remaining investment, although the carrying value we have recorded is supported by recent valuations made by potential third-party purchasers. Due to the fact that we are not projecting any further power plant development projects, we currently expect that segment earnings from our Power segment in 2003 will decline by approximately 45-50%. Actual future results may differ significantly from our projections.

Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, prior to the end of 2003, we expect to make an additional investment in our Colorado power businesses in the form of approximately 1.6 million Kinder Morgan Energy Partners common units (that we currently own or acquire). We expect to deliver these units to an entity controlled by the former Thermo owners, which entity will be required to retain these units for a period ending in 2007, during which period we will be entitled to receive distributions made by Kinder Morgan Energy Partners attributable to those units. The effect of this incremental investment will be to increase our ownership in the Thermo entities beginning in 2010.

Kinder Morgan Texas Pipeline

We transferred Kinder Morgan Texas Pipeline to Kinder Morgan Energy Partners in December 2000. See Note 5 of the accompanying Notes to Consolidated Financial Statements for more information regarding this transaction.

	Year Ended December 31,
		2000
	(In thousands except systems throughput)
Operating Revenues		$ 1,747,499
		===========

Gross Margin		$ 81,330
		===========

Segment Earnings		$ 29,318
		===========


Systems Throughput (Trillion Btus)		654.4
		===========

Other Income and (Expenses)

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Interest Expense, Net	$ (161,935)	$ (216,200)	$ (243,155)
Equity in Earnings of Kinder Morgan Energy Partners:
Equity in Earnings	392,135	277,504	140,913
Amortization of Equity-method Goodwill	-	(25,644)	(27,593)
Equity in Earnings of Power Segment	7,674	5,299	3,669
Equity in Earnings of Horizon Pipeline	1,316	-	-
Equity in Earnings (Losses) of TransColorado	3,980	(5,268)	(10,336)
Other Equity in Earnings (Losses)	(179)	214	81
Minority Interests	(55,720)	(36,740)	(24,121)
Gains from Sales of Assets	13,030	22,621	61,684
Other, Net	8,111	1,131	10,881
	$ 208,412	$ 22,917	$ (87,977)
	===========	===========	===========

"Other Income and (Expenses)" increased from income of $22.9 million in 2001 to income of $208.4 million in 2002, an increase of $185.5 million. This increase was principally due to (i) increased equity in the earnings of Kinder Morgan Energy Partners due, in part, to the strong performance from the assets held by Kinder Morgan Energy Partners and the cessation of amortization of equity-method goodwill related to this investment due to the adoption of SFAS No. 142 (see Note 1(N) of the accompanying Notes to Consolidated Financial Statements), (ii) decreased interest expense, reflecting reduced interest rates and reduced debt outstanding and (iii) increased earnings from other equity investments, principally TransColorado Pipeline. These positive impacts were partially offset by (i) a $19.0 million increase in minority interest expense in 2002, principally attributable to the minority interests in Kinder Morgan Management, LLC and (ii) a $9.6 million decrease in 2002 gains from sales of assets.

"Other Income and (Expenses)" was a net decrease to earnings of $88.0 million in 2000 and a net increase to earnings of $22.9 million in 2001. This positive change of $110.9 million was principally due to: (i) an increase of $138.5 million in equity in earnings of Kinder Morgan Energy Partners, net of associated amortization, (ii) a decrease of $27.0 million in net interest expense in 2001, reflecting

reduced interest rates and reduced debt outstanding and (iii) a reduction of $5.1 million from equity in losses of TransColorado Pipeline. These favorable impacts were partially offset by (i) a decrease of $39.1 million in 2001 net gains from sales of assets, (ii) an increase of $12.6 million in expense due to minority interest in 2001, principally due to the issuance of Kinder Morgan Management shares and (iii) the fact that 2000 results include (a) $4.1 million due to the recovery of note receivable proceeds in excess of its carrying value and (b) $3.9 million due to the settlement of a regulatory matter for an amount less than that previously reserved.

Income Taxes - Continuing Operations

The income tax provision decreased from $168.6 million in 2001 to $135.9 million in 2002, a decrease of $32.7 million despite an increase of $37.8 million in income from continuing operations before income taxes. The income tax provision for 2002 was reduced by the combined impacts of (i) a decrease in the effective tax rate on current-year income from approximately 40% in 2001 to approximately 38% in 2002, principally due to a decrease in the provision for state income taxes, (ii) a decrease of approximately $21.0 million due to the impact of the lower effective tax rate on previously recorded deferred tax liabilities, (iii) a decrease of approximately $17.7 million due to the resolution of certain issues with respect to prior year tax returns at amounts less than those previously accrued and (iv) a decrease of approximately $3.6 million due to the impact of a dividends received deduction.

The increase of $45.6 million in the income tax provision from 2000 to 2001 is almost solely due to increased 2001 pre-tax income. The apparent increase in the effective tax rate in 2001 is due to the fact that the minority interest in the earnings of Kinder Morgan Management is presented net of its associated tax expense.

Discontinued Operations

During 1999, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing of natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids, (iii) international operations and (iv) the direct marketing of non-energy products and services. During 2000, we completed the disposition of these businesses, with the exception of international operations (principally consisting of a natural gas distribution system under construction in Hermosillo, Mexico), which, in the fourth quarter of 2000, we decided to retain. In the fourth quarter of 2000, we recorded an incremental loss on disposal of discontinued operations of $31.7 million (net of tax benefit of $21.2 million), representing the impact of final disposition transactions and adjustment of previously recorded estimates. During the fourth quarter of 2002, we recorded an incremental loss of approximately $5.0 million (net of tax benefit of $3.1 million) to adjust previously recorded liabilities to reflect current estimates of our remaining obligations. We had a remaining liability of approximately $7.1 million at December 31, 2002 associated with these discontinued operations, principally due to an indemnification obligation as discussed following. We do not expect significant additional financial impacts associated with these matters. Note 8 of the accompanying Notes to Consolidated Financial Statements contains certain additional financial information with respect to these discontinued operations.

Liquidity and Capital Resources

The following table illustrates the sources of our invested capital. In addition to our results of operations, these balances are affected by our financing activities as discussed following.

	December 31,
	2002	2001	2000
	(Dollars in thousands)
Long-term Debt:
Outstanding	$ 2,852,181	$ 2,409,798	$ 2,478,983
Market Value of Interest Rate Swaps¹	139,589	(4,831)	-
	2,991,770	2,404,967	2,478,983
Minority Interests	967,802	817,513	4,910
Common Equity	2,354,997	2,259,997	1,777,624
Capital Securities	275,000	275,000	275,000
	6,589,569	5,757,477	4,536,517
Less Market Value of Interest Rate Swaps	(139,589)	4,831	-
Capitalization	6,449,980	5,762,308	4,536,517
Short-term Debt, Less Cash and Cash Equivalents²	465,614	613,918	766,244
Invested Capital	$ 6,915,594	$ 6,376,226	$ 5,302,761
	===========	===========	===========

Capitalization:
Outstanding Long-term Debt	44.2%	41.8%	54.6%
Minority Interests	15.0%	14.2%	0.1%
Common Equity	36.5%	39.2%	39.2%
Capital Securities	4.3%	4.8%	6.1%

Invested Capital:
Total Debt (Excluding Interest Rate Swaps)	48.0%	47.4%	61.2%
Equity, Including Capital Securities and Minority Interests	52.0%	52.6%	38.8%

¹	See "Short-Term Liquidity and Financing Transactions" following.
²	Cash and cash equivalents netted against short-term debt were $35,653, $16,134 and $141,923 for December 31, 2002, 2001 and 2000, respectively.

In addition to the direct sources of debt and equity financing shown in the preceding table, we obtain financing indirectly through our ownership interests in unconsolidated entities. Our largest unconsolidated investment is in Kinder Morgan Energy Partners. Kinder Morgan G.P., Inc., our subsidiary that is the general partner in Kinder Morgan Energy Partners, is obligated to support the operations and debt service payments of Kinder Morgan Energy Partners. This obligation, however, does not arise until the assets of Kinder Morgan Energy Partners have been fully utilized in meeting its own obligations and, in any event, does not extend beyond the assets of Kinder Morgan G.P., Inc.

We utilize equity method accounting for several investees and have interests in or obligations with respect to these entities as shown following:

	At December 31, 2002
Entity	Investment Amount	Investment Percent	Entity Assets¹	Entity Debt	Incremental Investment Obligation	Our Debt Responsibility
	(Dollars in millions)
Ft. Lupton Power Plant	$ 86.6	49.5%	$ 161.2	$ 133.2²	-		$ -

Horizon Pipeline
Company	17.8	50.0%	90.9	49.5²	-		-

Igasamex	5.9	21.0%	16.3	5.3	-		1.1

Kinder Morgan Energy
Partners, L.P.	$3,003.4	19.2%	$8,353.6	$3,826.5	-		$ 522.7³

¹	At recorded value, in each case consisting principally of property, plant and equipment.
²	Non-recourse to owners.
³	We would only be obligated if Kinder Morgan Energy Partners, L.P. and/or its assets cannot satisfy its obligations.


		Amount of Commitment Expiration Per Period
	Total	Less than 1 year	2-3 years	4-5 years	After 5 years
	(In millions)
Contractual Obligations:
Long-term Debt, Including
Current Maturities	$3,354.1	$ 501.3	$ 512.5	$ 17.3	$2,323.0
Operating Leases	53.3	9.2	19.3	17.6	7.2
Kinder Morgan - Obligated Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan	275.0	-	-	-	275.0
Incremental Investment in Power Plants	12.0	12.0	-	-	-
Gas Purchase Contracts¹	35.5	8.6	14.8	12.1	-
Discontinued Operations Indemnification²	6.6	1.9	2.8	1.9	-
Total Contractual Cash Obligations	$3,736.5	$ 533.0	$ 549.4	$ 48.9	$2,605.2
	========	========	========	========	========

Other Commercial Commitments:
Standby Letters of Credit³	$ 31.5	$ 31.5	$ -	$ -	$ -
	========	========	========	========	========
Capital Expenditures	$ 1.0	$ 1.0	$ -	$ -	$ -
	========	========	========	========	========
Incremental Investment in Thermo Companies	$ N/A⁴	$ -	$ -	$ -	$ -
	========	========	========	========	========

¹	We are obligated to purchase natural gas at above-market prices from certain wells in Montana through the life of the field, production from which is currently expected to become uneconomic in 2007. We have recorded a liability for our probable losses under these contracts; see Note 1(M) of the accompanying Notes to Consolidated Financial Statements.
²	In conjunction with a disposal of certain discontinued operations in 1999 we agreed to indemnify the purchasing party from losses associated with the sale of certain natural gas volumes from a processing facility. This obligation of $6.6 million as of December 31, 2002 will be settled as these volumes are sold and the indemnification payments are made.
³	The $31.5 million in letters of credit outstanding at December 31, 2002 consisted of the following: (i) three letters of credit, totaling $5.7 million, required under provisions of our property and casualty, worker's compensation and general liability insurance policies, (ii) a $13.0 million letter of credit supporting the subordination of operating fees payable to us for operation of the Jackson, Michigan power generation facility to payments due under the operating lease of the facilities, (iii) a $3.4 million letter of credit supporting our obligation to attach a specified number of meters within a specified timeframe in our Hermosillo, Mexico natural gas distribution operations, (iv) a $6.6 million letter of credit associated with the outstanding debt of KN Thermo LLC, the entity responsible for the operation of our Colorado power generation assets and (v) a $2.8 million letter of credit supporting KN Thermo LLC's performance under its contract with Public Service Company of Colorado, the principal customer of our Colorado power generation assets.
⁴	Prior to December 31, 2003, we are committed to make an additional investment in the Thermo Companies in the form of approximately 1.6 million Kinder Morgan Energy Partners common units as discussed under "Power and Other" elsewhere herein.

We expect to have sufficient liquidity to satisfy our near-term obligations through the combination of free cash flow and our credit facilities totaling $775 million.

Contingent Liabilities:	Contingency	Amount of Contingent Liability at December 31, 2002
Guarantor of the Bushton Gas Processing Plant Lease¹	Default by ONEOK, Inc.	Averages $23 million per year through 2012; Total $226.2 million
Power Plant Incremental Investment	Operational Performance	$3 to 8 million per year for 16 years
Power Plant Incremental Investment	Cash Flow Performance	Up to a total of $25 million beginning in the 17^th year following commercial operations

In conjunction with our sale of the Bushton gas processing facility to ONEOK, Inc., at December 31, 1999 we became secondarily liable under the associated operating lease. Should ONEOK, Inc. fail to make payments as required under the lease, we would be required to make such payments, with recourse only to ONEOK.

Cash Flows

The following discussion of cash flows should be read in conjunction with the accompanying Consolidated Statements of Cash Flows and related supplemental disclosures. All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents.

Net Cash Flows from Operating Activities

"Net Cash Flows Provided by Operating Activities" increased from $437.3 million in 2001 to $443.0 million in 2002, an increase of $5.7 million (1.3%). This positive variance principally reflects a $71.5 million increase in cash distributions received in 2002 attributable to our interest in Kinder Morgan Energy Partners and a decrease of $69.1 million in cash outflows for gas in underground storage during 2002. Significant year-to-year variations in cash used or generated from gas in storage transactions are due to changes in injection and withdrawal volumes as well as fluctuations in natural gas prices. These positive impacts were partially offset by several non-recurring cash payments and cash flow timing issues including (i) a second-quarter 2002 $22.1 million payment and escrow deposit in settlement of certain litigation involving Jack J. Grynberg, (ii) a $20 million pension contribution in 2002 of which $18.7 million was in excess of book expense, (iii) a decrease of $58.8 million in cash associated with other working capital items, primarily attributable to interest and taxes receivable and (iv) a decrease of $31.3 million in 2002 cash attributable to deferred purchased gas costs. The $20 million pension contribution made in April 2002 was deductible under Internal Revenue Service regulations but was not required to be made under ERISA minimum contribution guidelines.

"Net Cash Flows Provided by Operating Activities" increased from $167.1 million in 2000 to $437.3 million in 2001, an increase of $270.2 million, or 162%. This increase is primarily due to (i) a decrease

of $106.7 million in cash flows used for discontinued operations, primarily attributable to the termination of our receivables sales program (see "Short-term Liquidity and Financing Transactions" following), (ii) a $117.5 million increase in cash distributions received in 2001 attributable to our interest in Kinder Morgan Energy Partners and (iii) a $20.8 million increase in cash inflow in 2001 due to decreased deferred purchase gas costs resulting from lower natural gas prices.

In general, distributions from Kinder Morgan Energy Partners are declared in the month following the end of the quarter to which they apply and are paid in the month following the month of declaration to the general partner and unit holders of record as of the end of the month of declaration. Therefore, the accompanying Statements of Consolidated Cash Flows for 2002, 2001 and 2000 reflect the receipt of $310.3 million, $238.8 million and $121.3 million, respectively, of cash distributions from Kinder Morgan Energy Partners for (i) the fourth quarter of 2001 and the first nine months of 2002, (ii) the fourth quarter of 2000 and the first nine months of 2001 and (iii) the fourth quarter of 1999 and the first nine months of 2000, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2002 total $87.0 million and $326.9 million, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2001 total $70.3 million and $264.5 million, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2000 totaled $44.5 million and $149.9 million, respectively. The increase in distributions during 2002 and 2001 reflects, among other factors, acquisitions made by Kinder Morgan Energy Partners and improvements in its results of operations. Summarized financial information for Kinder Morgan Energy Partners is contained in Note 2 of the accompanying Notes to Consolidated Financial Statements.

Net Cash Flows from Investing Activities

"Net Cash Flows Used in Investing Activities" decreased from $1.3 billion in 2001 to $835.3 million in 2002, a decrease of $439.4 million. This decreased use of cash is principally due to the fact that 2001 included a $1.0 billion cash outflow versus a $331.9 million cash outflow during 2002 for investments in Kinder Morgan Energy Partners, principally for the purchase of i-units. This favorable variance was partially offset by (i) an increase of $132.6 million in 2002 for investments in power plants, (ii) an increase of $50.8 million in capital expenditures in 2002, principally for the Natural Gas Pipeline Company of America pipeline extension to East St. Louis, Illinois, (iii) a $16.5 million 2002 cash outflow for an investment in Horizon Pipeline Company and (iv) the fact that 2001 included $25.7 million of proceeds from discontinued operations sold during 2000. Incremental investment in the TransColorado Pipeline system totaled $104.7 million in 2001 (as we retired our 50% share of its debt) and $95.6 million (net of cash acquired) in 2002 (as we acquired an incremental 50% interest).

"Net Cash Flows Provided by (Used in) Investing Activities" decreased from a source of $498.7 million in 2000 to a use of $1.3 billion in 2001, a net increased cash use of $1.8 billion. This increased use of cash is principally due to (i) an outflow of $1.0 billion in 2001 for additional investment in Kinder Morgan Energy Partners, (ii) a $500.3 million decrease in cash inflows due to the fact that 2000 cash flows included proceeds from our December 1999 and December 2000 transfers of certain assets and interests to Kinder Morgan Energy Partners, (iii) an outflow of $51.0 million in 2001 for investments in power plant facilities, (iv) an outflow of $104.7 million in 2001 for additional investment in TransColorado Gas Transmission Company (in the form of paydown of debt) and (v) a $128.4 million decrease in cash flows from discontinued investing activities in 2001 as a result of (1) $25.7 million received in 2001 for discontinued operations sold during 2000 and (2) for 2000, an inflow of $163.9 million received for discontinued operations sold, partially offset by an outflow of $59.9 million for a lease buyout on assets included in discontinued operations prior to divestiture. Please refer to Notes 4 and 8 of the accompanying Notes to Consolidated Financial Statements for additional information regarding these transactions.

Total proceeds received in 2001 from asset sales were $32.8 million, of which $25.7 million represented proceeds from the 2000 sale of our gathering and processing businesses in Oklahoma, Kansas and West Texas as well as our marketing and trading business to ONEOK. During the year 2000, major asset dispositions included (i) Kinder Morgan Texas Pipeline, the Casper and Douglas Natural Gas Gathering and Processing Systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. to Kinder Morgan Energy Partners, (ii) gathering and processing businesses in Oklahoma, Kansas and West Texas as well as our marketing and trading business to ONEOK, (iii) three natural gas gathering systems and a natural gas processing facility to WBI Holdings, Inc. and (iv) certain assets within Wildhorse Energy Partners, LLC to Tom Brown, Inc. Total proceeds received in 2000 from asset sales were $730.3 million of which $330 million represented proceeds from a 1999 transfer of assets to Kinder Morgan Energy Partners. Notes 4 and 8 of the accompanying Notes to Consolidated Financial Statements and "Net Cash Flows from Financing Activities" following contain more information concerning these transactions.

Net Cash Flows from Financing Activities

"Net Cash Flows Provided by Financing Activities" decreased from $711.6 million in 2001 to $411.8 million in 2002, a decrease of $299.8 million. This decrease is principally due to (i) the fact that 2001 and 2002 included proceeds, net of issuance costs, of $888.1 million and $328.6, respectively, from the issuance of Kinder Morgan Management shares, (ii) a $747.6 million decrease during 2002 in net short-term borrowing, (iii) the issuance of $200 million of Floating Rate Notes in 2001 and the repayment of those notes during 2002 and (iv) $60.5 million of cash used in 2002 for the early retirement of our 7.85% debentures due September 1, 2022 and our 8.35% sinking fund debentures due September 15, 2022 (see Note 13 of the accompanying Notes to Consolidated Financial Statements). Partially offsetting this net decrease in cash inflows were (i) $995.6 million of net proceeds received in 2002 from the issuance of our 6.50% Senior Notes due September 1, 2012, (ii) the fact that 2001 included a $495.7 million cash outflow for the early extinguishment of three series of debt securities (see Note 13 of the accompanying Notes to Consolidated Financial Statements) and (iii) a reduction of $116.6 million in 2002 purchases of treasury stock.

"Net Cash Flows Provided by (Used in) Financing Activities" increased from a use of $550.3 million in 2000 to a source of $711.6 million in 2001, a net increased source of cash of $1.3 billion. This increase is principally due to (i) net proceeds of $888.1 million in 2001 from the issuance of membership shares by Kinder Morgan Management, (ii) $495.7 million of cash used in 2001 for the early extinguishment of three series of debt securities, (iii) $265.7 million of cash used in 2001 to repurchase a portion of our outstanding common stock, (iv) proceeds of $460.4 million in 2001 from the issuance of 13,382,474 shares of additional common stock due to the maturity of our Premium Equity Participating Security Units, primarily offset by cash used for the retirement of the $400 million of 6.45% Series of Senior Notes and (v) a change in net short-term borrowing of $798.2 million principally due to (1) a reduction in net short-term borrowing in 2000 facilitated by cash inflows from investing activities (see "Net Cash Flows from Investing Activities" above) and (2) an increase in net short-term borrowing in 2001, principally to fund a portion of the early extinguishment of long-term debt and the reacquisition of a portion of our outstanding common shares, in each case as discussed preceding. Notes 3 and 13 of the accompanying Notes to Consolidated Financial Statements contain additional information on these matters.

Short-term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are our revolving bank facilities, our commercial paper program (which is supported by our revolving bank facilities) and cash provided by operations. As of

December 31, 2002, we had available a $430 million 364-day facility dated October 15, 2002, and a $345 million three-year revolving credit agreement dated October 15, 2002. These bank facilities can be used for general corporate purposes, including as backup for our commercial paper program. At December 31, 2002 and January 31, 2003, we had no bank borrowings or commercial paper issued and outstanding. After inclusion of applicable letters of credit, the remaining available borrowing capacity under the bank facilities was $746.3 million at December 31, 2002 and January 31, 2003. The bank facilities include covenants that are common in such arrangements. For example, both facilities require consolidated debt to be less than 65% of consolidated capitalization. In addition, both of the bank facilities require the debt of consolidated subsidiaries to be less than 10% of our consolidated debt and require the consolidated debt of each material subsidiary to be less than 65% of our consolidated total capitalization. Also, both credit agreements require that our consolidated net worth (inclusive of trust preferred securities) be at least $1.7 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the third quarter of 2002.

Our current maturities of long-term debt of $501.3 million at December 31, 2002 principally consisted of our $500 million of 6.45% Series of Senior Notes due 2003. Apart from our current maturities of long-term debt, our current assets exceeded our current liabilities by approximately $55.7 million at December 31, 2002. Given our expected cash flows from operations and our unused debt capacity as discussed preceding, including our three-year revolving credit facility, and based on our projected cash needs in the near term, we do not expect any liquidity issues to arise. Our next significant debt maturities are our $500 million of 6.65% Senior Notes in 2005 and our $300 million of 6.80% Senior Notes in 2008.

On February 14, 2003, we paid a cash dividend on our common stock of $0.15 per share to common stockholders of record as of January 31, 2003.

On November 1, 2002, we retired the full $35 million of our 8.35% Series Sinking Fund Debentures due September 15, 2022 at a premium of 104.175% of the face amount of the debentures. We recorded an extraordinary loss of $1.0 million (net of associated tax benefit of $0.7 million) in connection with this early extinguishment of debt. This loss, and the loss recorded in conjunction with the early extinguishment of debt associated with the retirement of our 7.85% Series Debentures described below, are included under the caption "Extraordinary Item, Loss on Early Extinguishment of Debt" in the accompanying Consolidated Statements of Operations for 2002. These losses will be reclassified to continuing operations beginning with 2003 reporting as a result of our implementation of Statement of Financial Accounting Standards ("SFAS") No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.

On October 10, 2002, we retired our $200 million of Floating Rate Notes due October 10, 2002, utilizing a combination of cash and incremental short-term debt. Effective September 1, 2002, we retired our $24 million of 7.85% Series Debentures due September 1, 2022 at par. We recorded an extraordinary loss of $420,000 (net of associated tax benefit of $275,000) in conjunction with this early extinguishment of debt, consisting of the unamortized debt expense associated with these debentures.

On August 27, 2002, we issued $750 million of our 6.50% Senior Notes due September 1, 2012, in an offering made pursuant to Rule 144A of the regulations of the Securities and Exchange Commission, with registration rights. The proceeds were used to retire our short-term notes payable then outstanding, with the balance invested in short-term commercial paper and money market funds. On October 18, 2002, we commenced an exchange offer to exchange these notes for our 6.50% Senior Notes due September 1, 2012, which have been registered under the Securities Act of 1933. These new notes have the same form and terms and evidence the same debt as the original notes, and were offered for

exchange to satisfy our obligation to exchange the original notes for registered notes. In December 2002 we re-opened this issue and sold an additional $250 million of 6.50% Senior Notes, which are also expected to be exchanged for registered securities pursuant to our currently effective registration statement on Form S-4.

On November 30, 2001, our Premium Equity Participating Security Units matured, which resulted in our receipt of $460 million in cash and our issuance of 13,382,474 shares of additional common stock. We used the cash proceeds to retire the $400 million of 6.45% Series of Senior Notes that became due on the same date and a portion of our short-term borrowings then outstanding.

On October 10, 2001, we issued $200 million of Floating Rate Notes due October 10, 2002 in an offering made pursuant to Rule 144A of the regulations of the Securities and Exchange Commission. These notes bore interest at the three-month London Interbank Offered Rate (LIBOR) plus 95 basis points, with interest paid quarterly. The proceeds from the offering were used to retire a portion of our short-term borrowings then outstanding. As discussed above, these notes have been retired.

On September 10, 2001, we retired our $45 million of 9.625% Series Sinking Fund Debentures due March 1, 2021, utilizing incremental short-term borrowings. In March 2001, we retired (i) our $400 million of Reset Put Securities due March 1, 2021 and (ii) our $20 million of 9.95% Series Sinking Fund Debentures due 2020, utilizing a combination of cash and incremental short-term borrowings. In conjunction with these early extinguishments of debt, we recorded extraordinary losses of $13.6 million (net of associated tax benefit of $9.0 million). These losses are included under the caption, "Extraordinary Item, Loss on Early Extinguishment of Debt" in the accompanying Consolidated Statements of Operations for 2001 and will be reclassified to continuing operations beginning with 2003 reporting as discussed above.

On August 14, 2001, we announced a program to repurchase $300 million of our outstanding common stock, which program was increased to $400 million and $450 million at February 5, 2002 and July 17, 2002, respectively. As of December 31, 2002, we had repurchased a total of approximately $414.7 million (8,308,200 shares) of our outstanding common stock under the program, of which $144.3 million (3,013,400 shares) and $270.4 million (5,294,800 shares) were repurchased in the years ended December 31, 2002 and 2001, respectively. In January 2003, our board of directors approved a plan to purchase shares of Kinder Morgan Management on the open market. Through February 1, 2003, such purchases were insignificant.

As further described under "Risk Management" following, in August 2001, we entered into $1 billion face value of fixed-to-floating interest rate swaps, effectively converting the interest expense associated with two of our fixed-rate debt issues to a floating rate based on the three-month LIBOR. In September 2002, we entered into an incremental $750 notional amount of swaps, effectively converting our $750 million of 6.50% Senior Notes due September 1, 2012 to a LIBOR-based floating rate. These swaps are accounted for as fair value hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

Kinder Morgan Management. We have certain rights and obligations with respect to these securities. By approval of Kinder Morgan Management shareholders other than us, effective at the close of business on July 23, 2002, we no longer have an obligation to, upon presentation by the holder thereof, exchange publicly held Kinder Morgan Management shares for either Kinder Morgan Energy Partners' common units that we own or, at our election, cash.

In the initial public offering, 10 percent of Kinder Morgan Management's shares were purchased by us, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which is consolidated in our financial statements) purchased by the public created an additional minority interest on our balance sheet of $892.7 million at the time of the transaction. On August 6, 2002, Kinder Morgan Management closed the issuance and sale of 12,478,900 limited liability shares in an underwritten public offering. The net proceeds of approximately $328.6 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. We did not purchase any of the offered shares. In addition, during 2002, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $3.4 million. The earnings recorded by Kinder Morgan Management that are attributable to its shares held by the public are reported as "minority interest" in our consolidated statements of operations. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management's 2002 Annual Report on Form 10-K.

In September 1999, we established an accounts receivable sales facility that provided up to $150 million of additional liquidity. In accordance with this agreement, we received proceeds of $150 million on September 30, 1999. Cash flows associated with this facility are included with "Cash flows from Operating Activities" in the accompanying Consolidated Statements of Cash Flows in 2000. In February 2000, we reduced our participation in this receivables sales program by $124.9 million, principally as a result of our then-pending disposition of our wholesale gas marketing business. On April 25, 2000, we repaid the residual balance and terminated the agreement.

Capital Expenditures and Commitments

Capital expenditures in 2002 were $175.0 million. The 2003 capital expenditure budget totals approximately $141.1 million. We expect that funding for the capital expenditure budget will be provided from internal sources and, if necessary, incremental borrowings. Approximately $1.0 million of this amount had been committed for the purchase of plant and equipment at December 31, 2002. Additional information on commitments is contained under "Liquidity and Capital Resources" elsewhere herein and in Note 18 of the accompanying Notes to Consolidated Financial Statements.

Litigation and Environmental

Our anticipated environmental capital costs and expenses for 2003, including expected costs for remediation efforts, are approximately $ 3.9 million, compared to approximately $ 5.75 million of such costs and expenses incurred in 2002. A substantial portion of our environmental costs are either recoverable through insurance and indemnification provisions or have previously recorded liabilities associated with them. We had an established environmental reserve of approximately $15.5 million at December 31, 2002, to address remediation issues associated with approximately 35 projects. This reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort and to identify if the reserve allocation is appropriately valued. In assessing environmental risks in conjunction with proposed

acquisitions, we review records relating to environmental issues, conduct site inspections, interview employees, and, if appropriate, collect soil and groundwater samples. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with environmental regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new or existing facts or conditions will not cause us to incur significant unanticipated costs.

Refer to Notes 10(A) and 10(B) of the accompanying Consolidated Financial Statements for additional information on our pending environmental and litigation matters, respectively. We believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact.

Regulation

See Note 9 of the accompanying Notes to Consolidated Financial Statements for additional information regarding regulatory matters.

Risk Management

The following discussion should be read in conjunction with Note 15 of the accompanying Notes to Consolidated Financial Statements, which contains additional information on our risk management activities.

Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, "Statement 133." Statement 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. Statement 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, Statement 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.

We enter into derivative contracts solely for the purpose of hedging exposures that accompany our normal business activities. As a result of the adoption of Statement 133, the fair value of our derivative financial instruments utilized for hedging activities as of January 1, 2001 (a loss of $11.9 million) was reported as accumulated other comprehensive income. In accordance with the provisions of Statement 133, we designated these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs.

We enter into these transactions only with counterparties whose debt securities are rated investment grade by the major rating agencies. In general, the risk of default by these counterparties is low. During the fourth quarter of 2001, however, 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 Statement 133. Upon making that determination, we (i) ceased to account for those derivatives as hedges, (ii) entered into new derivative transactions with other counterparties to replace our position with Enron, (iii) designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions and (iv) recognized a $5.0 million pre-tax 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.

Our businesses require that we purchase, sell and consume natural gas. Specifically, we purchase, sell and/or consume natural gas (i) to serve our regulated natural gas distribution sales customers, (ii) to serve certain of our retail natural gas distribution customers in areas where regulatory restructuring has provided for competition in natural gas supply, for customers who have selected the Company as their supplier of choice under our "Choice Gas" program, (iii) as fuel in certain of our Colorado power generation facilities, (iv) as fuel for compressors located on Natural Gas Pipeline Company of America's pipeline system and (v) for operational sales of gas by Natural Gas Pipeline Company of America. With respect to item (i), we have no commodity risk because the regulated retail gas distribution regulatory structure provides that actual gas cost is "passed-through" to our customers. With respect to item (iii), only one of these power generation facilities is not covered by a long-term, fixed price gas supply agreement at a level sufficient for the current and projected capacity utilization. With respect to item (iv), this fuel is supplied by in-kind fuel recoveries that are part of the transportation tariff. Items (ii), (v) and the one power facility included under item (iii) that is not covered by a long-term fixed-price natural gas supply agreement, give rise to natural gas commodity price risk which we have chosen to substantially mitigate through our risk management program. We provide this mitigation through the use of financial derivative products, and we do not utilize these derivatives for any purpose other than risk mitigation.

applicable, over-the-counter basis swaps to mitigate the risk associated with the difference in price changes between Henry Hub (NYMEX) basis and the expected physical delivery location. In addition, we mitigate a portion of the volumetric risk through the purchase of over-the-counter natural gas options. The time period covered by this risk management strategy does not extend beyond one year.

With respect to the power generation facility described above that is not covered by an adequately sized, fixed-price gas supply contract, we are exposed to changes in the price of natural gas as we purchase it to use as fuel for the electricity-generating turbines. In order to mitigate this exposure, we purchase natural gas futures on the NYMEX and, as discussed above, over-the-counter basis swaps on the NYMEX, in amounts representing our expected fuel usage in the near term. In general, we do not hedge this exposure for periods longer than one year.

With respect to operational sales of natural gas made by Natural Gas Pipeline Company of America, we are exposed to risk associated with changes in the price of natural gas during the periods in which these sales are made. We mitigate this risk by selling natural gas futures and, as discussed above, over-the-counter basis swaps, on the NYMEX in the periods in which we expect to make these sales. In general, we do not hedge this exposure for periods in excess of 18 months.

We use a Value-at-Risk model to measure the risk of price changes in the natural gas and natural gas liquids markets. Value-at-Risk is a statistical measure of how much the marked-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We use a closed form model to evaluate risk on a daily basis. Our Value-at-Risk computations use a confidence level of 97.7 percent for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7 percent probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk amount presented. Instruments evaluated by the model include forward physical gas, storage and transportation contracts and financial products including commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. During 2002, Value-at-Risk reached a high of $9.4 million and a low of $8.6 million. Value-at-Risk at December 31, 2002, was $9.4 million and, based on quarter-end values, averaged $8.8 million for 2002.

Our calculated Value-at-Risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivatives assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. In addition, as discussed preceding, we enter into these derivatives solely for the purpose of mitigating the risks that accompany our normal business activities and, therefore, the change in the market value of our portfolio of derivatives is, with the exception of a minor amount of hedging inefficiency, offset by changes in the value of the underlying physical transactions.

During 2002 and 2001, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized approximately $46,000 and $5,000 of pre-tax loss during 2002 and 2001, respectively, as a result of ineffectiveness of these hedges, which amounts are reported within the caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statements of Income for 2002 and 2001. There was no component of these derivative instruments' gain or loss excluded from the assessment of hedge effectiveness.

reclassify into earnings, during 2003, substantially all of the $20.9 million balance in accumulated other comprehensive income representing unrecognized net losses on derivative activities at December 31, 2002. During 2002, no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

We also provide certain administrative risk management services to Kinder Morgan Energy Partners, although Kinder Morgan Energy Partners retains the obligations and rights arising from all derivative transactions entered into on its behalf.

Our business activities expose us to credit risk with respect to collection of accounts receivable. In order to mitigate that risk, we routinely monitor the credit status of our existing and potential customers. When customers' credit ratings do not meet our requirements for the extension of unsupported credit, we obtain cash prepayments or letters of credit. Note 1 (G) of the accompanying Notes to Consolidated Financial Statements provides information on the amount of prepayments we have received.

In order to maintain a cost effective capital structure, it is our policy to borrow funds utilizing a mixture of fixed-interest-rate and floating-interest-rate debt. In August 2001, in order to move closer to a mix of 50% fixed, 50% floating, we entered into fixed-to-floating interest rate swap agreements with a notional principal amount of $1.0 billion. In September 2002, we entered into similar fixed-to-floating interest rate swap agreements with a notional principal amount of $750 million. These agreements effectively converted the interest expense associated with our 6.65% Senior Notes due in 2005, our 7.25% Debentures due in 2028 and our 6.50% Senior Notes due in 2012 from fixed rates to floating rates based on three-month LIBOR plus a credit spread. These swaps have been designated as fair value hedges as defined by Statement 133. These swaps meet the conditions required to assume no ineffectiveness under Statement 133 and, therefore, we have accounted for them utilizing the "shortcut" method prescribed for fair value hedges. Accordingly, the carrying value of the swap is adjusted to its fair value as of each reporting period, with an offsetting entry to adjust the carrying value of the debt whose fair value is being hedged. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually. Based on the long-term debt effectively converted to floating rate debt as a result of the swap discussed above, at December 31, 2002, the market risk related to a one percent change in interest rates would result in a $17.5 million annual impact on pre-tax income.

Recent Accounting Pronouncements

In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. The provisions of this statement related to the rescission of FASB Statement No. 4 are effective for fiscal years beginning after May 15, 2002, the provisions related to FASB Statement No. 13 are effective for transactions occurring after May 15, 2002, and all other provisions of this statement are effective for financial statements issued on or after May 15, 2002. The principal effect of this statement on our reporting is that, beginning with reporting for 2003, previously recorded extraordinary losses on early retirement of debt, as well as any such future losses, will not be classified as extraordinary items but will, instead, be reported as part of income from continuing operations and separately described, if material.

In January 2003, The FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities. This interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of variable interest entities (some, but not all, of which have been referred to as "special purpose entities") with certain defined characteristics. One provision of the interpretation increases the minimum amount of third-party investment required to support non-

consolidation from 3% to 10%. Certain of the disclosure provisions contained in the interpretation are effective for financial statements issued after January 31, 2003, all of the provisions are immediately applicable to variable interest entities created after January 31, 2003 and public entities with variable interests in entities created before February 1, 2003 are required to apply the provisions (other than the transition disclosure provisions) to that entity no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003. The principal impact of this interpretation on us is that, upon implementation of this interpretation, we expect to begin consolidation of Triton Power Company LLC, the lessee of the Jackson, Michigan power generation facility. We operate and have a preferred interest in this entity in which the common interest is owned by others. Triton Power Company LLC has no debt but, as a result of this consolidation, we will include the lease obligation on the Jackson plant in our consolidated financial statements. We expect to apply the provisions of the statement beginning with the third quarter of 2003 and, at that time, the total remaining lease payments under the operating lease will be $553.3 million and will be $21.7 million, $20.3 million, $20.3 million, $20.4 million and $20.6 million for 2004 through 2008, respectively. Because the lease is an operating lease, it will not be recorded as a liability on our consolidated balance sheet. The difference between the earnings impact under consolidation and under the currently-applied cost method is not expected to be material.

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This Statement contains disclosure requirements that provide descriptions of asset retirement obligations and reconciliations of changes in the components of those obligations. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Earlier applications are encouraged. We have a number of assets with associated retirement obligations that are subject to the provisions of this statement. With respect to the Natural Gas Pipeline Company of America system, 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 not 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 retail natural gas distribution operations, we generally are not obligated to remove our equipment or otherwise perform remediation related to our utility assets. We do have an obligation to perform removal and remediation activities associated with certain wells utilized in conjunction with our storage facilities. With respect to our power activities, we generally are not obligated to perform removal or remediation activities associated with our owned power generation facilities and any such obligations associated with the power generation facilities we do not own are the responsibility of others. 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 will be settled. Our first quarter 2003 financial statements will reflect an obligation for those asset retirement obligations that can be reasonably estimated.

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. The interpretive guidance incorporated from Interpretation No. 34 continues to be required for financial statements for fiscal years ending after June 15, 1981. For more information, see heading titled "Liquidity and Capital Resources" preceding and Note 18 of the accompanying Notes to Consolidated Financial Statements.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. This amendment to FASB Statement No. 123 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 FASB Statement 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.

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. 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. We will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002.

Information Regarding Forward-looking Statements

This filing includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," "will," or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, operating results or the ability to generate sales, income or cash flow or to pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include but are not limited to the following:

•	price trends, stability and overall demand for natural gas and electricity in the United States;
•	economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

•	changes in our tariff rates or those of Kinder Morgan Energy Partners implemented by the FERC or another regulatory agency or, with respect to Kinder Morgan Energy Partners, the California Public Utilities Commission;
•	Kinder Morgan Energy Partners' ability to integrate any acquired operations into its existing operations;

•	Kinder Morgan Energy Partners ability and our ability to acquire new businesses and assets and to make expansions to our respective facilities;
•	difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to Kinder Morgan Energy Partners' bulk terminals;
•	Kinder Morgan Energy Partners' ability and our ability to successfully identify and close acquisitions and make cost-saving changes in operations;
•	shut-downs or cutbacks at major refineries, petrochemical or chemical plants, utilities, military bases or other businesses that use or supply our services;
•	changes in laws or regulations, third party relations and approvals, decisions of courts, regulators and governmental bodies may adversely affect our business or our ability to compete;
•	our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;
•	our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;
•	interruptions of electric power supply to facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;
•	acts of sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits;
•	the condition of the capital markets and equity markets in the United States;
•	the political and economic stability of the oil producing nations of the world;
•	national, international, regional and local economic, competitive and regulatory conditions and developments;
•	the ability to achieve cost savings and revenue growth;
•	rates of inflation;
•	interest rates;
•	the pace of deregulation of retail natural gas and electricity;
•	the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain

	agricultural products; and
•	the timing and success of business development efforts.

You should not put undue reliance on any forward-looking statements.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

Information required by this item is in Item 7 under the heading "Risk Management."

Item 8.

Financial Statements and Supplementary Data.

INDEX

	Page

Report of Independent Accountants	57
Consolidated Statements of Operations	58
Consolidated Statements of Comprehensive Income	59
Consolidated Balance Sheets	60
Consolidated Statements of Stockholders' Equity	61
Consolidated Statements of Cash Flows	62
Notes to Consolidated Financial Statements	63-105
Selected Quarterly Financial Data (unaudited)	106-107

Report of Independent Accountants

To the Board of Directors
and Stockholders of Kinder Morgan, Inc.

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan, Inc. and its subsidiaries 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 Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with 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 1(N) to the consolidated financial statements, the Company changed its method of accounting for goodwill and other intangible assets effective January 1, 2002.

As discussed in Note 15 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Houston, Texas
February 21, 2003

CONSOLIDATED STATEMENTS OF OPERATIONS
KINDER MORGAN, INC. AND SUBSIDIARIES

	Year Ended December 31,
	2002	2001	2000
	(In thousands except per share amounts)
Operating Revenues:
Natural Gas Transportation and Storage	$ 628,172	$ 645,369	$ 596,774
Natural Gas Sales	312,764	301,994	1,965,633
Other	74,319	107,544	116,549
Total Operating Revenues	1,015,255	1,054,907	2,678,956

Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales	311,224	339,301	1,925,971
Operations and Maintenance	125,565	126,553	164,268
General and Administrative	73,496	73,319	59,799
Depreciation and Amortization	106,496	105,680	106,007
Taxes, Other Than Income Taxes	27,282	25,735	27,768
Revaluation of Power Investments	134,525	-	-
Total Operating Costs and Expenses	778,588	670,588	2,283,813
Operating Income	236,667	384,319	395,143

Other Income and (Expenses):
Kinder Morgan Energy Partners:
Equity in Earnings	392,135	277,504	140,913
Amortization of Equity-method Goodwill	-	(25,644)	(27,593)
Equity in Earnings (Losses) of Other Equity Investments	12,791	245	(6,586)
Interest Expense, Net	(161,935)	(216,200)	(243,155)
Minority Interests	(55,720)	(36,740)	(24,121)
Other, Net	21,141	23,752	72,565
Total Other Income and (Expenses)	208,412	22,917	(87,977)
Income from Continuing Operations Before Income Taxes	445,079	407,236	307,166
Income Taxes	135,912	168,601	123,017
Income from Continuing Operations	309,167	238,635	184,149
Loss on Disposal of Discontinued Operations	(4,986)	-	(31,734)
Income Before Extraordinary Item	304,181	238,635	152,415
Extraordinary Item - Loss on Early Extinguishment of Debt,
Net of Income Tax Benefit of $893 and $9,044	(1,456)	(13,565)	-
Net Income	$ 302,725	$ 225,070	$ 152,415
	===========	===========	===========

Basic Earnings (Loss) Per Common Share:
Income From Continuing Operations	$ 2.53	$ 2.07	$ 1.62
Loss on Disposal of Discontinued Operations	(0.04)	-	(0.28)
Extraordinary Item - Loss on Early Extinguishment of Debt	(0.01)	(0.12)	-
Total Basic Earnings Per Common Share	$ 2.48	$ 1.95	$ 1.34
	===========	===========	===========

Number of Shares Used in Computing Basic
Earnings (Loss) Per Common Share (Thousands)	122,184	115,243	114,063
	===========	===========	===========

Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$ 2.50	$ 1.97	$ 1.61
Loss on Disposal of Discontinued Operations	(0.04)	-	(0.28)
Extraordinary Item - Loss on Early Extinguishment of Debt	(0.01)	(0.11)	-
Total Diluted Earnings Per Common Share	$ 2.45	$ 1.86	$ 1.33
	===========	===========	===========

Number of Shares Used in Computing Diluted
Earnings (Loss) Per Common Share (Thousands)	123,402	121,326	115,030
	===========	===========	===========

Dividends Per Common Share	$ 0.30	$ 0.20	$ 0.20
	===========	===========	===========

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
KINDER MORGAN, INC. AND SUBSIDIARIES

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Net Income	$ 302,725	$ 225,070	$ 152,415
Other Comprehensive Income, Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes
(Net of Tax Benefit of $23,880 and Tax of $24,068, respectively)	(36,837)	36,102	-
Reclassification of Change in Fair Value of Derivatives to Net Income
(Net of Tax of $4,467 and Tax Benefit of $9,567, respectively)	6,031	(14,351)	-
Reclassification of Unrealized Gain on Available-for-Sale
Securities (Net of Tax of $1,068)	-	-	1,602
Adjustment to Recognize Minimum Pension Liability
(Net of Tax Benefit of $10,865)	(17,727)	-	-
Equity in Other Comprehensive Income of Equity Method
Investees (Net of Tax Benefit of $5,996)	(9,784)	-	-
Minority Interest in Other Comprehensive Income of Equity
Method Investees	3,730	-	-
Cumulative Effect of Transition Adjustment (Net of
Tax Benefit of $7,922)	-	(11,883)	-
Total Other Comprehensive Income	(54,587)	9,868	1,602

Comprehensive Income	$ 248,138	$ 234,938	$ 154,017
	==========	==========	==========

The accompanying notes are an integral part of these statements.

CONSOLIDATED BALANCE SHEETS
KINDER MORGAN, INC. AND SUBSIDIARIES

	December 31,
	2002	2001
	(In thousands)
ASSETS
Current Assets:
Cash and Cash Equivalents	$ 35,653	$ 16,134
Restricted Deposits	2,783	15,010
Notes Receivable:
Related Party	-	22,576
Other	-	18,890
Accounts Receivable, Net:
Trade	82,258	138,567
Related Parties	48,054	29,502
Inventories	62,760	61,959
Gas Imbalances	32,033	24,977
Other	157,454	52,425
	420,995	380,040
Investments:
Kinder Morgan Energy Partners	2,034,160	1,772,027
Goodwill	990,878	1,055,767
Other	285,883	427,408
	3,310,921	3,255,202

Property, Plant and Equipment, Net	6,048,107	5,703,952

Deferred Charges and Other Assets	322,727	173,927
Total Assets	$10,102,750	$ 9,513,121
	===========	===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current Maturities of Long-term Debt	$ 501,267	$ 206,267
Notes Payable	-	423,785
Accounts Payable:
Trade	88,227	160,309
Related Parties	50	70,606
Accrued Interest	80,158	60,373
Accrued Expenses	49,580	43,399
Accrued Taxes	27,355	14,933
Gas Imbalances	50,394	40,158
Other	69,501	64,302
	866,532	1,084,132
Other Liabilities and Deferred Credits:
Deferred Income Taxes	2,435,780	2,428,504
Other	210,869	243,008
	2,646,649	2,671,512
Long-term Debt	2,991,770	2,404,967

Kinder Morgan-Obligated Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan	275,000	275,000

Minority Interests in Equity of Subsidiaries	967,802	817,513
Commitments and Contingent Liabilities (Notes 3, 10 and 18)
Stockholders' Equity:
Preferred Stock (Note 14)	-	-
Common Stock-
Authorized - 150,000,000 Shares, Par Value $5 Per Share; Outstanding - 129,861,650 and 129,092,689 Shares, Respectively, Before Deducting 8,168,241 and 5,165,911 Shares Held in Treasury	649,308	645,463
Additional Paid-in Capital	1,681,042	1,652,846
Retained Earnings	486,062	219,995
Treasury Stock	(406,630)	(263,967)
Deferred Compensation	(10,066)	(4,208)
Accumulated Other Comprehensive Income	(44,719)	9,868
Total Stockholders' Equity	2,354,997	2,259,997
Total Liabilities and Stockholders' Equity	$10,102,750	$ 9,513,121
	===========	===========

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
KINDER MORGAN, INC. AND SUBSIDIARIES

	Year Ended December 31,
	2002		2001		2000
	Shares	Amount	Shares	Amount	Shares	Amount
	(Dollars in thousands)
COMMON STOCK:
Beginning Balance	129,092,689	$ 645,463	114,578,800	$ 572,894	112,838,379	$ 564,192
Acquisitions of Businesses	-	-	-	-	946,207	4,731
Conversion of Premium Equity
Participating Security Units (PEPS)	-	-	13,382 474	66,912	-	-
Employee Benefit Plans	768,961	3,845	1,131,415	5,657	794,214	3,971
Ending Balance	129,861,650	649,308	129,092,689	645,463	114,578,800	572,894

ADDITIONAL PAID-IN CAPITAL:
Beginning Balance		1,652,846		1,189,270		1,203,008
Costs Related to PEPS Offering		-		(504)		(1,151)
Revaluation of Kinder Morgan Energy
Partners (KMP) Investment (Note 5)		(29,350)		28,322		(51,074)
Gain on KMP Units Exchanged for
Kinder Morgan Management
(KMR) Shares (Note 3)		35,720		15,722		-
Issuance Costs Related to
KMR Offering		-		(4,548)		-
Shares Issued for KMR Shares		(197)		-		-
Acquisition of Businesses		(2)		(72)		23,824
Conversion of PEPS		-		393,446		-
Employee Benefit Plans		22,025		31,210		14,663
Ending Balance		1,681,042		1,652,846		1,189,270

RETAINED EARNINGS (DEFICIT):
Beginning Balance		219,995		17,787		(111,841)
Net Income		302,725		225,070		152,415
Cash Dividends, Common Stock		(36,658)		(22,862)		(22,787)
Ending Balance		486,062		219,995		17,787

TREASURY STOCK AT COST:
Beginning Balance	(5,165,911)	(263,967)	(96,140)	(2,327)	(172,402)	(4,142)
Treasury Stock Acquired	(3,013,400)	(144,269)	(5,294,800)	(270,410)	-	-
Treasury Stock Issued	17,827	889	-	-	-	-
Employee Benefit Plans	(6,757)	717	225,029	8,770	76,262	1,815
Ending Balance	(8,168,241)	(406,630)	(5,165,911)	(263,967)	(96,140)	(2,327)

OTHER:

DEFERRED COMPENSATION:
PLANS:
Beginning Balance		(4,208)		-		-
Current Year Activity		(5,858)		(4,208)		-
Ending Balance		(10,066)		(4,208)		-

ACCUMULATED OTHER
COMPREHENSIVE
INCOME (Net Of Tax):
Beginning Balance		9,868		-		(1,602)
Unrealized Gain (Loss) on Derivatives
Utilized for Hedging Purposes		(30,806)		21,751		-
Adjustment to Recognize Minimum
Pension Liability		(17,727)		-		-
Equity in Other Comprehensive
Income of Equity Method Investees		(9,784)		-		-
Minority Interest in Other
Comprehensive Income of
Equity Method Investees		3,730		-		-
Sale of Tom Brown, Inc.
Common Stock		-		-		1,602
Cumulative Effect Transition
Adjustment		-		(11,883)		-
Ending Balance		(44,719)		9,868		-

TOTAL STOCKHOLDERS'
EQUITY	121,693,409	$ 2,354,997	123,926,778	$ 2,259,997	114,482,660	$ 1,777,624
	===========	===========	===========	===========	===========	===========

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
KINDER MORGAN, INC. AND SUBSIDIARIES

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$ 302,725	$ 225,070	$ 152,415
Adjustments to Reconcile Net Income to Net Cash Flows
from Operating Activities:
Loss from Discontinued Operations, Net of Tax	4,986	-	31,734
Loss from Revaluation of Power Investments	134,525	-	-
Extraordinary Loss on Early Extinguishment of Debt	2,349	22,609	-
Depreciation and Amortization	106,496	105,680	106,007
Deferred Income Taxes	55,748	129,911	105,714
Equity in Earnings of Kinder Morgan Energy Partners	(392,135)	(251,860)	(113,320)
Distributions from Kinder Morgan Energy Partners	310,290	238,775	121,323
Equity in (Earnings) Losses of Other Investments	(12,791)	(245)	6,586
Minority Interests in Income of Consolidated Subsidiaries	33,808	14,827	2,208
Deferred Purchased Gas Costs	(7,792)	23,499	2,685
Net Gains on Sales of Facilities	(2,566)	(22,621)	(61,684)
Litigation Settlement	(22,050)	-	-
Pension Contribution in Excess of Expense	(18,700)	-	-
Changes in Gas in Underground Storage	5,291	(63,804)	37,726
Changes in Other Working Capital Items [Note 1(Q)]	(40,525)	18,298	(95,483)
Changes in Deferred Revenues	(8,940)	(5,228)	(4,457)
Other, Net	(2,745)	6,128	(13,967)
Net Cash Flows Provided by Continuing Operations	447,974	441,039	277,487
Net Cash Flows Used in Discontinued Operations	(4,930)	(3,737)	(110,399)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	443,044	437,302	167,088

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital Expenditures	(174,953)	(124,171)	(85,654)
Proceeds from Sales to Kinder Morgan Energy Partners	-	-	500,302
Acquisition of TransColorado	(95,560)	-	-
Other Acquisitions	(35,838)	(23,899)	(19,412)
Investment in Kinder Morgan Energy Partners (Note 3)	(331,912)	(1,003,585)	-
Other Investments	(200,958)	(155,903)	(80,511)
Exchange of Kinder Morgan Management Shares	(69)	-	-
Proceeds from Sale of Tom Brown, Inc. Stock	-	-	14,823
Proceeds from Sales of Other Assets	3,949	7,077	14,998
Net Cash Flows Provided by (Used in) Continuing Investing Activities	(835,341)	(1,300,481)	344,546
Net Cash Flows Provided by Discontinued Investing Activities	-	25,742	154,176
NET CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES	(835,341)	(1,274,739)	498,722

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term Debt, Net	(423,785)	323,785	(474,400)
Floating Rate Notes Issued	-	200,000	-
Long-term Debt Issued	1,000,000	-	-
Long-term Debt Retired	(265,292)	(872,185)	(14,055)
Issuance of Shares by Kinder Morgan Management	343,170	942,614	-
Common Stock Issued for Premium Equity Participating Securities	-	460,358	-
Other Common Stock Issued	15,558	31,184	17,773
Premiums Paid on Early Extinguishment of Debt	(1,461)	(30,694)	-
Advances (To) From Unconsolidated Affiliates	(53,003)	7,951	11,511
Discontinued Operations Financing	-	-	(56,750)
Treasury Stock Issued	1,701	2,464	1,877
Treasury Stock Acquired	(149,062)	(265,706)	(62)
Cash Dividends, Common and Preferred	(36,658)	(22,862)	(22,787)
Minority Interests, Net	(384)	375	(2,436)
Premium Equity Participating Securities Contract Fee	-	(10,931)	(10,936)
Debt Issuance Costs	(4,357)	(225)	-
Securities Issuance Costs	(14,611)	(54,480)	-
NET CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES	411,816	711,648	(550,265)

Net Increase (Decrease) in Cash and Cash Equivalents	19,519	(125,789)	115,545
Cash and Cash Equivalents at Beginning of Year	16,134	141,923	26,378
Cash and Cash Equivalents at End of Year	$ 35,653	$ 16,134	$ 141,923
	==========	===========	==========

The accompanying notes are an integral part of these statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations and Summary of Significant Accounting Policies

(A) Nature of Operations

We are an energy transportation, storage and related services provider and have operations in the Rocky Mountain and mid-continent regions, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma, Texas and Wyoming. Services we currently offer or have offered in recent periods include: (i) storing, transporting and selling natural gas, (ii) providing retail natural gas distribution services, and (iii) designing, developing, constructing and operating electric generation facilities. We have both regulated and nonregulated operations. Our common stock is traded on the New York Stock Exchange under the ticker symbol "KMI." During 1999, we acquired Kinder Morgan Delaware as discussed in the following paragraph. As a result, we own, through Kinder Morgan Delaware, the general partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline limited partnership, referred to in these Notes as "Kinder Morgan Energy Partners." We also own a significant limited partner interest in Kinder Morgan Energy Partners and receive a substantial portion of our earnings from returns on our investment in this entity.

In October 1999, K N Energy, Inc. (as we were then named), a Kansas corporation, acquired Kinder Morgan, Inc., a Delaware corporation, referred to in these Notes as "Kinder Morgan Delaware." We then changed our name to Kinder Morgan, Inc. Unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation and formerly known as K N Energy, Inc.) and its consolidated subsidiaries. During 1999, we adopted and implemented plans to discontinue our businesses involved in (i) wholesale marketing of natural gas and natural gas liquids, (ii) gathering and processing of natural gas, including field services and short-haul intrastate pipelines, (iii) direct marketing of non-energy products and services and (iv) international operations. During the fourth quarter of 2000, we determined that, due to the start-up nature of our international operations and the unwillingness of buyers to pay for the value created to date, it was not in the best interests of the Company to dispose of our international operations and, accordingly, we decided to retain them. Additional information concerning discontinued operations is contained in Note 8.

(B) Basis of Presentation

Our consolidated financial statements include the accounts of Kinder Morgan, Inc. and its majority-owned subsidiaries. Investments in jointly owned operations in which we have the ability to exercise significant influence over their operating and financial policies are accounted for under the equity method, as is our investment in Kinder Morgan Energy Partners, which accounting is further described in Note 1(S). All material intercompany transactions and balances have been eliminated. Certain prior year amounts have been reclassified to conform to the current presentation.

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

(C) Accounting for Regulatory Activities

Our regulated utilities are accounted for in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation, which prescribes the circumstances in which the application of generally accepted accounting principles

is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. The following regulatory assets and liabilities are reflected in the accompanying Consolidated Balance Sheets:

	December 31,
	2002	2001
	(In thousands)
REGULATORY ASSETS:
Employee Benefit Costs	$ 6,362	$ 6,355
Debt Refinancing Costs	1,064	1,342
Deferred Income Taxes	15,681	16,405
Purchased Gas Costs	33,439	3,431
Plant Acquisition Adjustments	454	454
Rate Regulation and Application Costs	3,585	2,580
Total Regulatory Assets	60,585	30,567

REGULATORY LIABILITIES:
Employee Benefit Costs	5,967	5,967
Deferred Income Taxes	23,554	26,311
Purchased Gas Costs	19,195	19,890
Total Regulatory Liabilities	48,716	52,168
NET REGULATORY ASSETS (LIABILITIES)	$ 11,869	$ (21,601)
	=========	=========

The purchased gas costs December 31, 2002 balance of $33.4 million shown above as a regulatory asset includes $32.5 million in litigated gas costs. See Note 9 for additional information regarding this matter. As of December 31, 2002, $52.6 million of our regulatory assets and $42.7 million of our regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from 1 to 11 years.

(D) Revenue Recognition Policies

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. Our rate-regulated retail natural gas distribution business bills customers on a monthly cycle billing basis. Revenues are recorded on an accrual basis, including an estimate at the end of each accounting period for gas delivered and, if applicable, title has passed but for which bills have not yet been rendered. With respect to our power generating facility construction activities in 2002 and prior periods, we utilized the percentage of completion method whereby revenues and associated expenses are recognized over the construction period based on work performed in relation to the total expected for the entire project.

We provide various types of natural gas storage and transportation services to customers, principally through Natural Gas Pipeline Company of America's and TransColorado Pipeline's pipeline systems. The natural gas remains the property of these customers at all times. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue ratably over the contract period. The per-unit charge is recognized as revenue when the volumes are delivered to the customers' agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported on firm service.

(E) Earnings Per Share

Basic earnings per common share is computed based on the weighted-average number of common shares outstanding during each period. Diluted earnings per common share is computed based on the weighted-average number of common shares outstanding during each period, increased by the assumed exercise or conversion of securities (stock options and, during periods in which they were outstanding, premium equity participating security units) convertible into common stock, for which the effect of conversion or exercise using the treasury stock method would be dilutive.

	2002	2001	2000
	(In thousands)
Weighted Average Common Shares Outstanding	122,184	115,243	114,063
Premium Equity Participating Security Units	-	4,328	-
Dilutive Common Stock Options	1,218	1,755	967
Shares Used to Compute Diluted Earnings Per Common Share	123,402	121,326	115,030
	========	========	========

Weighted-average stock options outstanding totaling 2.5 million for 2002, 9,200 for 2001 and 307,100 for 2000 were excluded from the diluted earnings per common share calculation because the effect of including them would have been antidilutive. Common shares issuable upon conversion of the premium equity participating security units were not included in diluted earnings per common share calculations in 2000 because to do so would have been antidilutive. These common shares were given dilutive effect in 2001 and are included in the weighted-average common shares outstanding beginning with their issuance in November 2001 as a result of the maturity of the premium equity participating security units. Note 13 (B) contains more information regarding premium equity participating security units, while Note 17 contains more information regarding stock options.

(F) Restricted Deposits

Restricted Deposits consist of monies on deposit with brokers that are restricted to support our risk management activities; see Note 15.

(G) Accounts Receivable

The caption "Accounts Receivable, Net" in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts. 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. In support of credit extended to certain customers, we had received prepayments of $13.5 million at December 31, 2002, included with other current liabilities in the accompanying Consolidated Balance Sheet. The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2002, 2001 and 2000.

Allowance for Doubtful Accounts

	Year Ended December 31,
	2002	2001	2000
	(In millions)
Beginning Balance	$ 3.4	$ 2.3	$ 1.7
Additions: Charged to Cost and Expenses	5.2	6.7	9.9
Deductions: Write-off of Uncollectible Accounts	(3.7)	(5.6)	(9.3)
Ending Balance	$ 4.9	$ 3.4	$ 2.3
	=======	=======	=======

(H) Inventories

	December 31,
	2002	2001
	(In thousands)
Gas in Underground Storage (Current)	$ 49,106	$ 46,451
Materials and Supplies	13,654	15,508
	$ 62,760	$ 61,959
	=========	=========

Inventories are accounted for using the following methods, with the percent of the total dollars at December 31, 2002 shown in parentheses: average cost (28.11%), last-in, first-out (71.29%) and first-in, first-out (0.60%). All non-utility inventories held for resale are valued at the lower of cost or market. The excess of current cost over the reported last-in, first-out value of gas in underground storage valued under that method was not material at December 31, 2002. We also maintain gas in our underground storage facilities on behalf of certain third parties. We receive a fee from our storage service customers but do not reflect the value of their gas stored in our facilities in the accompanying Consolidated Balance Sheets.

(I) Current Assets: Other

	December 31,
	2002	2001
	(In thousands)
Assets Held for Sale - Turbines and Boilers	$ 82,000	$ -
Income Tax Overpayments	32,389	-
Prepaid Expenses	11,176	13,551
Other	31,889	38,874
	$ 157,454	$ 52,425
	=========	=========

(J) Goodwill

	Kinder Morgan Energy Partners		Power Segment	Total
	(In thousands)
Balance as of December 31, 2000		$1,157,637	$ 22,460	$1,180,097

Amortization¹		(25,644)	(812)	(26,456)

Change in ownership percentage of Kinder Morgan Energy Partners related to Kinder Morgan Management initial public offering		(97,874)	-	(97,874)

Balance as of December 31, 2001		1,034,119	21,648	1,055,767

Change in ownership percentage of Kinder Morgan Energy Partners related to Kinder Morgan Management secondary offering		(64,889)	-	(64,889)

Balance as of December 31, 2002		$ 969,230	$ 21,648	$ 990,878
		==========	==========	==========


¹	Beginning January 1, 2002, goodwill is no longer amortized; see Note 1(N).

(K) Other Investments

	December 31,
	2002	2001
	(In thousands)
TransColorado Pipeline Company¹	$ -	$ 134,255
Power Investments:
Thermo Companies	122,879	117,291
Wrightsville/Jackson Plant Investments	137,205	97,471
Other Site Development Investments	-	68,806
Horizon Pipeline Company	17,816	565
Other	7,983	9,020
	$ 285,883	$ 427,408
	==========	==========


¹	We began consolidation of this entity in October 2002 when we became the sole owner; see Note 4.

Investments consist primarily of equity method investments in unconsolidated subsidiaries and joint ventures, and include ownership interests in net profits. At December 31, 2002 and 2001, "Other" included an investment in Igasamex USA, Ltd. of approximately $6 million and assets held for deferred employee compensation, among other individually insignificant items.

(L) Property, Plant and Equipment

Property, plant and equipment is stated at historical cost, which for constructed plant includes indirect costs such as payroll taxes, other employee benefits, administrative and general costs. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of depreciable utility property, plant and equipment, plus the cost of removal less salvage, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-utility property, plant and equipment, and utility property, plant and equipment constituting an operating unit or system, when sold or abandoned.

In accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we review the carrying values of our long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. In the fourth quarter of 2002, we recorded an impairment of certain assets associated with our power business; see Note 6.

(M) 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. We are obligated under certain gas purchase contracts, dating from 1973, to purchase natural gas at fixed and escalating prices from a certain field in Montana. This take obligation, which continues for the life of the field, is based on production from specific wells and, thus, varies from year to year. The total cost to purchase natural gas under these contracts is estimated to be $35.5 million. We have recorded a liability representing our estimate of probable losses resulting from the resale of these purchased quantities, which amount is evaluated and, if necessary, adjusted as new pricing and production data become available. During 2002, this liability was increased by a pre-tax charge of approximately $12.7 million (approximately $7.8 million or $0.06 per diluted share after tax) to reflect increases in both (i) estimated production volumes subject to this purchase obligation and (ii) the difference between the price to be paid under these contracts and the expected sales price. This obligation was approximately $16 million at December 31, 2002 and is expected to be credited to earnings in an amount approximating $4 million per year for the next four years as gas volumes are purchased and resold.

(N) Depreciation and Amortization

Depreciation on our long-lived assets is computed based on the straight-line method over the estimated useful lives of assets. The range of estimated useful lives used in depreciating assets for each property type are as follows:

Property Type		Range of Estimated Useful Lives of Assets
		(In years)
Natural Gas Pipelines Retail Natural Gas Distribution Power Generation General and Other		24 to 68 (Transmission assets: average 56) 33 30 3 to 56

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, which we adopted effective January 1, 2002. This statement required that goodwill no longer be amortized and that goodwill be tested at least annually for impairment. As a result of our implementation of this statement, the goodwill associated with our 1998 acquisition of the Thermo Companies and the equity-method goodwill associated with our 1999 acquisition of Kinder Morgan, Inc. was not amortized during 2002. Had the provisions of this

statement been in effect during 2001 and 2000, our reported earnings and earnings per share would have been as follows:

	Year Ended December 31,
	2001	2000
	(In thousands, except per share amounts)
Reported Income Before Extraordinary Item	$ 238,635	$ 152,415
Add Back: Goodwill Amortization, Net of Related Tax Benefit	16,198	17,368
Adjusted Income Before Extraordinary Item	254,833	169,783
Extraordinary Item	(13,565)	-
Adjusted Net Income	$ 241,268	$ 169,783
	=========	=========
Reported Earnings per Diluted Share	$ 1.86	$ 1.33
	=========	=========
Earnings per Diluted Share, as Adjusted	$ 1.99	$ 1.48
	=========	=========

(O) Interest Expense, Net

	Year Ended December 31,
	2002	2001	2000
	(In millions)
Interest Expense	$ 163.7	$ 221.0	$ 248.4
AFUDC - Interest	(1.8)	(4.8)	(2.6)
Interest Income	-	-	(2.6)
Interest Expense, Net	$ 161.9	$ 216.2	$ 243.2
	========	========	========

"Interest Expense, Net" as presented in the accompanying Consolidated Statements of Operations is net of (i) the debt component of the allowance for funds used during construction ("AFUDC - Interest") and (ii) in 2000, interest income attributable to (1) our note receivable from Kinder Morgan Energy Partners associated with the transfer of certain interests (see Note 5) and (2) interest income associated with settlement of our net cash position with ONEOK, Inc.

In conjunction with our sale of certain assets to ONEOK as discussed in Note 8, we agreed to continue managing cash for these assets for a period of months, following which an audit was conducted to affirm the assignment of specific amounts to the two parties based on the timing of the underlying business transactions. We included the interest income attributable to our net receivable resulting from this transaction, together with the related interest expense, in the caption "Interest Expense, Net" in the accompanying Consolidated Statements of Operations.

(P) Other, Net

"Other, Net" as presented in the accompanying Consolidated Statements of Operations includes $13.0 million, $22.6 million and $61.7 million in 2002, 2001 and 2000, respectively, attributable to net gains from sales of assets. These transactions are discussed in Note 5.

(Q) Cash Flow Information

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. "Other, Net," presented as a component of "Net Cash Flows From Operating Activities" in the accompanying Consolidated Statements of Cash Flows includes, among other things, distributions from unconsolidated subsidiaries and joint ventures (other than Kinder Morgan Energy Partners) and other non-cash charges and credits to income.

ADDITIONAL CASH FLOW INFORMATION:

Changes in Other Working Capital Items:
(Net of Effects of Acquisitions and Sales)
Increase (Decrease) in Cash and Cash Equivalents

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Accounts Receivable	$ 45,111	$ (18,794)	$ (172,781)
Materials and Supplies Inventory	1,854	(1,512)	(2,626)
Other Current Assets	(43,217)	21,270	(28,550)
Accounts Payable	(62,449)	33,375	122,421
Other Current Liabilities	18,176	(16,041)	(13,947)
	$ (40,525)	$ 18,298	$ (95,483)
	==========	==========	==========

Supplemental Disclosures of Cash Flow Information:

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Cash Paid for:
Interest (Net of Amount Capitalized)	$ 147,088	$ 225,327	$ 248,177
	==========	==========	==========
Distributions on Preferred Capital Trust Securities	$ 21,913	$ 21,913	$ 21,913
	==========	==========	==========
Income Taxes Paid (Net of Refunds)	$ 114,264	$ 27,524	$ 7,674
	==========	==========	==========

During 2002 and 2001, we made non-cash grants of restricted shares of common stock in the amounts of $9.2 million and $5.6 million, respectively.

In April 2000, we made the final scheduled payment for our third-quarter 1998 acquisition of interests in the Thermo Companies using 961,153 shares of our common stock, representing approximately $30 million of value. For our December 31, 2000 sale of assets to Kinder Morgan Energy Partners, we received both cash and non-cash consideration. Note 5 contains additional information on this matter.

(R) Stock-Based Compensation

SFAS 123, Accounting for Stock-Based Compensation, encourages, but does not require, entities to adopt the fair value method of accounting for stock-based compensation plans. As allowed under SFAS 123, we continue to apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, compensation expense is not recognized for stock options unless the options are granted at an exercise price lower than the market price on the grant date. Had compensation cost for these plans been determined consistent with SFAS No. 123, net income and diluted earnings per share would have been reduced to the pro forma amounts shown in the table below. Because the SFAS 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. Additionally, the pro forma amounts include $1.1 million, $1.0 million and $0.8 million related to the purchase discount offered under the employee stock purchase plan for 2002, 2001 and 2000, respectively. Note 17 contains information regarding our common stock option and purchase plans.

	Year Ended December 31,
	2002	2001	2000
	(In thousands except per share amounts)
Net Income:
As Reported	$ 302,725	$ 225,070	$ 152,415
Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all awards,
net of related tax effects	(14,497)	(15,656)	(7,762)
Pro Forma	$ 288,228	$ 209,414	$ 144,653
	==========	==========	==========

Earnings Per Basic Share:
As Reported	$ 2.48	$ 1.95	$ 1.34
	==========	==========	==========
Pro Forma	$ 2.36	$ 1.81	$ 1.27
	==========	==========	==========

Earnings Per Diluted Share:
As Reported	$ 2.45	$ 1.86	$ 1.33
	==========	==========	==========
Pro Forma	$ 2.33	$ 1.73	$ 1.26
	==========	==========	==========

The weighted-average fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions:

	Year Ended December 31,
	2002	2001	2000
Risk-free Interest Rate (%)	4.01	4.30	4.97
Expected Weighted-average Life	6.0 years¹	6.5 years	4.5 years
Volatility	0.39¹	0.34²	0.34
Expected Dividend Yield (%)	0.71	0.36	0.38



1 For options granted under the 1992 Directors' Plan, the expected weighted-average life was 4.0 years and the volatility assumption was 0.45.
2 The volatility assumption for the options issued under the 1992 Directors' Plan was 0.44.

During 2002 and 2001, we made of restricted common stock grants of 162,250 and 112,500 shares, respectively. These grants, valued at $9.2 million and $5.6 million, respectively, based on the closing market price of our common stock on the date of grant, are accounted for in the equity section of our Consolidated Balance Sheets under the caption, "Deferred Compensation." Grants of restricted shares are vested over a four year period and are amortized to expense according to the vesting schedule.

(S) Transactions with Related Parties

We account for our investment in Kinder Morgan Energy Partners (among other entities) under the equity method of accounting. In each accounting period, we record our share of these investees' earnings. We adjust the amount of any recorded "equity method goodwill" when an equity method investee or a consolidated subsidiary issues additional equity (or reacquires equity shares) in any manner that alters our ownership percentage. Differences between the per unit sales proceeds from these equity issuances (or reacquisitions) and our underlying book basis, as well as the pro rata portion of the equity method goodwill (including associated deferred taxes), are recorded directly to paid-in capital rather than being recognized as gains or losses. Four such transactions are described in Note 5. If incremental equity is received in conjunction with sales of assets to equity method investees, gains and losses are not recognized to the extent of the interest retained in the assets transferred.

The Accounts Receivable, Related Party balance at December 31, 2002 is primarily attributable to Kinder Morgan Energy Partners for amounts arising from performing administrative functions for them, including cash management, hedging activities, centralized payroll and employee benefits services and expenses incurred in performing as general partner of Kinder Morgan Energy Partners. The net monthly balance payable or receivable from these activities is settled in cash in the following month.

The Notes Receivable and Accounts Receivable related party balances at December 31, 2001 consisted primarily of advances to Horizon Pipeline Company, an enterprise we jointly own with Nicor, Inc.; see Note 5. The note receivable from Horizon Pipeline Company was repaid in part and replaced with an equity investment in Horizon, which completed its long-term financing in 2002. The accounts receivable from Horizon relates to construction costs that were reimbursed to us in January 2002. The Accounts Payable Related Party balance at December 31, 2001 related to balances owed to Kinder Morgan Energy Partners in connection with our performance of functions for them as previously discussed.

The caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statements of Operations includes related-party costs totaling $22.3 million, $47.4 million and $22.2 million for the years 2002, 2001 and 2000, respectively, primarily for natural gas transportation and storage services and natural gas provided by entities owned by Kinder Morgan Energy Partners.

(T) Accounting for Risk Management Activities

We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas and associated transportation. 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. This policy is described in detail in Note 15, as is our present policy, which is based on SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which became effective for us on January 1, 2001.

(U) Income Taxes

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. Note 12 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities.

(V) Accounting for Legal Costs

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.

2. Investment in Kinder Morgan Energy Partners, L.P.

We own the general partner of, and a significant limited partner interest in, Kinder Morgan Energy Partners, the largest publicly traded pipeline limited partnership in the United States in terms of market capitalization and the owner of the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Kinder Morgan Energy Partners owns and/or operates a

diverse group of assets used in the transportation, storage and processing of energy products, including refined petroleum products pipeline systems with more than 10,000 miles of products pipeline and over 32 associated terminals. Kinder Morgan Energy Partners owns over 15,000 miles of natural gas transportation pipelines, plus natural gas gathering and storage facilities. Kinder Morgan Energy Partners also owns or operates approximately 50 liquid and bulk terminal facilities and over 60 rail transloading facilities located throughout the United States, handling over 60 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 35 million barrels for refined petroleum products, chemicals and other liquid products. In addition, Kinder Morgan Energy Partners owns Kinder Morgan CO₂ Company, L.P., which transports, markets and produces carbon dioxide for use in enhanced oil recovery operations, primarily in the Permian Basin of West Texas.

At December 31, 2002, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management, LLC we owned, approximately 31.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 13.0 million common units, 5.3 million Class B units and 13.5 million i-units, represent approximately 17.6 percent of the total limited partner interests of Kinder Morgan Energy Partners. See Note 3 for additional information regarding Kinder Morgan Management and Kinder Morgan Energy Partners' i-units. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2 percent interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represent approximately 19.2 percent of Kinder Morgan Energy Partners' total equity interests at December 31, 2002. We receive quarterly distributions on the i-units owned by Kinder Morgan Management in additional i-units and distributions on our other units in cash.

In addition to distributions received on our limited partner interests and our Kinder Morgan Management shares as discussed above, we also receive an incentive distribution from Kinder Morgan Energy Partners as a result of our ownership of the general partner interest in Kinder Morgan Energy Partners. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to unit holders exceed specified target levels as set forth in Kinder Morgan Energy Partners' partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit. Including both our general and limited partner interests in Kinder Morgan Energy Partners, at the 2002 distribution level, we received approximately 51% of all quarterly distributions from Kinder Morgan Energy Partners, of which approximately 40% is attributable to our general partner interest and 11% is attributable to our limited partner interest. The actual level of distributions we will receive in the future will vary with the level of distributable cash determined in accordance with Kinder Morgan Energy Partners' partnership agreement.

Following is summarized financial information for Kinder Morgan Energy Partners. Additional information regarding Kinder Morgan Energy Partners' results of operations and financial position are contained in its 2002 Annual Report on Form 10-K.

	Summarized Income Statement Information Year Ended December 31,
	2002	2001	2000
	(In thousands)
Operating Revenues	$ 4,237,057	$ 2,946,676	$ 816,442
Operating Expenses	3,512,759	2,382,848	500,881
Operating Income	$ 724,298	$ 563,828	$ 315,561
	===========	===========	===========

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


	Summarized Balance Sheet Information As of December 31,
	2002	2001
	(In thousands)
Current Assets	$ 669,390	$ 568,043
	============	============
Noncurrent Assets	$ 7,684,186	$ 6,164,623
	============	============
Current Liabilities	$ 813,327	$ 962,704
	============	============
Noncurrent Liabilities	$ 4,082,287	$ 2,545,692
	============	============
Minority Interest	$ 42,033	$ 65,236
	============	============

3. Kinder Morgan Management, LLC

In May 2001, Kinder Morgan Management, LLC, one of our indirect subsidiaries, issued and sold its limited liability shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. In addition, during 2001, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $11.7 million. Upon purchase of the i-units, Kinder Morgan Management became a limited partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners' general partner the responsibility to manage and control the business and affairs of Kinder Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests that have been, and will be, issued only to Kinder Morgan Management. We have certain rights and obligations with respect to these securities. By approval of Kinder Morgan Management shareholders other than us, effective at the close of business on July 23, 2002, we no longer have an obligation to, upon presentation by the holder thereof, exchange publicly held Kinder Morgan Management shares for either Kinder Morgan Energy Partners' common units that we own or, at our election, cash. In conjunction with the elimination of the exchange feature, on July 29, 2002, Kinder Morgan, Inc. issued to each of Kinder Morgan Management shareholder (i) .09853 shares of Kinder Morgan, Inc. common stock for each 100 Kinder Morgan Management listed shares held of record by such shareholder at the close of business on July 23, 2002, and (ii) cash in lieu of fractional shares. Prior to the elimination of the exchange feature, 6,830,013 and 2,840,374 Kinder Morgan Energy Partners common units were exchanged in the years ended December 31, 2002 and 2001, respectively, for a total of 9,670,387 Kinder Morgan Management shares. These exchanges had the effect of increasing (i) additional paid-in capital by $35.7 million and (ii) associated income taxes payable by $21.9 million and decreasing (i) our investment in Kinder Morgan Energy Partners by $150.1 million and (ii) minority interests by $207.7 million during 2002.

In the initial public offering, Kinder Morgan Management issued a total of 29,750,000 shares, of which 2,975,000 shares were purchased by us (utilizing incremental short-term borrowings), with the balance purchased by the public. The equity interest in Kinder Morgan Management (our consolidated

subsidiary) purchased by the public created a minority interest on our balance sheet of $892.7 million at the time of the transaction.

On August 6, 2002, Kinder Morgan Management closed the issuance and sale of 12,478,900 limited liability shares in an underwritten public offering. The net proceeds of approximately $328.6 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. We did not purchase any of the offered shares. In addition, during 2002, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $3.4 million. At December 31, 2002, we owned approximately 13.5 million (29.6%) of Kinder Morgan Management's outstanding shares, including the only two voting shares. The issuance of i-units by Kinder Morgan Energy Partners decreased our percentage ownership of Kinder Morgan Energy Partners from approximately 20.4 percent to approximately 19.1 percent. We have elected to treat transactions such as this as "capital" transactions and, accordingly, no gain or loss was recorded. Instead, the impact of the difference between sales proceeds and our underlying book basis had the effect of increasing our investment in the net assets of Kinder Morgan Energy Partners by $17.5 million and decreasing (i) our equity-method goodwill in Kinder Morgan Energy Partners by $64.9 million, (ii) associated deferred income taxes by $18.0 million and (iii) paid-in capital by $29.4 million.

On November 14, 2002, Kinder Morgan Management paid a share distribution of 937,658 of its shares to shareholders of record as of October 31, 2002, based on the $0.61 per common unit distribution declared by Kinder Morgan Energy Partners. On February 14, 2003, Kinder Morgan Management made a distribution totaling 858,981 of its shares to shareholders of record as of January 31, 2003, based on the $0.625 per common unit distribution declared by Kinder Morgan Energy Partners. These distributions are paid in the form of additional shares or fractions thereof based on the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Kinder Morgan Management has paid share distributions totaling 2,538,785 shares and 886,361 shares in the years ended December 31, 2002 and 2001, respectively.

On July 18, 2001, Kinder Morgan Energy Partners announced a two-for-one split of its common units. The common unit split, in the form of a one-common-unit distribution for each common unit outstanding, occurred on August 31, 2001. This split resulted in Kinder Morgan, Inc. receiving one additional common unit for each common unit it owned and Kinder Morgan Management receiving one additional i-unit for each i-unit it owned. Also on July 18, 2001, Kinder Morgan Management announced a two-for-one split of its shares. This share split, in the form of a one-share distribution for each share outstanding, occurred on August 31, 2001. All references to amounts of these securities in these Notes reflect the impact of these splits.

4. Business Combinations

TransColorado Gas Transmission Company, referred to in this note as "TransColorado," was formed to construct and operate a 280-mile-long interstate natural gas pipeline system that extends from near Rangely, Colorado to its southern terminus at the Blanco Hub near Aztec, Colorado. TransColorado was placed in service in April 1999 and was operated as a 50/50 joint venture between Questar Corp. and us until we acquired Questar's interest effective October 1, 2002 for a total of approximately $107.6 million (including transaction costs of approximately $2.1 million), making us the sole owner. As a result of our acquisition of control of this entity, we began consolidation in October 2002 and, in accordance with authoritative accounting guidelines, recorded the acquisition of the incremental 50% interest as a business combination, requiring that we allocate the purchase price to the assets acquired and liabilities assumed based on their relative fair values. The historical carrying value of current assets and current liabilities were determined to be approximately equal to their fair values, and property plant and equipment was valued using a combination of net present value and earnings multiple methods. No goodwill was recorded, as the fair value of the net assets acquired exceeded the consideration paid.

These values were as follows (in millions):

Cash	$ 6.0
Other Current Assets	1.6
Net Property, Plant and Equipment	103.2
Other Assets	0.1
Current Liabilities	(2.2)
Deferred Credits	(1.1)

Total Purchase Price	$ 107.6
	=======

5. Investments and Sales

In August 2002, Kinder Morgan Energy Partners issued i-units in conjunction with the Kinder Morgan Management secondary public offering of its shares to the public. We did not acquire any of the Kinder Morgan Management shares in the secondary offering. This issuance of i-units reduced our percentage ownership of Kinder Morgan Energy Partners from approximately 20.4 percent to approximately 19.1 percent and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $17.5 million and reducing (i) our excess investment in Kinder Morgan Energy Partners by $64.9 million, (ii) paid-in capital by $29.4 million and (iii) associated accumulated deferred income taxes by $18.0 million; see Notes 1(R) and 3.

Effective July 1, 2002, construction and testing of the Jackson, Michigan 550-megawatt power generation facility were completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power Company, our wholly owned subsidiary, made a preferred investment in Triton Power Company LLC valued at approximately $105 million; (ii) Triton Power Company LLC, through its wholly owned affiliate, Triton Power Michigan LLC, entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC, and (iii) we received full payment of our $104.4 million construction note receivable. Our preferred equity interest has no management or voting rights, but does retain certain protective rights, and is entitled to a cumulative return, compounded monthly, of 9.0 percent per annum. We account for this investment under the cost method, under which earnings are recognized as cash is received.

Also effective July 1, 2002, construction and testing of the 550-megawatt Wrightsville, Arkansas power generation facility were completed and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville power facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Our preferred equity interest has no management or voting rights, but does retain certain protective rights, and is entitled to a cumulative preferred dividend return that escalates over time from 6.3 percent to 8.8 percent. We account for this investment under the cost method, and recorded entries to reduce the carrying value of this investment during the fourth quarter of 2002; see Note 6.

Horizon Pipeline Company, L.L.C. ("Horizon"), a joint venture between Nicor-Horizon, a subsidiary of Nicor Inc. (NYSE: GAS), and Natural Gas Pipeline Company of America, completed and placed into service its new $82 million natural gas pipeline in northern Illinois on May 11, 2002. This pipeline is being operated as an interstate pipeline company under the authority of the Federal Energy Regulatory Commission ("FERC"). Horizon's natural gas pipeline consists of 28 miles of newly constructed 36-inch diameter pipe, the lease of capacity in 42 miles of existing pipeline from Natural Gas Pipeline Company of America, and newly installed gas compression facilities. Horizon Pipeline can transport up to 380 million cubic feet of natural gas per day from near Joliet into McHenry County, connecting the emerging supply hub at Joliet with the northern part of the Nicor Gas distribution system and the existing Natural Gas Pipeline Company of America pipeline system.

On December 28, 2001, we completed the previously announced sale of certain assets in the Wattenberg field area of the Denver-Julesberg Basin to Kerr-McGee Gathering LLC (formerly HS Resources, Inc.). Under terms of agreements with them, Kerr-McGee Gathering LLC has operated these assets since December 1999 and made monthly payments to us until the sale of assets was completed. We recorded a pre-tax loss of $22.1 million (approximately $13.3 million after tax or $0.11 per diluted share) in conjunction with this sale, shown in the caption "Other Net" in the accompanying Consolidated Statement of Operations for 2001.

Effective December 1, 2001, we purchased natural gas distribution assets from Citizens Communications Company for approximately $11 million in cash and assumed liabilities. The natural gas distribution assets serve approximately 13,400 residential, commercial and agricultural customers in Bent, Crowley, Otero, Archuleta, La Plata and Mineral Counties in Colorado. On October 31, 2001, the Colorado Public Utilities Commission approved this transaction.

In May 2001, Kinder Morgan Energy Partners issued i-units in conjunction with the Kinder Morgan Management initial public offering of its shares to the public. This issuance of i-units reduced our percentage ownership of Kinder Morgan Energy Partners from approximately 22.7 percent to approximately 20.8 percent and had the associated effects of increasing (i) our investment in the net assets of Kinder Morgan Energy Partners by $145.1 million, (ii) associated accumulated deferred income taxes by $18.9 million and (iii) paid-in capital by $28.3 million and reducing (i) our excess investment in Kinder Morgan Energy Partners by $97.9 million and (ii) the monthly amortization of the excess investment by $192 thousand; see Notes 1(R) and 3.

In December 2000, we contributed, for consideration valued at approximately $300 million, certain assets to Kinder Morgan Energy Partners effective December 31, 2000. The largest asset we transferred was our wholly owned subsidiary Kinder Morgan Texas Pipeline, L.P. and certain associated entities (the lessee of a major intrastate natural gas pipeline system). We also contributed the Douglas and Casper gas processing facilities and associated natural gas gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. As consideration for the transfer, we received approximately $150 million in cash (with an additional cash payment for working capital), 1.3 million Kinder Morgan Energy Partners' common limited partner units and 5.3 million Class-B Kinder Morgan Energy Partners' limited partner units. The transaction was unanimously approved by our independent directors with the benefit of independent legal advice and a fairness opinion from Merrill Lynch. At December 31, 2000, we recorded a pre-tax gain of $61.6 million (approximately $37.0 million after tax or $0.32 per diluted share) in conjunction with this sale. During 2001, we made a final working capital adjustment associated with this transfer, and reduced our provision for exposure under an indemnification provision of the contribution agreement, resulting in positive pre-tax adjustments of $17.0 million (approximately $10.2 million after tax or $0.08 per diluted share) and $9.9 million (approximately $5.9 million after tax or $0.05 per diluted share). A final pre-tax adjustment of $10.4 million was made at December 31, 2002, the expiration of the indemnification obligations, increasing income by $6.5 million after-tax or $0.05 per diluted share. In each case these amounts were adjusted for our continuing interest in the assets transferred.

In April 2000, Kinder Morgan Energy Partners issued 9.0 million common units in a public offering at a price of $19.875 per common unit, receiving total net proceeds (after underwriting discount) of $171.3 million. We did not acquire any of these common units. This transaction reduced our then percentage ownership of Kinder Morgan Energy Partners from approximately 19.9% to approximately 18.6% and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $6.1 million and reducing (i) our equity method goodwill in Kinder Morgan Energy Partners by $81.1 million, (ii) associated accumulated deferred income taxes by $30.0 million, (iii) paid-in capital by $45.0 million and (iv) our monthly amortization of the equity method goodwill by approximately $176 thousand. In February 2000, Kinder Morgan Energy Partners issued 1.1 million common units,

assumed approximately $7.0 million in liabilities and paid $0.8 million in cash as consideration for acquiring all the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $1.1 million and reducing (i) our equity method goodwill in Kinder Morgan Energy Partners by $11.3 million, (ii) associated accumulated deferred income taxes by $4.1 million, (iii) paid-in capital by $6.1 million and (iv) the monthly amortization of the equity method goodwill by approximately $21 thousand; see Note 1(S).

In March 2000, we sold the 918,367 shares of Tom Brown, Inc. common stock we had held since early 1996. We recorded a pre-tax gain of $1.4 million ($0.8 million after tax or approximately $0.01 per diluted common share) in conjunction with the sale.

See Note 8 for information regarding sales of assets and businesses included in discontinued operations.

6. Revaluation of Power Investments

During 2002, we noted and reported a number of negative factors affecting the market for electric power and the announced plans for future power plant development, as well as the declining financial condition of many participants in electric markets, including certain of our partners in our power development activities. In the fourth quarter of 2002, we completed our analysis of these developments and their likely impact on our business activities in this arena. As a result of that analysis, we elected to discontinue our participation in the power development business and reduced the carrying value of our investments in (i) sites for future power plant development and (ii) turbines and associated equipment, in each case to their estimated fair value less cost to sell. In addition, we reduced the carrying value of our preferred investment in the Wrightsville, Arkansas power generation facility to reflect an other than temporary decline in its value. In total, these charges reduced our pre-tax earnings by $134.5 million ($83.4 million or $0.68 per diluted share after-tax). We are engaging in ongoing efforts to sell our remaining turbines and associated equipment and exploring our opportunities to maximize the value of our remaining investment in the Wrightsville facility. The conditions in the power generation and marketing business remain dynamic and we will continue to evaluate the carrying amounts of these investments in light of changing circumstances.

7. Accounts Receivable Sales Facility

In September 1999, we entered into a five-year agreement with a financial institution whereby we could sell, on a revolving basis, an undivided percentage ownership interest in certain eligible accounts receivable, as defined, up to a maximum of $150 million. This transaction was accounted for as a sale of receivables. Losses from the sale of these receivables were included in "Other, Net" in the accompanying Consolidated Statements of Operations during the periods in which the facility was utilized. We received $150 million in proceeds from the sale of receivables in 1999. The proceeds were used to retire notes payable of Kinder Morgan Delaware that were outstanding when we acquired it. In 2000 we repaid $150 million and terminated the agreement. Cash flows associated with this program are included with "Accounts Receivable" under "Cash Flows from Operating Activities" in the accompanying Statements of Consolidated Cash Flows for 2000.

8. Discontinued Operations

Prior to mid-1999, we had major business operations in the upstream (gathering and processing), midstream (natural gas pipelines) and downstream (wholesale and retail marketing) portions of the natural gas industry and, in addition, had (i) non-energy retail marketing operations in the form of a joint venture called en•able and (ii) limited international operations. During 1999, we adopted and

implemented plans to discontinue the following lines of business: (i) gathering and processing natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids, (iii) the direct marketing of non-energy products and services and (iv) international operations, which we subsequently decided to retain as discussed following.

In accordance with the provisions of Accounting Principles Board Opinion No. 30, Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions ("APB 30"), our consolidated financial statements have been restated to present these businesses as discontinued operations. Accordingly, the revenues, costs and expenses, assets and liabilities and cash flows of these discontinued operations have been excluded from the respective captions in the accompanying Consolidated Statements of Operations and Consolidated Statements of Cash Flows, and have been reported in the various statements under the captions "Loss from Discontinued Operations, Net of Tax"; "Loss on Disposal of Discontinued Operations, Net of Tax"; "Net Cash Flows Used in Discontinued Operations" and "Net Cash Flows Provided by Discontinued Investing Activities" for all relevant periods. In addition, certain of these Notes have been restated for all relevant periods to reflect the discontinuance of these operations.

During the fourth quarter of 2000, we decided that, due to the start-up nature of our limited international operations and the unwillingness of buyers to pay for the value created to date, it was not in the best interests of the Company to dispose of our international operations, which consist principally of a natural gas distribution system under development in Hermosillo, Mexico. Consequently, results from our international operations have been reclassified to continuing operations for all periods presented. The $3.9 million estimated after-tax loss on disposal recorded in 1999, consisting principally of a write down to estimated net realizable value including estimated costs of disposal, was reversed in 2000 and is included under the caption "Loss on Disposal of Discontinued Operations" in the accompanying Consolidated Statements of Operations. At December 31, 2000, our international operations represented assets of approximately $32.3 million and liabilities of approximately $4.0 million, while operating revenues and the operating losses for the year ended December 31, 2000 were $5.7 million and $(2.1) million, respectively.

Summarized financial data of discontinued operations are as follows:

Income Statement Data			Year Ended December 31, 2000
			(In thousands)

Operating Revenues:
Wholesale Natural Gas and Liquids Marketing			$ 580,159
Gathering and Processing, Including Field Services and Short-haul
Intrastate Pipelines			$ 436,979

Loss on Disposal of Discontinued Operations, Net of Tax:
Wholesale Marketing, Net of Tax Benefits of $2,013			$ (3,013)
Gathering and Processing, Net of Tax Benefits of $21,617			$ (32,638)
International Operations, Net of $2,430 of Tax			$ 3,917

With the exception of our international operations, which, as discussed above, we decided to retain, we completed the divestiture of our discontinued operations by December 31, 2000. In the fourth quarter of 2000, we recorded an incremental loss on disposal of discontinued operations of $31.7 million (net of $21.2 million of tax benefit), representing the impact of final disposition transactions and adjustment of previously recorded estimates. In the fourth quarter of 2002, we recorded an incremental pre-tax loss of

$8.1 million ($5.0 million or $0.04 per share after-tax) to increase previously recorded liabilities to reflect updated estimates. We had a remaining liability of approximately $7.1 million at December 31, 2002 associated with these discontinued operations, including $6.6 million representing an indemnification obligation associated with our sale of assets to ONEOK as discussed below. Following is additional information concerning the various disposition transactions that occurred during the periods presented.

Effective March 1, 2000, ONEOK purchased (i) our gathering and processing businesses in Oklahoma, Kansas and West Texas, (ii) our marketing and trading business and (iii) certain storage and transmission pipelines in the Mid-continent region. As consideration, ONEOK paid us approximately $108 million plus approximately $56 million for estimated net working capital at closing. In addition, ONEOK assumed (i) the operating lease associated with the Bushton, Kansas processing plant (although we remain secondarily liable as discussed in Note 18) and (ii) long-term throughput capacity commitments on Natural Gas Pipeline Company of America.

During the second quarter of 2000, we completed the sale of three natural gas gathering systems and a natural gas processing facility to WBI Holdings, Inc., the natural gas pipeline unit of MDU Resources Group, Inc. for approximately $21 million. Gathering systems included in the sale were the Bowdoin System located in north-central Montana, the Niobrara System located in northeastern Colorado and northwestern Kansas, and the Yenter System located in northeastern Colorado and western Nebraska. The natural gas processing facility included in the sale was the Yenter Plant, located northwest of Sterling, Colorado.

During the fourth quarter of 2000, Wildhorse Energy Partners, LLC distributed all of its assets to its members and was dissolved. Formed in 1996, Wildhorse was owned 55 percent by us and 45 percent by Tom Brown. All the Wildhorse gathering and processing assets were distributed to Tom Brown and we received the Wolf Creek storage facility (which is utilized in our natural gas distribution business) and cash. Also during the fourth quarter of 2000, our Douglas and Casper gas processing facilities and associated natural gas gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. were included as part of a larger transaction with Kinder Morgan Energy Partners; see Note 5.

9. Regulatory Matters

On July 17, 2000, Natural Gas Pipeline Company of America filed its compliance plan, including pro forma tariff sheets, pursuant to the FERC's Order Nos. 637 and 637-A. The FERC directed all interstate pipelines to file pro forma tariff sheets to comply with new regulatory requirements in the Orders regarding scheduling procedures, capacity segmentation, imbalance management services and penalty credits, or in the alternative, to explain why no changes to existing tariff provisions are necessary. On November 21, 2002, the FERC issued an order approving much of Natural Gas Pipeline Company of America's Order 637 filing, but requiring additional changes. The primary changes related to Natural Gas Pipeline Company of America's segmentation proposal, the ability of shippers to designate additional primary points on a segmented release, a shipper's rights to request discounts at alternate points and Natural Gas Pipeline Company of America's unauthorized overrun charges. Natural Gas Pipeline Company of America made its compliance filing on December 23, 2002 and filed for rehearing. Other parties have objected to certain aspects of Natural Gas Pipeline Company of America's compliance filing. These filings are awaiting action by the FERC. Natural Gas Pipeline Company of America's Order 637 compliance filing will not be in effect until after further order by the FERC.

On April 5, 2002, the D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C. Circuit did remand the FERC's decision to impose a 5-year cap on bids the 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. Numerous parties, including Natural Gas Pipeline Company of America, have filed comments on the remanded issues.

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: (i) 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 at all is necessary given existing regulatory controls; (ii) affirmed the FERC's policy that a segmented transaction consisting of both a forward-haul up to contract demand and a backhaul up to contract demand to the same point is permissible, and accordingly required, under Section 5 of the Natural Gas Act, pipelines that the FERC had previously found must permit segmentation on their systems to file tariff revisions within 30 days to permit such segmented forward-haul and backhaul transactions to the same point.

The FERC, in a Notice of Proposed Rulemaking in RM01-10-000, has proposed standards of conduct to govern interactions between interstate natural gas pipelines and electric transmission utilities and their energy affiliates. These standards would entirely replace the current standards of conduct related to affiliate interaction. Numerous parties, including Natural Gas Pipeline Company of America, have filed comments on the proposed rulemaking. In May 2002, the FERC held a technical conference on the proposed rulemaking. To date the FERC has not acted on the proposal.

The FERC, in a Notice of Proposed Rulemaking in RM02-14-000, has proposed new regulation of 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. Natural Gas Pipeline Company of America filed comments on August 28, 2002. All parties are awaiting further action by the FERC.

As a part of the settlement of litigation styled, Jack J. Grynberg, individually and as general partner for the Greater Green River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and K N Energy, Inc., Case No. 90-CV-3686, in early 2002, Mr. Grynberg received $16.825 million from us (including forgiveness of a $10.4 million obligation owing from Mr. Grynberg) and an additional $15.625 million was paid into escrow. Rocky Mountain Natural Gas Company agreed to seek to recover these amounts from its customers/rate payers in a proceeding before the Public Utilities Commission for the State of Colorado. Rocky Mountain Natural Gas Company and Kinder Morgan, Inc. made regulatory filings with the Public Utilities Commission for the State of Colorado on September 30, 2002, proposing recovery of these amounts as part of their annual Gas Cost Adjustment filing process. We proposed to collect these litigated gas costs, including associated carrying charges, over a 15-year amortization period. On October 30, 2002, the Public Utilities Commission for the State of Colorado decided, in open meeting, to allow us to place rates in effect and begin recovery of these costs effective November 1, 2002, subject to refund pending a final determination as to our ability to recover these costs in our rates. A hearing in this matter is scheduled to begin on June 23, 2003. Mr. Grynberg will receive the money in escrow only to the extent rates allowing us to collect this gas cost are finally approved.

The Wyoming Choice Gas program is being reviewed by the Wyoming Public Service Commission to determine whether the existing program should continue and whether any program modifications should be made. A hearing was conducted in February of 2003 and a decision is expected in March.

Currently, there are no material proceedings challenging the base rates on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable statutes and 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.

10. Environmental and Legal Matters

(A) Environmental Matters

We have an established environmental reserve of approximately $15.5 million at December 31, 2002 to address remediation issues associated with approximately 35 projects. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with environmental regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs.

(B) Litigation Matters

K N TransColorado, Inc. v. TransColorado Gas Transmission Company, et. al., Case No. 00-CV-129, District Court, County of Garfield, State of Colorado. On June 15, 2000, K N TransColorado filed suit against Questar TransColorado, its parent Questar Pipeline Company, and other affiliated Questar entities. The TransColorado partnership was made a defendant for purposes of an accounting. The lawsuit alleged, among other things, that Questar breached its fiduciary duties as a partner. K N TransColorado sought to recover damages in excess of $152 million due to Questar's breaches and, in addition, sought punitive damages. In response to the complaint, on July 28, 2000, the Questar entities filed a counterclaim and third party claims against Kinder Morgan and certain of its affiliates for claims arising out of the construction and operation of the TransColorado pipeline project. The Questar entities sought to recover damages in excess of $185 million for an alleged breach of fiduciary duty and other claims. The Court dismissed Questar's counterclaims for breach of duty of good faith and fair dealing and for indemnity and contribution and dismissed Questar's Third Party Complaint. On August 14, 2001, the Court granted leave to Questar to file its First Amended Answer and Counterclaim, once again naming Kinder Morgan, Inc. as a counterclaim defendant, and making similar allegations against us as set forth above. Trial of the matter concluded on May 3, 2002. On August 26, 2002, the Court entered its Judgment in the matter. The parties have settled the matter. Under the terms of the settlement, we purchased an indirect 50 percent interest in TransColorado Gas Transmission Company from an affiliate of Questar Corp. We paid $105.5 million for the stock of the Questar affiliate that owned the 50 percent interest. In addition to its pipeline assets, TransColorado had approximately $12 million in cash that became ours following the close of the transaction. The agreement settles all outstanding litigation between Questar and us relating to TransColorado and provides for an effective date of October 1, 2002. The transaction received Hart-Scott-Rodino approval and is complete. We now own 100 percent of the TransColorado Pipeline. This matter is now resolved.

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). 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 MDL case 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. Mr. 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.

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 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 25 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 interest 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 above, 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. 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. 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 Court has pending the Plaintiffs' Motion to certify the class. Merits discovery has been stayed. 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 motion is pending.

K N Energy, Inc., et al. v. James P. Rode and Patrick R. McDonald, Case No. 99CV1239, filed in the District Court, Jefferson County, Division 8, Colorado. The case was filed on May 21, 1999. Defendants counterclaimed and filed third party claims against several of our former officers and/or directors. Messrs. Rode and McDonald are former principal shareholders of Interenergy Corporation. We acquired Interenergy on December 19, 1997 pursuant to a Merger Agreement dated August 25, 1997. Rode and McDonald allege that K N Energy committed securities fraud, common law fraud and negligent misrepresentation as well as breach of contract. Rode and McDonald are seeking an unspecified amount of compensatory damages, greater than $2 million, plus unspecified exemplary or punitive damages, attorney's fees and their costs. We filed a motion to dismiss, and on April 21, 2000, the Jefferson County District Court Judge dismissed the case against the individuals and us with prejudice. On April 6, 2001, the Colorado Court of Appeals affirmed the dismissal. Rode and McDonald also filed a federal securities fraud action in the United States District Court for the District of Colorado on January 27,

2000 titled James P. Rode and Patrick R. McDonald v. K N Energy, Inc., et al., Civil Action No. 00-N-190. This case initially raised the identical state law claims contained in the counterclaim and third party complaint in state court. Rode and McDonald filed an amended Complaint, which dropped the state-law claims. On June 20, 2000, the federal district court dismissed this Complaint with prejudice. The district court's dismissal was subsequently affirmed by the Tenth Circuit Court of Appeals on April 23, 2002. A third related class action case styled, Adams vs. Kinder Morgan, Inc., et al., Civil Action No. 00-M-516, in the United States District Court for the District of Colorado was served on us on April 10, 2000. As of this date no class has been certified. On February 23, 2001, the federal district court dismissed several claims raised by the plaintiff, with prejudice, and dismissed the remaining claims, without prejudice. On April 27, 2001, the Adams plaintiffs filed their second amended complaint. On March 29, 2002, the court dismissed the Adams plaintiffs' second amended complaint with prejudice. On May 2, 2002, the Adams plaintiffs appealed the dismissal. Briefing at the Tenth Circuit Court of Appeals is complete and oral argument on the appeal was heard on January 13, 2003.

Darrell Sargent d/b/a Double D Production v. Parker & Parsley Gas Processing Co., American Processing, L.P. and Cesell B. Cheatham, et al., Cause No. 878, filed in the 100th Judicial District Court, Carson County, Texas. Plaintiff filed a purported class action suit in 1999 and amended its petition in late 2002 to assert claims on behalf of over 1,000 producers who process gas through as many as ten gas processing plants formerly owned by American Processing, L.P. ("American Processing"), a former wholly owned subsidiary of Kinder Morgan, Inc. ("KMI"), in Carson and Gray counties and other surrounding Texas counties. Plaintiff claims that American Processing (and subsequently, ONEOK, which purchased American Processing, L.P. from us in 2000) improperly allocated liquids and gas proceeds to the producers. In particular, among other claims, the plaintiff challenges the accuracy of a computer model used at the plants to allocate liquid and gas proceeds among the producers and processors. The petition asserts claims for breach of contract and Natural Resources Code violations relating to the period from 1994 to the present. To date, the plaintiff has not made a specific monetary demand nor produced a specific calculation of alleged damages. Plaintiff has alleged generally in the petition that damages are "not to exceed $200 million" plus attorney's fees, costs and interest. Defendants have filed a counterclaim for overpayments made to producers.

Pioneer Natural Resources USA, Inc., formerly known as Parker & Parsley Gas Processing Company ("Parker & Parsley"), is a co-defendant. Parker & Parsley has claimed indemnity from American Processing based on its sale of assets to American Processing on October 4, 1995. We have accepted indemnity and defense subject to a reservation of rights pending resolution of the suit. Plaintiff has also named ONEOK as a defendant. We and ONEOK are defending the case pursuant to an agreement whereby ONEOK is responsible for any damages that may be attributable to the period following ONEOK's acquisition of American Processing from us in 2000.

The purported class has not been certified. Plaintiff has filed a motion for pre-trial conference on class certification issues and seeks to establish a schedule for class discovery. Defendants have filed a motion to deny class certification because of plaintiff's delay in proceeding with the class action. The motions are pending before the court. In the event class discovery is allowed to proceed, defendants expect to assert additional objections to class certification.

Manna Petroleum Services, L.P., et al v. American Processing, L.P. and Cesell B. Cheatham, et al., Cause No. 31,485, filed in the 223rd Judicial District Court of Gray County, Texas. Plaintiff filed suit in late 1999 and alleges that American Processing (and subsequently ONEOK) improperly allocated liquids and gas proceeds. This suit, which was filed by the same attorney who represents the purported class in the Sargent case discussed above, involves similar allegations as those presented in Sargent except this suit is not styled as a class action. See the discussion of Sargent above for further details. Defendants have filed a counterclaim for overpayments to the plaintiff. The parties are presently engaged in fact discovery, with expert discovery and trial presently scheduled to occur in 2003.

Energas Company, a Division of Atmos Energy Company v. ONEOK Energy Marketing and Trading Company, L.P., et al., Cause No. 2001-516,386, filed in the 72nd District Court of Lubbock County, Texas. Plaintiff is suing several ONEOK entities for alleged overcharges in connection with gas sales, transportation, and other services, and alleged misallocations and meter errors, in and around Lubbock, under three different gas contracts. While the petition is vague, it is broad enough to include claims for the period before and after March 1, 2000 when the assets in question were conveyed by us to ONEOK. We and ONEOK are defending the case pursuant to an agreement whereby ONEOK is responsible for any damages that may be attributable to the period following ONEOK's acquisition of the assets in question. In an amended petition filed in mid-2002, plaintiff alleged damages in excess of $12 million. Defendants have filed a counterclaim for offsetting damages and accounting corrections under the contracts with the plaintiff. The parties are currently engaged in an informal dispute resolution process in an attempt to resolve their accounting and other differences. In the event this process does not resolve the claims, a scheduling order will be established for completion of fact discovery and trial. We believe that the resolution of plaintiff's claims will be for amounts substantially less than the amounts sought.

We believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants and will vigorously defend against them. Based on our evaluation of the above matters, and after consideration of reserves established, we believe that the resolution of such matters will not have a material adverse effect on our businesses, cash flows, financial position or results of operations.

In addition, 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.

11. Property, Plant and Equipment

Investments in property, plant and equipment ("PP&E"), at cost, and accumulated depreciation and amortization ("Accumulated D&A") are as follows:

	December 31, 2002
	Property, Plant and Equipment	Accumulated D&A	Net
	(In thousands)
Natural Gas Pipelines	$ 6,017,871	$ 305,648	$ 5,712,223
Retail Natural Gas Distribution	334,406	124,274	210,132
Electric Power Generation	39,105	5,895	33,210
General and Other	153,036	60,494	92,542
PP&E Related to Continuing Operations	$ 6,544,418	$ 496,311	$ 6,048,107
	============	============	============

	December 31, 2001
	Property, Plant and Equipment	Accumulated D&A	Net
	(In thousands)
Natural Gas Pipelines	$ 5,613,578	$ 216,302	$ 5,397,276
Retail Natural Gas Distribution	285,674	101,520	184,154
Electric Power Generation	23,087	3,228	19,859
General and Other	156,495	53,832	102,663
PP&E Related to Continuing Operations	$ 6,078,834	$ 374,882	$ 5,703,952
	============	============	============

12. Income Taxes

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

	Year Ended December 31,
	2002	2001	2000
	(Dollars in thousands)
Current Tax Provision:
Federal	$ 61,889	$ 3,729	$ 3,212
State	17,382	25,917	14,091
Total	79,271	29,646	17,303

Deferred Tax Provision:
Federal	85,026	128,266	94,688
State	(28,385)	10,689	11,026
	56,641	138,955	105,714
Total Tax Provision	$ 135,912	$ 168,601	$ 123,017
	=========	==========	=========

Effective Tax Rate	30.5%	41.4%	40.0%
	=====	=====	=====

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:
State Income Tax, Net of Federal Benefit	3.0%	5.7%	5.6%
Kinder Morgan Management minority interest	2.8%	1.4%	-
Deferred Tax Rate Change	(4.9%)	-	-
Prior Year Adjustments	(1.9%)	-	-
Resolution of Internal Revenue Service Audit	(2.0%)	-	-
Other	(1.5%)	(0.7%)	(0.6%)
Effective Tax Rate	30.5%	41.4%	40.0%
	=====	=====	=====

Income taxes included in the financial statements were composed of the following:

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Continuing Operations	$ 135,912	$ 168,601	$ 123,017
Discontinued Operations	(3,056)	-	(21,200)
Extraordinary Item	(893)	(9,044)	-
Cumulative Effect of Transition Adjustment	-	(7,922)	-
Equity Items	(44,867)	43,866	(30,311)
Total	$ 87,096	$ 195,501	$ 71,506
	=========	==========	=========

Deferred tax assets and liabilities result from the following:

	December 31,
	2002	2001
	(In thousands)
Deferred Tax Assets:
Postretirement Benefits	$ 14,011	$ 15,133
Gas Supply Realignment Deferred Receipts	6,766	12,154
State Taxes	101,846	111,828
Book Accruals	93,819	29,208
Derivatives	18,829	-
Discontinued Operations	2,618	2,089
Alternative Minimum Tax Credits	-	12,283
Net Operating Loss Carryforwards	-	29,540
Capital Loss Carryforwards	-	28,640
Valuation Allowance	-	(2,462)
Other	8,958	5,020
Total Deferred Tax Assets	246,847	243,433
Deferred Tax Liabilities:
Property, Plant and Equipment	1,983,060	1,972,881
Investments	696,251	688,224
Derivatives	-	6,580
Other	3,316	4,252
Total Deferred Tax Liabilities	2,682,627	2,671,937
Net Deferred Tax Liabilities	$2,435,780	$2,428,504
	==========	==========

The effective tax rate for 2002 was reduced by approximately two percent, principally due to a decrease in the provision for state income taxes. As a result, deferred tax liabilities were decreased by approximately $21.0 million. During 2002, we resolved certain issues with the Internal Revenue Service at amounts less than those previously accrued. At December 31, 2001, we had available capital loss carryforwards of $71.6 million. A valuation allowance of $2.5 million had been provided for the deferred tax benefits related to a portion of the capital loss carryforwards. At December 31, 2002, all capital loss carryforwards had been utilized so the valuation allowance was reversed.

13. Financing

(A) Notes Payable

At December 31, 2002, we had available a $430 million 364-day credit facility dated October 15, 2002, and a $345 million three-year revolving credit agreement dated October 15, 2002. These bank facilities can be used for general corporate purposes, including backup for our commercial paper program, and include covenants that are common in such arrangements. For example, both facilities require consolidated debt to be less than 65% of consolidated capitalization. Also, both of the bank facilities require the debt of consolidated subsidiaries to be less than 10% of our consolidated debt and require the consolidated debt of each material subsidiary to be less than 65% of our consolidated total capitalization. In addition, both credit agreements require our consolidated net worth (inclusive of trust preferred securities) be at least $1.7 billion plus 50% of consolidated net income earned for each fiscal quarter beginning with the third quarter of 2002. Under the bank facilities, we are required to pay a facility fee based on the total commitment, at a rate that varies based on our senior debt investment rating. Facility fees paid in 2002 and 2001 were $1.0 million and $1.4 million, respectively. At December 31, 2002 and 2001, no amounts were outstanding under the bank facilities.

Commercial paper issued by us and supported by the bank facilities are unsecured short-term notes with maturities not to exceed 270 days from the date of issue. During 2002, all commercial paper was redeemed within 99 days, with interest rates ranging from 1.5 percent to 2.5 percent. There was no

commercial paper outstanding at December 31, 2002 and $423.8 million of commercial paper was outstanding at December 31, 2001. Average short-term borrowings outstanding during 2002 and 2001 were $415.2 million and $447.8 million, respectively. During 2002 and 2001, the weighted-average interest rates on short-term borrowings outstanding were 2.07 percent and 3.91 percent, respectively.

(B) Long-term Debt and Premium Equity Participating Security Units

	December 31,
	2002	2001
	(In Thousands)
Debentures:
6.50% Series, Due 2013	$ 50,000	$ 50,000
7.85% Series, Due 2022	-	24,025
8.75% Series, Due 2024	75,000	75,000
7.35% Series, Due 2026	125,000	125,000
6.67% Series, Due 2027	150,000	150,000
7.25% Series, Due 2028	493,000	493,000
7.45% Series, Due 2098	150,000	150,000
Sinking Fund Debentures:
8.35% Series, Due 2022	-	35,000
Senior Notes:
7.27% Series, Due 2002	-	5,000
6.45% Series, Due 2003	500,000	500,000
6.65% Series, Due 2005	500,000	500,000
6.80% Series, Due 2008	300,000	300,000
6.50% Series Due 2012	1,000,000	-
Floating Rate Notes, Due 2002	-	200,000
Other	11,083	12,350
Carrying Value Adjustment for Interest Rate Swaps¹	139,589	(4,831)
Unamortized Premium on Long-term Debt	4,237	-
Unamortized Debt Discount	(4,872)	(3,310)
Current Maturities of Long-term Debt	(501,267)	(206,267)
Total Long-term Debt	$2,991,770	$2,404,967
	==========	==========



1Adjustment of carrying value of long-term securities subject to interest rate swaps; see Note 15.

Maturities of long-term debt (in thousands) for the five years ending December 31, 2007 are $501,267, $6,267, $506,267, $12,282, and $5,000, respectively.

The 2013 Debentures and the 2003 and 2005 Senior Notes are not redeemable prior to maturity. The 2028 and 2098 Debentures and the 2008 and 2012 Senior Notes are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. The 2024, 2026 and 2027 Debentures are redeemable in whole or in part, at our option after October 15, 2004, August 1, 2006, and November 1, 2004, respectively, at redemption prices defined in the associated prospectus supplements.

On November 1, 2002, we retired the full $35 million of our 8.35% Series Sinking Fund Debentures due September 15, 2022 at a premium of 104.175% of the face amount of the debentures. We recorded an extraordinary loss of $1.0 million (net of associated tax benefit of $0.7 million) in connection with this early extinguishment of debt. This loss, and the loss recorded in conjunction with the early extinguishment of debt associated with the retirement of our 7.85% Series Debentures described below, are included under the caption "Extraordinary Item, Loss on Early Extinguishment of Debt" in the accompanying Consolidated Statements of Operations for 2002 but will be reclassified in future reports as discussed in Note 21.

On October 10, 2002, we retired our $200 million of Floating Rate Notes due October 10, 2002, utilizing a combination of cash and incremental short-term debt. Effective September 1, 2002, we retired our $24 million of 7.85% Series Debentures due September 1, 2022 at par. We recorded an extraordinary loss of $420 thousand (net of associated tax benefit of $275 thousand) in conjunction with this early extinguishment of debt, consisting of the unamortized debt expense associated with these debentures.

On September 10, 2001, we retired our $45 million of 9.625% Series Sinking Fund Debentures due March 1, 2021, utilizing incremental short-term borrowings. In March 2001, we retired (i) our $400 million of Reset Put Securities due March 1, 2021 and (ii) our $20 million of 9.95% Series Sinking Fund Debentures due 2020, utilizing a combination of cash and incremental short-term borrowings. In conjunction with these early extinguishments of debt, we recorded extraordinary losses of $13.6 million (net of associated tax benefit of $9.0 million). These losses are included under the caption, "Extraordinary Item, Loss on Early Extinguishment of Debt" in the accompanying Consolidated Statements of Operations for 2001 but will be reclassified in future reports as discussed in Note 21.

At December 31, 2002 and 2001, the carrying amount of our long-term debt was $3.5 billion and $2.6 billion, respectively. The estimated fair values of our long-term debt at December 31, 2002 and 2001 are shown in Note 19.

(C) Capital Securities

Our wholly owned business trusts, K N Capital Trust I and K N Capital Trust III, are obligated for $100 million of 8.56% Capital Trust Securities maturing on April 15, 2027 and $175 million of 7.63% Capital Trust Securities maturing on April 15, 2028, respectively. The transactions and balances of K N Capital Trust I and K N Capital Trust III are included in our consolidated financial statements, with the Capital Securities treated as a minority interest, shown in our Consolidated Balance Sheets under the caption "Kinder Morgan-Obligated Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan." Periodic payments made to the holders of these securities are classified under "Minority Interests" in the accompanying Consolidated Statements of Operations. See Note 19 for the fair value of these securities.

(D) Common Stock

On February 14, 2003, we paid a cash dividend on our common stock of $0.15 per share to stockholders of record as of January 31, 2003.

On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock, which program was increased to $400 million and $450 million at February 5, 2002 and July 17, 2002, respectively. As of December 31, 2002, we had repurchased a total of approximately $414.7 million (8,308,200 shares) of our outstanding common stock under the program, of which $144.3 million (3,013,400 shares) and $270.4 million (5,294,800 shares) were repurchased in the years ended December 31, 2002 and 2001, respectively.

(E) Kinder Morgan Management, LLC

In May 2001, Kinder Morgan Management, one of our indirect subsidiaries, issued and sold its shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the i-units, Kinder Morgan Management became a partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners' general partner the responsibility to manage and control Kinder Morgan Energy Partners' business and affairs. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests that have been, and will be, issued only to Kinder Morgan Management. In the initial public offering, 10 percent of Kinder Morgan Management's shares were purchased by Kinder Morgan, Inc., with the balance purchased by the public. The equity interest in Kinder Morgan Management (our consolidated subsidiary) purchased by the public created a minority interest on our balance sheet of $892.7 million at the time of the transaction. See Note 3 for additional information regarding these transactions.

In January 2003, our board of directors approved a plan to purchase shares of Kinder Morgan Management on the open market. Through February 1, 2003, such purchases were insignificant.

14. Preferred Stock

We have authorized 200,000 shares of Class A and 2,000,000 shares of Class B preferred stock, all without par value. At December 31, 2002, 2001 and 2000, we did not have any outstanding shares of preferred stock.

15. Risk Management

Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, "Statement 133." Statement 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. The accompanying Consolidated Balance Sheet as of December 31, 2002, includes, exclusive of amounts related to interest rate swaps as

discussed below, balances of approximately $9.6 million, $41 thousand, $36.9 million and $1.2 million in the captions "Current Assets: Other," "Deferred Charges and Other Assets," "Current Liabilities: Other," and "Other Liabilities and Deferred Credits: Other" respectively, related to these derivative financial instruments. Statement 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, Statement 133 allows a derivative's gains and losses to offset related results from 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.

We enter into derivative contracts solely for the purpose of hedging exposures that accompany our normal business activities. As a result of the adoption of Statement 133, the fair value of our derivative financial instruments utilized for hedging activities as of January 1, 2001 (a loss of $11.9 million) was reported as a cumulative effect transition adjustment within accumulated other comprehensive income. All but an insignificant amount of this transition adjustment was reclassified into earnings during 2001. In accordance with the provisions of Statement 133, we designated these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs.

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 Statement 133. Upon making that determination, we (i) ceased to account for those derivatives as hedges, (ii) entered into new derivative transactions with other counterparties to replace our position with Enron, (iii) designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions and (iv) recognized a $5.0 million pre-tax 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.

With respect to item (i), we have no commodity risk because the regulated retail gas distribution regulatory structure provides that actual gas cost is "passed-through" to our customers. With respect to item (iii), only one of these power generation facilities is not covered by a long-term, fixed price gas supply agreement at a level sufficient for the current and projected capacity utilization. With respect to item (iv), this fuel is supplied by in-kind fuel recoveries that are part of the transportation tariff. Items (ii), (v) and the one power facility included under item (iii) that is not covered by a long-term fixed-price natural gas supply agreement, give rise to natural gas commodity price risk which we have chosen to substantially mitigate through our risk management program. We provide this mitigation through the use

of financial derivative products, and we do not utilize these derivatives for any purpose other than risk mitigation.

Under our Choice Gas program, customers in certain areas served by Kinder Morgan Retail are allowed to choose their natural gas supplier from a list of qualified suppliers, although the transportation of the natural gas to the homes and businesses continues to be provided by Kinder Morgan Retail in all cases. When those customers choose Kinder Morgan Retail as their Choice Gas supplier, we enter into agreements providing for sales of gas to these customers during a one-year period at fixed prices per unit, but variable volumes. We mitigate the risk associated with these anticipated sales of gas by purchasing natural gas futures contracts on the New York Mercantile Exchange ("NYMEX") and, as applicable, over-the-counter basis swaps to mitigate the risk associated with the difference in price changes between Henry Hub (NYMEX) basis and the expected physical delivery location. In addition, we mitigate a portion of the volumetric risk through the purchase of over-the-counter natural gas options. The time period covered by this risk management strategy does not extend beyond one year.

During 2002 and 2001, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized approximately $46,000 and $5,000 of pre-tax loss during 2002 and 2001, respectively, as a result of ineffectiveness of these hedges, which amounts are reported within the caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statements of Operations for 2002 and 2001. There was no component of the derivative instruments' gain or loss excluded from the assessment of hedge effectiveness.

As the hedged sales and purchases take place and we record them into earnings, we will also reclassify the gains and losses included in accumulated other comprehensive income into earnings. We expect to reclassify into earnings, during 2003, substantially all of the accumulated other comprehensive income balance of $20.9 million at December 31, 2002, representing unrecognized net losses on derivative activities. During 2002, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

converted the interest expense associated with our 6.65% Senior Notes due in 2005, our 7.25% Debentures due in 2028 and our 6.50% Senior Notes due in 2012 from fixed rates to floating rates based on three-month LIBOR plus a credit spread. These swaps have been designated as fair value hedges as defined by Statement 133. These swaps meet the conditions required to assume no ineffectiveness under Statement 133 and, therefore, we have accounted for them utilizing the "shortcut" method prescribed for fair value hedges. Accordingly, the carrying value of the swap is adjusted to its fair value as of each reporting period, with an offsetting entry to adjust the carrying value of the debt whose fair value is being hedged. The carrying value of the swaps was $139.6 million at December 31, 2002, and is included in the caption "Deferred Charges and Other Assets" on the Consolidated Balance Sheets. The carrying value of the swaps at December 31, 2001, included $7.2 million in the caption "Deferred Charges and Other Assets" and $12.2 million in the caption "Other Liabilities and Deferred Credits: Other" on the Consolidated Balance Sheets. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually. Based on the long-term debt effectively converted to floating rate debt as a result of the swap discussed above, at December 31, 2002, the market risk related to a one percent change in interest rates would result in a $17.5 million annual impact on pre-tax income.

Following is selected information concerning our natural gas risk management activities:

	December 31, 2002
	Commodity Contracts	Over-the-Counter Swaps and Options		Total
	(Dollars in thousands)

Deferred Net (Loss) Gain	$ (3,381)		$ (17,227)	$ (20,608)
Contract Amounts - Gross	$ 105,538		$ 117,370	$ 222,908
Contract Amounts - Net	$ (10,739)		$ (89,868)	$(100,607)

	(Number of Contracts¹)
Notional Volumetric Positions: Long	329		998
Notional Volumetric Positions: Short	(1,151)		(2,769)
Net Notional Totals To Occur in 2003	(822)		(1,723)
Net Notional Totals To Occur in 2004 and Beyond	-		(48)



1 A term of reference describing a volumetric unit of commodity trading. One natural gas contract equals 10,000 MMBtus.

Our over-the-counter swaps and options are with a number of parties, each of which is an investment grade credit. We both owe money and are owed money under these financial instruments and, at December 31, 2002, if all parties owing us failed to pay us amounts due at that date under these arrangements, our pre-tax credit loss would have been $0.5 million. At December 31, 2002, the largest credit exposure to a single counterparty was $0.5 million.

16. Employee Benefits

(A) Retirement Plans

We have defined benefit pension plans covering eligible full-time employees. These plans provide pension benefits that are based on the employees' compensation during the period of employment, age and years of service. These plans are tax-qualified subject to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended. Our funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds. Plan assets included our common stock valued at $14.3 million and

$12.3 million as of December 31, 2002 and 2001, respectively.

Net periodic pension cost includes the following components:

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Service Cost	$ 7,121	$ 5,329	$ 7,306
Interest Cost	10,484	9,421	8,600
Expected Return on Assets	(15,665)	(15,145)	(14,034)
Net Amortization and Deferral	21	(1,282)	(1,257)
Settlement Loss	76	-	-
Net Periodic Pension (Benefit) Cost	$ 2,037	$ (1,677)	$ 615
	==========	==========	==========

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:

	2002	2001
	(In thousands)
Benefit Obligation at Beginning of Year	$ (140,767)	$ (125,091)
Service Cost	(7,121)	(5,329)
Interest Cost	(10,484)	(9,421)
Actuarial (Gain) Loss	(6,629)	(7,447)
Benefits Paid	9,021	7,512
Settlement Loss	(70)	-
Plan Amendments	(1,482)	(991)
Business Combinations/Mergers	(4,649)	-
Benefit Obligation at End of Year	$ (162,181)	$ (140,767)
	==========	==========

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of the plans' assets, the plans' funded status and prepaid (accrued) pension cost:

	December 31,
	2002	2001
	(In thousands)
Fair Value of Plan Assets at Beginning of Year	$ 149,477	$ 163,096
Actual Return on Plan Assets During the Year	(17,739)	(6,211)
Contributions by Employer	20,238	104
Benefits Paid During the Year	(9,021)	(7,512)
Business Combinations/Mergers	4,636	-
Fair Value of Plan Assets at End of Year	147,591	149,477
Benefit Obligation at End of Year	(162,181)	(140,767)
Plan Assets in Excess of (Less Than) Projected Benefit Obligation	(14,590)	8,710
Unrecognized Net (Gain) Loss	37,683	(2,770)
Prior Service Cost Not Yet Recognized in Net Periodic Pension Costs	2,195	993
Unrecognized Net Asset at Transition	(358)	(529)
Prepaid Pension Cost Prior to Adjustment to Recognize
Minimum Liability	24,930	6,404
Adjustment to Recognize Minimum Liability	(30,787)	(207)
Prepaid /(Accrued) Pension Cost After Adjustment to Recognize
Minimum Liability	$ (5,857)	$ 6,197
	==========	==========

The rate of increase in future compensation was 3.5 percent for 2002, 2001 and 2000. The expected long-term rate of return on plan assets was 9.0 percent for 2002 and 9.5 percent for 2001 and 2000. The

weighted-average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.0 percent for 2002, 7.25 percent for 2001 and 7.75 percent for 2000.

As is required by SFAS No. 87, Employers' Accounting for Pensions, for plans where the accumulated benefit obligation exceeds the fair value of plan assets, we have recognized in the accompanying Consolidated Balance Sheets the minimum liability of the unfunded accumulated benefit obligation as a long-term liability with an offsetting intangible asset and equity adjustment, net of tax impact. As of December 31, 2002, this minimum liability amounted to $5.9 million. At December 31, 2001, the fair value of plan assets exceeded the accumulated benefit obligation; therefore no minimum liability was recognized. Prepaid pension cost as of December 31, 2001 is recognized under the caption, "Current Assets: Other" in our Consolidated Balance Sheets.

Effective January 1, 2001, we added a cash balance plan to our retirement plan. Certain collectively bargained employees and "grandfathered" employees will continue to accrue benefits through the defined pension benefit plan described above. All other employees will accrue benefits through a personal retirement account in the new cash balance plan. All employees converting to the cash balance plan were credited with the current fair value of any benefits they have previously accrued through the defined benefit plan. We make contributions on behalf of these employees equal to 3% of eligible compensation every pay period. In addition, we may make discretionary contributions to the plan based on our performance. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees will be fully vested in the plan after five years, and they may take a lump sum distribution upon termination or retirement.

On December 31, 2000, the Hall-Buck Marine Services Company Pension Plan ("Hall-Buck Plan") was merged into our retirement plan. The Hall-Buck Plan's projected benefit obligation of $2.0 million, unrecognized transition obligation of $1.3 million and plan assets of $1.8 million were transferred to our retirement plan, and the Hall-Buck Plan was terminated. Also on December 31, 2000, all employees who were not previously eligible to participate in our retirement plan and were not otherwise covered under a collective bargaining agreement became eligible under the new cash balance plan.

Effective December 31, 2001 we merged the Pinney Dock Retirement Plan, the Boswell Oil Company Pension Plan, and the River Transportation Retirement Plan into our retirement plan. As of January 1, 2002, all assets and liabilities of these plans were transferred to our retirement plan.

In 2000, we merged the Kinder Morgan Bulk Terminals Retirement Savings Plan and the Kinder Morgan Retirement Savings Plan with the Kinder Morgan Profit Sharing and Savings Plan, a defined contribution plan. The merged plan was renamed the Kinder Morgan, Inc. Savings Plan. On July 2, 2000, we began making regular contributions to the Plan. Contributions are made each pay period in an amount equal to 4% of compensation on behalf of each eligible employee. All contributions are in the form of Company stock, which is immediately convertible into other available investment vehicles at the employee's discretion. On July 25, 2000, our Board of Directors authorized an additional 6 million shares to be issued through the Plan, for a total of 6.7 million shares available. In addition to the above contributions, we may make annual discretionary contributions based on our performance. These contributions are made in the year following the year for which the contribution amount is calculated. The total amount contributed for 2002, 2001 and 2000 was $11.4 million, $9.5 million and $3.7 million, respectively.

(B) Other Postretirement Employee Benefits

We have a defined benefit postretirement plan providing medical and life insurance benefits upon retirement for eligible employees and their eligible dependents. We fund a portion of the future expected postretirement benefit cost under the plan by making payments to Voluntary Employee Benefit

Association trusts. Plan assets consist primarily of pooled fixed income funds.

Net periodic postretirement benefit cost includes the following components:

	Year Ended December 31,
	2002	2001	2000
	(In thousands)
Service Cost	$ 419	$ 340	$ 413
Interest Cost	7,251	7,266	7,159
Expected Return on Assets	(6,721)	(5,431)	(4,790)
Net Amortization and Deferral	2,352	1,501	992
Net Periodic Postretirement Benefit Cost	$ 3,301	$ 3,676	$ 3,774
	==========	==========	==========

The following table sets forth the reconciliation of the beginning and ending balances of the accumulated postretirement benefit obligation:

	2002	2001
	(In thousands)

Benefit Obligation at Beginning of Year	$ (101,063)	$ (95,178)
Service Cost	(419)	(340)
Interest Cost	(7,251)	(7,266)
Actuarial Gain (Loss)	(9,304)	(3,209)
Benefits Paid	16,440	10,504
Retiree Contributions	(3,681)	(2,529)
Plan Amendments	-	(3,045)
Benefit Obligation at End of Year	$ (105,278)	$ (101,063)
	==========	==========

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets, the plan's funded status and the amounts included under the caption "Other" in the category "Other Liabilities and Deferred Credits" in our Consolidated Balance Sheets:

	December 31,
	2002	2001
	(In thousands)

Fair Value of Plan Assets at Beginning of Year	$ 80,098	$ 51,156
Actual Return on Plan Assets	(2,522)	3,496
Contributions by Employer	-	31,683
Retiree Contributions	4,715	1,852
Benefits Paid	(11,332)	(8,089)
Asset Value Adjustment	(5,875)	-
Fair Value of Plan Assets at End of Year	65,084	80,098
Benefit Obligation at End of Year	(105,278)	(101,063)
Excess of Projected Benefit Obligation Over Plan Assets	(40,194)	(20,965)
Unrecognized Net (Gain) Loss	40,829	17,591
Unrecognized Net Obligations at Transition	9,291	10,220
Unrecognized Prior Service Cost	2,567	2,807
Accrued Expense	$ 12,493	$ 9,653
	===========	===========

The weighted-average discount rate used in determining the actuarial present value of the accumulated postretirement benefit obligation was 7.0 percent for 2002, 7.25 percent for 2001 and 7.75 percent for 2000. The expected long-term rate of return on plan assets was 9.0 percent for 2002 and 9.5 percent for 2001 and 2000. The assumed health care cost trend rate for all years presented was 3 percent (7 percent

for certain collectively bargained employees). A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2002 net periodic postretirement benefit cost by approximately $5,849 ($5,466) and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2002 by approximately $81,287 ($74,695).

17. Common Stock Option and Purchase Plans

We have the following stock option plans: The 1982 Incentive Stock Option Plan, the 1982 Stock Option Plan for Non-Employee Directors, the 1986 Incentive Stock Option Plan, the 1988 Incentive Stock Option Plan, the 1992 Non-Qualified Stock Option Plan for Non-Employee Directors, the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which also provides for the issuance of restricted stock), the American Oil and Gas Corporation Stock Incentive Plan ("AOG Plan") and the Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan. We also have an employee stock purchase plan.

We account for these plans using the "intrinsic value" method contained in Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Had we applied the "fair value" method contained in SFAS No. 123, Accounting for Stock-Based Compensation, our earnings would have been affected; see Note 1(R).

On October 8, 1999, our Board of Directors approved the creation of our 1999 stock option plan, a broadly based non-qualified stock option plan. Under the plan, options may be granted to individuals who are regular full-time employees, including officers and directors who are employees. Options under the plan vest in 25 percent increments on the anniversary of the grant over a four-year period from the date of grant. All options that have been granted under the plan have a 10-year life, and all options granted under the plan must be granted at not less than the fair market value of Kinder Morgan, Inc. common stock at the close of trading on the date of grant. On January 17, 2001, our Board of Directors approved an additional 5 million shares for future grants to participants in the 1999 Stock Option Plan, which brings the aggregate number of shares subject to the plan to 10.5 million. The Board also recommended, and our shareholders approved at our May 8, 2001 annual meeting, an additional 0.5 million shares for future grants to participants in the 1992 Directors' Plan, which brings the aggregate number of shares subject to that plan to 1.03 million.

Under all plans, except the Long-term Incentive Plan and the AOG Plan, options must be granted at not less than 100 percent of the market value of the stock at the date of grant. Under the Long-term Incentive Plan options may be granted at less than 100 percent of the market value of the stock at the date of grant although we do not expect to make any grants of options at less than 100 percent of the market value of the stock at the grant date. Compensation expense was recorded totaling $1.4 million, $0.6 million and $0 for 2002, 2001 and 2000, respectively, relating to restricted stock grants awarded under the plans.

Plan Name	Shares Subject to the Plan	Option Shares Granted Through December 31, 2002	Vesting Period	Expiration Period

1982 Plan	1,332,788	1,332,788	Immediate	10 Years
1982 Directors' Plan	186,590	186,590	3 Years	10 Years
1986 Plan	618,750	618,750	Immediate	10 Years
1988 Plan	618,750	618,750	Immediate	10 Years
1992 Directors' Plan	1,025,000	537,875	0 - 6 Months	10 Years
Long-term Incentive Plan	5,700,000	3,083,688	0 - 5 Years	5 - 10 Years
AOG Plan	775,500	775,500	3 Years	10 Years
1999 Plan	10,500,000	7,572,727	4 Years	10 Years

A summary of the status of our stock option plans at December 31, 2002, 2001 and 2000, and changes during the years then ended is presented in the table and narrative below:

	2002		2001		2000
	Shares	Wtd. Avg. Exercise Price	Shares	Wtd. Avg. Exercise Price	Shares	Wtd. Avg. Exercise Price
Outstanding at Beginning
of Year	6,975,717	$ 33.12	6,093,819	$ 26.05	7,542,898	$ 24.92
Granted	1,231,525	$ 47.76	2,140,200	$ 51.17	1,364,500	$ 30.42
Exercised	(519,091)	$ 23.46	(899,664)	$ 25.36	(537,400)	$ 19.26
Forfeited	(207,236)	$ 38.64	(358,638)	$ 35.14	(2,276,179)	$ 25.69
Outstanding at End of Year	7,480,915	$ 35.94	6,975,717	$ 33.12	6,093,819	$ 26.05
	==========	=======	==========	=======	==========	=======

Exercisable at End of Year	3,978,017	$ 31.93	2,922,471	$ 29.93	2,056,771	$ 27.03
	==========	=======	==========	=======	==========	=======

Weighted-Average Fair
Value of Options Granted		$ 19.36		$ 21.31		$ 10.51
		=======		=======		=======

The following table sets forth our December 31, 2002, common stock options outstanding, weighted-average exercise prices, weighted-average remaining contractual lives, common stock options exercisable and the exercisable weighted-average exercise price:

Options Outstanding				Options Exercisable
Price Range	Number Outstanding	Wtd. Avg. Exercise Price	Wtd. Avg. Remaining Contractual Life	Number Exercisable	Wtd. Avg. Exercise Price

$00.00 - $23.72	108,352	$ 21.19	4.25 years	108,102	$ 21.19
$23.81 - $23.81	2,741,484	$ 23.81	6.77 years	1,888,316	$ 23.81
$24.04 - $39.12	2,092,991	$ 32.75	7.31 years	1,062,419	$ 30.96
$39.38 - $53.20	1,936,513	$ 50.94	8.17 years	812,755	$ 50.37
$53.60 - $56.99	601,575	$ 56.70	9.02 years	106,425	$ 55.93
	7,480,915	$ 35.94	7.43 years	3,978,017	$ 31.93
	==========			==========

Under the employee stock purchase plan, we may sell up to 2,400,000 shares of common stock to eligible employees. Employees purchase shares through voluntary payroll deductions. Shares are purchased quarterly at a 15 percent discount from the closing price of the common stock on the last trading day of each calendar quarter. Employees purchased 127,425 shares, 88,333 shares and 86,630 shares for plan years 2002, 2001 and 2000, respectively. Using the Black-Scholes model to assign value to the option inherent in the right to purchase stock under the provisions of the employee stock purchase plan, the weighted-average fair value per share of purchase rights granted in 2002, 2001 and 2000 was $9.60, $10.66 and $6.60, respectively.

18. Commitments and Contingent Liabilities

(A) Leases and Guarantee

Expenses incurred under operating leases were $8.1 million in 2002, $7.1 million in 2001 and $47.1 million in 2000. Future minimum commitments under major operating leases as of December 31, 2002 are as follows:

Year			Commitment
			(In thousands)

2003			$ 9,248
2004			9,557
2005			9,786
2006			8,684
2007			8,908
Thereafter			7,157
Total			$ 53,340
			==========

As a result of our December 1999 sale of assets to ONEOK, ONEOK assumed our obligation for the lease of the Bushton gas processing facility. We remain secondarily liable for the lease, which had a remaining minimum obligation of approximately $226.2 million at December 31, 2002, with payments that average approximately $23 million per year through 2012. In conjunction with our contributions of assets to Kinder Morgan Energy Partners at December 31, 1999 and 2000, we are a guarantor of approximately $522.7 million of Kinder Morgan Energy Partners' debt. We would be obligated to perform under this guarantee only if Kinder Morgan Energy Partners and/or its assets were unable to satisfy its obligations.

(B) Capital Expenditures Budget

Approximately $1.0 million of our consolidated capital expenditure budget for 2003 had been committed for the purchase of plant and equipment at December 31, 2002.

(C) Commitments for Incremental Investment

We are obligated to invest an additional $12 million during 2003 at one power generation facility, which represents approximately $6 million of additional preferred equity investment plus approximately $6 million to fund operating cash deficiencies plus interest. In addition, we could be obligated (i) based on operational performance of the equipment at one power generation facility to invest up to an additional $3 to $8 million per year for the next 16 years and (ii) based on cash flows generated by the facility, to invest up to an additional $25 million beginning in year 17, in each case in the form of an incremental preferred interest. Prior to December 31, 2003, we are committed to make an incremental investment in the Thermo Companies in the form of approximately 1.6 million common units of Kinder Morgan Energy Partners, either currently owned by us or acquired, in exchange for an incremental ownership interest beginning in 2010.

(D) Standby Letters of Credit

Letters of credit totaling $31.5 million outstanding at December 31, 2002 consisted of the following: (i) three letters of credit, totaling $5.7 million, required under provisions of our property and casualty, worker's compensation and general liability insurance policies, (ii) a $13.0 million letter of credit supporting the subordination of operating fees payable to us for operation of the Jackson, Michigan power generation facility to payments due under the operating lease of the facilities, (iii) a $3.4 million

letter of credit supporting our obligation to attach a specified number of meters within a specified timeframe in our Hermosillo, Mexico natural gas distribution operations, (iv) a $6.6 million letter of credit associated with the outstanding debt of KN Thermo LLC, the entity responsible for the operation of our Colorado power generation assets and (v) a $2.8 million letter of credit supporting KN Thermo LLC's performance under its contract with Public Service Company of Colorado, the principal customer of our Colorado power generation assets.

(E) Other Obligations

Other obligations are discussed in Note 1(M) and Note 8.

19. Fair Value

The following fair values of Long-term Debt and Capital Securities were estimated based on an evaluation made by an independent securities analyst. Fair values of "Energy Financial Instruments, Net" reflect the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. Market quotes are available for substantially all instruments we use.

	December 31,
	2002		2001
	Carrying Value	Fair Value	Carrying Value	Fair Value
	(In millions)
Financial Liabilities:
Long-term Debt	$ 3,493.7¹	$ 3,632.8¹	$ 2,614.5¹	$ 2,624.5¹
Capital Securities	$ 275.0	$ 280.6	$ 275.0	$ 279.7
Energy Financial Instruments, Net	$ (20.6)	$ (20.6)	$ 16.2	$ 16.2
Interest Rate Swaps	$ (139.6)	$ (139.6)	$ 4.8	$ 4.8



1 Includes an adjustment exactly offsetting the value of the interest rate swaps. See Note 15.

20. Business Segment Information

In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business segment performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America, a major interstate natural gas pipeline and storage system; (2) TransColorado Gas Transmission Company, referred to as TransColorado Pipeline, an interstate natural gas pipeline located in western Colorado and northwest New Mexico; (3) Kinder Morgan Retail, the regulated sale and transportation of natural gas to residential, commercial and industrial customers (including a small distribution system currently being built-out in Hermosillo, Mexico) and the non-regulated sales of natural gas to certain utility customers under the Choice Gas Program and (4) Power and Other, the construction and operation of natural gas-fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments. In previous periods, we owned and operated other lines of business that we discontinued during 1999. In addition, our direct investment in the natural gas transmission and storage business decreased significantly as a result of the December 2000 transfer of Kinder Morgan Texas Pipeline, L.P. to Kinder Morgan Energy Partners. The results of operations of this business are included in our financial statements until its disposition, which is discussed in Note 5.

The accounting policies we apply in the generation of business segment information are generally the

100

same as those described in Note 1, except that (i) certain items below the "Operating Income" line are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners and certain insignificant international investees, are included in segment results. These equity method earnings are included in "Other Income and (Expenses)" in our Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not allocated to individual business segments and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value. As necessary for comparative purposes, we have reclassified prior period results and balances to conform to the current presentation.

Natural Gas Pipeline Company of America's principal delivery market area encompasses the states of Illinois, Indiana, Iowa and portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural Gas Pipeline Company of America is the largest transporter of natural gas to the Chicago, Illinois area, its largest market. During 2002, approximately 42 percent of Natural Gas Pipeline Company of America's transportation represented deliveries to this market. Natural Gas Pipeline Company of America's storage capacity is largely located near its transportation delivery markets, effectively serving the same customer base. Natural Gas Pipeline Company of America has a number of individually significant customers, including local gas distribution companies in the greater Chicago area and major natural gas marketers and, during 2002, approximately 60 percent of its operating revenues from tariff services were attributable to its eight largest customers. TransColorado Pipeline's principal transport business consists primarily of transporting natural gas from the developing gas supply basins on the Western Slope of Colorado into the interstate natural gas pipeline grid in the Blanco Hub area of New Mexico. During 2002, 44 percent of TransColorado Pipeline's transport business was with producers or their own marketing affiliates, 42 percent was with third-party marketers and the remaining 14 percent was primarily with gathering companies. Approximately 43 percent of TransColorado Pipeline's transport business in 2002 was conducted with its three largest customers. Kinder Morgan Retail's markets are represented by residential, commercial and industrial customers located in Colorado, Nebraska and Wyoming. These markets represent varied types of customers in many industries, but a significant amount of Kinder Morgan Retail's load is represented by the use of natural gas for space heating, grain drying and irrigation. The latter two groups of customers are concentrated in the agricultural industry, and all markets are affected by the weather. Power's current principal market is represented by the local electric utilities in Colorado, which purchase the power output from its generation facilities.

Our business activities expose us to credit risk with respect to collection of accounts receivable. In order to mitigate that risk, we routinely monitor the credit status of our existing and potential customers. When customers' credit ratings do not meet our requirements for the extension of unsupported credit, we obtain cash prepayments or letters of credit. Note 1(G) provides information on the amount of prepayments we have received.

During 2002 and 2001, we did not have revenues from any single customer that exceeded 10 percent of our consolidated operating revenues. In 2000, we had revenues from a single customer of $740.5 million, an amount in excess of 10% of consolidated operating revenues for that year. Both Natural Gas Pipeline Company of America and Kinder Morgan Texas Pipeline made sales to this customer. Sales to this customer did not exceed 10% of consolidated operating revenues in 2001 because we contributed Kinder Morgan Texas Pipeline to Kinder Morgan Energy Partners effective December 31, 2000.

101

Business Segment Information

	Year Ended December 31, 2002					December 31, 2002
	Segment Earnings	Revenues From External Customers	Intersegment Revenues	Depreciation And Amortization	Capital Expenditures	Segment Assets
	(In thousands)
Natural Gas Pipeline Company of America	$ 359,911	$ 699,998	$ -	$ 87,305	$ 132,026	$ 5,629,355
TransColorado Pipeline¹	12,648	7,725	93	1,062	325	258,627
Kinder Morgan Retail	64,056	259,748	-	15,044	25,395	406,797
Power and Other	36,673	47,784	-	3,085	17,207	389,596
Segment Totals	473,288	$1,015,255	$ 93	$ 106,496	$ 174,953	6,684,375
		==========	========	=========	=========
Earnings from Investment in Kinder Morgan Energy Partners	392,135			Investment In Kinder Morgan Energy Partners		2,034,160
General and Administrative Expenses	(73,496)			Goodwill		990,878
General and Administrative Expenses	(73,496)			Other³		393,337
Other Income and (Expenses)	(346,848)			Consolidated		$10,102,750
Income from Continuing Operations Before Income Taxes	$ 445,079					===========
	=========
	Year Ended December 31, 2001					December 31, 2001
	Segment Earnings (Loss)	Revenues From External Customers	Intersegment Revenues	Depreciation And Amortization	Capital Expenditures	Segment Assets
	(In thousands)
Natural Gas Pipeline Company of America	$ 346,569	$ 646,804	$ -	$ 85,843	$ 88,045	$ 5,598,239
TransColorado Pipeline¹	(5,268)	-	-	-	-	134,256
Kinder Morgan Retail	56,696	290,300	44	12,590	35,629	380,339
Power and Other	65,983	117,803	2,029	7,247	497	327,821
Segment Totals	463,980	$1,054,907	$ 2,073	$ 105,680	$ 124,171	6,440,655
		==========	========	=========	=========
Earnings from Investment in Kinder Morgan Energy Partners	251,860			Investment In Kinder Morgan Energy Partners		1,772,027
General and Administrative Expenses	(73,319)			Goodwill		1,055,767
General and Administrative Expenses	(73,319)			Other³		244,672
Other Income and (Expenses)	(235,285)			Consolidated		$ 9,513,121
Income from Continuing Operations Before Income Taxes	$ 407,236					===========
	=========

102

	Year Ended December 31, 2000					December 31, 2000
	Segment Earnings (Loss)	Revenues From External Customers	Intersegment Revenues	Depreciation And Amortization	Capital Expenditures	Segment Assets
	(In thousands)
Natural Gas Pipeline Company of America	$ 344,405	$ 622,020	$ (18)	$ 84,975	$ 49,771	$ 5,486,880
TransColorado Pipeline¹	(10,336)	-	-	-	-	34,824
Kinder Morgan Retail	47,705	235,209	(1)	11,904	19,008	377,384
Kinder Morgan Texas Pipeline²	29,318	1,747,499	-	2,211	16,734	-
Power and Other	37,222	74,228	4	6,917	141	230,399
Discontinued Operations	-	-	-	-	3,185	-
Segment Totals	448,314	$2,678,956	$ (15)	$ 106,007	$ 88,839	6,129,487
		==========	========	=========	=========
Earnings from Investment in Kinder Morgan Energy Partners	113,320			Investment In Kinder Morgan Energy Partners		661,644
General and Administrative Expenses	(59,799)			Goodwill		1,180,097
General and Administrative Expenses	(59,799)			Other³		425,450
Other Income and (Expenses)	(194,669)			Consolidated		$ 8,396,678
Income from Continuing Operations Before Income Taxes	$ 307,166					===========
	=========

¹ We purchased the remaining 50% of this entity effective October 1, 2002. Prior to October 1, 2002 we accounted for our TransColorado investment under the equity method
of accounting. Accordingly, the results presented represent a 50% equity interest prior to October 1, 2002 and a 100% consolidated interest thereafter.

² Kinder Morgan Texas Pipeline was transferred to Kinder Morgan Energy Partners effective December 31, 2000.

³ Includes, as applicable to each particular year, market value of derivative instruments (including interest rate swaps), income tax receivables and miscellaneous Corporate assets
(such as information technology and telecommunications equipment) not allocated to individual segments.

Geographic Information

All but an insignificant amount of our assets and operations are located in the continental United States.

21. Recent Accounting Pronouncements

103

effective for financial statements issued after January 31, 2003, all of the provisions are immediately applicable to variable interest entities created after January 31, 2003 and public entities with variable interests in entities created before February 1, 2003 are required to apply the provisions (other than the transition disclosure provisions) to that entity no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003. The principal impact of this interpretation on us is that, upon implementation, we expect to begin consolidation of Triton Power Company LLC, the lessee of the Jackson, Michigan power generation facility. We operate and have a preferred interest in this entity in which the common interest is owned by others. Triton Power Company LLC has no debt but, as a result of this consolidation, we will include the lease obligation on the Jackson plant in our consolidated financial statements. We expect to apply the provisions of the statement beginning with the third quarter of 2003 and, at that time, the total remaining lease payments will be $553.5 million and will be $21.7 million, $20.3 million, $20.3 million, $20.4 million and $20.6 million for 2004 through 2008, respectively. The difference between the earnings impact under consolidation and under the currently-applied equity method is not expected to be material.

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This Statement contains disclosure requirements that provide descriptions of asset retirement obligations and reconciliations of changes in the components of those obligations. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Earlier applications are encouraged. We have a number of assets with associated retirement obligations that are subject to the provisions of this statement. With respect to the Natural Gas Pipeline Company of America system, 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 not 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 Retail Distribution, we generally are not obligated to remove our equipment or otherwise perform remediation related to our utility assets. We do have an obligation to perform removal and remediation activities associated with certain wells utilized in conjunction with our storage facilities and otherwise. With respect to Power, we generally are not obligated to perform removal or remediation activities associated with our owned power facilities and any such obligations associated with the power facilities we do not own are the responsibility of others. 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 will be settled.

In November 2002, the FASB issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation 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 FASB Interpretation No. 34, Disclosure of Indirect Guarantees of Indebtedness of Others, which is being superceded. The initial recognition and initial measurement provisions of this interpretation 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. The interpretive guidance incorporated from Interpretation No. 34 continues to be required for financial statements for fiscal years ending after June 15, 1981. For more information, see Note 18.

104

105

SELECTED QUARTERLY FINANCIAL DATA

KINDER MORGAN, INC. AND SUBSIDIARIES
Quarterly Operating Results for 2002

	2002- Three Months Ended
	March 31	June 30	September 30	December 31
	(In thousands except per share amounts)
	(Unaudited)
Operating Revenues	$ 291,401	$ 213,734	$ 225,111	$ 285,009
Gas Purchases and Other Costs of Sales	101,247	53,310	57,291	99,376
Gross Margin	190,154	160,424	167,820	185,633
Other Operating Expenses	81,799	83,553	83,154	218,858
Operating Income (Loss)	108,355	76,871	84,666	(33,225)¹
Other Income and (Expenses)	43,711	46,293	54,327	64,081
Income from Continuing Operations
Before Income Taxes	152,066	123,164	138,993	30,856
Income Taxes (Benefit)	63,678	50,712	58,170	(36,648)
Income from Continuing Operations	88,388	72,452	80,823	67,504
Loss on Disposal of Discontinued Operations	-	-	-	(4,986)
Extraordinary Item - Loss on Early
Extinguishment of Debt, Net of Income
Tax Benefits of $275 and $618	-	-	(420)	(1,036)
Net Income	$ 88,388	$ 72,452	$ 80,403	$ 61,482
	==========	==========	==========	==========

Basic Earnings (Loss) Per Common Share:
Income from Continuing Operations	$ 0.72	$ 0.59	$ 0.66	$ 0.56
Loss on Disposal of Discontinued Operations	-	-	-	(0.04)
Extraordinary Item - Loss on Early
Extinguishment of Debt	-	-	-	(0.01)
Total Basic Earnings Per Common Share	$ 0.72	$ 0.59	$ 0.66	$ 0.51
	==========	==========	==========	==========

Number of Shares Used in Computing
Basic Earnings Per Share	123,398	122,015	121,736	121,688
	==========	==========	==========	==========

Diluted Earnings (Loss) Per Common Share:
Income from Continuing Operations	$ 0.71	$ 0.59	$ 0.66	$ 0.55
Loss on Disposal of Discontinued Operations	-	-	-	(0.04)
Extraordinary Item - Loss on Early
Extinguishment of Debt	-	-	-	(0.01)
Total Diluted Earnings Per Common Share	$ 0.71	$ 0.59	$ 0.66	$ 0.50
	==========	==========	==========	==========

Number of Shares Used in Computing
Diluted Earnings Per Share	124,829	123,230	122,743	122,638
	==========	==========	==========	==========

^{1 Includes a charge of $134.5 million to revalue certain of our Power
assets; see Note 6.}

106

SELECTED QUARTERLY FINANCIAL DATA

KINDER MORGAN, INC. AND SUBSIDIARIES
Quarterly Operating Results for 2001

	2001- Three Months Ended
	March 31	June 30	September 30	December 31
	(In thousands except per share amounts)
	(Unaudited)
Operating Revenues	$ 325,224	$ 218,842	$ 227,025	$ 283,816
Gas Purchases and Other Costs of Sales	133,308	59,286	53,484	93,223
Gross Margin	191,916	159,556	173,541	190,593
Other Operating Expenses	79,494	78,731	82,145	90,917
Operating Income	112,422	80,825	91,396	99,676
Other Income and (Expenses)	(17,752)	4,259	11,718	24,692
Income Before Income Taxes and
Extraordinary Item	94,670	85,084	103,114	124,368
Income Taxes	37,868	35,184	43,443	52,106
Income Before Extraordinary Item	56,802	49,900	59,671	72,262
Extraordinary Item - Loss on Early
Extinguishment of Debt, Net of Income
Tax Benefits of $8,080 and $964	(12,119)	-	(1,446)	-
Net Income	$ 44,683	$ 49,900	$ 58,225	$ 72,262
	==========	==========	==========	==========

Basic Earnings Per Common Share:
Income Before Extraordinary Item	$ 0.50	$ 0.43	$ 0.52	$ 0.62
Extraordinary Item - Loss on Early
Extinguishment of Debt	(0.11)	-	(0.01)	-
Total Basic Earnings Per Common Share	$ 0.39	$ 0.43	$ 0.51	$ 0.62
	==========	==========	==========	==========

Number of Shares Used in Computing
Basic Earnings Per Share	114,844	115,258	114,980	115,892
	==========	==========	==========	==========

Diluted Earnings Per Common Share:
Income Before Extraordinary Item	$ 0.47	$ 0.41	$ 0.49	$ 0.60
Extraordinary Item - Loss on Early
Extinguishment of Debt	(0.10)	-	(0.01)	-
Total Diluted Earnings Per Common Share	$ 0.37	$ 0.41	$ 0.48	$ 0.60
	==========	==========	==========	==========

Number of Shares Used in Computing
Diluted Earnings Per Share	121,320	122,359	121,446	120,298
	==========	==========	==========	==========

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

None.

PART III

Item 10. Directors and Executive Officers of the Registrant.

Certain information required by this item is contained in our Proxy Statement related to the 2003 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.

107

For information regarding our current executive officers, see Executive Officers of the Registrant under Part I.

Item 11. Executive Compensation.

Information required by this item is contained in our Proxy Statement related to the 2003 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.

Item 12.

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

Item 13. Certain Relationships and Related Transactions.

Item 14. Controls and Procedures.

Within the 90-day period prior to the filing of this report, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14(c) under the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective. No significant changes were made in our internal controls or in other factors that could significantly affect these controls and procedures subsequent to the date of their evaluation.

PART IV

Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

(a)	(1)	Financial Statements
		Reference is made to the listings of financial statements and supplementary data under Item 8 in Part II.

(2)		Financial Statement Schedules

Schedule II - Valuation and Qualifying Accounts is omitted because the required information is shown in Note 1(G) of the accompanying Notes to Consolidated Financial Statements.

The financial statements, including the notes thereto, of Kinder Morgan Energy Partners, an equity method investee of the Registrant, are incorporated herein by reference from pages 89 through 159 of Kinder Morgan Energy Partners' Annual Report on Form 10-K for the year ended December 31, 2002.

108

(3)

Exhibits

Any reference made to K N Energy, Inc. in the exhibit listing that follows is a reference to the former name of Kinder Morgan, Inc., a Kansas corporation and the registrant, and is made because the exhibit being listed and incorporated by reference was originally filed before October 7, 1999, the date of the change in the Registrant's name.

Exhibit Number		Description

Exhibit 2.1		Agreement and Plan of Merger, dated as of July 8, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-1 of Registration Statement on Form S-4 (File No. 333-85747))
Exhibit 2.2		First Amendment to Agreement and Plan of Merger, dated as of August 20, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-2 of Registration Statement on Form S-4 (File No. 333-85747))
Exhibit 2.3		Contribution Agreement, dated as of December 30, 1999, by and among Kinder Morgan, Inc., Natural Gas Pipeline Company of America, K N Gas Gathering, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. (Exhibit 99.1 to Current Report on Form 8-K filed on January 14, 2000)
Exhibit 3.1		Restated Articles of Incorporation of Kinder Morgan, Inc. (Exhibit 3(a) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000)
Exhibit 3.2		Certificate of Amendment to the Restated Articles of Incorporation of Kinder Morgan, Inc. as filed on October 7, 1999, with the Secretary of State of Kansas (Exhibit 3.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999)
Exhibit 3.3		Certificate of Restatement of Articles of Incorporation of K N Energy, Inc. (Exhibit 4.19 to the Registration Statement on Form S-3 File No. 333-55921 of K N Energy, Inc., filed on June 3, 1998)
Exhibit 3.4		Bylaws of Kinder Morgan, Inc., as amended to October 7, 1999 (Exhibit 3.2 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999)
Exhibit 4.1		Indenture dated as of September 1, 1988, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4(a) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000)
Exhibit 4.2		First supplemental indenture dated as of January 15, 1992, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4.2, File No. 33-45091)

109

Exhibit Number		Description

Exhibit 4.3		Second supplemental indenture dated as of December 15, 1992, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4(c) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000)
Exhibit 4.4		Indenture dated as of November 20, 1993, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4.1, File No. 33-51115) Note - Copies of instruments relative to long-term debt in authorized amounts that do not exceed 10 percent of the consolidated total assets of Kinder Morgan, Inc. and its subsidiaries have not been furnished. Kinder Morgan, Inc. will furnish such instruments to the Commission upon request.
Exhibit 4.5*		$421,277,778 364-Day Credit Agreement among Kinder Morgan, Inc., certain banks listed therein and JPMorgan Chase Bank, dated October 15, 2002
Exhibit 4.6*		Modification Agreement to $421,277,778 364-Day Credit Agreement among Kinder Morgan, Inc., certain banks listed therein and JPMorgan Chase Bank, dated December 13, 2002
Exhibit 4.7*		Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. dated May 18, 2001
Exhibit 4.8		Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of August 21, 1995 (Exhibit 1 on Form 8-A dated August 21, 1995)
Exhibit 4.9		Amendment No. 1 to Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of September 8, 1998 (Exhibit 10(cc) to the Annual Report on Form 10-K for the year ended December 31, 1998)
Exhibit 4.10		Amendment No. 2 to Rights Agreement of Kinder Morgan, Inc. dated July 8, 1999, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as successor-in-interest to the Bank of New York, as Rights Agent (Exhibit 4.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999)
Exhibit 4.11		Form of Amendment No. 3 to Rights Agreement of Kinder Morgan, Inc. dated September 1, 2001, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as Rights Agent (Exhibit 4(m) to the Annual Report on Form 10-K for the year ended December 31, 2001)
Exhibit 4.12		Form of Indenture dated as of August 27, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan, Inc. Registration Statement on Form S-4, File No. 333-100338, filed on October 4, 2002)

110

Exhibit Number		Description

Exhibit 4.13		Form of First Supplemental Indenture dated as of December 6, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan, Inc. Registration Statement on Form S-4, File No. 333-102873, filed on January 31, 2003)
Exhibit 4.14		Form of 6.50% Note (contained in the Indenture incorporated by reference to Exhibit 4.12 hereto)
Exhibit 4.15		Form of Registration Rights Agreement dated as of December 6, 2002 among Kinder Morgan, Inc., Wachovia Securities, Inc., and Barclays Capital Inc. (filed as Exhibit 4.4 to Kinder Morgan, Inc. Registration Statement on Form S-4, File No. 333-102873, filed on January 31, 2003)
Exhibit 4.16		Form of certificate representing the common stock of Kinder Morgan, Inc. (filed as Exhibit 4.1 to Kinder Morgan, Inc. Registration Statement on Form S-3, File No. 333-102963, filed on February 4, 2003)
Exhibit 4.17		Form of Senior Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan, Inc. Registration Statement on Form S-3, File No.333-102963, filed on February 4, 2003)
Exhibit 4.18		Form of Senior Note of Kinder Morgan, Inc. (included in the Form of Senior Indenture incorporated by reference to Exhibit 4.17 hereto)
Exhibit 4.19		Form of Subordinated Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.4 to Kinder Morgan, Inc. Registration Statement on Form S-3, File No. 333-102963, filed on February 4, 2003)
Exhibit 4.20		Form of Subordinated Note of Kinder Morgan, Inc. (included in the Form of Subordinated Indenture incorporated by reference to Exhibit 4.19 hereto)
Exhibit 10.1		1994 Amended and Restated Kinder Morgan, Inc. Long-term Incentive Plan (Appendix A to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A)
Exhibit 10.2*		Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan
Exhibit 10.3		Kinder Morgan, Inc. Amended and Restated 1992 Stock Option Plan for Nonemployee Directors (Appendix C to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A)
Exhibit 10.4		2000 Annual Incentive Plan of Kinder Morgan, Inc. (Appendix D to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A)
Exhibit 10.5		Kinder Morgan, Inc. Employees Stock Purchase Plan (Appendix E to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A)

111

Exhibit Number		Description

Exhibit 10.6		Form of Nonqualified Stock Option Agreement (Exhibit 10(f) to the Annual Report on Form 10-K for the year ended December 31, 2000)
Exhibit 10.7		Form of Restricted Stock Agreement (Exhibit 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000)
Exhibit 10.8		Directors and Executives Deferred Compensation Plan effective January 1, 1998 for executive officers and directors of K N Energy, Inc. (Exhibit 10(aa) to the Annual Report on Form 10-K for the year ended December 31, 1998)
Exhibit 10.9		Employment Agreement dated October 7, 1999, between the Company and Richard D. Kinder (Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on October 8, 1999)
Exhibit 10.10		Employment Agreement dated April 20, 2000, by and among Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Michael C. Morgan (filed as Exhibit 10(b) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended March 31, 2000)
Exhibit 10.11		Retention Agreement dated January 17, 2002, by and between Kinder Morgan, Inc. and C. Park Shaper (Exhibit 10(l) to the Annual Report on Form 10-K for the year ended December 31, 2001)
Exhibit 10.12		Form of Purchase Provisions between Kinder Morgan Management, LLC and Kinder Morgan, Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement of Kinder Morgan Management, LLC filed as Exhibit 4.2 to Kinder Morgan Management, LLC's Registration Statement on Form 8-A/A filed on July 24, 2002)
Exhibit 21.1*		Subsidiaries of the Registrant
Exhibit 23.1*		Consent of Independent Accountants
Exhibit 99.1*		The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries included on pages 89 through 159 on the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2002
Exhibit 99.2*		Chief Executive Officer Certification
Exhibit 99.3*		Chief Financial Officer Certification



* Filed herewith.

112

(b)	Reports on Form 8-K

(1)

Current Report on Form 8-K dated October 28, 2002 was filed on October 28, 2002 pursuant to Item 9. of that form.

We announced our intention to make presentations during the week of October 28, 2002 at various meetings with investors, analysts and others to discuss our third quarter and year-to-date financial results, business plans and objectives and those of Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC, and the availability of materials to be presented at the meetings on our website.

(2)

Current Report on Form 8-K dated January 15, 2003 was filed on January 15, 2003 pursuant to Item 7. and Item 9. of that form.

Pursuant to Item 9. of that form, we disclosed that on January 15, 2003 we issued a press release.

Pursuant to Item 7. of that form, we filed our press release issued January 15, 2003 as an exhibit.

(3)

Current Report on Form 8-K dated January 21, 2003 was filed on January 21, 2003 pursuant to Item 9. of that form.

We announced our intention to make presentations on January 22, 2003 at the Kinder Morgan 2003 Analyst Conference to investors, analysts and others to address the fiscal year 2002 results, the fiscal year 2003 outlook and other business information about us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC, and the availability of materials to be presented at the meetings on our website and the ability of interested parties to access the presentations by audio webcast, both live and on-demand.

113

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	KINDER MORGAN, INC. (Registrant)
	By	/s/ C. PARK SHAPER
		C. Park Shaper Vice President, Treasurer and Chief Financial Officer
Date: February 26, 2003

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

/s/ EDWARD H. AUSTIN, JR.		Director
Edward H. Austin, Jr.

/s/ CHARLES W. BATTEY		Director
Charles W. Battey

/s/ STEWART A. BLISS		Director
Stewart A. Bliss

/s/ TED A. GARDNER		Director
Ted A. Gardner

/s/ WILLIAM J. HYBL		Director
William J. Hybl

/s/ RICHARD D. KINDER		Director, Chairman and Chief Executive Officer
Richard D. Kinder		(Principal Executive Officer)

/s/ MICHAEL C. MORGAN		President and Director
Michael C. Morgan

/s/ EDWARD RANDALL, III		Director
Edward Randall, III

/s/ FAYEZ SAROFIM		Director
Fayez Sarofim

/s/ C. PARK SHAPER		Vice President, Treasurer and Chief Financial Officer
C. Park Shaper		(Principal Financial and Accounting Officer)

/s/ H. A. TRUE, III		Director
H. A. True, III

114

CERTIFICATIONS

	I, Richard D. Kinder, certify that:
1.	I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
	a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
	b)	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
	c)	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
	a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.	The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

	/s/ Richard D. Kinder
	Richard D. Kinder
	Chairman and Chief Executive Officer
	Date: February 26, 2003

115

	I, C. Park Shaper, certify that:
1.	I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
	a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
	b)	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
	c)	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
	a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.	The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

	/s/ C. Park Shaper
	C. Park Shaper
	Vice President, Treasurer and Chief Financial Officer
	Date: February 26, 2003

116

EX-4.5 3 kmiex45.htm KMI 364-DAY CREDIT AGREEMENT Kinder Morgan, Inc. Exhibit 4.5 - 364-Day Credit Agreement
Exhibit 4.5

jpgif.gif (2163 bytes)

$421,277,778

364-DAY CREDIT AGREEMENT

dated as of

October 15, 2002

among

KINDER MORGAN, INC.

The Lenders Party Hereto

JPMORGAN CHASE BANK,
as Administrative Agent

WACHOVIA BANK, NATIONAL ASSOCIATION,
as Syndication Agent

and

CITIBANK, N.A. and
COMMERZBANK AG, NEW YORK AND GRAND CAYMAN BRANCHES
as Documentation Agents

___________________________

J.P. MORGAN SECURITIES INC. and WACHOVIA SECURITIES, INC.,
as Joint Bookrunners and Joint Lead Arrangers

TABLE OF CONTENTS

Page


ARTICLE I Definitions		1

SECTION 1.01	Defined Terms	1
SECTION 1.02	Classification of Loans and Borrowings	11
SECTION 1.03	Terms Generally	11
SECTION 1.04	Accounting Terms; GAAP	11

ARTICLE II The Credits		12

SECTION 2.01	Commitments	12
SECTION 2.02	Loans and Borrowings	12
SECTION 2.03	Requests for Revolving Borrowings	13
SECTION 2.04	Reserved	13
SECTION 2.05	Reserved	13
SECTION 2.06	Reserved	13
SECTION 2.07	Funding of Borrowings	13
SECTION 2.08	Interest Elections	14
SECTION 2.09	Termination and Reduction of Commitments	15
SECTION 2.10	Repayment of Loans; Evidence of Debt	15
SECTION 2.11	Prepayment of Loans	16
SECTION 2.12	Fees	16
SECTION 2.13	Interest	17
SECTION 2.14	Alternate Rate of Interest	18
SECTION 2.15	Increased Costs	18
SECTION 2.16	Break Funding Payments	19
SECTION 2.17	Taxes	19
SECTION 2.18	Payments Generally; Pro Rata Treatment; Sharing of Set-offs	20
SECTION 2.19	Mitigation Obligations; Replacement of Lenders	22
SECTION 2.20	Extensions of Termination Date; Removal of Lenders	22
SECTION 2.21	Conversion to Term Loans	24

ARTICLE III Representations and Warranties		24

SECTION 3.01	Organization; Powers	24
SECTION 3.02	Authorization; Enforceability	25
SECTION 3.03	Governmental Approvals; No Conflicts	25
SECTION 3.04	Financial Condition; No Material Adverse Change	25
SECTION 3.05	Properties	25
SECTION 3.06	Litigation and Environmental Matters	25
SECTION 3.07	Compliance with Laws and Agreements	26
SECTION 3.08	Investment and Holding Company Status	26
SECTION 3.09	Taxes	26

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SECTION 3.10	ERISA	26
SECTION 3.11	Disclosure	26

ARTICLE IV Conditions		27

SECTION 4.01	Effective Date	27
SECTION 4.02	Each Credit Event	28
SECTION 4.03	Conditions Precedent to Conversions	28

ARTICLE V Affirmative Covenants		28

SECTION 5.01	Financial Statements; Ratings Change and Other Information	28
SECTION 5.02	Notices of Material Events	30
SECTION 5.03	Existence; Conduct of Business	31
SECTION 5.04	Payment of Obligations	31
SECTION 5.05	Maintenance of Properties; Insurance	31
SECTION 5.06	Books and Records; Inspection Rights	31
SECTION 5.07	Compliance with Laws	31
SECTION 5.08	Use of Proceeds	31

ARTICLE VI Negative Covenants		32

SECTION 6.01	Financial Covenants	32
SECTION 6.02	Liens	32
SECTION 6.03	Fundamental Changes	33
SECTION 6.04	Transactions with Affiliates	33

ARTICLE VII Events of Default		34

ARTICLE VIII The Administrative Agent		36

ARTICLE IX Miscellaneous		37

SECTION 9.01	Notices	37
SECTION 9.02	Waivers; Amendments	38
SECTION 9.03	Expenses; Indemnity; Damage Waiver	38
SECTION 9.04	Successors and Assigns	39
SECTION 9.05	Survival	42
SECTION 9.06	Counterparts; Integration; Effectiveness	42
SECTION 9.07	Severability	42
SECTION 9.08	Right of Setoff	43
SECTION 9.09	Governing Law; Jurisdiction; Consent to Service of Process	43
SECTION 9.10	WAIVER OF JURY TRIAL	43
SECTION 9.11	Headings	44
SECTION 9.12	Confidentiality	44
SECTION 9.13	Interest Rate Limitation	44
SECTION 9.14	Existing Credit Facility	44

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SCHEDULES:

Schedule 1.01 -- Pricing Schedule
Schedule 2.01 -- Commitments

EXHIBITS:

Exhibit A -- Form of Assignment and Assumption
Exhibit B-1 -- Form of Opinion of Borrower's Kansas Counsel
Exhibit B-2 – Form of Opinion of Borrower's New York Counsel

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CREDIT AGREEMENT dated as of October 15, 2002, among KINDER MORGAN, INC., a Kansas corporation, the LENDERS party hereto, JPMORGAN CHASE BANK, as Administrative Agent, WACHOVIA BANK, NATIONAL ASSOCIATION, as Syndication Agent, and CITIBANK, N.A. and COMMERZBANK AG, NEW YORK AND GRAND CAYMAN BRANCHES, as Documentation Agents.

The parties hereto agree as follows:

ARTICLE I

Definitions

SECTION 1.01 Defined Terms. As used in this Agreement, the following terms have the meanings specified below:

"ABR", when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

"Adjusted LIBO Rate" means, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/100 of 1%) equal to (a) the LIBO Rate for such Interest Period multiplied by (b) the Statutory Reserve Rate.

"Administrative Agent" means JPMorgan Chase Bank, in its capacity as administrative agent for the Lenders hereunder.

"Administrative Questionnaire" means an Administrative Questionnaire in a form supplied by the Administrative Agent.

"Affiliate" means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

"Alternate Base Rate" means, for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day and (b) the Federal Funds Effective Rate in effect on such day plus1/2 of 1%. Any change in the Alternate Base Rate due to a change in the Prime Rate or the Federal Funds Effective Rate shall be effective from and including the effective date of such change in the Prime Rate or the Federal Funds Effective Rate, respectively.

"Applicable Percentage" means, with respect to any Lender, the percentage of the total Commitments represented by such Lender's Commitment. If the Commitments have terminated or expired, the Applicable Percentages shall be determined based upon the Commitments most recently in effect, giving effect to any assignments.

"Applicable Rate" means, for any day, with respect to any ABR Loan or Eurodollar Loan, or with respect to the facility fees or the utilization fees payable hereunder, as the case may be, the applicable rate per annum (expressed in bps) set forth in the Pricing Schedule under the caption "ABR Spread", "Eurodollar Spread", "Facility Fee Rate" or "Utilization Fee Rate", as the case may be.

"Approved Fund" has the meaning assigned to such term in Section 9.04.

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"Assignment and Assumption" means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by Section 9.04), and accepted by the Administrative Agent, in the form of Exhibit A or any other form approved by the Administrative Agent.

"Availability Period" means the period from and including the Effective Date to but excluding the earlier of the Revolving Credit Termination Date and the date of termination of the Commitments.

"Benefit Arrangement" means at any time an employee benefit plan within the meaning of Section 3(3) of ERISA which is not a Plan or a Multiemployer Plan and which is maintained or otherwise contributed to by any member of the ERISA Group.

"Board" means the Board of Governors of the Federal Reserve System of the United States of America.

"Borrower" means Kinder Morgan, Inc., a Kansas corporation.

"Borrowing" means Loans of the same Type, made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

"Borrowing Request" means a request by the Borrower for a Revolving Borrowing in accordance with Section 2.03.

"Business Day" means any day that is not a Saturday, Sunday or other day on which commercial banks in New York City are authorized or required by law to remain closed; provided that, when used in connection with a Eurodollar Loan, the term "Business Day" shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

"Capital Lease Obligations" of any Person means the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on a balance sheet of such Person under GAAP, and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP.

"Change in Control" means (a) the acquisition of ownership, directly or indirectly, beneficially or of record, by any Person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the Securities and Exchange Commission thereunder as in effect on the date hereof), of Equity Interests representing more than 30% of the aggregate ordinary voting power represented by the issued and outstanding Equity Interests of the Borrower; or (b) during any period of twelve consecutive calendar months, individuals who were directors of the Borrower on the first day of such period shall cease to constitute a majority of the board of directors of the Borrower.

"Change in Law" means (a) the adoption of any law, rule or regulation after the date of this Agreement, (b) any change in any law, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the date of this Agreement or (c) compliance by any Lender (or, for purposes of Section 2.15(b), by any lending office of such Lender or by such Lender's holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement.

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"Class", when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are Revolving Loans or Term Loans.

"Code" means the Internal Revenue Code of 1986, as amended from time to time.

"Commitment" means, with respect to each Lender, the commitment of such Lender to make Revolving Loans and to convert the Revolving Loans outstanding on the Revolving Credit Termination Date to Term Loans, expressed as an amount representing the maximum aggregate amount of such Lender's Credit Exposure hereunder, as such commitment may be (a) reduced from time to time pursuant to Section 2.09 and (b) increased pursuant to Section 2.01 or reduced or increased from time to time pursuant to assignments by or to such Lender pursuant to Section 9.04. The initial amount of each Lender's Commitment is set forth on Schedule 2.01 or in the Assignment and Assumption pursuant to which such Lender shall have assumed its Commitment, as applicable, as such obligation may be reduced or increased pursuant to this Agreement. The initial aggregate amount of the Lenders' Commitments is US $421,277,778.

"Consenting Lender" has the meaning assigned to such term in Section 2.20.

"Consolidated Assets" means the total amount of assets appearing on the consolidated balance sheet of the Borrower and its Consolidated Subsidiaries, prepared in accordance with GAAP as of the date of the most recent regularly prepared consolidated financial statements prior to the taking of any action for the purposes of which the determination is being made.

"Consolidated Indebtedness" of any Person means at any date the sum (without duplication) of (i) the Indebtedness of such Person and its Consolidated Subsidiaries, determined on a consolidated basis as of such date plus (ii) the excess (if any) of the Trust Preferred Securities of such Person over 10% of the Consolidated Total Capitalization of such Person at such date.

"Consolidated Net Income" means, for any period, the net income of the Borrower and its Consolidated Subsidiaries before extraordinary items, determined on a consolidated basis for such period.

"Consolidated Net Worth" of any Person means at any date the sum (without duplication) of (i) the consolidated stockholders' equity of such Person and its Consolidated Subsidiaries, determined as of such date plus (ii) the Trust Preferred Securities of such Person; provided that the amount of Trust Preferred Securities added pursuant to this clause (ii) shall not exceed 10% of Consolidated Total Capitalization of such Person at such date.

"Consolidated Subsidiary" of any Person means at any date any Subsidiary or other entity the accounts of which would be consolidated with those of such Person in its consolidated financial statements if such statements were prepared as of such date.

"Consolidated Total Capitalization" of any Person means at any date the sum of Consolidated Indebtedness of such Person and Consolidated Net Worth of such Person, each determined as of such date.

"Control" means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. "Controlling" and "Controlled" have meanings correlative thereto.

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"Credit Exposure" means, with respect to any Lender at any time, the sum of the outstanding principal amount of such Lender's Loans at such time.

"Default" means any event or condition which constitutes an Event of Default or which upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

"dollars" or "$" refers to lawful money of the United States of America.

"Effective Date" means the date on which the conditions specified in Section 4.01 are satisfied (or waived in accordance with Section 9.02).

"Environmental Laws" means all laws, rules, regulations, codes, ordinances, orders, decrees, judgments, injunctions, notices or binding agreements issued, promulgated or entered into by any Governmental Authority, relating in any way to the environment, preservation or reclamation of natural resources, the management, release or threatened release of any Hazardous Material or to health and safety matters.

"Environmental Liability" means any liability, contingent or otherwise (including any liability for damages, costs of environmental remediation, fines, penalties or indemnities), of the Borrower or any Subsidiary directly or indirectly resulting from or based upon (a) violation of any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the release or threatened release of any Hazardous Materials into the environment or (e) any contract, agreement or other consensual arrangement pursuant to which liability is assumed or imposed with respect to any of the foregoing.

"Equity Interests" means shares of capital stock, partnership interests, membership interests in a limited liability company, beneficial interests in a trust or other equity ownership interests in a Person, and any warrants, options or other rights entitling the holder thereof to purchase or acquire any such equity interest.

"ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time.

"ERISA Group" means the Borrower, any Subsidiary and all members of a controlled group of corporations and all trades or businesses (whether or not incorporated) under common control which, together with the Borrower or any Subsidiary, are treated as a single employer under Section 414 of the Code.

"Eurodollar", when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted LIBO Rate.

"Event of Default" has the meaning assigned to such term in Article VII.

"Excluded Taxes" means, with respect to the Administrative Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of the Borrower hereunder, (a) income or franchise taxes imposed on (or measured by) its net income by the United States of America, or by the jurisdiction under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes imposed by the United States of America or any similar tax imposed by any

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other jurisdiction in which the Borrower is located and (c) in the case of a Foreign Lender (other than an assignee pursuant to a request by the Borrower under Section 2.19(b)), any withholding tax that is imposed on amounts payable to such Foreign Lender at the time such Foreign Lender becomes a party to this Agreement (or designates a new lending office) or is attributable to such Foreign Lender's failure to comply with Section 2.17(e), except to the extent that such Foreign Lender's assignor (if any) was entitled, at the time of assignment, to receive additional amounts from the Borrower with respect to such withholding tax pursuant to Section 2.17(a).

"Existing Credit Facility" means the credit facility governed by that certain 364-Day Credit Agreement, dated October 25, 2000, by and among the Borrower, the lenders party thereto and Bank of America, N.A., as administrative agent, as amended by First Amendment to 364-Day Credit Agreement, dated as of October 23, 2001, among the Borrower, the lenders party thereto, and The Chase Manhattan Bank, as administrative agent.

"Existing Revolving Credit Termination Date" has the meaning set forth in Section 2.20.

"Extended Revolving Credit Termination Date" means, as at any date, the date to which the Revolving Credit Termination Date has then most recently been extended pursuant to Section 2.20.

"Federal Funds Effective Rate" means, for any day, the weighted average (rounded upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

"Final Maturity Date" means (i) if the Revolving Loans are converted to Term Loans pursuant to Section 2.21, then with respect to any Term Loan, the date that is one year from the Revolving Credit Termination Date as of the time of such conversion, or (ii) if the Revolving Loans are not so converted, the Revolving Credit Termination Date.

"Financial Officer" means the chief financial officer, principal accounting officer, treasurer or controller of the Borrower.

"Foreign Lender" means any Lender that is organized under the laws of a jurisdiction other than that in which the Borrower is located. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

"GAAP" means generally accepted accounting principles in the United States of America.

"Governmental Authority" means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government.

"Guarantee" of or by any Person (the "guarantor") means any obligation, contingent or otherwise, of the guarantor guaranteeing or having the economic effect of guaranteeing any Indebtedness

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or other obligation of any other Person (the "primary obligor") in any manner, whether directly or indirectly, and including any obligation of the guarantor, direct or indirect, (a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or to advance or supply funds for the purchase of) any security for the payment thereof, (b) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness or other obligation of the payment thereof, (c) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation or (d) as an account party in respect of any letter of credit or letter of guaranty issued to support such Indebtedness or obligation; provided, that the term Guarantee shall not include endorsements for collection or deposit in the ordinary course of business.

"Hazardous Materials" means all explosive or radioactive substances or wastes and all hazardous or toxic substances, wastes or other pollutants, including petroleum or petroleum distillates, asbestos or asbestos containing materials, polychlorinated biphenyls, radon gas, infectious or medical wastes and all other substances or wastes of any nature regulated pursuant to any Environmental Law.

"Hedging Agreement" means any interest rate protection agreement, foreign currency exchange agreement, commodity price protection agreement or other interest or currency exchange rate or commodity price hedging arrangement.

"Indebtedness" of any Person means, without duplication, (a) all obligations of such Person for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such Person evidenced by bonds, debentures, notes or similar instruments, (c) all obligations of such Person under conditional sale or other title retention agreements relating to property acquired by such Person, (d) all obligations of such Person in respect of the deferred purchase price of property or services or any other similar obligation upon which interest changes are customarily paid (excluding trade accounts payable incurred in the ordinary course of business), (e) all Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien on property owned or acquired by such Person, whether or not the Indebtedness secured thereby has been assumed, (f) all Guarantees by such Person of Indebtedness of others (provided that in the event that any Indebtedness of the Borrower or any Subsidiary shall be the subject of a Guarantee by one or more Subsidiaries or by the Borrower, as the case may be, the aggregate amount of the outstanding Indebtedness of the Borrower and the Subsidiaries in respect thereof shall be determined by reference to the primary Indebtedness so guaranteed, and without duplication by reason of the existence of any such Guarantee), (g) all Capital Lease Obligations of such Person, (h) all obligations, contingent or otherwise, of such Person as an account party in respect of letters of credit and letters of guaranty, and (i) all obligations, contingent or otherwise, of such Person in respect of bankers' acceptances. The Indebtedness of any Person shall include the Indebtedness of any other Person (including any partnership in which such Person is a general partner) to the extent such Person is liable therefor as a result of such Person's ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness provide that such Person is not liable therefor.

"Indemnified Taxes" means Taxes other than Excluded Taxes.

"Index Debt" means senior, unsecured, long-term indebtedness for borrowed money of the Borrower that is not guaranteed by any other Person or subject to any other credit enhancement.

"Information Memorandum" means the Confidential Information Memorandum dated September 2002 relating to the Borrower and the Transactions.

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"Interest Election Request" means a request by the Borrower to convert or continue a Borrowing in accordance with Section 2.08.

"Interest Payment Date" means, (a) with respect to any ABR Loan, the last day of each March, June, September and December and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months' duration, each day prior to the last day of such Interest Period that occurs at intervals of three months' duration after the first day of such Interest Period.

"Interest Period" means, with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is one, two, three or six months thereafter, as the Borrower may elect; provided, that (i) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day and (ii) any Interest Period that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period. For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and, in the case of a Revolving Borrowing, thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

"Lenders" means the Persons listed on Schedule 2.01 and any other Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.

"LIBO Rate" means, with respect to any Eurodollar Borrowing for any Interest Period, the rate appearing on Page 3750 of the Dow Jones Market Service (or on any successor or substitute page of such Service, or any successor to or substitute for such Service, providing rate quotations comparable to those currently provided on such page of such Service, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason, then the "LIBO Rate" with respect to such Eurodollar Borrowing for such Interest Period shall be the rate at which dollar deposits of $5,000,000 and for a maturity comparable to such Interest Period are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period.

"Lien" means, with respect to any asset, (a) any mortgage, deed of trust, lien, pledge, hypothecation, encumbrance, charge or security interest in, on or of such asset and (b) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset.

"Loans" means the Revolving Loans or the Term Loans made by the Lenders to the Borrower pursuant to this Agreement.

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"Material Adverse Effect" means a material adverse effect on (a) the business, assets, liabilities (actual or contingent), operations, or financial condition of the Borrower and the Subsidiaries taken as a whole, (b) the ability of the Borrower to perform any of its obligations under this Agreement or (c) the rights of or benefits available to the Lenders under any material provision of this Agreement.

"Material Indebtedness" means Indebtedness (other than the Loans), or obligations in respect of one or more Hedging Agreements, of any one or more of the Borrower and its Subsidiaries in an aggregate principal amount exceeding $100,000,000. For purposes of determining Material Indebtedness, the "principal amount" of the obligations of the Borrower or any Subsidiary in respect of any Hedging Agreement at any time shall be the maximum aggregate amount (giving effect to any netting agreements) that the Borrower or such Subsidiary would be required to pay if such Hedging Agreement were terminated at such time.

"Material Subsidiary" means any Consolidated Subsidiary the consolidated assets of which constitute 10% or more of Consolidated Assets.

"Moody's" means Moody's Investors Service, Inc.

"Multiemployer Plan" means a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

"Nominee" has the meaning set forth in Section 2.20.

"Non-Consenting Lender" has the meaning set forth in Section 2.20.

"Notice of Extension" has the meaning set forth in Section 2.20.

"Other Taxes" means any and all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement.

"Participant" has the meaning set forth in Section 9.04.

"PBGC" means the Pension Benefit Guaranty Corporation referred to and defined in ERISA and any successor entity performing similar functions.

"Permitted Encumbrances" means:

(a) Liens imposed by law for taxes that are not yet due or are being contested in compliance with Section 5.04;

(b) carriers', warehousemen's, mechanics', materialmen's, repairmen's and other like Liens imposed by law, arising in the ordinary course of business and securing obligations that are not overdue by more than 30 days or are being contested in compliance with Section 5.04;

(c) pledges and deposits made in the ordinary course of business in compliance with workers' compensation, unemployment insurance and other social security laws or regulations;

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(d) deposits to secure the performance of bids, trade contracts, leases, statutory obligations, surety and appeal bonds, performance bonds and other obligations of a like nature, in each case in the ordinary course of business;

(e) judgment liens in respect of judgments that do not constitute an Event of Default under clause (k) of Article VII;

(f) easements, zoning restrictions, rights-of-way and similar encumbrances on real property imposed by law or arising in the ordinary course of business that do not secure any monetary obligations and do not materially detract from the value of the affected property or interfere with the ordinary conduct of business of the Borrower or any Subsidiary;

(g) any interest or title of a lessor in property subject to any Capital Lease Obligation or operating lease which, in each case, is permitted under this Agreement; and

(h) Liens in favor of collecting or payor banks resulting from a right of setoff, revocation, refund or chargeback with respect to money or instruments of the Borrower or any Subsidiary on deposit with or in possession of such bank;

provided that the term "Permitted Encumbrances" shall not include any Lien securing Indebtedness, except as provided in clause (g) above.

"Person" means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

"Plan" means any employee pension benefit plan (other than a Multiemployer Plan) subject to the provisions of Title IV of ERISA or Section 412 of the Code or Section 302 of ERISA, and in respect of which the Borrower or any member of the ERISA Group is (or, if such plan were terminated, would under Section 4069 of ERISA be deemed to be) an "employer" as defined in Section 3(5) of ERISA.

"Pricing Schedule" means the schedule attached hereto as Schedule 1.01 and identified as such.

"Prime Rate" means the rate of interest per annum publicly announced from time to time by JPMorgan Chase Bank as its prime rate in effect at its principal office in New York City; each change in the Prime Rate shall be effective from and including the date such change is publicly announced as being effective.

"Register" has the meaning set forth in Section 9.04.

"Related Parties" means, with respect to any specified Person, such Person's Affiliates and the respective directors, officers, employees, agents and advisors of such Person and such Person's Affiliates.

"Required Lenders" means, at any time, Lenders having Credit Exposures and unused Commitments representing greater than 50% of the sum of the total Credit Exposures and unused Commitments hereunder.

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"Responsible Officer" means the Chairman, Vice Chairman, President, any Vice President, Chief Executive Officer, Chief Financial Officer, Controller or Treasurer of the Borrower.

"Revolving Credit Exposure" means, with respect to any Lender, at any time prior to any conversion of Revolving Loans to Term Loans pursuant to Section 2.21, the Credit Exposure of such Lender.

"Revolving Credit Termination Date" means the earlier of (x) the later of (i) October 14, 2003 and (ii) an Extended Revolving Credit Termination Date and (y) the date which is the effective date of any other termination, cancellation or acceleration of all Commitments hereunder.

"Revolving Loan" means a Loan made pursuant to Section 2.01(a).

"S&P" means Standard & Poor's Ratings Group, a division of The McGraw-Hill Companies, Inc.

"Statutory Reserve Rate" means a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board to which the Administrative Agent is subject for eurocurrency funding (currently referred to as "Eurocurrency Liabilities" in Regulation D of the Board). Such reserve percentages shall include those imposed pursuant to such Regulation D. Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation. The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

"subsidiary" means, with respect to any Person (the "parent") at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent's consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or, in the case of a partnership, more than 50% of the general partnership interests are, as of such date, owned, controlled or held, or (b) that is, as of such date, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.

"Subsidiary" means any subsidiary of the Borrower.

"Taxes" means any and all present or future taxes, levies, imposts, duties, deductions, charges or withholdings imposed by any Governmental Authority.

"Term Loan" means a Revolving Loan that is converted to a Term Loan pursuant to Section 2.21.

"Term Out Period" means the period commencing on the Revolving Credit Termination Date and ending on the first anniversary thereof.

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"Three-Year Facility" means the credit facility governed by that certain $337,022,222 Three-Year Credit Agreement, dated as of even date herewith, by and among the Borrower, the lenders party thereto and JPMorgan Chase Bank, as administrative agent.

"Transactions" means the execution, delivery and performance by the Borrower of this Agreement, the borrowing of Loans and the use of the proceeds thereof.

"Trust Preferred Securities" means, with respect to the Borrower, mandatorily redeemable capital trust securities of trusts which are Subsidiaries and the subordinated debentures of the Borrower in which the proceeds of the issuance of such capital trust securities are invested, including, without limitation, $275,000,000 of such securities outstanding at the Effective Date.

"Type", when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Adjusted LIBO Rate or the Alternate Base Rate.

SECTION 1.02 Classification of Loans and Borrowings. For purposes of this Agreement, Loans may be classified and referred to by Class (e.g., a "Revolving Loan") or by Type (e.g., a "Eurodollar Loan") or by Class and Type (e.g., a "Eurodollar Revolving Loan"). Borrowings also may be classified and referred to by Class (e.g., a "Revolving Borrowing") or by Type (e.g., a "Eurodollar Borrowing") or by Class and Type (e.g., a "Eurodollar Revolving Borrowing").

SECTION 1.03 Terms Generally. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words "include", "includes" and "including" shall be deemed to be followed by the phrase "without limitation". The word "will" shall be construed to have the same meaning and effect as the word "shall". Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person's successors and assigns, (c) the words "herein", "hereof" and "hereunder", and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (d) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement and (e) the words "asset" and "property" shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

SECTION 1.04 Accounting Terms; GAAP. Except as otherwise expressly provided herein, all terms of an accounting or financial nature shall be construed in accordance with GAAP, as in effect from time to time; provided that, if the Borrower notifies the Administrative Agent that the Borrower requests an amendment to any provision hereof to eliminate the effect of any change occurring after the date hereof in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent notifies the Borrower that the Required Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith.

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ARTICLE II

The Credits

SECTION 2.01 Commitments. (a) Subject to the terms and conditions set forth herein, each Lender agrees (i) to make Revolving Loans to the Borrower from time to time during the Availability Period in an aggregate principal amount that will not result in (x) such Lender's Credit Exposure exceeding such Lender's Commitment or (y) the sum of the total Credit Exposures exceeding the total Commitments and (ii) at the election of the Borrower, to convert the principal amount of any Revolving Loans remaining outstanding on the Revolving Credit Termination Date to Term Loans pursuant to Section 2.21. Within the foregoing limits and subject to the terms and conditions set forth herein, the Borrower may borrow, prepay and reborrow Revolving Loans.

(b) The Borrower shall have the right, without the consent of the Lenders but with the prior approval of the Administrative Agent, not to be unreasonably withheld, to cause from time to time an increase in the total Commitments of the Lenders by adding to this Agreement one or more additional Lenders or by allowing one or more Lenders to increase their respective Commitments; provided, however, (i) no Default or Event of Default shall have occurred hereunder which is continuing, (ii) no such increase shall cause (A) the aggregate Commitments hereunder to exceed $500,000,000, or (B) the sum of the aggregate Commitments hereunder plus the aggregate commitments under the Three-Year Facility to exceed $900,000,000, and (iii) no Lender's Commitment shall be increased without such Lender's consent.

SECTION 2.02 Loans and Borrowings. (a) Each Revolving Loan shall be made as part of a Borrowing consisting of Revolving Loans made by the Lenders ratably in accordance with their respective Commitments. The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments of the Lenders are several and no Lender shall be responsible for any other Lender's failure to make Loans as required.

(b) Subject to Section 2.14, each Revolving Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Borrower may request in accordance herewith. Each Lender at its option may make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of the Borrower to repay such Loan in accordance with the terms of this Agreement.

(c) At the commencement of each Interest Period for any Eurodollar Revolving Borrowing, such Borrowing shall be in an aggregate amount that is an integral multiple of $1,000,000 and not less than $5,000,000. At the time that each ABR Revolving Borrowing is made, such Borrowing shall be in an aggregate amount that is an integral multiple of $1,000,000 and not less than $5,000,000; provided that an ABR Borrowing may be in an aggregate amount that is equal to the entire unused balance of the total Commitments. Borrowings of more than one Type may be outstanding at the same time; provided that there shall not at any time be more than a total of ten Eurodollar Borrowings outstanding.

(d) Notwithstanding any other provision of this Agreement (i) the Borrower shall not be entitled to request, or to elect to convert (except for a conversion to a Term Loan pursuant to Section 2.21) or continue, any Revolving Loan if the Interest Period requested with respect thereto would end after the Revolving Credit Termination Date and (ii) the Borrower shall not be entitled to request, to elect to convert or continue, any Term Loan if the Interest Period requested with respect thereto would end after the Final Maturity Date.

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SECTION 2.03 Requests for Revolving Borrowings. To request a Revolving Borrowing, the Borrower shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than 11:00 a.m., New York City time, three Business Days before the date of the proposed Borrowing or (b) in the case of an ABR Borrowing, not later than 11:00 a.m., New York City time, on the date of the proposed Borrowing. Each such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Borrowing Request in a form approved by the Administrative Agent and signed by the Borrower. Each such telephonic and written Borrowing Request shall specify the following information in compliance with Section 2.02:

(i) the aggregate amount of the requested Borrowing;

(ii) the date of such Borrowing, which shall be a Business Day;

(iii) whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing;

(iv) in the case of a Eurodollar Borrowing, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term "Interest Period"; and

(v) the location and number of the Borrower's account to which funds are to be disbursed, which shall comply with the requirements of Section 2.07.

If no election as to the Type of Revolving Borrowing is specified, then the requested Borrowing shall be an ABR Borrowing. If no Interest Period is specified with respect to any requested Eurodollar Revolving Borrowing, then the Borrower shall be deemed to have selected an Interest Period of one month's duration. Promptly following receipt of a Borrowing Request in accordance with this Section, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender's Loan to be made as part of the requested Borrowing.

SECTION 2.04 Reserved.

SECTION 2.05 Reserved.

SECTION 2.06 Reserved.

SECTION 2.07 Funding of Borrowings. (a) Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof by wire transfer of immediately available funds by 2:00 p.m., New York City time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders. The Administrative Agent will make such Loans available to the Borrower by promptly crediting the amounts so received, in like funds, to an account of the Borrower maintained with the Administrative Agent in New York City and designated by the Borrower in the applicable Borrowing Request.

(b) Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender's share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with paragraph (a) of this Section and may, in reliance upon such assumption, make available to the Borrower a corresponding amount. In such event,

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if a Lender has not in fact made its share of the applicable Borrowing available to the Administrative Agent, then the applicable Lender and the Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation or (ii) in the case of the Borrower, the interest rate applicable to ABR Loans. If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender's Loan included in such Borrowing.

SECTION 2.08 Interest Elections. (a) Each Borrowing initially shall be of the Type specified in the applicable Borrowing Request and, in the case of a Eurodollar Borrowing, shall have an initial Interest Period as specified in such Borrowing Request. Thereafter, the Borrower may elect to convert such Borrowing to a different Type or to continue such Borrowing and, in the case of a Eurodollar Borrowing, may elect Interest Periods therefor, all as provided in this Section. The Borrower may elect different options with respect to different portions of the affected Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a separate Borrowing.

(b) To make an election pursuant to this Section, the Borrower shall notify the Administrative Agent of such election by telephone by the time that a Borrowing Request would be required under Section 2.03 if the Borrower were requesting a Revolving Borrowing of the Type resulting from such election to be made on the effective date of such election. Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Interest Election Request in a form approved by the Administrative Agent and signed by the Borrower.

(c) Each telephonic and written Interest Election Request shall specify the following information in compliance with Section 2.02:

          (i)          the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to clauses (iii) and (iv) below shall be specified for each resulting Borrowing);

          (ii)         the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day;

          (iii)        whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing; and

          (iv)         if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term "Interest Period".

If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an Interest Period, then the Borrower shall be deemed to have selected an Interest Period of one month's duration.

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(d) Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender's portion of each resulting Borrowing.

(e) If the Borrower fails to deliver a timely Interest Election Request with respect to a Eurodollar Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be converted to an ABR Borrowing. Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing and the Administrative Agent, at the request of the Required Lenders, so notifies the Borrower, then, so long as an Event of Default is continuing (i) no outstanding Borrowing may be converted to or continued as a Eurodollar Borrowing and (ii) unless repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.

SECTION 2.09 Termination and Reduction of Commitments. (a) Unless previously terminated, the Commitments shall terminate on the Revolving Credit Termination Date.

(b) The Borrower may at any time terminate, or from time to time reduce, the Commitments; provided that (i) each reduction of the Commitments shall be in an amount that is an integral multiple of $1,000,000 and not less than $10,000,000 and (ii) the Borrower shall not terminate or reduce the Commitments if, after giving effect to any concurrent prepayment of the Loans in accordance with Section 2.11, the sum of the Revolving Credit Exposures would exceed the total Commitments.

(c) The Borrower shall notify the Administrative Agent of any election to terminate or reduce the Commitments under paragraph (b) of this Section at least three Business Days prior to the effective date of such termination or reduction, specifying such election and the effective date thereof. Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof. Each notice delivered by the Borrower pursuant to this Section shall be irrevocable; provided that a notice of termination of the Commitments delivered by the Borrower may state that such notice is conditioned upon the effectiveness of other credit facilities, in which case such notice may be revoked by the Borrower (by notice to the Administrative Agent on or prior to the specified effective date) if such condition is not satisfied. Any termination or reduction of the Commitments shall be permanent. Each reduction of the Commitments shall be made ratably among the Lenders in accordance with their respective Commitments.

SECTION 2.10 Repayment of Loans; Evidence of Debt. (a) The Borrower hereby unconditionally promises to pay (i) to the Administrative Agent for the account of each Lender the then unpaid principal amount of each Revolving Loan on the Revolving Credit Termination Date (unless converted to Term Loans pursuant to Section 2.21) and (ii) to the Administrative Agent for the account of the Lender the then unpaid principal amount of each Term Loan on the Final Maturity Date.

(b) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

(c) The Administrative Agent shall maintain accounts in which it shall record (i) the amount of each Loan made hereunder, the Type thereof and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder for the account of the Lenders and each Lender's share thereof.

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(d) The entries made in the accounts maintained pursuant to paragraph (b) or (c) of this Section shall be prima facie evidence of the existence and amounts of the obligations recorded therein; provided that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay the Loans in accordance with the terms of this Agreement.

(e) Any Lender may request that Loans made by it be evidenced by a promissory note. In such event, the Borrower shall prepare, execute and deliver to such Lender a promissory note payable to the order of such Lender (or, if requested by such Lender, to such Lender and its registered assigns) and in a form approved by the Administrative Agent. Thereafter, the Loans evidenced by such promissory note and interest thereon shall at all times (including after assignment pursuant to Section 9.04) be represented by one or more promissory notes in such form payable to the order of the payee named therein (or, if such promissory note is a registered note, to such payee and its registered assigns).

SECTION 2.11 Prepayment of Loans. (a) The Borrower shall have the right at any time and from time to time to prepay any Borrowing in whole or in part, subject to prior notice in accordance with paragraph (c) of this Section.

(b) If at any time the aggregate outstanding principal amount of the Revolving Credit Exposures exceeds the sum of the total Commitments, the Borrower shall prepay the Revolving Loans in an amount equal to such excess. Each prepayment of Loans pursuant to this Section 2.11 shall be accompanied by payment of accrued interest on the amount prepaid to the date of prepayment and, in the case of prepayments of Eurodollar Loans, any amounts payable pursuant to Section 2.16.

(c) The Borrower shall notify the Administrative Agent by telephone (confirmed by telecopy) of any prepayment hereunder (i) in the case of prepayment of a Eurodollar Borrowing, not later than 11:00 a.m., New York City time, three Business Days before the date of prepayment, or (ii) in the case of prepayment of an ABR Borrowing, not later than 11:00 a.m., New York City time, on the date of prepayment. Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of each Borrowing or portion thereof to be prepaid; provided that, if a notice of prepayment is given in connection with a conditional notice of termination of the Commitments as contemplated by Section 2.09, then such notice of prepayment may be revoked if such notice of termination is revoked in accordance with Section 2.09. Promptly following receipt of any such notice relating to a Borrowing, the Administrative Agent shall advise the Lenders of the contents thereof. Each partial prepayment of any Borrowing shall be in an amount that would be permitted in the case of an advance of a Borrowing of the same Type as provided in Section 2.02. Each prepayment of a Borrowing shall be applied ratably to the Loans included in the prepaid Borrowing. Prepayments shall be accompanied by accrued interest to the extent required by Section 2.13.

SECTION 2.12 Fees. (a) The Borrower agrees to pay to the Administrative Agent for the account of each Lender a facility fee, which shall accrue at the Applicable Rate on (i) the daily amount of the Commitment of such Lender, whether used or unused, during the period from and including the Effective Date to but excluding the Revolving Credit Termination Date (provided that, if such Lender continues to have any Credit Exposure after its Commitment terminates, then such facility fee shall continue to accrue on the daily amount of such Lender's Credit Exposure from and including the date on which its Commitment terminates to but excluding the date on which such Lender ceases to have any Credit Exposure) and (ii) the daily amount of the Credit Exposure of such Lender during the Term Out Period, if any. Accrued facility fees shall be payable in arrears on the last day of March, June, September and December of each year, commencing December 31, 2002 and on the date the Loans are paid in full. All facility fees shall be computed on the basis of a year of 365 or 366 days, as the case may

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be, and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

(b) Prior to any Term Out Period, the Borrower agrees to pay to the Administrative Agent for the account of each Lender, at all times when the aggregate outstanding principal amount of the Loans is greater than 50% of the Commitments, a utilization fee computed at the Applicable Rate on the daily amount of the Credit Exposure of such Lender. During the Term Out Period, if any, the Borrower agrees to pay to the Administrative Agent for the account of each Lender, at all times when the aggregate outstanding principal amount of the Loans is greater than 50% of the Commitments at the time immediately prior to the beginning of the Term Out Period, a utilization fee computed at the Applicable Rate on the daily amount of the Credit Exposure of such Lender. Accrued utilization fees shall be payable in arrears on the last day of March, June, September and December of each year, commencing December 31, 2002 and on the date the Loans are paid in full. All utilization fees shall be computed on the basis of a year of 365 or 366 days, as the case may be, and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

(c) The Borrower agrees to pay to the Administrative Agent, for its own account, fees payable in the amounts and at the times separately agreed upon between the Borrower and the Administrative Agent.

(d) All fees payable hereunder shall be paid on the dates due, in immediately available funds, to the Administrative Agent for distribution, in the case of facility fees and utilization fees, to the Lenders. Fees paid shall not be refundable under any circumstances.

SECTION 2.13 Interest. (a) The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Rate.

(b) The Loans comprising each Eurodollar Borrowing shall bear interest at the Adjusted LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Rate.

(c) Notwithstanding the foregoing, if any principal of or interest on any Loan or any fee or other amount payable by the Borrower hereunder is not paid when due, whether at stated maturity, upon acceleration or otherwise, such overdue amount shall bear interest, after as well as before judgment, at a rate per annum equal to (i) in the case of overdue principal of any Loan, 2% plus the rate otherwise applicable to such Loan as provided in the preceding paragraphs of this Section or (ii) in the case of any other amount, 2% plus the rate applicable to ABR Loans as provided in paragraph (a) of this Section.

(d) Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan and on the Final Maturity Date; provided that (i) interest accrued pursuant to paragraph (c) of this Section shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan, accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment and (iii) in the event of any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

(e) All interest hereunder shall be computed on the basis of a year of 360 days, except that interest computed by reference to the Alternate Base Rate at times when the Alternate Base Rate is based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day). The applicable Alternate Base Rate, Adjusted LIBO Rate or LIBO Rate

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shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error.

SECTION 2.14 Alternate Rate of Interest. If prior to the commencement of any Interest Period for a Eurodollar Borrowing:

(a) the Administrative Agent determines (which determination shall be conclusive absent manifest error) that adequate and reasonable means do not exist for ascertaining the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period; or

(b) the Administrative Agent is advised by the Required Lenders that the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period will not adequately and fairly reflect the cost to such Lenders of making or maintaining their Loans included in such Borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone or telecopy as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, (i) any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective, and (ii) if any Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made as an ABR Borrowing; provided that if the circumstances giving rise to such notice affect only one Type of Borrowings, then the other Type of Borrowings shall be permitted.

SECTION 2.15 Increased Costs. (a) If any Change in Law shall:

(i) impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender (except any such reserve requirement reflected in the Adjusted LIBO Rate); or

(ii) impose on any Lender or the London interbank market any other condition affecting this Agreement or Eurodollar Loans made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such Loan) or to reduce the amount of any sum received or receivable by such Lender hereunder (whether of principal, interest or otherwise), then the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender, for such additional costs incurred or reduction suffered.

(b) If any Lender determines that any Change in Law regarding capital requirements has or would have the effect of reducing the rate of return on such Lender's capital or on the capital of such Lender's holding company, if any, as a consequence of this Agreement or the Loans made by such Lender to a level below that which such Lender or such Lender's holding company could have achieved but for such Change in Law (taking into consideration such Lender's policies and the policies of such Lender's holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender's holding company for any such reduction suffered.

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(c) A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in paragraph (a) or (b) of this Section shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 Business Days after receipt thereof.

(d) Failure or delay on the part of any Lender to demand compensation pursuant to this Section shall not constitute a waiver of such Lender's right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender pursuant to this Section for any increased costs or reductions incurred more than 180 days prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender's intention to claim compensation therefor; provided further that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 180 day period referred to above shall be extended to include the period of retroactive effect thereof.

SECTION 2.16 Break Funding Payments. In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default), (b) the conversion of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto, (c) the failure to borrow, convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto (regardless of whether such notice may be revoked under Section 2.11(c) and is revoked in accordance therewith), or (d) the assignment of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto as a result of a request by the Borrower pursuant to Section 2.19, then, in any such event, the Borrower shall compensate each Lender for the loss, cost and expense attributable to such event. In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount determined by such Lender to be the excess, if any, of (i) the amount of interest that such Lender would pay for a deposit equal to the principal amount of such Loan for the period from the date of such payment, conversion, failure or assignment to the last day of the then current Interest Period for such Loan (or, in the case of a failure to borrow, convert or continue, the duration of the Interest Period that would have resulted from such borrowing, conversion or continuation) if the interest rate payable on such deposit were equal to the LIBO Rate for such Interest Period, over (ii) the amount of interest that such Lender would earn on such principal amount for such period if such Lender were to invest such principal amount for such period at the interest rate that would be bid by such Lender (or an Affiliate of such Lender) for dollar deposits from other banks in the Eurodollar market at the commencement of such period. A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 Business Days after receipt thereof.

SECTION 2.17 Taxes. (a) Any and all payments by or on account of any obligation of the Borrower hereunder shall be made free and clear of and without deduction for any Indemnified Taxes or Other Taxes; provided that if the Borrower shall be required to deduct any Indemnified Taxes or Other Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section) the Administrative Agent or Lender (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower shall make such deductions and (iii) the Borrower shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

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(b) In addition, the Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c) The Borrower shall indemnify the Administrative Agent and each Lender, within 10 Business Days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes paid by the Administrative Agent or such Lender, as the case may be, (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender, or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(d) As soon as practicable after any payment of Indemnified Taxes or Other Taxes by the Borrower to a Governmental Authority, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e) Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax under the law of the jurisdiction in which the Borrower is located, or any treaty to which such jurisdiction is a party, with respect to payments under this Agreement shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law or reasonably requested by the Borrower as will permit such payments to be made without withholding or at a reduced rate.

(f) If the Administrative Agent or a Lender determines, in its sole discretion, that it has received a refund of any Taxes or Other Taxes as to which it has been indemnified by the Borrower or with respect to which the Borrower has paid additional amounts pursuant to this Section 2.17, it shall pay over such refund to the Borrower (but only to the extent of indemnity payments made, or additional amounts paid, by the Borrower under this Section 2.17 with respect to the Taxes or Other Taxes giving rise to such refund), net of all out-of-pocket expenses of the Administrative Agent or such Lender and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund); provided, that the Borrower, upon the request of the Administrative Agent or such Lender, agrees to repay the amount paid over to the Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Administrative Agent or such Lender in the event the Administrative Agent or such Lender is required to repay such refund to such Governmental Authority. This Section shall not be construed to require the Administrative Agent or any Lender to make available its tax returns (or any other information relating to its taxes which it deems confidential) to the Borrower or any other Person.

SECTION 2.18 Payments Generally; Pro Rata Treatment; Sharing of Set-offs. (a) The Borrower shall make each payment required to be made by it hereunder (whether of principal, interest, fees, or of amounts payable under Section 2.15, 2.16 or 2.17, or otherwise) prior to 12:00 noon, New York City time, on the date when due, in immediately available funds, without set-off or counterclaim. Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon. All such payments shall be made to the Administrative Agent at its offices at 270 Park Avenue, New York, New York, except that payments pursuant to Sections 2.15, 2.16, 2.17 and 9.03 shall be made directly to the Persons entitled thereto. The Administrative Agent shall distribute any such payments

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received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof. If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension. All payments hereunder shall be made in dollars.

(b) If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal then due to such parties.

(c) If any Lender shall, by exercising any right of set-off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Loans and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Loans of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this paragraph shall not be construed to apply to any payment made by the Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans to any assignee or participant, other than to the Borrower or any Subsidiary or Affiliate thereof (as to which the provisions of this paragraph shall apply). The Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

(d) Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders hereunder that the Borrower will not make such payment, the Administrative Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders the amount due. In such event, if the Borrower has not in fact made such payment, then each of the Lenders severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

(e) If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.07(b) or 2.18(d), then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender's obligations under such Sections until all such unsatisfied obligations are fully paid.

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SECTION 2.19 Mitigation Obligations; Replacement of Lenders. (a) If any Lender requests compensation under Section 2.15, or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.17, then such Lender shall use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 2.15 or 2.17, as the case may be, in the future and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender.

(b) If any Lender requests compensation under Section 2.15, or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.17, or if any Lender defaults in its obligation to fund Loans hereunder, then the Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in Section 9.04), all its interests, rights and obligations under this Agreement to an assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that (i) the Borrower shall have received the prior written consent of the Administrative Agent, which consent shall not unreasonably be withheld, (ii) such Lender shall have received payment of an amount equal to the outstanding principal of its Loans, accrued interest thereon, accrued fees and all other amounts payable to it hereunder, from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts) and (iii) in the case of any such assignment resulting from a claim for compensation under Section 2.15 or payments required to be made pursuant to Section 2.17, such assignment will result in a reduction in such compensation or payments. A Lender shall not be required to make any such assignment and delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.

SECTION 2.20 Extensions of Termination Date; Removal of Lenders. (a) The Borrower may, by written notice to the Administrative Agent (a "Notice of Extension") given not less than 30 nor more than 45 days prior to the then effective Revolving Credit Termination Date, advise the Lenders that it requests an extension of the then effective Revolving Credit Termination Date (such then effective Revolving Credit Termination Date being the "Existing Revolving Credit Termination Date") by 364 calendar days, effective on the Existing Revolving Credit Termination Date. The Administrative Agent will promptly, and in any event within five Business Days of the receipt of such Notice of Extension, notify the Lenders of the contents of each such Notice of Extension.

(b) Each Notice of Extension shall (i) be irrevocable and (ii) constitute a representation by the Borrower that (A) neither any Event of Default nor any Default has occurred and is continuing, and (B) the representations and warranties contained in Article III are correct on and as of such date, as though made on and as of such date (unless any representation and warranty expressly relates to an earlier date, in which case such representation and warranty shall be correct as of such earlier date). In the event the Existing Revolving Credit Termination Date is extended pursuant to the terms of this Section 2.20, the Borrower shall be deemed to represent on and as of the effective date of such extension that (i) neither any Event of Default nor any Default has occurred and is continuing, and (ii) the representations and warranties contained in Article III are correct on and as of such date, as though made on and as of such date (unless any representation and warranty expressly relates to an earlier date, in which case such representation and warranty shall be correct as of such earlier date).

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(c) In the event a Notice of Extension is given to the Administrative Agent as provided in Section 2.20(a) and the Administrative Agent notifies a Lender of the contents thereof, such Lender shall on or before the 20th day next preceding the Existing Revolving Credit Termination Date advise the Administrative Agent in writing whether or not such Lender consents to the extension requested thereby and if any Lender fails so to advise the Administrative Agent, such Lender shall be deemed to have not consented to such extension. If Lenders holding 80% or more of the sum of the aggregate Revolving Credit Exposures and unused Commitments so consent (the "Consenting Lenders") to such extension and any and all Lenders who have not consented (the "Non-Consenting Lenders") are replaced pursuant to paragraph (d) or (e) of this Section 2.20 or repaid pursuant to paragraph (f) of this Section 2.20, the Revolving Credit Termination Date, and the Commitments of the Consenting Lenders and the Nominees (as defined below) shall be automatically extended 364 calendar days from the Existing Revolving Credit Termination Date, effective on the Existing Revolving Credit Termination Date. The Administrative Agent shall promptly notify the Borrower and all of the Lenders of each written notice of consent given pursuant to this Section 2.20(c).

(d) In the event the Consenting Lenders hold less than 100% of the sum of the aggregate Revolving Credit Exposures and unused Commitments, the Consenting Lenders, or any of them, shall have the right (but not the obligation) to assume all or any portion of the Non-Consenting Lenders' Commitments by giving written notice to the Borrower and the Administrative Agent of their election to do so on or before the 15th day next preceding the Existing Revolving Credit Termination Date, which notice shall be irrevocable and shall constitute an undertaking to (i) assume, as of the close of business on the Existing Revolving Credit Termination Date, all or such portion of the Commitments of the Non-Consenting Lenders, as the case may be, as may be specified in such written notice, and (ii) purchase (without recourse) from the Non-Consenting Lenders, at the close of business on the Existing Revolving Credit Termination Date, the Credit Exposures outstanding on the Existing Revolving Credit Termination Date that correspond to the portion of the Commitments to be so assumed at a price equal to the sum of (x) the unpaid principal amount of all Loans so purchased, plus (y) the aggregate amount, if any, previously funded by the transferor or any participations so purchased, plus (z) all accrued and unpaid interest thereon. Such Commitments and Credit Exposures, or portion thereof, to be assumed and purchased by Consenting Lenders shall be allocated among those Consenting Lenders who have so elected to assume the same pro rata in accordance with the respective Commitments of such Consenting Lenders as of the Existing Revolving Credit Termination Date (provided, however, in no event shall a Consenting Lender be required to assume and purchase an amount or portion of the Commitments and Credit Exposures of the Non-Consenting Lenders in excess of the amount which such Consenting Lender agreed to assume and purchase pursuant to the immediately preceding sentence) or on such other basis as such Consenting Lender shall agree. The Administrative Agent shall promptly notify the Borrower and the other Consenting Lenders in the event it receives any notice from a Consenting Lender pursuant to this Section 2.20(d).

(e) In the event that the Consenting Lenders shall not elect as provided in Section 2.20(d) to assume and purchase all of the Non-Consenting Lenders' Commitments and Credit Exposures, the Borrower may designate, by written notice to the Administrative Agent and the Consenting Lenders given on or before the tenth day next preceding the Existing Revolving Credit Termination Date, one or more assignees not a party to this Agreement (individually, a "Nominee" and collectively, the "Nominees") to assume all or any portion of the Non-Consenting Lenders' Commitments not to be assumed by the Consenting Lenders and to purchase (without recourse) from the Non-Consenting Lenders all Credit Exposures outstanding at the close of business on the Existing Revolving Credit Termination Date that corresponds to the portion of the Commitments so to be assumed at the price specified in Section 2.20(d). Each assumption and purchase under this Section 2.20(e) shall be effective

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as of the close of business on the Existing Revolving Credit Termination Date when each of the following conditions has been satisfied in a manner satisfactory to the Administrative Agent:

     (i)        each Nominee and the Non-Consenting Lenders have executed an Assignment and Assumption pursuant to which such Nominee shall (A) assume in writing its share of the obligations of the Non-Consenting Lenders hereunder, including its share of the Commitments of the Non-Consenting Lenders and (B) agree to be bound as a Lender by the terms of this Agreement;

     (ii)       each Nominee shall have completed and delivered to the Administrative Agent an Administrative Questionnaire; and

     (iii)     the assignment shall otherwise comply with Section 9.04.

(f) If all of the Commitments of the Non-Consenting Lenders are not replaced on or before the Existing Revolving Credit Termination Date, then, at the Borrower's option, either (i) all Commitments shall terminate on the Existing Revolving Credit Termination Date or (ii) the Borrower shall give prompt notice of termination on the Existing Revolving Credit Termination Date of the Commitments of each Non-Consenting Lender not so replaced to the Administrative Agent, and shall prepay on the Existing Revolving Credit Termination Date the Loans, if any, of such Non-Consenting Lenders, which shall reduce the aggregate Commitments accordingly (to the extent not assumed), and the Existing Revolving Credit Termination Date shall be extended in accordance with this Section 2.20 for the remaining Commitments of the Consenting Lenders; provided, however, that (A) Lenders having Revolving Credit Exposures and unused Commitments representing more than 80% of the sum of the aggregate Revolving Credit Exposures and unused Commitments have consented to such extension pursuant to Section 2.20(c) and (B) no Lender after giving effect to the extension contemplated hereunder shall have more than 20% of the aggregate Commitments without such Lender's prior written consent.

SECTION 2.21 Conversion to Term Loans. At the option of the Borrower and subject to the satisfaction of the conditions precedent for a Borrowing set forth in Section 4.02, upon written notice delivered to the Administrative Agent no earlier than 60 days and no later than one Business Day prior to the Revolving Credit Termination Date, the aggregate principal amount of all, but not less than all, of the Revolving Loans remaining outstanding at the close of the Administrative Agent's business on the Revolving Credit Termination Date shall automatically convert to Term Loans with a maturity of one year. Any portion of each Lender's Commitment not utilized on or before the Revolving Credit Termination Date shall be permanently cancelled. Any Term Loans that are prepaid may not be reborrowed.

ARTICLE III

Representations and Warranties

The Borrower represents and warrants to the Lenders that:

SECTION 3.01 Organization; Powers. Each of the Borrower and its Subsidiaries is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has all requisite power and authority to carry on its business as now conducted and, except where the failure

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to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect, is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required.

SECTION 3.02 Authorization; Enforceability. The Transactions are within the Borrower's corporate powers and have been duly authorized by all necessary corporate and, if required, stockholder action. This Agreement has been duly executed and delivered by the Borrower and constitutes a legal, valid and binding obligation of the Borrower, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors' rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

SECTION 3.03 Governmental Approvals; No Conflicts. The Transactions (a) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority, except such as have been obtained or made and are in full force and effect and such matters relating to performance as would ordinarily be done in the ordinary course of business after the Effective Date, (b) will not violate any applicable law or regulation or any order of any Governmental Authority, (c) will not violate the charter, by-laws or other organizational documents of the Borrower, (d) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or any of its Subsidiaries or its assets, or give rise to a right thereunder to require any payment to be made by the Borrower or any of its Subsidiaries, and (e) will not result in the creation or imposition of any Lien on any asset of the Borrower or any of its Subsidiaries, except for breaches, violations and defaults under clauses (b) and (d) that neither individually nor in the aggregate could reasonably be expected to result in a Material Adverse Effect.

SECTION 3.04 Financial Condition; No Material Adverse Change. (a) The consolidated balance sheet of the Borrower and its Consolidated Subsidiaries and the related consolidated statements of income, common stockholders equity and cash flows (i) as of and for the fiscal year ended December 31, 2001, reported on by Pricewaterhouse Coopers LLP, independent public accountants and set forth in the Borrower's 2001 Form 10-K, and (ii) as of and for the fiscal quarter and the portion of the fiscal year ended June 30, 2002, set forth in the Borrower's latest Form 10-Q, present fairly, in all material respects, the consolidated financial position and results of operations and cash flows of the Borrower and its Consolidated Subsidiaries as of such dates and for such periods in accordance with GAAP, subject to year-end audit adjustments and the absence of footnotes in the case of the statements referred to in clause (ii) above.

(b) As of the Effective Date, since December 31, 2001, there has been no material adverse change in the business, assets, liabilities (actual or contingent), operations, or financial condition of the Borrower and the Subsidiaries taken as a whole.

SECTION 3.05 Properties. Each of the Borrower and the Subsidiaries has good title to, or valid leasehold or other interests in, all its real and personal property material to its business, except for Liens permitted pursuant to Section 6.02.

SECTION 3.06 Litigation and Environmental Matters. (a) Except as disclosed in the most recent Annual Report on Form 10-K delivered by the Borrower to the Lenders, there is no action, suit or proceeding by or before any arbitrator or Governmental Authority pending against or, to the knowledge of the Borrower, threatened against or affecting the Borrower or any of the Subsidiaries (i) as to which there is a reasonable possibility of an adverse determination and that, if adversely determined, could

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reasonably be expected to result in a Material Adverse Effect or (ii) that involves this Agreement or the Transactions.

(b) In the ordinary course of its business, the Borrower conducts an ongoing review of the effect of Environmental Laws on the business, operations and properties of the Borrower and the Subsidiaries, in the course of which it identifies and evaluates associated liabilities and costs (including any capital or operating expenditures required for clean-up or closure of properties currently or previously owned, any capital or operating expenditures required to achieve or maintain compliance with environmental protection standards imposed by law or as a condition of any license, permit or contract, any related constraints on operating activities, including any periodic or permanent shutdown of any facility or reduction in the level of or change in the nature of operations conducted threat, any costs or liabilities in connection with off-site disposal of wastes or Hazardous Materials, and any actual or potential liabilities to third parties, including employees, and any related costs and expenses). On the basis of this review, the Borrower has reasonably concluded that such associated liabilities and costs, including the costs of compliance with Environmental Laws, are unlikely to result in a Material Adverse Effect.

SECTION 3.07 Compliance with Laws and Agreements. Each of the Borrower and its Subsidiaries is in compliance with all laws, regulations and orders of any Governmental Authority applicable to it or its property and all indentures, agreements and other instruments binding upon it or its property, except where the failure to do so, individually or in the aggregate for the Borrower and its Subsidiaries, could not reasonably be expected to result in a Material Adverse Effect.

SECTION 3.08 Investment and Holding Company Status. Neither the Borrower nor any of its Subsidiaries is (a) an "investment company" as defined in, or subject to regulation under, the Investment Company Act of 1940 or (b) a "holding company" as defined in, or subject to regulation under, the Public Utility Holding Company Act of 1935.

SECTION 3.09 Taxes. The Borrower and the Subsidiaries have caused to be filed all federal income tax returns and other material tax returns, statements and reports (or obtained extensions with respect thereto) which are required to be filed and have paid or deposited or made adequate provision in accordance with GAAP for the payment of all taxes (including estimated taxes shown on such returns, statements and reports) which are shown to be due pursuant to such returns, except for taxes as are being contested in good faith by appropriate proceedings for which adequate reserves have been established in accordance with GAAP and where the failure to pay such taxes (individually or in the aggregate for the Borrower and the Subsidiaries) would not have a Material Adverse Effect.

SECTION 3.10 ERISA. Each member of the ERISA Group has fulfilled its obligations under the minimum funding standards of ERISA and the Code with respect to each Plan and is in compliance in all material respects with the presently applicable provisions of ERISA and the Code with respect to each Plan. No member of the ERISA Group has (i) sought a waiver of the minimum funding standard under Section 412 of the Code in respect of any Plan, (ii) failed to make any contribution or payment to any Plan or Multiemployer Plan or in respect of any Benefit Arrangement, or made any amendment to any Plan or Benefit Arrangement, which has resulted or could result in the imposition of a Lien or the posting of a bond or other security under ERISA or the Code or (iii) incurred any liability under Title IV of ERISA other than a liability to the PBGC for premiums under Section 4007 of ERISA, which waiver, failure or liability could reasonably be expected to result in a Material Adverse Effect.

SECTION 3.11 Disclosure. All information heretofore furnished by the Borrower to the Administrative Agent or any Lender for purposes of or in connection with this Agreement or any

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transaction contemplated hereby is, and all such information hereafter furnished by the Borrower to the Administrative Agent or any Lender will be, true and accurate in all material respects on the date as of which such information is stated or certified. None of the reports, financial statements, certificates or other information furnished by or on behalf of the Borrower to the Administrative Agent or any Lender in connection with the syndication or negotiation of this Agreement or delivered hereunder (as modified or supplemented by other information so furnished) contains any material misstatement of fact or omits to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading.

ARTICLE IV

Conditions

SECTION 4.01 Effective Date. The obligations of the Lenders to make Loans hereunder shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 9.02):

(a) The Administrative Agent (or its counsel) shall have received from each party hereto either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include telecopy transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

(b) The Administrative Agent shall have received favorable written opinions (addressed to the Administrative Agent and the Lenders and dated the Effective Date) of Polsinelli Shalton & Welte, P.C., Kansas counsel for the Borrower, and Bracewell & Patterson, L.L.P., counsel for the Borrower, substantially in the forms of Exhibit B-1 and B-2, and covering such other matters relating to the Borrower, this Agreement or the Transactions as the Required Lenders shall reasonably request. The Borrower hereby requests such counsels to deliver such opinions.

(c) The Administrative Agent shall have received such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, existence and good standing of the Borrower, the authorization of the Transactions and any other legal matters relating to the Borrower, this Agreement or the Transactions, all in form and substance satisfactory to the Administrative Agent and its counsel.

(d) The Administrative Agent shall have received a certificate, dated the Effective Date and signed by the President, a Vice President or a Financial Officer of the Borrower, confirming compliance with the conditions set forth in paragraphs (a) and (b) of Section 4.02.

(e) The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses required to be reimbursed or paid by the Borrower hereunder.

(f) The Administrative Agent shall have received a written irrevocable notice from the Borrower terminating the Existing Credit Facility (including all commitments thereunder) and directing the Administrative Agent to prepay by wire transfer, in immediately available funds, in full any loans and other amounts then outstanding thereunder, together with accrued interest thereon and any unpaid fees then accrued.

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(g) The conditions precedent to the making of loans under the Three-Year Facility shall have been satisfied or waived in accordance with such facility.

The Administrative Agent shall notify the Borrower and the Lenders of the Effective Date, and such notice shall be conclusive and binding. Notwithstanding the foregoing, the obligations of the Lenders to make Loans hereunder shall not become effective unless each of the foregoing conditions is satisfied (or waived pursuant to Section 9.02) at or prior to 3:00 p.m., New York City time, on October 22, 2002 (and, in the event such conditions are not so satisfied or waived, the Commitments shall terminate at such time).

SECTION 4.02 Each Credit Event. The obligation of each Lender to make a Loan on the occasion of any Borrowing is subject to the satisfaction of the following conditions:

(a) The representations and warranties of the Borrower set forth in this Agreement shall be true and correct on and as of the date of such Borrowing (unless any representation and warranty expressly relates to an earlier date, in which case such representation and warranty shall be correct as of such earlier date).

(b) At the time of and immediately after giving effect to such Borrowing, no Default shall have occurred and be continuing.

Each Borrowing shall be deemed to constitute a representation and warranty by the Borrower on the date thereof as to the matters specified in paragraphs (a) and (b) of this Section.

SECTION 4.03 Conditions Precedent to Conversions. Notwithstanding the foregoing, the obligation of the Lenders to convert or continue any existing Borrowing into or as a Eurodollar Borrowing is subject to the condition precedent that on the date of such conversion or continuation no Default or Event of Default shall have occurred and be continuing or would result from the making of such conversion. The acceptance of the benefits of each such conversion or continuation shall constitute a representation and warranty by the Borrower to each of the Lenders that no Default or Event of Default shall have occurred and be continuing or would result from the making of such conversion or continuation.

ARTICLE V

Affirmative Covenants

Until the Commitments have expired or been terminated and the principal of and interest on each Loan and all fees payable hereunder shall have been paid in full, the Borrower covenants and agrees with the Lenders that:

SECTION 5.01 Financial Statements; Ratings Change and Other Information. The Borrower will furnish to the Administrative Agent and each Lender:

(a) before the earlier of (i) 100 days after the end of each fiscal year of the Borrower and (ii) 10 days after filing with the Securities and Exchange Commission is required, its audited consolidated balance sheet and related statements of operations, common stockholders' equity and cash flows as of the end of and for such year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on by Pricewaterhouse Coopers L.L.P. or other independent public accountants of recognized national standing (without a "going concern" or like qualification or exception

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and without any qualification or exception as to the scope of such audit) to the effect that such consolidated financial statements present fairly in all material respects the financial condition and results of operations of the Borrower and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied; provided, however, that (x) if the Borrower has timely made its Annual Report on Form 10-K available on "EDGAR" and/or on its home page on the worldwide web (at the date of this Agreement located at http://www.kindermorgan.com) and complied with the last grammatical paragraph of this Section 5.01 in respect thereof, and (y) if said Annual Report contains such consolidated balance sheet and related statements of operations, common stockholders' equity and cash flows, and the report thereon of such independent public accountants (without qualification or exception, and to the effect, as specified above), then the Borrower shall be deemed to have satisfied the requirements of this clause (a);

(b) before the earlier of (i) 50 days after the end of each of the first three fiscal quarters of each fiscal year of the Borrower and (ii) five days after filing with the Securities and Exchange Commission is required, its consolidated balance sheet and related statements of operations, common stockholders' equity and cash flows as of the end of and for such fiscal quarter and the then elapsed portion of the fiscal year, setting forth in each case in comparative form the figures for the corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the previous fiscal year, all certified by one of its Financial Officers as presenting fairly in all material respects the financial condition and results of operations of the Borrower and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes; provided, however, that (x) if the Borrower has timely made its Quarterly Report on Form 10-Q available on "EDGAR" and/or on its home page on the worldwide web (at the date of this Agreement located at http://www.kindermorgan.com) and complied with the last grammatical paragraph of this Section 5.01 in respect thereof, and (y) if said Quarterly Report contains such consolidated balance sheet and related statements of operations, common stockholders' equity and cash flows, and such certifications, then the Borrower shall be deemed to have satisfied the requirements of this clause (b);

(c) concurrently with any delivery of financial statements under clause (a) or (b) above, a certificate of a Financial Officer of the Borrower (i) certifying as to whether a Default has occurred and, if a Default has occurred, specifying the details thereof and any action taken or proposed to be taken with respect thereto, (ii) setting forth reasonably detailed calculations demonstrating compliance with Section 6.01, and (iii) stating whether any change in GAAP or in the application thereof that has an effect on the financial statements of the Borrower or on the calculation of the financial covenants pursuant to Section 6.01 has occurred since the date of the audited financial statements referred to in Section 3.04 and, if any such change has occurred, specifying the effect of such change on the financial statements accompanying such certificate or on such financial covenant calculations;

(d) concurrently with any delivery of financial statements under clause (a) above, a certificate (which certificate may be limited to the extent required by accounting rules or guidelines) of the accounting firm that reported on such financial statements stating (i) whether they obtained knowledge during the course of their examination of such financial statements of any Default ; provided, however, that such accountants shall not be liable to anyone by reason of their failure to obtain knowledge of any Default which would not be disclosed in the course of an audit conducted in accordance with GAAP, and (ii) confirming the calculations set forth in the certificate delivered simultaneously therewith pursuant to clause (c) above;

(e) without duplication of any other requirement of this Section 5.01, promptly after the same become publicly available, copies of all periodic and other reports, proxy statements and other

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materials filed by the Borrower or any Subsidiary with the Securities and Exchange Commission, or any Governmental Authority succeeding to any or all of the functions of said Commission, or with any national securities exchange, or distributed by the Borrower to its shareholders generally, as the case may be;

(f) promptly after Moody's or S&P shall have announced a change in the rating established or deemed to have been established for the Index Debt, written notice of such rating change;

(g) within five Business Days after any officer of the Borrower obtains knowledge of any Default, if such Default is then continuing, a certificate of the Financial Officer of the Borrower setting forth the details thereof and the action which the Borrower is taking or proposes to take with respect thereto; and

(h) promptly following any request therefor, such other information regarding the operations, business affairs and financial condition of the Borrower or any Subsidiary, or compliance with the terms of this Agreement, as the Administrative Agent or any Lender may reasonably request.

Information required to be delivered pursuant to Section 5.01(a), 5.01(b), or 5.01(e) above shall be deemed to have been delivered on the date on which the Borrower provides notice to the Administrative Agent that such information has been posted on "EDGAR" or the Borrower's website or another website identified in such notice and accessible by the Administrative Agent and the Lenders without charge (and the Borrower hereby agrees to provide such notice); provided that such notice may be included in a certificate delivered pursuant to Section 5.01(c).

SECTION 5.02 Notices of Material Events. The Borrower will furnish to the Administrative Agent and each Lender prompt written notice of the following:

(a) if and when any member of the ERISA Group (i) gives or is required to give notice to the PBGC of any "reportable event" (as defined in Section 4043 of ERISA) (other than such event as to which the 30-day notice requirement is waived) with respect to any Plan which might constitute grounds for a termination of such Plan under Title IV of ERISA, or knows that the plan administrator of any Plan has given or is required to give notice of any such reportable event, a copy of the notice of such reportable event given or required to be given to the PBGC; (ii) receives notice of complete or partial withdrawal liability under Title IV of ERISA or notice that any Multiemployer Plan is in reorganization, is insolvent or has been terminated, a copy of such notice; (iii) receives notice from the PBGC under Title IV of ERISA of an intent to terminate, impose liability (other than for premiums under Section 4007 of ERISA) in respect of, or appoint a trustee to administer any Plan, a copy of such notice; (iv) applies for a waiver of the minimum funding standard under Section 412 of the Code, a copy of such application; (v) gives notice of intent to terminate any Plan under Section 4041(c) of ERISA, a copy of such notice and other information filed with the PBGC; (vi) gives notice of withdrawal from any Plan pursuant to Section 4063 of ERISA, a copy of such notice; or (vii) fails to make any payment or contribution to any Plan or Multiemployer Plan or in respect of any Benefit Arrangement or makes any amendment to any Plan or Benefit Arrangement which has resulted or could result in the imposition of a Lien or the posting of a bond or other security in an amount that could reasonably be expected to have a Material Adverse Effect, a certificate of the chief financial officer or the chief accounting officer of the Borrower setting forth details as to such occurrence and action, if any, which the Borrower or applicable member of the ERISA Group is required or proposes to take; and

(b) any other development that results in, or could reasonably be expected to result in, a Material Adverse Effect.

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Each notice delivered under this Section shall be accompanied by a statement of a Financial Officer or other executive officer of the Borrower setting forth the details of the event or development requiring such notice and any action taken or proposed to be taken with respect thereto.

SECTION 5.03 Existence; Conduct of Business. The Borrower will, and will cause each of its Material Subsidiaries to, do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence and the rights, licenses, permits, privileges and franchises material to the conduct of its business; provided that the foregoing shall not prohibit any merger, consolidation, liquidation or dissolution permitted under Section 6.03.

SECTION 5.04 Payment of Obligations. The Borrower will, and will cause each of its Subsidiaries to, before the same shall become delinquent or in default, pay its obligations, including Tax liabilities, that, if not paid, could result in a Material Adverse Effect except where (a) the validity or amount thereof is being contested in good faith by appropriate proceedings, (b) the Borrower or such Subsidiary has set aside on its books adequate reserves with respect thereto in accordance with GAAP and (c) the failure to make payment pending such contest could not reasonably be expected to result in a Material Adverse Effect.

SECTION 5.05 Maintenance of Properties; Insurance. The Borrower will, and will cause each of its Material Subsidiaries to, (a) keep and maintain all property material to the conduct of its business in good working order and condition, ordinary wear and tear excepted, and (b) maintain, with financially sound and reputable insurance companies, insurance in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations.

SECTION 5.06 Books and Records; Inspection Rights. The Borrower will, and will cause each of its Subsidiaries to, keep proper books of record and account in which full, true and correct entries are made of all dealings and transactions in relation to its business and activities. The Borrower will, and will cause each of its Subsidiaries to, permit any representatives designated by the Administrative Agent or any Lender, upon reasonable prior notice during normal business hours, to visit and inspect its properties, to examine and make extracts from its books and records (subject to compliance with confidentiality agreements and applicable copyright law), and to discuss its affairs, finances and condition with its officers and independent accountants, all at such reasonable times and as often as reasonably requested.

SECTION 5.07 Compliance with Laws. The Borrower will, and will cause each of its Subsidiaries to, comply with all laws, rules, regulations and orders of any Governmental Authority applicable to it or its property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

SECTION 5.08 Use of Proceeds. The proceeds of the Loans will be used only for (a) payment in full of all amounts owing under the Existing Credit Facility, (b) working capital, and (c) general lawful corporate purposes, including but not limited to providing liquidity for commercial paper backup. No part of the proceeds of any Loan will be used, whether directly or indirectly, for any purpose that entails a violation of any of the Regulations of the Board, including Regulations U and X.

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ARTICLE VI

Negative Covenants

Until the Commitments have expired or terminated and the principal of and interest on each Loan and all fees payable hereunder have been paid in full, the Borrower covenants and agrees with the Lenders that:

SECTION 6.01 Financial Covenants.

(a) Indebtedness.

          (i)           Consolidated Indebtedness of the Borrower.  The Consolidated Indebtedness of the Borrower shall at no time exceed 65.0% of the Consolidated Total Capitalization of the Borrower.

          (ii)          Total Consolidated Indebtedness of Consolidated Subsidiaries. The aggregate Indebtedness of all Consolidated Subsidiaries of the Borrower (excluding Indebtedness of a Consolidated Subsidiary of the Borrower to the Borrower or to another Consolidated Subsidiary of the Borrower) shall at no time exceed 10% of the Consolidated Indebtedness of the Borrower.

          (iii)         Consolidated Indebtedness of Material Subsidiaries. The Consolidated Indebtedness of each Material Subsidiary shall at no time exceed 65.0% of the Consolidated Total Capitalization of such Material Subsidiary.

(b) Minimum Net Worth. The Consolidated Net Worth of the Borrower will at no time be less than an amount equal to the sum of (a) $1,700,000,000 plus (b) 50% of Consolidated Net Income for each fiscal quarter of the Borrower ending on or after September 30, 2002 (but only if such consolidated Net Income for such fiscal quarter is a positive amount).

SECTION 6.02 Liens. The Borrower will not, and will not permit any Subsidiary to, create, incur, assume or permit to exist any Lien on any property or asset now owned or hereafter acquired by it, or assign or sell any income or revenues (including accounts receivable) or rights in respect of any thereof, except:

(a) Permitted Encumbrances;

(b) any Lien existing on any property or asset prior to the acquisition thereof by the Borrower or any Subsidiary or existing on any property or asset of any Person that becomes a Subsidiary after the date hereof prior to the time such Person becomes a Subsidiary; provided that (i) such Lien is not created in contemplation of or in connection with such acquisition or such Person becoming a Subsidiary, as the case may be, (ii) such Lien shall not apply to any other property or assets of the Borrower or any Subsidiary and (iii) such Lien shall secure only those obligations which it secures on the date of such acquisition or the date such Person becomes a Subsidiary, as the case may be and extensions, renewals and replacements thereof that do not increase the outstanding principal amount thereof;

(c) Liens arising in the ordinary course of its business which (i) do no secure Indebtedness or Hedging Agreements, (ii) do not secure obligations in an aggregate amount exceeding

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$150,000,000 and (iii) do not in the aggregate materially detract from the value of its assets or materially impair the use thereof in the operation of its business;

(d) Liens on cash and cash equivalents securing Hedging Agreements, provided that the aggregate amount of cash and cash equivalents subject to such Liens may at no time exceed $75,000,000; and

(e) Liens not otherwise permitted by the foregoing clauses of this Section securing Indebtedness in an aggregate principal or face amount at any date not to exceed 10% of Consolidated Net Worth of the Borrower.

SECTION 6.03 Fundamental Changes. (a) The Borrower will not, and will not permit any Subsidiary to, merge into or consolidate with any other Person, or permit any other Person to merge into or consolidate with it, or sell, transfer, lease or otherwise dispose of (in one transaction or in a series of transactions) all or substantially all of its assets, or all or substantially all of the Equity Interests of any of its Subsidiaries (in each case, whether now owned or hereafter acquired), or liquidate or dissolve, except that if at the time thereof and immediately after giving effect thereto no Default shall have occurred and be continuing (i) if the Borrower is involved in any such transaction, (x) any Person may merge into the Borrower in a transaction in which the Borrower is the surviving corporation, or (y) if the Borrower is not the surviving entity, (A) the Person formed by or surviving such transaction or the recipient of any such sale, transfer, lease or other disposition of assets, assumes all Obligations, (B) the Person formed by or surviving such transaction or the recipient of any such sale, transfer lease or other disposition, is organized under the laws of the United States or any state thereof, and (C) the Borrower has delivered to the Administrative Agent an officer's certificate and an opinion of counsel, each stating that such consolidation, merger, transfer, lease or other disposition complies with the provisions hereof. (ii) any Person may merge into any Subsidiary in a transaction in which the surviving entity is a Subsidiary, (iii) any Subsidiary may sell, transfer, lease or otherwise dispose of its assets to the Borrower or to another Subsidiary and (iv) any Subsidiary may liquidate or dissolve if the Borrower determines in good faith that such liquidation or dissolution is in the best interests of the Borrower and such liquidation or dissolution is not materially disadvantageous to the Lenders.

(b) The Borrower will not, and will not permit any of its Material Subsidiaries to, engage to any material extent in any business other than businesses of the type conducted by the Borrower and its Subsidiaries on the date of execution of this Agreement and businesses reasonably related thereto.

SECTION 6.04 Transactions with Affiliates. The Borrower will not, and will not permit any of the Subsidiaries to, sell, lease or otherwise transfer any property or assets to, or purchase, lease or otherwise acquire any property or assets from, or otherwise engage in any other transactions with, any of its Affiliates, except (a) in the ordinary course of business at prices and on terms and conditions not less favorable to the Borrower or such Subsidiary than could be obtained on an arm's-length basis from unrelated third parties and (b) transactions between or among the Borrower and the wholly-owned Subsidiaries not involving any other Affiliate.

SECTION 6.05 Capital Lease Obligations. The Borrower will not, and will not permit any of the Subsidiaries to, incur any Capital Lease Obligations if, after giving effect to the incurrence of such Capital Lease Obligations, the aggregate principal amount of all outstanding Capital Lease Obligations of the Borrower and the Subsidiaries would exceed $500,000,000.

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ARTICLE VII

Events of Default

If any of the following events ("Events of Default") shall occur:

(a) the Borrower shall fail to pay any principal of any Loan when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof or otherwise;

(b) the Borrower shall fail to pay any interest on any Loan or any fee or any other amount (other than an amount referred to in clause (a) of this Article) payable under this Agreement, when and as the same shall become due and payable, and such failure shall continue unremedied for a period of three Business Days;

(c) any representation or warranty made or deemed made by or on behalf of the Borrower or any Subsidiary in or in connection with this Agreement or any amendment or modification hereof or waiver hereunder, or in any report, certificate, financial statement or other document furnished pursuant to or in connection with this Agreement or any amendment or modification hereof or waiver hereunder, shall prove to have been incorrect in any material respect when made or deemed made;

(d) the Borrower shall fail to observe or perform any covenant, condition or agreement contained in Section 5.01(g), 5.03 (with respect to the Borrower's existence) or 5.08 or in Article VI;

(e) the Borrower shall fail to observe or perform any covenant, condition or agreement contained in this Agreement (other than those specified in clause (a), (b) or (d) of this Article), and such failure shall continue unremedied for a period of 30 days after the earlier of (i) written notice thereof from the Administrative Agent to the Borrower (which notice will be given at the request of any Lender) or (ii) a Responsible Officer of the Borrower becomes aware of such failure;

(f) any Subsidiary shall fail to make any payment (whether of principal or interest and regardless of amount) in respect of any Material Indebtedness, when and as the same shall become due and payable or within any applicable grace period (not to exceed 30 days);

(g) any event or condition occurs that results in the acceleration of the maturity of any Material Indebtedness or requires the prepayment, repurchase, redemption or defeasance thereof, prior to its scheduled maturity of any Material Indebtedness; provided that this clause (g) shall not apply to secured Indebtedness that becomes due as a result of the voluntary sale or transfer of the property or assets securing such Indebtedness so long as such Indebtedness is paid in full when due;

(h) an involuntary proceeding shall be commenced or an involuntary petition shall be filed seeking (i) liquidation, reorganization or other relief in respect of the Borrower or any Material Subsidiary or its debts, or of a substantial part of its assets, under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect or (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or any Material Subsidiary or for a substantial part of its assets, and, in any such case, such proceeding or petition shall continue undismissed for 60 days or an order or decree approving or ordering any of the foregoing shall be entered;

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(i) the Borrower or any Material Subsidiary shall (i) voluntarily commence any proceeding or file any petition seeking liquidation, reorganization or other relief under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or petition described in clause (h) of this Article, (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or any Material Subsidiary or for a substantial part of its assets, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors or (vi) take any action for the purpose of effecting any of the foregoing;

(j) the Borrower or any Material Subsidiary shall become unable, admit in writing its inability or fail generally to pay its material debts as they become due;

(k) one or more judgments for the payment of money in an aggregate amount in excess of $75,000,000 shall be rendered against the Borrower, any Subsidiary or any combination thereof and the same shall remain undischarged for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to attach or levy upon any assets of the Borrower or any Subsidiary to enforce any such judgment;

(l) any member of the ERISA Group shall fail to pay when due an amount which it shall have become liable to pay under Title IV of ERISA; or notice of intent to terminate a Plan shall be filed under Title IV of ERISA by any member of the ERISA Group, any plan administrator or any combination of the foregoing; or the PBGC shall institute proceedings under Title IV of ERISA to terminate, to impose liability (other than for premiums under Section 4007 of ERISA) in respect of, or to cause a trustee to be appointed to administer any Plan; or a condition shall exist by reason of which the PBGC would be entitled to obtain a decree adjudicating that any Plan must be terminated; or there shall occur a complete or partial withdrawal from, or a default, within the meaning of Section 4219(c)(5) of ERISA, with respect to, one or more Multiemployer Plans which could cause one or more members of the ERISA Group to incur a current payment obligation; and in each of the foregoing instances such condition could reasonably be expected to result in a Material Adverse Effect; or

(m) a Change in Control shall occur;

then, and in every such event (other than an event with respect to the Borrower described in clause (h) or (i) of this Article), and at any time thereafter during the continuance of such event, the Administrative Agent may, and at the request of the Required Lenders shall, by notice to the Borrower, take either or both of the following actions, at the same or different times: (i) terminate the Commitments, and thereupon the Commitments shall terminate immediately, and (ii) declare the Loans then outstanding to be due and payable in whole (or in part, in which case any principal not so declared to be due and payable may thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and all fees and other obligations of the Borrower accrued hereunder, shall become due and payable immediately, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower; and in case of any event with respect to the Borrower described in clause (h) or (i) of this Article, the Commitments shall automatically terminate and the principal of the Loans then outstanding, together with accrued interest thereon and all fees and other obligations of the Borrower accrued hereunder, shall automatically become due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower.

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ARTICLE VIII

The Administrative Agent

Each of the Lenders hereby irrevocably appoints the Administrative Agent as its agent and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof, together with such actions and powers as are reasonably incidental thereto.

The bank serving as the Administrative Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Administrative Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if it were not the Administrative Agent hereunder.

The Administrative Agent shall not have any duties or obligations except those expressly set forth herein. Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing, (b) the Administrative Agent shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby that the Administrative Agent is required to exercise in writing as directed by the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 9.02), and (c) except as expressly set forth herein, the Administrative Agent shall not have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Subsidiaries that is communicated to or obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity. The Administrative Agent shall not be liable for any action taken or not taken by it with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 9.02) or in the absence of its own gross negligence or willful misconduct. The Administrative Agent shall be deemed not to have knowledge of any Default unless and until written notice thereof is given to the Administrative Agent by the Borrower or a Lender, and the Administrative Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement, (ii) the contents of any certificate, report or other document delivered hereunder or in connection herewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Article IV or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent.

The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

The Administrative Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by the Administrative Agent. The Administrative

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Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties. The exculpatory provisions of the preceding paragraphs shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

Subject to the appointment and acceptance of a successor Administrative Agent as provided in this paragraph, the Administrative Agent may resign at any time by notifying the Lenders and the Borrower. Upon any such resignation, the Required Lenders shall have the right, in consultation with the Borrower, to appoint a successor. If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent which shall be a bank with an office in New York, New York, or an Affiliate of any such bank. Upon the acceptance of its appointment as Administrative Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the Administrative Agent's resignation hereunder, the provisions of this Article and Section 9.03 shall continue in effect for the benefit of such retiring Administrative Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while it was acting as Administrative Agent.

Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any related agreement or any document furnished hereunder or thereunder.

ARTICLE IX

Miscellaneous

SECTION 9.01 Notices. (a) Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to paragraph (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

(i) if to the Borrower, to it at One Allen Center, 500 Dallas, Suite 1000, Houston, Texas 77002, Attention of Park Shaper (Telecopy No. (713) 495-2782);

(ii) if to the Administrative Agent, to JPMorgan Chase Bank, Loan and Agency Services Group, One Chase Manhattan Plaza, 8th Floor, New York, New York 10081, Attention of Janet Belden (Telecopy No. (212) 552-5658), with a copy to JPMorgan Chase Bank, 270 Park Avenue, New York, New York 10017, Attention of Steve Wood (Telecopy No. (212) 270-3897);

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(iii) if to any other Lender, to it at its address (or telecopy number) set forth in its Administrative Questionnaire.

(b) Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to Article II unless otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(c) Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt.

SECTION 9.02 Waivers; Amendments. (a) No failure or delay by the Administrative Agent or any Lender in exercising any right or power hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Administrative Agent and the Lenders hereunder are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or consent to any departure by the Borrower therefrom shall in any event be effective unless the same shall be permitted by paragraph (b) of this Section, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. Without limiting the generality of the foregoing, the making of a Loan shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent or any Lender may have had notice or knowledge of such Default at the time.

(b) Neither this Agreement nor any provision hereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Required Lenders or by the Borrower and the Administrative Agent with the consent of the Required Lenders; provided that no such agreement shall (i) increase the Commitment of any Lender without the written consent of such Lender, (ii) reduce the principal amount of any Loan or reduce the rate of interest thereon, or reduce any fees payable hereunder, without the written consent of each Lender affected thereby, (iii) postpone the scheduled date of payment of the principal amount of any Loan, or any interest thereon, or any fees payable hereunder, or reduce the amount of, waive or excuse any such payment, or postpone the scheduled date of expiration of any Commitment, without the written consent of each Lender affected thereby, (iv) change Section 2.18(b) or (c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, or (v) change any of the provisions of this Section or the definition of "Required Lenders" or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or make any determination or grant any consent hereunder, without the written consent of each Lender; provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent hereunder without the prior written consent of the Administrative Agent.

SECTION 9.03 Expenses; Indemnity; Damage Waiver. (a) The Borrower shall pay (i) all reasonable out-of-pocket expenses incurred by the Administrative Agent and its Affiliates, including the reasonable fees, charges and disbursements of counsel for the Administrative Agent, in connection with the syndication of the credit facilities provided for herein, the preparation and administration of this

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Agreement or any amendments, modifications or waivers of the provisions hereof, and (ii) all out-of-pocket expenses incurred by the Administrative Agent or any Lender, including the fees, charges and disbursements of any counsel for the Administrative Agent or any Lender, in connection with the enforcement or protection of its rights in connection with this Agreement, including its rights under this Section, or in connection with the Loans made hereunder, including all such out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans.

(b) The Borrower shall indemnify the Administrative Agent and each Lender, and each Related Party of any of the foregoing Persons (each such Person being called an "Indemnitee") against, and hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related expenses, including the fees, charges and disbursements of any counsel for any Indemnitee, incurred by or asserted against any Indemnitee arising out of, in connection with, or as a result of (i) the execution or delivery of this Agreement or any agreement or instrument contemplated hereby, the performance by the parties hereto of their respective obligations hereunder or the consummation of the Transactions or any other transactions contemplated hereby, (ii) any Loan or the use of the proceeds therefrom, (iii) any actual or alleged presence or release of Hazardous Materials on or from any property owned or operated by the Borrower or any of its Subsidiaries, or any Environmental Liability related in any way to the Borrower or any of its Subsidiaries, or (iv) any actual or prospective claim, litigation, investigation or proceeding relating to any of the foregoing, whether based on contract, tort or any other theory and regardless of whether any Indemnitee is a party thereto; provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses are determined by a court of competent jurisdiction by final and nonappealable judgment to have resulted from the gross negligence or willful misconduct of such Indemnitee.

(c) To the extent that the Borrower fails to pay any amount required to be paid by it to the Administrative Agent under paragraph (a) or (b) of this Section, each Lender severally agrees to pay to the Administrative Agent such Lender's Applicable Percentage (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent in its capacity as such.

(d) To the extent permitted by applicable law, the Borrower shall not assert, and hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement or any agreement or instrument contemplated hereby, the Transactions, any Loan or the use of the proceeds thereof.

(e) All amounts due under this Section shall be payable not later than thirty days after written demand therefor.

SECTION 9.04 Successors and Assigns. (a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants (to the extent provided in paragraph (c) of this Section) and, to the extent expressly contemplated hereby, the Related Parties of

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each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b) (i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld) of:

               (A) the Borrower, provided that no consent of the Borrower shall be required for an assignment to a Lender, an Affiliate of a Lender, an Approved Fund or, if an Event of Default has occurred and is continuing, any other assignee; and

               (B) the Administrative Agent, provided that no consent of the Administrative Agent shall be required for an assignment of any Commitment to an assignee that is a Lender with a Commitment immediately prior to giving effect to such assignment.

        (ii) Assignments shall be subject to the following additional conditions:

               (A) except in the case of an assignment to a Lender or an Affiliate of a Lender or an assignment of the entire remaining amount of the assigning Lender's Commitment or Loans, the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $5,000,000 unless each of the Borrower and the Administrative Agent otherwise consent, provided that no such consent of the Borrower shall be required if an Event of Default under clause (a), (b), (h) or (i) of Article VII has occurred and is continuing;

               (B) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender's rights and obligations under this Agreement;

               (C) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500; and

               (D) the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

For the purposes of this Section 9.04(b), the term "Approved Fund" has the following meaning:

"Approved Fund" means any Person (other than a natural person) that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course of its business and that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

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          (iii)         Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) of this Section, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender's rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.15, 2.16, 2.17 and 9.03). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 9.04 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (c) of this Section.

          (iv)        The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitment of, and principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the "Register"). The entries in the Register shall be conclusive, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

          (v)         Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an assignee, the assignee's completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) of this Section and any written consent to such assignment required by paragraph (b) of this Section, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.

(c) (i) Any Lender may, without the consent of the Borrower or the Administrative Agent, sell participations to one or more banks or other entities (a "Participant") in all or a portion of such Lender's rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it); provided that (A) such Lender's obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the first proviso to Section 9.02(b) that affects such Participant. Subject to paragraph (c)(ii) of this Section, the Borrower agrees that each

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Participant shall be entitled to the benefits of Sections 2.15, 2.16 and 2.17 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 9.08 as though it were a Lender, provided such Participant agrees to be subject to Section 2.18(c) as though it were a Lender.

(i) A Participant shall not be entitled to receive any greater payment under Section 2.15 or 2.17 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower's prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.17 unless the Borrower is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrower, to comply with Section 2.17(e) as though it were a Lender.

(d) Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including without limitation any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

SECTION 9.05 Survival. All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Loans, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid and so long as the Commitments have not expired or terminated. The provisions of Sections 2.15, 2.16, 2.17 and 9.03 and Article VIII shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans and the Commitments or the termination of this Agreement or any provision hereof.

SECTION 9.06 Counterparts; Integration; Effectiveness. This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. This Agreement and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof. Except as provided in Section 4.01, this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Delivery of an executed counterpart of a signature page of this Agreement by telecopy shall be effective as delivery of a manually executed counterpart of this Agreement.

SECTION 9.07 Severability. Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such

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invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

SECTION 9.08 Right of Setoff. If an Event of Default shall have occurred and be continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations at any time owing by such Lender or Affiliate to or for the credit or the account of the Borrower against any of and all the obligations of the Borrower now or hereafter existing under this Agreement held by such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement and although such obligations may be unmatured. The rights of each Lender under this Section are in addition to other rights and remedies (including other rights of setoff) which such Lender may have.

SECTION 9.09 Governing Law; Jurisdiction; Consent to Service of Process. (a) This Agreement shall be construed in accordance with and governed by the law of the State of New York.

(b) The Borrower hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the Supreme Court of the State of New York sitting in New York County and of the United States District Court of the Southern District of New York, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State or, to the extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that the Administrative Agent or any Lender may otherwise have to bring any action or proceeding relating to this Agreement against the Borrower or its properties in the courts of any jurisdiction.

(c) The Borrower hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement in any court referred to in paragraph (b) of this Section. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

(d) Each party to this Agreement irrevocably consents to service of process in the manner provided for notices in Section 9.01. Nothing in this Agreement will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

SECTION 9.10 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE

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BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

SECTION 9.11 Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

SECTION 9.12 Confidentiality. Each of the Administrative Agent and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates' directors, officers, employees and agents, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority, (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (d) to any other party to this Agreement, (e) in connection with the exercise of any remedies hereunder or any suit, action or proceeding relating to this Agreement or the enforcement of rights hereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any swap or derivative transaction relating to the Borrower and its obligations, (g) with the consent of the Borrower or (h) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section or (ii) becomes available to the Administrative Agent or any Lender on a nonconfidential basis from a source other than the Borrower. For the purposes of this Section, "Information" means all information received from the Borrower relating to the Borrower or its business, other than any such information that is available to the Administrative Agent or any Lender on a nonconfidential basis prior to disclosure by the Borrower; provided that, in the case of information received from the Borrower after the date hereof, such information is clearly identified at the time of delivery as confidential. Any Person required to maintain the confidentiality of Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information.

SECTION 9.13 Interest Rate Limitation. Notwithstanding anything herein to the contrary, if at any time the interest rate applicable to any Loan, together with all fees, charges and other amounts which are treated as interest on such Loan under applicable law (collectively the "Charges"), shall exceed the maximum lawful rate (the "Maximum Rate") which may be contracted for, charged, taken, received or reserved by the Lender holding such Loan in accordance with applicable law, the rate of interest payable in respect of such Loan hereunder, together with all Charges payable in respect thereof, shall be limited to the Maximum Rate and, to the extent lawful, the interest and Charges that would have been payable in respect of such Loan but were not payable as a result of the operation of this Section shall be cumulated and the interest and Charges payable to such Lender in respect of other Loans or periods shall be increased (but not above the Maximum Rate therefor) until such cumulated amount, together with interest thereon at the Federal Funds Effective Rate to the date of repayment, shall have been received by such Lender.

SECTION 9.14 Existing Credit Facility. The undersigned agree and acknowledge that, except for provisions that expressly provide for their survival of termination, the Existing Credit Facility shall be terminated on the Effective Date and all Commitments thereunder (as defined in the Existing Credit Facility) shall be terminated on the Effective Date, and the undersigned waive any right to receive any notice of such termination. Notice of termination given to any other Bank (as defined in the Existing Credit Facility) on the Effective Date shall constitute effective termination of the Existing Credit Facility

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with respect to such Bank. Each Lender that was a party to the Existing Credit Facility agrees to return to the Borrower, with reasonable promptness, all Notes (as defined in the Existing Credit Facility) delivered by the Borrower to such Lender under the Existing Credit Facility.

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

	KINDER MORGAN, INC.


	By:	/s/ C. Park Shaper
	Name:	C. Park Shaper
	Title:	Vice President, Chief Financial Officer and Treasurer

	JPMORGAN CHASE BANK, individually and as Administrative Agent,


	By:	/s/ Steven Wood
	Name:	Steven Wood
	Title:	Vice President

	WACHOVIA BANK, NATIONAL ASSOCIATION, individually and as Syndication Agent,



	By:	/s/ Russell Clingman
	Name:	Russell Clingman
	Title:	Director

	CITIBANK, N.A.


	By:	/s/ Michael W. Nepveux
	Name:	Michael W. Nepveux
	Title:	Attorney-in-Fact

	THE BANK OF NOVA SCOTIA


	By:	/s/ M. D. Smith
	Name:	M. D. Smith
	Title:	Agent

	THE BANK OF TOKYO-MITSUBISHI, LTD


	By:	/s/ Kelton Glasscock
	Name:	Kelton Glasscock
	Title:	Vice President & Manager

	Bank One, N.A. (Main Office – Chicago)


	By:	/s/ Jeanie Gonzalez
	Name:	Jeanie Gonzalez
	Title:	Director

	BARCLAYS BANK PLC


	By:	/s/ Nicholas A. Bell
	Name:	Nicholas A. Bell
	Title:	Director

	BMO Nesbitt Burns Financing, Inc.


	By:	/s/ Thomas H. Peer
	Name:	Thomas H. Peer
	Title:	Vice President

	Commerzbank AG, New York and Grand Cayman Branches


	By:	/s/ Harry Yergey
	Name:	Harry Yergey
	Title:	Senior Vice President


	By:	/s/ David Suttles
	Name:	David Suttles
	Title:	Vice President

	CREDIT LYONNAIS NEW YORK BRANCH


	By:	/s/ Olivier Audemard
	Name:	Olivier Audemard
	Title:	Senior Vice President

	Royal Bank of Canada


	By:	/s/ Lorne Gartner
	Name:	Lorne Gartner
	Title:	Vice President

	The Royal Bank of Scotland plc.


	By:	/s/ Keith Johnson
	Name:	Keith Johnson
	Title:	Senior Vice President

	SUNTRUST BANK


	By:	/s/ Joseph M. McCreery
	Name:	Joseph M. McCreery
	Title:	Vice President

	WELLS FARGO BANK TEXAS, N.A.


	By:	/s/ Paul A. Squires
	Name:	Paul A. Squires
	Title:	Vice President

SCHEDULE 1.01

PRICING SCHEDULE

The "ABR Spread", "Eurodollar Spread", "Facility Fee Rate" or "Utilization Fee Rate", as the case may be, for any fiscal quarter are the applicable rates per annum (expressed in bps) set forth below in the applicable row and column corresponding to the ratings that exist on the last day of the immediately preceding fiscal quarter:

Index Debt Ratings:	ABR Spread	Eurodollar Spread	Facility Fee Rate	All-in Spread (<or= 50% Utilization)	Utilization Fee Rate (> 50% Utilization)	All-in Spread (> 50% Utilization)
Category 1 >or= Baa1/BBB+	0.00 bps	52.5 bps	10.0 bps	62.5 bps	12.5 bps	75.0 bps
Category 2 Baa2/BBB	0.00 bps	62.5 bps	12.5 bps	75.0 bps	12.5 bps	87.5 bps
Category 3 Baa3/BBB-	0.00 bps	70.0 bps	17.5 bps	87.5 bps	12.5 bps	100.0 bps
Category 4 Ba1/BB+	12.5 bps	100.0 bps	25.0 bps	125.0 bps	25.0 bps	150.0 bps
Category 5 <Ba1/BB+	50.0 bps	140.0 bps	35.0 bps	175.0 bps	25.0 bps	200.0 bps

In the event Revolving Loans are converted to Term Loans pursuant to Section 2.21, the ABR Spread and the Eurodollar Spread shall automatically increase by 0.25%.

For purposes of the foregoing, (i) if either Moody's or S&P shall not have in effect a rating for the Index Debt (other than by reason of the circumstances referred to in the last sentence of this definition), then such rating agency shall be deemed to have established a rating in Category 5; (ii) if the ratings established or deemed to have been established by Moody's and S&P for the Index Debt shall fall within different Categories, the Applicable Rate shall be based on the higher of the two ratings unless one of the two ratings is two or more Categories lower than the other, in which case the Applicable Rate shall be determined by reference to the Category next above that of the lower of the two ratings; and (iii) if the ratings established or deemed to have been established by Moody's and S&P for the Index Debt shall be changed (other than as a result of a change in the rating system of Moody's or S&P), such change shall be effective as of the date on which it is first announced by the applicable rating agency, irrespective of when notice of such change shall have been furnished by the Borrower to the Administrative Agent and the Lenders pursuant to Section 5.01 or otherwise. Each change in the Applicable Rate shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change. If the rating system of Moody's or S&P shall change, or if either such rating agency shall cease to be in the business of rating corporate debt obligations, the Borrower and the Lenders shall negotiate in good faith to amend this definition to reflect such changed rating system or the unavailability of ratings from such rating agency and, pending the effectiveness of any such amendment, the Applicable Rate shall be determined by reference to the rating most recently in effect prior to such change or cessation.

Schedule 1.01-1

SCHEDULE 2.01

COMMITMENTS

Lender	Commitment
JPMorgan Chase Bank	$50,000,000
Wachovia Bank, National Association	$50,000,000
Citicorp North America, Inc.	$50,000,000
Commerzbank AG, New York and Grand Cayman Branches	$31,000,000
The Bank of Tokyo-Mitsubishi, Ltd.	$27,777,778
Royal Bank of Canada	$25,000,000
SunTrust Bank	$25,000,000
Bank One, N.A.	$25,000,000
Credit Lyonnais New York Branch	$25,000,000
The Royal Bank of Scotland plc	$25,000,000
BMO Nesbitt Burns Financing, Inc.	$25,000,000
Barclays Bank plc	$25,000,000
The Bank of Nova Scotia	$25,000,000
Wells Fargo Bank Texas, N.A.	$12,500,000

Schedule 2.01-1

EX-4.6 4 kmiex46.htm KMI MODIFICATION OF 364-DAY CREDIT AGREEMENT Kinder Morgan, Inc. 364-Day Modification of Credit Agreement

Exhibit 4.6

Modification of

Credit Agreement Commitment

Effective as of December 13, 2002

among

Kinder Morgan, Inc.,

Wachovia Bank, National Association

and

JPMorgan Chase Bank
as Administrative Agent

MODIFICATION OF
CREDIT AGREEMENT COMMITMENT

THIS MODIFICATION OF CREDIT AGREEMENT COMMITMENT (this "Modification") is made and entered into effective as of the 13^th day of December, 2002 (the "Modification Effective Date", among KINDER MORGAN, INC., a Kansas corporation (the "Company"), WACHOVIA BANK, NATIONAL ASSOCIATION, in its capacity as a Lender (as defined below) ("Wachovia"), and JPMORGAN CHASE BANK, as administrative agent (the "Administrative Agent") for each of the lenders (the "Lenders") that is a signatory or which becomes a signatory to the hereinafter defined Credit Agreement.

R E C I T A L S:

A. On October 15, 2002, the Company, the Lenders, Wachovia Bank, National Association, as syndication agent, Citibank, N.A. and Commerzbank AG, New York and Grand Cayman Branches, as documentation agents, and the Administrative Agent entered into a 364-Day Credit Agreement (the "Credit Agreement") whereby, upon the terms and conditions therein stated, the Lenders agreed to make certain Loans (as defined in the Credit Agreement) to the Company and extend certain other credit to the Company.

B. Pursuant to Section 2.01 of the Credit Agreement, the Company has the right, with the consent of the Administrative Agent, to increase the total Commitments of the Lenders by adding to the Credit Agreement one or more additional Lenders or by allowing one or more Lenders to increase its Commitment; provided (1) no Default or Event of Default shall then exist, (2) no such increase shall cause (a) the aggregate Commitments under the Credit Agreement to exceed $500,000,000 or (b) the sum of the aggregate Commitments under the Credit Agreement plus the aggregate commitments under the Three-Year Facility to exceed $900,000,000, and (3) no Lender’s Commitment shall be increased without such Lender’s consent.

C. Wachovia has agreed with the Company to increase its Commitment from $50,000,000 to $58,722,222 and the Administrative Agent has consented to such increase.

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained, the Company, Wachovia and the Administrative Agent hereby agree as follows:

1. Certain Definitions.

1.1 Terms Defined Above. As used in this Modification, the terms "Administrative Agent", "Company", "Credit Agreement", "Lender", "Modification", "Modification Effective Date", and "Wachovia" shall have the meanings indicated above.

1.2 Terms Defined in Agreement. Unless otherwise defined herein, all capitalized terms which are defined in the Credit Agreement shall have the same meanings herein as therein unless the context hereof otherwise requires.

2. Modification of Wachovia’s Commitment. On the Modification Effective Date, Wachovia’s Commitment shall be $58,722,222.

3. Conditions Precedent. The increase of Wachovia’s Commitment shall be conditioned upon the receipt by the Administrative Agent of (a) a counterpart of this Modification, duly completed and executed by the Company and Wachovia and (b) fees agreed to be paid by the Company to Wachovia.

4. Representations and Warranties. The Company represents and warrants that:

(a) there exists no Default or Event of Default; and

(b) after giving effect to this Modification, (i) the aggregate Commitments of the Lenders is $430,000,000, and (ii) the sum of the aggregate Commitments hereunder plus the aggregate commitments under the Three-Year Facility does not exceed $900,000,000.

5. Extent of Modification: Ratification. Except as expressly modified herein, all of the terms, conditions, defined terms, covenants, representations, warranties and all other provisions of the Credit Agreement and the other documents furnished in connection therewith are herein ratified and confirmed and shall remain in full force and effect.

6. Counterparts. This Modification may be executed in two or more counterparts, and it shall not be necessary that the signatures of all parties hereto be contained on any one counterpart hereof; each counterpart shall be deemed an original, but all of which together shall constitute one and same instrument.

7. References. On and after the Modification Effective Date, the term "Commitment" when used in the Credit Agreement with respect to Wachovia shall refer to the Commitment of Wachovia, as modified hereby.

THIS MODIFICATION, THE CREDIT AGREEMENT, AS MODIFIED HEREBY, THE NOTES AND ANY SEPARATE LETTER AGREEMENTS WITH RESPECT TO FEES PAYABLE TO THE ADMINISTRATIVE AGENT REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

This Modification shall benefit and bind the parties hereto, as well as their respective assigns, successors, and legal representatives.


EXECUTED as of the Modification Effective Date.

	KINDER MORGAN, INC.

	By:	/s/ JOSEPH LISTENGART
	Name:	Joseph Listengart
	Title:	Vice President


		JPMORGAN CHASE BANK
		as Administrative Agent

		By:	/s/ MICHAEL J. DEFORGE
		Name:	Michael J. Deforge
		Title:	Vice President


		WACHOVIA BANK, NATIONAL
		ASSOCIATION, as a Lender

		By:	/s/ RUSSELL T. CLINGMAN
		Name:	Russell T. Clingman
		Title:	Director

EX-4.7 5 kmiex47.htm KMI REGISTRATION RIGHTS AGREEMENT Kinder Morgan, Inc. Exhibit 4.7 Registration Rights Agreement
EXHIBIT 4.7

REGISTRATION RIGHTS AGREEMENT

This REGISTRATION RIGHTS AGREEMENT (this "Agreement"), dated as of May 18, 2001, is by and between Kinder Morgan Management, LLC, a Delaware limited liability company (the "Issuer"), Kinder Morgan Energy Partners, L.P., a Delaware limited partnership (the "Partnership"), and Kinder Morgan, Inc., a Kansas corporation (the "Holder").

W I T N E S S E T H:

WHEREAS, the Holder purchased 1,487,500 shares representing limited liability company interests of the Issuer and identified in the LLC Agreement (as hereinafter defined) as listed shares ("Listed Shares") in an offering by the Issuer pursuant to a registration statement on Form S-1 (Registration No. 333-55868) under the Securities Act of 1933, as amended (the "Securities Act"), filed with the Securities and Exchange Commission (the "Commission"); and

WHEREAS, the Exchange Provisions (the "Exchange Provisions") attached as Annex A to, and made a part of, the Issuer's Amended and Restated Limited Liability Company Agreement, dated as of May 14, 2001 (including the Exchange Provisions and the Purchase Provisions (as hereinafter defined), the "LLC Agreement"), provide that holders of Listed Shares may exchange Listed Shares with the Holder for common units ("Common Units") of the Partnership, subject to the right of the Holder to settle the exchange in cash rather than in Common Units (such provisions of the LLC Agreement being collectively referred to as the "Exchange Feature"); and

WHEREAS, the Holder has the right and, in certain cases, the obligation to purchase all outstanding Listed Shares pursuant to the Purchase Provisions (the "Purchase Provisions") attached as Annex B to, and made a part of, the LLC Agreement; and

WHEREAS, the Issuer may effect in the future one or more public offerings of Listed Shares (the "Offerings"); and

WHEREAS, the parties believe it appropriate for the resale by the Holder of any Listed Shares it holds to be registered under the Securities Act, and the Issuer is agreeable to preparing, filing and maintaining the effectiveness of registration statements therefor as provided herein; and

WHEREAS, such resale by the Holder may be deemed to involve the offer and sale of Common Units, and the Partnership is agreeable to preparing, filing and maintaining the effectiveness of registration statements therefor as provided herein.

NOW THEREFORE, in consideration of the premises and mutual covenants hereinafter set forth and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

Section 1

Definitions

1.1 Specific Definitions. Unless the context clearly requires otherwise, the following terms shall have the meanings set forth below:

"Agreement" has the meaning set forth in the preamble of this Agreement.

"Commission" has the meaning set forth in the recitals of this Agreement.

"Common Units" has the meaning set forth in the recitals of this Agreement.

"Confidential Information" means information that the Issuer or the Partnership, as the case may be, determines, in good faith, is confidential, other than information which (i) is or becomes generally available to the public other than as a result of a disclosure by the Holder or an Inspector to which it was provided, (ii) was within the possession of the Holder or an Inspector prior to its being furnished to the Holder or an Inspector by or on behalf of the Issuer pursuant hereto, provided that the source of such information was not known by the Holder or such Inspector to be bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to the Issuer or any other party with respect to such information or (iii) becomes available to the Holder or an Inspector on a non-confidential basis from a source other than the Issuer, provided that such source is not bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to the Issuer or any other party with respect to such information.

"Entity" means a corporation, limited liability company, venture, partnership, trust, unincorporated organization, association or other entity.

"Exchange Act" means the Securities Exchange Act of 1934, as amended.

"Exchange Feature" has the meaning set forth in the recitals of this Agreement.

"Exchange Provisions" has the meaning set forth in the recitals of this Agreement.

"Holder" has the meaning set forth in the preamble of this Agreement.

"Inspectors" has the meaning set forth in Section 2.2(i).

"Issuer" has the meaning set forth in the preamble of this Agreement.

"Listed Shares" has the meaning set forth in the recitals of this Agreement.

"LLC Agreement" has the meaning set forth in the recitals of this Agreement.

"Offerings" has the meaning set forth in the recitals of this Agreement.

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"Partnership" has the meaning set forth in the preamble of this Agreement.

"Person" means a natural person or an Entity.

"Records" has the meaning set forth in Section 2.2(i).

"Registration Expenses" has the meaning set forth in Section 3.1.

"Registration Request" has the meaning set forth in Section 2.1.

"Resale Registration Statement" has the meaning set forth in Section 2.2(a)(ii).

"Section" means a section of this Agreement.

"Securities Act" has the meaning set forth in the recitals of this Agreement.

1.2 Rules of Construction. Unless the context otherwise clearly requires:

(a) terms defined include the plural as well as the singular and vice versa;

(b) references to any document, agreement, instrument or provision thereof mean such document, agreement, instrument or provision thereof as the same may be duly amended, supplemented or restated from time to time;

(d) "or" is not exclusive; and

(e) the words "herein," "hereof," "hereunder" and other words of similar import refer to this Agreement as a whole and not to any particular Section or other subdivision.

Section 2

Registration Rights

2.1 Request for Resale Registration. At any time the Holder may submit to the Issuer one or more written requests (each, a "Registration Request") that the Issuer file a registration statement under the Securities Act registering the resale of the number of Listed Shares specified in such Registration Request, whereupon the Issuer shall proceed in accordance with Section 2.2.

2.2 Provisions Relating to Registration Statements. The Issuer agrees that after a Registration Request is submitted it will:

(a) prepare and file with the Commission as soon as practicable, but in no event later than 45 days after the Registration Request is submitted, except as provided in Section 2.4:

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	(i) if the Issuer is not eligible to file a registration statement on Form S-3 under the Securities Act, a registration statement on Form S-1 under the Securities Act registering the resale of the number of Listed Shares specified in such Registration Request; provided, however, that the parties agree that the Issuer shall not be obligated under this Agreement to file more than two registration statements on Form S-1 under the Securities Act; and

	(ii) if the Issuer is eligible to file a registration statement on Form S-3 under the Securities Act, a registration statement on Form S-3 under the Securities Act registering the resale of the number of Listed Shares specified in such Registration Request (each registration statement described in subsection (i), above, and this subsection (ii) being referred to hereinafter as a "Resale Registration Statement");

(b) use its reasonable efforts to cause any Resale Registration Statement to become effective, including to file any amendment or supplement to the Resale Registration Statement or any prospectus or other offering document used in connection therewith to the extent necessary in order to cause such Resale Registration Statement to become effective;

(c) for so long as any Listed Shares owned by the Holder and covered by a Resale Registration Statement remain unsold, amend or supplement such Resale Registration Statement or prospectus or other offering document used in connection therewith to the extent necessary in order to keep effective and maintain any registration, qualification or approval obtained in connection with the resale of any Listed Shares;

(d) furnish to the Holder such number of copies as the Holder may reasonably request of each Resale Registration Statement, each amendment and supplement thereto (in each case including all exhibits thereto and documents incorporated by reference therein) and the prospectus included in or used in connection with each Resale Registration Statement (including each preliminary prospectus, final prospectus and prospectus supplement);

(e) promptly notify the Holder of any stop order issued or, to the knowledge of the Issuer, threatened to be issued by the Commission with respect to such Resale Registration Statement and promptly take all reasonable actions to prevent the entry of such stop order or to obtain its withdrawal if entered;

(f) use its reasonable efforts to qualify the Listed Shares for resale under the securities, "blue sky" or similar laws of such jurisdictions (including any foreign country or any political subdivision thereof) as the Holder shall reasonably request and use its reasonable efforts to obtain all appropriate registrations, permits and consents required in connection therewith, except that the Issuer shall not for any such purpose be required to qualify generally to do business as a foreign corporation in any jurisdiction wherein it is not so qualified, or subject itself to taxation or file a general consent to service of process in any such jurisdiction;

(g) promptly inform the Holder (i) of the date on which such Resale Registration Statement or any post-effective amendment thereto becomes effective and, if applicable, of the date of filing a Rule 430A prospectus (and, in the case of any offering abroad

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of Listed Shares, of the date when any required filing under the securities and other laws of such foreign jurisdictions shall have been made and when the offering may be commenced in accordance with such laws) and (ii) of any request by the Commission, any securities exchange, government agency, self-regulatory body or other body having jurisdiction for any amendment of or supplement to such Resale Registration Statement or preliminary prospectus or prospectus included therein or used in connection therewith or any other offering document relating to such offering;

(h) as promptly as practicable notify the Holder of the occurrence of an event requiring the preparation of a supplement or amendment to the prospectus related to such Resale Registration Statement so that such prospectus will not contain an untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, and, notwithstanding Section 2.4, as promptly as practicable make available to the Holder any such supplement or amendment;

(i) with reasonable promptness make available for inspection by the Holder, and any attorney, accountant or other agent retained by the Holder, and any underwriter or prospective underwriter of the Holder and any attorney or agent of any such underwriter (collectively, the "Inspectors"), all financial and other records, pertinent corporate documents and properties of the Issuer (collectively, the "Records") as shall be reasonably necessary to enable them to exercise their due diligence responsibility, and cause the Issuer's officers and employees to supply all information reasonably requested for such purpose by any such Inspector in connection with any Resale Registration Statement; provided, however, that the selection of any Inspector other than an officer or employee of, or attorney or accountant for, the Holder or any such underwriter shall be subject to the consent of the Issuer, which shall not be unreasonably withheld. Each Inspector that actually reviews Records supplied by the Issuer that include Confidential Information may be required by the Issuer, prior to any such review, to execute an agreement with the Issuer in customary form reasonably satisfactory to the Issuer providing that such Inspector shall not publicly disclose any Confidential Information unless such disclosure is required by applicable law or legal process. The Holder agrees that Confidential Information obtained by it as a result of such inspections shall not be used by it as the basis for any transactions in securities of the Issuer unless and until such information is made generally available to the public. The Holder further agrees that it will, upon learning that disclosure of Confidential Information supplied to the Holder or an Inspector is sought in a court of competent jurisdiction from the Holder or an Inspector, give notice to the Issuer and allow the Issuer, at its expense, to undertake appropriate action to prevent disclosure of the Confidential Information. The Holder also agrees that the due diligence investigation made by the Inspectors shall be conducted in a manner that shall not unreasonably disrupt the operations of the Issuer or the work performed by the Issuer's officers and employees; and

(j) if the plan of distribution proposed by the Holder involves an underwritten offering, enter into an underwriting agreement in customary form with the underwriter or underwriters selected for such offering by the Holder.

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2.3 Documents to be Furnished to the Holder. The Issuer shall furnish (a) at least two business days prior to filing with the Commission, any Resale Registration Statement, any amendment or supplement to any Resale Registration Statement, any prospectus used in connection therewith and any amendment or supplement to any such prospectus, which documents will be subject to the reasonable review of the Holder, and Issuer shall not file any such documents with the Commission to which the Holder shall reasonably object until the Holder and the Issuer have in good faith resolved any of the Holder's objections; and (b) a copy of any and all transmittal letters or other correspondence with the Commission or any other governmental agency or self-regulatory body or other body having jurisdiction (including any domestic or foreign securities exchange) relating to the resale of the Listed Shares.

2.4 Certain Notices by Issuer.

(a) Upon notice to the Holder, the Issuer may delay the filing of a Resale Registration Statement otherwise required pursuant to Section 2.2 or require the Holder to suspend the use of the prospectus or any prospectus supplement related to a Resale Registration Statement, in each case for a reasonable period of time, not to exceed 90 consecutive days or 120 days in any 12-month period, if (i) the Issuer would be required to disclose information regarding the Issuer it was not otherwise then required by law to disclose publicly where such disclosure would reasonably be expected to adversely affect any material business transaction or negotiation in which the Issuer is then engaged or (ii) the Issuer is in registration with respect to an underwritten public offering of its securities and the managing underwriter for such public offering determines in good faith that the filing of a Resale Registration Statement would be materially adverse to such public offering. Any periods under this Section 2.4(a) shall be aggregated with periods under Section 2.4(b) in determining whether the periods of 90 consecutive days or 120 days in any 12-month period have been exceeded.

(b) The Holder agrees that, upon receipt of any notice from the Issuer of the happening of any event of the kind described in Section 2.2(h) hereof, the Holder will forthwith discontinue disposition of Listed Shares pursuant to any Resale Registration Statement until the Holder's receipt of the copies of the supplemented or amended prospectus contemplated by Section 2.2(h), and, if so directed by the Issuer, the Holder will deliver to the Issuer (at the Issuer's expense) all copies, other than permanent file copies, then in the Holder's possession, of the prospectus covering such Listed Shares current at the time of receipt of such notice. The Holder also agrees to notify the Issuer if any event relating to the Holder occurs that would require the preparation of a supplement or amendment to the prospectus so that such prospectus will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading.

2.5 Registration by the Partnership. With respect to any Resale Registration Statement, the resale of Listed Shares by the Holder may be deemed to involve the offer and sale of Common Units, and the Partnership is agreeable to registering such offer and sale as provided herein. Therefore the Partnership agrees that with respect to any Registration Request delivered to both the Issuer and the Partnership, the Partnership will, mutatis mutandis, be bound by, and take the actions provided in, Section 2 as though it were the Issuer. Any registration statement to

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be prepared or filed by the Partnership pursuant to this Section 2.3 shall also be a "Resale Registration Statement" for purposes of this Agreement.

2.6 Joint Registration Statement. In connection with any Resale Registration Statement, the Issuer and the Partnership understand that the resale of Listed Shares by the Holder may require registration by the Holder of the Exchange Feature and of the purchase obligations provided in the Purchase Provisions. The parties agree that any Resale Registration Statement may be a joint registration statement of the Issuer, the Partnership and the Holder with respect to their respective securities.

Section 3

Expenses

3.1 Registration Expenses. The Partnership agrees to bear and to pay or cause to be paid promptly upon request being made therefor all third party expenses incident to the Partnership's and the Issuer's performance of or compliance with this Agreement, including (a) all Commission and any NASD registration and filing fees and expenses; (b) all fees and expenses in connection with the qualification of the securities being registered for offering and sale under the state or foreign securities and blue sky laws referred to in Section 2.2(f), including reasonable fees and disbursements of counsel, in connection with such qualifications; (c) all expenses relating to the preparation, printing, distribution and reproduction of any Resale Registration Statement required to be filed hereunder, each prospectus included therein or prepared for distribution pursuant hereto, each amendment or supplement to the foregoing, the certificates representing Listed Shares and all other documents relating hereto; (d) fees, disbursements and expenses of counsel and independent certified public accountants of the Partnership or the Issuer (including the expenses of any opinions or "cold comfort" letters required by or incident to such performance and compliance); (e) fees and expenses of listing the securities being registered on all exchanges where such securities are listed; and (f) reasonable fees, disbursements and expenses of one counsel for the Holder retained in connection with any Resale Registration Statement and fees, expenses and disbursements of any other Persons, including special experts, retained by the Issuer in connection with such registration (collectively, the "Registration Expenses"). The Partnership and the Issuer shall each bear their own internal expenses, including all salaries and expenses of their officers and employees performing legal or accounting duties, subject to any other reimbursement arrangements between them. To the extent that any Registration Expenses are incurred, assumed or paid by the Holder, the Partnership shall reimburse the Holder for the full amount of the Registration Expenses so incurred, assumed or paid promptly after receipt of a documented request therefor. Notwithstanding the foregoing, the Holder shall pay all the fees and disbursements of any counsel or other advisors or experts retained by the Holder, other than the counsel and experts specifically referred to above, and any underwriting fees, discounts or commissions.

Section 4

Representations and Warranties

4.1 Representations and Warranties. The Issuer and the Partnership each represents and warrants to, and agrees with, the Holder that:

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(a) Each Resale Registration Statement and any further amendment or supplement to any Resale Registration Statement, when it becomes effective or is filed with the Commission, as the case may be, will conform in all material respects to the applicable requirements of the Securities Act and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading; and at all times at and subsequent to the time when such Resale Registration Statement has been declared effective under the Securities Act, other than from (i) such time as a notice has been given to the Holder pursuant to Section 2.2(h) until (ii) such time as the Issuer or the Partnership, as the case may be, furnishes an amended or supplemented prospectus pursuant to Section 2.2(h) or such time as the Issuer or the Partnership, as the case may be, provides notice that offers and sales pursuant to such Resale Registration Statement may continue, each prospectus (including any preliminary or summary prospectus) contained in or prepared in connection with any Resale Registration Statement, and each prospectus (including any summary prospectus) furnished pursuant to Section 2.2(d), as then amended or supplemented, will conform in all material respects to the applicable requirements of the Securities Act and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided, however, that this representation and warranty shall not apply to any statements or omissions made in reliance upon and in conformity with information furnished in writing to the Issuer or the Partnership, as the case may be, by or on behalf of the Holder expressly for use therein in any such Resale Registration Statement or prospectus.

(b) Any documents of the Issuer or the Partnership, as the case may be, incorporated by reference in any prospectus referred to in this Agreement, when they become or became effective or are or were filed with the Commission, as the case may be, will conform or conformed in all material respects to the requirements of the Securities Act or the Exchange Act, as applicable, and none of such documents will contain or contained an untrue statement of a material fact or will omit or omitted to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided, however, that this representation and warranty shall not apply to any statements or omissions made in reliance upon and in conformity with information furnished in writing to the Issuer or the Partnership, as the case may be, by the Holder expressly for use therein.

(c) The compliance by the Issuer or the Partnership, as the case may be, with all of the provisions of this Agreement and the consummation of the transactions herein contemplated will not contravene any provision of applicable law or the LLC Agreement or the agreement of limited partnership of the Partnership, or any order, rule, regulation or decree of any court or governmental agency or authority located in the United States having jurisdiction over the Issuer or the Partnership, as the case may be, or any of its subsidiaries or any property of the Issuer or the Partnership, as the case may be, or any of its subsidiaries; and no consent, authorization or order of, or filing or registration with, any court or governmental agency or authority is required for the consummation by the Issuer or the Partnership, as the case may be, of the transactions contemplated by this Agreement, except the registration under the Securities

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Act contemplated hereby, and such consents, approvals, authorizations, registrations or qualifications as may be required under state or foreign securities or blue sky laws.

(d) This Agreement has been duly authorized, executed and delivered by the Issuer or the Partnership, as the case may be.

Section 5

Indemnification and Contributions

5.1 (a) The Issuer and the Partnership, jointly and severally, will indemnify and hold harmless the Holder against any losses, claims, damages or liabilities, joint or several, to which the Holder may become subject, under the Securities Act or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon an untrue statement or alleged untrue statement of a material fact contained in any preliminary prospectus, any Resale Registration Statement or any prospectus, or any amendment or supplement thereto, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, and will reimburse the Holder for any legal or other expenses reasonably incurred by the Holder in connection with investigating or defending any such action or claim as such expenses are incurred; provided, however, that the Issuer and the Partnership shall not be liable in any such case to the extent that any such loss, claim, damage or liability arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission made in any preliminary prospectus, any Resale Registration Statement or any prospectus or any such amendment or supplement in reliance upon and in conformity with written information furnished to the Issuer or the Partnership by the Holder expressly for use therein.

(b) The Holder will indemnify and hold harmless the Issuer and the Partnership against any losses, claims, damages or liabilities, joint or several, to which the Issuer or the Partnership may become subject, under the Securities Act or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon an untrue statement or alleged untrue statement of a material fact contained in any preliminary prospectus, any Resale Registration Statement or any prospectus, or any amendment or supplement thereto, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, in each case to the extent, but only to the extent, that such untrue statement or alleged untrue statement or omission or alleged omission was made in any preliminary prospectus, any Resale Registration Statement or any prospectus or any such amendment or supplement in reliance upon and in conformity with written information furnished to the Issuer or the Partnership by the Holder expressly for use therein; and will reimburse the Issuer or the Partnership, as the case may be, for any legal or other expenses reasonably incurred by the Issuer or the Partnership, as the case may be, in connection with investigating or defending any such action or claim as such expenses are incurred.

(c) Promptly after receipt by a party indemnified under subsection (a) or (b) above of notice of the commencement of any action, such indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party under such subsection, notify the

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indemnifying party in writing of the commencement thereof; but the omission so to notify the indemnifying party shall not relieve it from any liability that it may have to any indemnified party otherwise than under such subsection and shall not relieve the indemnifying party from any liability that it may have to any indemnified party under this Agreement unless such failure to give notice actually prejudices the indemnifying party's ability to defend the claim. In case any such action shall be brought against any indemnified party and it shall notify the indemnifying party of the commencement thereof, the indemnifying party shall be entitled to participate therein and, to the extent that it shall wish, to assume the defense thereof, with counsel satisfactory to such indemnified party (who shall not, except with the consent of the indemnified party, be counsel to the indemnifying party), and, after notice from the indemnifying party to such indemnified party of its election so to assume the defense thereof, the indemnifying party shall not be liable to such indemnified party under such subsection for any legal expenses of other counsel or any other expenses, in each case subsequently incurred by such indemnified party, in connection with the defense thereof other than reasonable costs of investigation. No indemnifying party shall, without the written consent of the indemnified party, effect the settlement or compromise of, or consent to the entry of any judgment with respect to, any pending or threatened action or claim in respect of which indemnification or contribution may be sought hereunder (whether or not the indemnified party is an actual or potential party to such action or claim) unless such settlement, compromise or judgment (i) includes an unconditional release of the indemnified party from all liability arising out of such action or claim and (ii) does not include a statement as to or an admission of fault, culpability or a failure to act, by or on behalf of any indemnified party.

(d) If the indemnification provided for in this Section 5 is unavailable to or insufficient to hold harmless an indemnified party under subsection (a) or (b) above in respect of any losses, claims, damages or liabilities (or actions in respect thereof) referred to therein, then each indemnifying party shall contribute to the amount paid or payable by such indemnified party as a result of such losses, claims, damages or liabilities (or actions in respect thereof) in such proportion as is appropriate to reflect the relative benefits received by the Issuer and the Partnership, on one hand, and the Holder, on the other hand, from the transactions contemplated by this Agreement and the earlier issuances by the Issuer of Listed Shares and by the Partnership of i-units. If, however, the allocation provided by the immediately preceding sentence is not permitted by applicable law or if the indemnified party failed to give the notice required under subsection (c) above and such failure actually prejudiced the indemnifying party's ability to defend the claim, then each indemnifying party shall contribute to such amount paid or payable by such indemnified party in such proportion as is appropriate to reflect not only such relative benefits but also the relative fault of the Issuer and the Partnership, on one hand, and the Holder in connection with the statements or omissions that resulted in such losses, claims, damages or liabilities (or actions in respect thereof), as well as any other relevant equitable considerations. The relative benefits received by the Issuer and the Partnership, on the one hand, and the Holder, on the other, from the transactions contemplated by this Agreement and such earlier sales shall be deemed to be in the same proportion as the total net proceeds (before deducting expenses) received by the Issuer from all issuances and sales of Listed Shares and by the Partnership from all related issuances and sales of i-units to the Issuer bear to the difference between the sum of the total net proceeds (before deducting expenses) to the Holder from the sale pursuant to such Resale Registration Statement of Listed Shares less an amount per Listed Share so sold equal to

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the weighted average of the market value on the date of surrender of all Listed Shares surrendered to the Holder pursuant to the Exchange Feature and the cash purchase price paid by the Holder to the Issuer for any direct purchases of Listed Shares. The relative fault shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Issuer, the Partnership or the Holder and the parties' relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission. The Issuer, the Partnership and the Holder agree that it would not be just or equitable if contributions pursuant to this subsection (d) were determined by pro rata allocation or by any other method of allocation that does not take account of the equitable considerations referred to above in this subsection (d). The amount paid or payable by an indemnified party as a result of the losses, claims, damages or liabilities (or actions in respect thereof) referred to above in this subsection (d) shall be deemed to include any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any such action or claim. No Person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who was not guilty of such fraudulent misrepresentation.

(e) The obligations of the Issuer and the Partnership under this Section 5 shall be in addition to any liability that the Issuer or the Partnership may otherwise have and shall extend, upon the same terms and conditions, to each Person, if any, who controls the Holder within the meaning of the Securities Act; and the obligations of the Holder under this Section 5 shall be in addition to any liability that the Holder may otherwise have and shall extend, upon the same terms and conditions, to each officer and director of the Issuer, the general partner of the Partnership or its delegate (including any Person who, with his or her consent, is named in any Resale Registration Statement as about to become a director of the Issuer, the general partner of the Partnership or its delegate) and to each Person, if any, who controls the Issuer or the Partnership within the meaning of the Act. As between the Issuer and the Partnership only, any agreement that provides for a different allocation of any obligations arising pursuant to this Section 5 will be given effect; but no such agreement will change the obligations each may have to third parties under this Agreement.

Section 6

Miscellaneous

6.1 Provision of Information. The Holder shall complete and execute, and shall cause its directors, officers, employees and agents to complete and execute, all such questionnaires and other documents as the Issuer or the Partnership shall reasonably request in connection with any registration of the resale of Listed Shares pursuant to this Agreement.

6.2 Injunctions. Irreparable damage would occur in the event that any of the provisions of this Agreement were not performed in accordance with their specified terms or were otherwise breached. Therefore, the parties hereto shall be entitled to an injunction or injunctions to prevent breaches of the provisions of this Agreement and to enforce specifically the terms of provisions hereof in any court having jurisdiction, such remedy being in addition to any other remedy to which they may be entitled at law or in equity.

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6.3 Severability. If any term or provision of this Agreement is held by a court of competent jurisdiction to be invalid, void or unenforceable, the remainder of the terms and provisions set forth herein shall remain in full force and effect and shall in no way be affected, impaired or invalidated, and the parties hereto shall use their best efforts to find and employ an alternative means to achieve the same or substantially the same result as that contemplated by such term or provision.

6.4 Further Assurances. Subject to the specific terms of this Agreement, the Holder, the Issuer and the Partnership shall make, execute, acknowledge and deliver such other instruments and documents, and take all such other actions as may be reasonably required in order to effectuate the purposes of this Agreement and to consummate the transactions contemplated hereby.

6.5 Entire Agreement. This Agreement contains the entire understanding of the parties with respect to the transactions contemplated hereby and supersedes all agreements and understandings entered into with respect thereto prior to the execution hereof.

6.6 Amendment. This Agreement may be amended only by an agreement in writing signed by each of the parties hereto.

6.7 Counterparts. For the convenience of the parties hereto, any number of counterparts of this Agreement may be executed by the parties hereto, but all such counterparts shall be deemed one and the same instrument.

6.8 Notices. All notices, consents, requests (including Registration Requests), demands and other communications hereunder shall be in writing and shall be given by hand or by mail (return receipt requested) or sent by overnight delivery service, cable, telegram or facsimile transmission to the parties at the following addresses or at such other address as shall be specified by the parties by like notice.

(a)		if to the Issuer, to:

		Kinder Morgan Management, LLC
		500 Dallas Street, Suite 1000
		Houston, Texas 77002
		Attention: General Counsel

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(b)		if to the Partnership, to:

		Kinder Morgan Energy Partners, L.P.
		c/o Kinder Morgan Management, LLC,
		the delegate of its General Partner
		500 Dallas Street, Suite 1000
		Houston, Texas 77002
		Attention: General Counsel

(c)		if to the Holder, to:

		Kinder Morgan, Inc.
		500 Dallas Street, Suite 1000
		Houston, Texas 77002
		Attention: General Counsel

Notice so given shall, in the case of notice so given by mail, be deemed to be given and received on the third business day after posting, in the case of notice so given by overnight delivery service, on the day after notice is deposited with such service, and in the case of notice so given by cable, telegram, facsimile transmission or, as the case may be, personal delivery, on the date of actual delivery.

6.9 Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED AND ENFORCED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO ANY CHOICE OF LAW PRINCIPLES WHICH MIGHT REQUIRE OR PERMIT THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION.

6.10 Successors and Assigns. This Agreement shall be binding upon and shall inure to the benefit of and be enforceable by and against the successors and permitted assigns of the parties hereto. Except (a) with the consent of the other parties, (b) for assignments by the Holder to any of its affiliates, or (c) as otherwise provided herein, the parties may not assign their rights or obligations under this Agreement. Any attempted assignment or delegation prohibited hereby shall be void.

6.11 Parties in Interest. Except as otherwise specifically provided herein, nothing in this Agreement expressed or implied is in tended or shall be construed to confer any right or benefit upon any Person, firm or corporation other than the Holder, the Partnership and the Issuer and their respective successors and permitted assigns.

(The signature page follows.)

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IN WITNESS WHEREOF, each of the Holder, the Partnership and the Issuer has caused this Agreement to be duly executed as of the date first above written.

		Kinder Morgan, Inc.


		By:	/s/ JOSEPH LISTENGART
		Name:	Joseph Listengart
		Title:	Vice President


Kinder Morgan Energy Partners, L.P.

	By:	Kinder Morgan G.P., Inc.,
		its General Partner

	By:	Kinder Morgan Management, LLC,
		its delegate

		By:	/s/ JOSEPH LISTENGART
		Name:	Joseph Listengart
		Title:	Vice President



			Kinder Morgan Management, LLC


		By:	/s/ JOSEPH LISTENGART
		Name:	Joseph Listengart
		Title:	Vice President

EX-10.2 6 kmiex102.htm KMI AMENDED AND RESTATED 1999 STOCK OPTION PLAN Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan

Exhibit 10.2

KINDER MORGAN, INC.
AMENDED AND RESTATED 1999 STOCK OPTION PLAN
(Effective January 17, 2001)

Section I.
Purpose of the Plan

This Plan is an amendment and restatement of the K N Energy, Inc. 1999 Stock Option Plan. The KINDER MORGAN, INC. AMENDED AND RESTATED 1999 STOCK OPTION PLAN (the "Plan) is intended to provide a means whereby certain employees of KINDER MORGAN, INC., a Kansas corporation (the "Company"), and its subsidiaries may develop a sense of proprietorship and personal involvement in the development and financial success of the Company, and to encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company and its shareholders. Accordingly, the Company may grant to certain employees ("Optionees") the option ("Option") to purchase shares of the common stock of the Company, par value $5.00 per share ("Stock"), as hereinafter set forth. Options granted under the Plan shall be options that do not constitute incentive stock options within the meaning of Section 422(b) of the Internal Revenue Code of 1986, as amended (the "Code").

Section II.
Administration

The Plan shall be administered by a committee (the "Committee") of, and appointed by, the Board of Directors of the Company (the "Board"), and the Committee shall be (a) comprised solely of two or more outside directors (within the meaning of Section 162(m) of the Code and applicable interpretive authority thereunder), and (b) constituted so as to permit the Plan to comply with Rule 16b-3, as currently in effect or as hereinafter modified or amended ("Rule 16b-3"), promulgated under the Securities Exchange Act of 1934, as amended (the "1934 Act"). The Committee shall have sole authority to select the Optionees from among those individuals eligible hereunder and to establish the number of shares of Stock which may be issued under each Option. In selecting the Optionees from among individuals eligible hereunder and in establishing the number of shares of Stock that may be issued under each Option, the Committee may take into account the nature of the services rendered by such individuals, their present and potential contributions to the Company's success and such other factors as the Committee in its discretion shall deem relevant. The Committee is authorized to interpret the Plan and may from time to time adopt such rules and regulations, consistent with the provisions of the Plan, as it may deem advisable to carry out the Plan. All decisions made by the Committee in selecting the Optionees, in establishing the number of shares of Stock which may be issued under each Option and in construing the provisions of the Plan shall be final, conclusive and binding on all persons, including the Company, its subsidiaries and other entities in which the Company has an ownership interest, its shareholders, Optionees and their estates and beneficiaries.

Section III.
Option Agreements

(a) Each Option shall be evidenced by a written agreement between the Company and the Optionee ("Option Agreement") which shall contain such terms and conditions as may be approved by the Committee, including, but not limited to, the number of shares of Stock that may be purchased under the Option and the price per share of Stock purchasable under the Option ("Option Price"). The terms and conditions of the respective Option Agreements need not be identical. Specifically, an Option Agreement may provide for the surrender of the right to purchase shares of Stock under the Option in return for a payment in cash or shares of Stock or a combination of cash and shares of Stock equal in value to the excess of the fair market value of the shares of Stock with respect to which the right to purchase is surrendered over the Option Price therefor ("Stock Appreciation Rights"), on such terms and conditions as the Committee in its sole discretion may prescribe. Moreover, an Option Agreement may provide for the payment of the Option Price, in whole or in part, by the delivery of a number of shares of Stock (plus cash if necessary) having a fair market value equal to such Option Price.

(b) For all purposes under the Plan, the fair market value of a share of Stock on a particular date shall be equal to the closing sales price of the Stock reported on the New York Stock Exchange Composite Tape on that date; or, if no prices are reported on that date, on the last preceding date on which such prices of the Stock are so reported. In the event Stock is not publicly traded at the time a determination of its value is required to be made hereunder, the determination of its fair market value shall be made by the Committee in such manner as it deems appropriate.

(c) Each Option and all rights granted thereunder shall not be transferable other than (i) by will or the laws of descent and distribution, (ii) between an Optionee and his or her former spouse, but only if such transfer is incident to a divorce under Section 1041(a) of the Code, or (iii) with the consent of the Committee.

Section IV.
Eligibility of Optionee

The Plan is intended to constitute a "broadly-based plan" for purposes of the shareholder approval policy of the New York Stock Exchange relating to stock option plans, and the Plan shall be administered accordingly.

Options may be granted only to individuals who are employees (including officers and directors who are also employees) of the Company or an entity in which the Company has an ownership interest, directly or indirectly, at the time the Option is granted or who will be future employees within 90 days of any grant of Options, and, in any event, at least a majority of the full-time employees in the United States of the Company or any parent or subsidiary corporation (as defined in Section 424 of the Code) (who are "exempt employees" under the Fair Labor Standards Act of 1938) shall be eligible to receive grants of Options. Options may be granted to the same individual on more than one occasion.

At least a majority of the shares of Stock underlying Options awarded under the Plan, during the three-year period commencing on the date the Plan is adopted by the Company, shall be made to eligible employees who are neither officers nor directors of the Company.

Section V.
Shares Subject to the Plan

Effective January 17, 2001, the aggregate number of shares of Stock which may be issued under Options granted under the Plan shall not exceed 10,500,000. Such shares may consist of authorized but unissued shares of Stock or previously issued shares of Stock reacquired by the Company. Any of such shares which remain unissued and which are not subject to outstanding Options at the termination of the Plan shall cease to be subject to the Plan, but, until termination of the Plan, the Company shall at all times make available a sufficient number of shares to meet the requirements of the Plan. Should any Option hereunder expire or terminate prior to its exercise in full, the shares theretofore subject to such Option may again be subject to an Option granted under the Plan to the extent permitted under Rule 16b-3. The aggregate number of shares of Stock which may be issued under the Plan shall be subject to adjustment in the same manner as provided in Paragraph VIII hereof with respect to shares of Stock subject to Options then outstanding. Exercise of an Option in any manner, including an exercise involving a Stock Appreciation Right, shall result in a decrease in the number of shares of Stock which may thereafter be available, both for purposes of the Plan and for sale to any one individual, by the number of shares as to which the Option is exercised.

Notwithstanding any provision in the Plan to the contrary, no more than 1,000,000 shares of Stock may be subject to Options granted under the Plan to any one individual during the term of the Plan. The limitation set forth in the preceding sentence shall be applied in a manner which will permit compensation generated under the Plan to constitute "performance-based" compensation for purposes of Section 162(m) of the Code, including, without limitation, counting against such maximum number of shares of Stock, to the extent required under Section 162(m) of the Code and applicable interpretive authority thereunder, any shares of Stock subject to Options that are canceled or repriced.

Section VI.
Option Price

The Option Price of Stock issued under each Option shall be determined by the Committee, but such Option Price shall not be less than the fair market value of Stock subject to the Option on the date the Option is granted.

Section VII.
Term of Plan

This Plan was originally effective on October 8, 1999 (the "Effective Date") and was amended and restated, effective January 20, 2000. This Plan, as further amended and restated, shall be effective on January 17, 2001, which is the date on which the Board adopted this

amended and restated Plan. Except with respect to Options then outstanding, if not sooner terminated under the provisions of Paragraph IX, the Plan shall terminate upon and no further Options shall be granted after the expiration of ten years from the Effective Date.

Section VIII.
Recapitalization or Reorganization

(a) The existence of the Plan and the Options granted hereunder shall not affect in any way the right or power of the Board or the shareholders of the Company to make or authorize any adjustment, recapitalization, reorganization or other change in the Company's capital structure or its business, any merger or consolidation of the Company, any issue of debt or equity securities, the dissolution or liquidation of the Company or any sale, lease, exchange or other disposition of all or any part of its assets or business or any other corporate act or proceeding.

(b) The shares with respect to which Options may be granted are shares of Stock as presently constituted, but if, and whenever, prior to the expiration of an Option theretofore granted, the Company shall effect a subdivision or consolidation of shares of Stock or the payment of a stock dividend on Stock without receipt of consideration by the Company, the number of shares of Stock with respect to which such Option may thereafter be exercised (i) in the event of an increase in the number of outstanding shares shall be proportionately increased, and the Option Price per share shall be proportionately reduced, and (ii) in the event of a reduction in the number of outstanding shares shall be proportionately reduced, and the Option Price per share shall be proportionately increased. Any fractional share resulting from such adjustment shall be rounded up to the next whole share.

(c) If the Company recapitalizes, reclassifies its capital stock, or otherwise changes its capital structure (a "Recapitalization"), the number and class of shares of Stock covered by an Option theretofore granted shall be adjusted so that such Option shall thereafter cover the number and class of shares of stock and securities to which the Optionee would have been entitled pursuant to the terms of the Recapitalization if, immediately prior to the Recapitalization, the Optionee had been the holder of record of the number of shares of Stock then covered by such Option. If (i) any "person," as such term is used in Sections 13(d) and 14(d) of the 1934 Act (other than the Company, any trustee or other fiduciary holding securities under an employee benefit plan of the Company or any corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company), is or becomes the "beneficial owner" (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of securities of the Company representing fifty percent (50%) or more of the combined voting power of the Company's then outstanding securities, (ii) during any period of two consecutive years (not including any period prior to the Effective Date of this Plan), individuals who at the beginning of such period constitute the Board, and any new director (other than a director designated by a person who has entered into an agreement with the Company to effect a transaction described in (i), (iii) or (iv) of this Paragraph VIII(c)) whose election by the Board or nomination for election by the Company's shareholders was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors

at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason other than normal retirement, death or disability to constitute at least a majority thereof, (iii) the shareholders of the Company approve a merger or consolidation of the Company with any other person, other than (1) a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities for the surviving entity) more than fifty percent (50%) of the combined voting power of the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation, or (2) a merger in which the Company is the surviving entity but no "person" (as defined above) acquires more than fifty percent (50%) of the combined voting power of the Company's then outstanding securities, or (iv) the shareholders of the Company approve a plan of complete liquidation of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets (or any transaction having a similar effect) (each such event described in clauses (i), (ii), (iii) and (iv) is referred to herein as a "Corporate Change"), no later than (A) ten days after the approval by the shareholders of the Company of such merger or consolidation, plan of complete liquidation, or sale or disposition of assets or (B) thirty days after a change of control of the type described in clause (i) or (ii), the Committee, acting in its sole discretion without the consent or approval of any Optionee, shall act to effect one or more of the following alternatives, which may vary among individual Optionees and which may vary among Options held by any individual Optionee: (I) accelerate the time at which Options then outstanding may be exercised so that such Options may be exercised in full for a limited period of time on or before a specified date (before or after such Corporate Change) fixed by the Committee, after which specified date all unexercised Options and all rights of Optionees thereunder shall terminate, (II) require the mandatory surrender to the Company by selected Optionees of some or all of the outstanding Options held by such Optionees (irrespective of whether such Options are then exercisable under the provisions of the Plan) as of a date, before or after such Corporate Change, specified by the Committee, in which event the Committee shall thereupon cancel such Options and the Company shall pay to each Optionee an amount of cash per share equal to the excess, if any, of the amount calculated in Subparagraph (d) below (the "Change of Control Value") of the shares subject to such Option over the Option Price(s) under such Options for such shares, (III) make such adjustments to Options then outstanding as the Committee deems appropriate to reflect such Corporate Change (provided, however, that the Committee may determine in its sole discretion that no adjustment is necessary to Options then outstanding) or (IV) provide that the number and class of shares of Stock covered by an Option theretofore granted shall be adjusted so that such Option shall thereafter cover the number and class of shares of Stock or other securities or property (including, without limitation, cash) to which the Optionee would have been entitled pursuant to the terms of the agreement of merger, consolidation or sale of assets and dissolution if, immediately prior to such merger, consolidation or sale of assets and dissolution, the Optionee had been the holder of record of the number of shares of Stock then covered by such Option. Notwithstanding anything herein to the contrary, if a Corporate Change occurs and, in connection with or as a result of such Corporate Change, neither William V. Morgan nor Richard D. Kinder holds or continues to hold the office of Chairman or Vice Chairman of the Company, all Options granted hereunder shall immediately become fully exercisable.

(d) For the purposes of clause (II) in Subparagraph (c) above, the "Change of Control Value" shall equal the amount determined in clause (i), (ii) or (iii), whichever is applicable, as follows: (i) the per share price offered to shareholders of the Company in any such merger, consolidation, reorganization, sale of assets or dissolution transaction, (ii) the price per share offered to shareholders of the Company in any tender offer or exchange offer whereby a Corporate Change takes place, or (iii) if such Corporate Change occurs other than pursuant to a tender or exchange offer, the fair market value per share of the shares into which such Options being surrendered are exercisable, as determined by the Committee as of the date determined by the Committee to be the date of cancellation and surrender of such Options. In the event that the consideration offered to shareholders of the Company in any transaction described in this Subparagraph (d) or Subparagraph (c) above consists of anything other than cash, the Committee shall determine the fair cash equivalent of the portion of the consolidation offered which is other than cash.

(e) Except as hereinbefore expressly provided, the issuance by the Company of shares of stock of any class or securities convertible into shares of stock of any class, for cash, property, labor or services, upon direct sale, upon the exercise of rights or warrants to subscribe therefor, or upon conversion of shares or obligations of the Company convertible into such shares or other securities, and in any case whether or not for fair value, shall not affect, and no adjustment by reason thereof shall be made with respect to, the number of shares of Stock subject to Options theretofore granted or the Option Price per share.

Section IX.
Amendment or Termination

The Board in its discretion may terminate the Plan at any time with respect to any shares for which Options have not theretofore been granted. The Board shall have the right to alter or amend the Plan or any part thereof from time to time; provided, that (a) no change in any Option theretofore granted may be made which would impair the rights of the Optionee without the consent of such Optionee; (b) the Board may not make any alteration or amendment which would decrease any authority granted to the Committee hereunder in contravention of Rule 16b-3; and (c) no such action of the Board shall be taken without approval of the Company's shareholders if such approval is required to comply with Rule 16b-3, any rule promulgated by the New York Stock Exchange, or Section 162(m) of the Code or any successor provisions.

Section X.
Securities Laws

(a) The Company shall not be obligated to issue any Stock pursuant to any Option granted under the Plan at any time when the offering of the shares covered by such Option have not been registered under the Securities Act of 1933 and such other state and federal laws, rules or regulations as the Company or the Committee deems applicable and, in the opinion of legal counsel for the Company, there is no exemption from the registration requirements of such laws, rules or regulations available for the offering and sale of such shares.

(b) It is intended that the Plan and any grant of an Option made to a person subject to Section 16 of the 1934 Act meet all of the requirements of Rule 16b-3. If any provision of the Plan or any such Option would disqualify the Plan or such Option under, or would otherwise not comply with, Rule 16b-3, such provision or Option shall be construed or deemed amended to conform to Rule 16b-3.

Section XI.
Miscellaneous

(a) Neither the adoption of the Plan by the Company nor any action of the Board or the Committee shall be deemed to give an employee any right to be granted an Option or any other rights hereunder except as may be evidenced by an Option Agreement duly executed on behalf of the Company, and then only to the extent and on the terms and conditions expressly set forth therein. The Plan shall be unfunded.

(b) Nothing contained in the Plan shall (i) confer upon any employee any right with respect to continuation of employment with the Company or any subsidiary or (ii) interfere in any way with the right of the Company or any subsidiary to terminate his or her employment at any time.

(c) Nothing contained in the Plan shall be construed to prevent the Company or any subsidiary from taking any corporate action which is deemed by the Company or such subsidiary to be appropriate or in its best interest, whether or not such action would have an adverse effect on the Plan or any Option made under the Plan. No employee, beneficiary or other person shall have any claim against the Company or any subsidiary as a result of any such action.

(d) Any Option Agreement or related document may be executed by facsimile signature. If any officer who shall have signed or whose facsimile signature shall have been placed upon any such Option Agreement or related document shall have ceased to be such officer before the related Option is granted by the Company, such Option may nevertheless be issued by the Company with the same effect as if such person were such officer at the date of grant.

(e) This Plan shall be construed in accordance with the laws of the State of Texas.

IN WITNESS WHEREOF, and as conclusive evidence of the adoption of the foregoing by the Board of Directors, Kinder Morgan, Inc. has caused these presents to be duly executed in its name and behalf by its proper officers thereunto duly authorized as of this 17th day of January, 2001.

	KINDER MORGAN, INC.



	By:	/s/ James E. Street
	Name:	James E. Street
	Title:	Senior Vice President - Human Resources and Administration

EX-21.1 7 kmiex211.htm KMI SUBSIDIARIES OF THE REGISTRANT Kinder Morgan, Inc. Subidiaries of the Registrant
Exhibit 21.1

KINDER MORGAN, INC.

1-  Kinder Morgan (Delaware), Inc. - DE
2-  Kinder Morgan G.P., Inc. - DE
3-  Kinder Morgan Management, LLC - DE
4-  KMGP Services Company, Inc. - DE
5-  Kinder Morgan Services LLC - DE
6-  KN Cogeneration, Inc. - CO
7-  Thermo Gas Marketing, Inc. - CO
8-  Thermo Project Management, Inc. - CO
9-  Valley Operating, Inc. - CO
10- KN Thermo, L.L.C. - CO
11- Kinder Morgan Ft. Lupton Operator LLC - DE
12- Thermo Greeley, LLC - CO
13- KN Telecommunications, Inc. - CO
14- KN Gas Supply Services, Inc. - CO
15- KN Natural Gas, Inc. - CO
16- Red Rock Energy, LLC - DE
17- Interenergy Corporation - CO
18- Kinder Morgan Power Company - CO
19- KN TransColorado, Inc. - CO
20- KN Wattenberg Transmission Limited Liability Company - CO
21- Slurco Corporation - CO
22- Rocky Mountain Natural Gas Company - CO
23- Kinder Morgan Foundation (nonprofit) - CO
24- Western Slope Energy Services, LLC - CO
25- KN Gas Gathering, Inc. - CO
26- MidCon Corp. - DE
27- MidCon Gas Services Corp. - DE
28- MCN Gulf Processing Corp. - DE
29- Natural Gas Pipeline Company of America - DE
30- NGPL Canyon Compression Co. - DE
31- Canyon Creek Compression Company - IL
32- KN Management Corp. - DE
33- MidCon Mexico Pipeline Corp. - DE
34- KN Energy International, Inc. - DE
35- Kinder Morgan Igasamex, Inc. - DE
36- KM International Services, Inc. - DE
37- Lake Power L.L.C. - DE
38- FR Holdings L.L.C. - CO
39- Front Range Energy Associates, LLC -DE
40- Kinder Morgan Michigan LLC - DE
41- Kinder Morgan Kansas LLC - DE
42- Kinder Morgan Illinois LLC - DE
43- Kinder Morgan Missouri LLC - DE
44- Kinder Morgan Power Partners LLC - DE
45- Kinder Morgan Georgia LLC - DE
46- Kinder Morgan Michigan Pipeline LLC - DE
47- Kinder Morgan Virginia LLC - DE
48- Kinder Morgan Arkansas LLC - DE
49- Kinder Morgan Oklahoma LLC - DE
50- Kinder Morgan Alabama LLC - DE
51- KM Turbine Facility #6 LLC - DE
52- KM Turbine Facility #7 LLC - DE
53- Kinder Morgan Operator LLC - DE
54- Kinder Morgan Michigan Operator LLC - DE
55- Kinder Morgan Michigan Servicer LLC - DE
56- Kinder Morgan Michigan Contractor LLC - DE
57- Kinder Morgan Michigan Developer LLC - DE
58- Triton Power Company LLC - DE
59- Triton Power Michigan LLC - DE
60- KMC Thermo, L.L.C. - CO
61- Special Purpose Venture, LLC - OH
62- Wildhorse Energy, LLC - DE
63- TransColorado Gas Transmission Company - NY
64- Administracion y Operacion de Infraestructura, S.A. de C.V. - Mexico
65- GNN Services, S. de R.L. de C.V. - Mexico
66- Gas Natural del Noroeste, S.A. de C.V. - Mexico
67- KN Thermo Acquisition, Inc. - CO
68- Kinder Morgan TransColorado LLC - DE
69- Kinder Morgan TransColorado, Inc. - UT

EX-23.1 8 kmiex231.htm KMI CONSENT OF INDEPENDENT ACCOUNTANTS Kinder Morgan, Inc. Exhibit 23.1
Exhibit 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-16 (Nos. 2-51894, 2-55664, 2-63470 and 2-75654), (ii) Form S-8 (Nos. 2-77752, 33-10747, 33-24934, 33-33018, 33-54403, 33-54443, 33-54555, 333-08059, 333-08087, 333-60839, 333-42178 and 333-53908), (iii) Form S-3 (Nos. 2-84910, 33-26314, 33-23880, 33-42698, 33-44871, 33-45091, 33-46999, 33-54317, 33-69432, 333-04385, 333-40869, 333-44421, 333-55921, 333-68257, 333-54896, 333-55866, 333-91257, 333-91316-02, 333-102963 and 333-102962-02) and (iv) Form S-4 (No. 333-102873) of Kinder Morgan, Inc. of our report dated February 21, 2003 relating to the financial statements, which appears in this Form 10-K, and of our report dated February 21, 2003 relating to the financial statements of Kinder Morgan Energy Partners, L.P., which appears in Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K which is incorporated by reference in this Form 10-K.

PricewaterhouseCoopers LLP

Houston, Texas
February 25, 2003

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.

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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.

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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>

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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

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<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.

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<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.

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<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

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<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

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<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

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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

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

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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

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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
========

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(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
========

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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.

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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.

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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

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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.

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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
=======

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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

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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.

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<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

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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.

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<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%

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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%).

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<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)
======== ======== ========
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<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
========= =========

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<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;

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<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

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<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

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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.

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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

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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

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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

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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

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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....................... $ -- $ --
========= =========

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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

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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

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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

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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.

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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

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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

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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

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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.

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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:

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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

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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.

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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.

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%

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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

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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.

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<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.

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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.

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<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,

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<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.

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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

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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.

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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

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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.

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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.

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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.

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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.

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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.

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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

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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.

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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."

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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

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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;

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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

EX-99.2 10 kmiex992.htm KMI CHIEF EXECUTIVE OFFICER CERTIFICATION Exhibit 99.2 Kinder Morgan, Inc. CEO Certification
Exhibit 99.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Kinder Morgan, Inc. (the "Company") on Form 10-K for the year ended December 31, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.

Dated: February 26, 2003		/s/ Richard D. Kinder
		Richard D. Kinder Chairman and Chief Executive Officer

EX-99.3 11 kmiex993.htm KMI CHIEF FINANCIAL OFFICER CERTIFICATION Exhibit 99.3 Kinder Morgan, Inc. CFO Certification
Exhibit 99.3

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.

Dated: February 26, 2003		/s/ C. Park Shaper
		C. Park Shaper Vice President, Treasurer and Chief Financial Officer

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	Market Price Per Share Data
	2002		2001
	Low	High	Low	High
Quarter Ended:
March 31	$36.810	$57.500	$42.875	$60.000
June 30	$37.110	$52.620	$50.250	$59.970
September 30	$33.100	$44.020	$46.220	$57.570
December 31	$30.050	$42.980	$46.950	$57.130


	Dividends Paid Per Share
	2002	2001
Quarter Ended:
March 31	$0.05	$0.05
June 30	$0.05	$0.05
September 30	$0.10	$0.05
December 31	$0.10	$0.05

Stockholders of Record as of January 31, 2003	38,600 (approximately)