10-K

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, 2003
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
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 o

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $5,258,619,030 at June 30, 2003.

The number of shares outstanding of the registrant's common stock, $5 par value, as of February 12, 2004 was 123,702,887 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Part III of this report incorporates by reference specific portions of the Registrant's Proxy Statement relating to its 2004 Annual Meeting of Stockholders.

KINDER MORGAN, INC. AND SUBSIDIARIES
CONTENTS

			Page Number
	PART I
Items 1 and 2:	Business and Properties		3-20
		Overview	6
		Natural Gas Pipeline Company Of America	7
		TransColorado Gas Transmission Company	9
		Kinder Morgan Retail	11
		Power	12
		Regulation	13
		Environmental Regulation	16
		Risk Factors	17
Item 3:	Legal Proceedings		20
Item 4:	Submission of Matters to a Vote of Security Holders		21
Executive Officers of the Registrant			21-23
	PART II
Item 5:	Market for Registrant's Common Equity, Related Stockholder
	Matters and Issuer Purchases of Equity Securities		24
Item 6:	Selected Financial Data		25-26
Item 7:	Management's Discussion and Analysis of Financial Condition and
	Results of Operations		27-54
		General	27
		Critical Accounting Policies and Estimates	28
		Consolidated Financial Results	30
		Results Of Operations	32
		Natural Gas Pipeline Company Of America	33
		TransColorado	35
		Kinder Morgan Retail	37
		Power	38
		Earnings from Investment in Kinder Morgan Energy Partners	40
		Other Income and (Expenses)	41
		Income Taxes - Continuing Operations	41
		Discontinued Operations	42
		Liquidity and Capital Resources	42
		Investment in Kinder Morgan Energy Partners	48
		Cash Flows	48
		Litigation and Environmental	51
		Regulation	51
		Recent Accounting Pronouncements	52
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk		54-56
Item 8:	Financial Statements and Supplementary Data		57-112
Item 9:	Changes in and Disagreements With Accountants on Accounting and
	Financial Disclosure		113
Item 9A:	Controls and Procedures		113
	PART III
Item 10:	Directors and Executive Officers of the Registrant		113
Item 11:	Executive Compensation		113
Item 12:	Security Ownership of Certain Beneficial Owners and Management
	and Related Stockholder Matters		113
Item 13:	Certain Relationships and Related Transactions		113
Item 14:	Principal Accounting Fees and Services		114
	PART IV
Item 15:	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		115-120
Signatures			121

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

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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 terms "dekatherms" and "MMBtus" mean 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.

(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. ("Kinder Morgan Energy Partners"), over 35,000 miles of natural gas and petroleum products pipelines and approximately 80 terminals. We own and operate (i) Natural Gas Pipeline Company of America, a major interstate natural gas pipeline system with approximately 9,900 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 241,000 customers in Colorado, Nebraska and Wyoming. We have constructed, currently operate and own interests in certain 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 Street, Suite 1000, Houston Texas 77002 and our telephone number is (713) 369-9000.

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. As a result of that acquisition and certain subsequent transactions, 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 39 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 52 liquid and bulk terminal facilities and approximately 57 rail transloading facilities located throughout the United States, handling nearly 60 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 55 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 has over 1,100 miles of pipelines and transports, markets and produces carbon dioxide for use in enhanced oil recovery operations and owns interests in and/or operates six oil fields in West Texas, all of which are using or have used carbon dioxide injection

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operations. Additional information concerning the business of Kinder Morgan Energy Partners is contained in Kinder Morgan Energy Partners' 2003 Annual Report on Form 10-K.

In May 2001, Kinder Morgan Management, LLC ("Kinder Morgan Management"), 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. 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. 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.

In the initial public offering, we purchased ten percent of the Kinder Morgan Management shares, 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 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 additional i-units from Kinder Morgan Energy Partners. We did not purchase any of the offered shares. In addition, during 2003 and 2002, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $1.8 million and $3.4 million, respectively. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management's 2003 Annual Report on Form 10-K.

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 within North America, (ii) increase utilization of our existing assets while controlling costs, (iii) make selected incremental acquisitions and expansions of properties that fit within our strategy and are accretive to earnings and cash flow, (iv) maximize the benefits of our financial structure to create and return value to our stockholders as discussed following and (v) continue to align employee and shareholder incentives.

With respect to financial strategy, we intend to maintain a relatively conservative capital structure that provides flexibility and stability, while returning value to our shareholders through dividends and share repurchases. During 2003, we utilized cash generated from operations to pay dividends, reduce our outstanding debt, finance our capital expenditures program and repurchase our common shares. In recent periods, we have increased our common stock dividends in response to changes in income tax laws that have made dividends a more efficient way to return cash to our shareholders. At December 31, 2003, our total debt to total capital had been reduced to approximately 43% from over 70% in late 1999, with approximately 50% of our debt subject to floating interest rates.

We expect to benefit from accretive acquisitions (primarily by Kinder Morgan Energy Partners) and business expansions. 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

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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's pipeline systems and acquire natural gas retail distribution properties that fit well with our current profile. In addition, we and Kinder Morgan Energy Partners have announced that we are considering the transfer of TransColorado to Kinder Morgan Energy Partners for fair market value, subject to various factors, including obtaining fairness opinions with respect to any such transaction for both us and Kinder Morgan Energy Partners.

It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under "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.

Developments During 2003

• Dividends
We increased our annual rate of cash dividends per share by $0.20 and $1.00 in the first and third quarters of 2003, respectively, and by $0.65 in the first quarter of 2004, reaching an annual rate of $2.25. These increases were principally in response to recently enacted federal tax legislation and increased cash flow available to fund capital expenditures, debt reduction, dividends and share repurchases.

• Share Repurchase Program
In November 2003, we expanded our common stock repurchase program by $50 million to $500 million. Since the inception of the program in August 2001, we have repurchased approximately $452.7 million of common stock, including $38.0 million in 2003.

• North Lansing Storage Expansion
In April 2003, Natural Gas Pipeline Company of America began construction of a 10.7 Bcf storage service expansion, all of which is subscribed under long-term contracts, at its existing North Lansing storage field in east Texas. Construction of the approximately $38 million project is expected to be completed in May 2004.

• Re-Contracting Transportation and Storage Capacity
During 2003, a year in which approximately 41% of its long-haul transportation capacity was scheduled to expire, Natural Gas Pipeline Company of America announced several significant new transportation and storage agreements and successfully negotiated a number of smaller agreements to the end that, as of the end of 2003, firm transportation capacity was approximately 98% sold out for the winter season and storage capacity was sold out through 2004.

• TransColorado Expansion
In September 2003, we announced our intention to expand TransColorado following the signing of a 10-year, firm natural gas transportation contract with an undisclosed shipper. The expansion will provide an additional 125,000 dekatherms per day of firm transportation capacity on TransColorado for an incremental investment of approximately $33 million and is expected to be completed in the third quarter of 2004.

• Retail Expansion
In December 2003, Retail began construction of a 60-mile natural gas pipeline from Montrose to Ouray, Colorado to provide service to several thousand new customers. The first phase of this

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approximately $20 million project is expected to be placed in service in the summer of 2004.

(B) Financial Information about Segments

Note 19 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 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, 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 the sales of natural gas to certain utility customers under our Choice Gas Program, a program that allows utility customers to choose their natural gas provider and (4) Power, the operation (and, in previous periods, construction) of natural gas-fired electric generation facilities.

Natural gas transportation, storage and retail sales accounted for approximately 95%, 93% and 90% of our consolidated revenues in 2003, 2002 and 2001, respectively. During 2003, 2002 and 2001, we did not have revenues from any single customer that exceeded 10 percent of our consolidated operating revenues. 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, production of oil and (iv) bulk and liquids terminals. Our equity in the earnings of Kinder Morgan Energy Partners (net of the associated amortization in periods prior to January 1, 2002) constituted approximately 60%, 65% and 40% of our income from continuing operations before interest and income taxes in 2003, 2002 and 2001, respectively. The following table gives our segment earnings, our earnings attributable to our investment in Kinder Morgan Energy Partners and the percent of the combined total each represents, for each of the last two years. In 1999, we discontinued our wholesale natural gas marketing, non-energy retail marketing services and natural gas gathering and processing businesses. Notes 5 and 19 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.

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	Year Ended December 31,
	2003		2002
	Amount	% of Total	Amount	% of Total
	(Dollars in thousands)
Investment in Kinder Morgan Energy Partners:
Equity in Earnings, Net of Kinder Morgan
Management, LLC Pre-tax Minority Interest	$398,325	45.21%	$338,504	41.70%
Segment Earnings:
Natural Gas Pipeline Company of America	372,017	42.23%	359,911	44.33%
TransColorado	23,112	2.62%	12,648	1.56%
Kinder Morgan Retail	65,482	7.43%	64,056	7.89%
Power	22,076	2.51%	36,673	4.52%
Total	$881,012	100.00%	$811,792	100.00%
	========	=======	========	=======

Natural Gas Pipeline Company of America

During 2003, Natural Gas Pipeline Company of America's segment earnings of $372.0 million represented approximately 42% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and approximately 48% of our income from continuing operations before interest and income taxes. Through Natural Gas Pipeline Company of America, we own and operate approximately 9,900 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 0.9 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 4,400 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 4,700 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 800-mile Amarillo/Gulf Coast pipeline. In addition, Natural Gas Pipeline Company of America owns a 50% equity interest in and operates Horizon Pipeline Company, L.L.C., a joint venture with Nicor-Horizon, a subsidiary of Nicor, Inc. This joint venture owns a natural gas pipeline in northern Illinois with a capacity of 380 MMcf per day.

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 if 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 somewhat higher in the first and fourth quarters of the calendar year, reflecting higher system utilization during the colder months. During the winter months, Natural Gas Pipeline

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Company of America collects higher transportation commodity revenue, higher interruptible transportation revenue, winter-only capacity revenue and higher 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 2003, Natural Gas Pipeline Company of America delivered an average of 1.76 trillion Btus per day of natural gas to this market. Given its strategic location at the center of the North American natural gas pipeline grid, we believe that Chicago is likely to continue to be a major natural gas trading hub for 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 67% of the total transportation volumes committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts as of January 7, 2004 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, and was very successful during 2003 as discussed under "Developments During 2003" elsewhere in this report. 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 in terms of operating revenues from tariff services. During 2003, approximately 54 percent of Natural Gas Pipeline Company of America's operating revenues from tariff services were attributable to its eight largest customers. Contracts representing approximately 10% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 7, 2004 are scheduled to expire during 2004.

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, 232 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.

During April 2003, Natural Gas Pipeline Company of America began construction of 10.7 Bcf of storage service expansion at its existing North Lansing storage facility in east Texas, all of which incremental storage capacity is fully subscribed under long-term contracts. Although construction on the approximately $38 million project is not expected to be completed until May 2004, the service is available at this time.

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

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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, makes it a strong competitor in many situations, but most customers still have alternative sources to meet 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 track record as 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 (TransColorado)

During 2003, TransColorado's segment earnings of $23.1 million represented approximately 3% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 3% of our income from continuing operations before interest and income taxes. Through TransColorado, 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 two compressor stations in mainline service having an aggregate of approximately 10,000 horsepower. TransColorado's system, which extends from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico, has 17 points of interconnection with five interstate pipelines, one intrastate pipeline, four gathering systems, and two 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. TransColorado 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's results as a 50/50 equity method investment prior to October 1, 2002 and on a 100% basis as a consolidated subsidiary thereafter. As discussed under "Business Strategy" elsewhere in this report, we are considering the transfer of TransColorado to Kinder Morgan Energy Partners for fair market value.

TransColorado 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 offers its customers firm and interruptible transportation and interruptible park and loan services. Under

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TransColorado'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 has the authority to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure. TransColorado's revenues have historically been higher during the second and third quarters of the calendar year, resulting from two factors: (i) winter heating market loads to the north of TransColorado and (ii) summer air conditioning market loads to the south of TransColorado.

TransColorado acts principally as a feeder pipeline system from the developing natural gas supply basins on the Western Slope of Colorado into the interstate natural gas pipelines that lead away from the Blanco Hub area of New Mexico. TransColorado 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 2003, TransColorado transported an average of 462,624 dekatherms per day of natural gas from these supply basins. TransColorado provides a strategically important link between the underdeveloped gas supply resources on the Western Slope of Colorado and the greater southwestern United States marketplace. During 2003, 46 percent of TransColorado's transport business was with producers or their own marketing affiliates, 44 percent was with third-party marketers and the remaining 10 percent was primarily with gathering companies. Approximately 36 percent of TransColorado's transport business in 2003 was conducted with its three largest customers.

Approximately 90% of TransColorado's pipeline capacity is committed under firm transportation contracts that extend through year-end 2007. TransColorado is actively pursuing full contract subscription through 2007 and beyond.

On September 25, 2003, we announced that we had signed a 10-year, firm natural gas transportation contract with an undisclosed shipper that will allow us to construct facilities to provide a 125,000 dekatherm per day expansion of capacity on the TransColorado system. The facilities consist of three new compressor stations and modifications at two existing compressor stations, which will increase compression by more than 20,000 horsepower. On October 31, 2003, we filed with the Federal Energy Regulatory Commission for authority to construct the facilities and place them into service. Subject to appropriate regulatory approvals, we expect to place the facilities into service during the third quarter of 2004.

The TransColorado open season for various supply laterals, mainline capacity expansion and mainline extension proposals ended April 30, 2003. Post open season negotiations successfully led to the filing discussed above of the mainline capacity expansion application with the Federal Energy Regulatory Commission. Negotiations with prospective shippers regarding the proposed mainline extension were primarily linked to downstream capacity negotiations on Kinder Morgan Energy Partners' proposed Silver Canyon Pipeline project. Accordingly, Kinder Morgan Energy Partners is now negotiating with prospective shippers on the proposed Silver Canyon Pipeline to include previously identified TransColorado mainline extension facilities as part of the Silver Canyon Pipeline project.

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

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TransColorado's shippers compete for market share with shippers drawing upon gas production facilities within the New Mexico portion of the San Juan Basin. TransColorado has phased its past construction and expansion efforts to coincide with the ability of the interstate pipeline grid at Blanco, New Mexico 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'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'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's transport concurrently ramped up over that period such that TransColorado 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 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 Kern River Gas Transmission expansion project, placed in service in May 2003, has had the effect of reducing 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's transport business will be less susceptible to changes in the price differential in the future.

Kinder Morgan Retail

During 2003, Kinder Morgan Retail's segment earnings of $65.5 million represented 7% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 8% of our income from continuing operations before interest and income taxes. As of December 31, 2003, through Kinder Morgan Retail, our retail natural gas distribution business served approximately 241,000 customers in Colorado, Nebraska and Wyoming through more than 11,000 miles of distribution and transmission pipelines, underground storage fields, field system lines and related facilities. Kinder Morgan Retail's intrastate pipelines, distribution facilities and retail natural gas sales in Colorado, Nebraska and Wyoming are subject to the regulatory authority of each state's utility commission. In addition, Kinder Morgan Retail owns and operates a small distribution system in Hermosillo, Mexico.

Kinder Morgan Retail's operations in Nebraska, Wyoming and eastern 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's operations include the sale of natural gas under Choice Gas programs and the sale of non-jurisdictional products and services, natural gas-related equipment, and installation and repair services.

To support Kinder Morgan Retail's business, underground storage facilities are used to provide natural gas deliverability 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 a wholly owned subsidiary of Kinder Morgan, Inc. and (iii) one facility located in Nebraska and owned by Kinder Morgan Energy Partners. The peak natural gas storage withdrawal capacity available for Kinder Morgan Retail's business is approximately 83 MMcf per day.

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Kinder Morgan Retail's natural gas distribution business relies on the intrastate pipelines it operates, Kinder Morgan Interstate Gas Transmission LLC, a subsidiary of Kinder Morgan Energy Partners, 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 our wholly owned subsidiary 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 have 29.7 Bcf of combined 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.

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. These Choice Gas Programs allow competing natural gas providers to sell natural gas to approximately 64% of Kinder Morgan Retail's total customers at present. In 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 52% of the end-use customers in these unbundled areas.

Power

Power's 2003 earnings, before non-cash charges to reduce the carrying value of certain of its assets, represented less than 3% of either the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners or our income from continuing operations before interest and income taxes. Kinder Morgan Power previously designed, developed and constructed power projects. In 2002, following a thorough assessment of the electric industry's business environment and a marked deterioration in the financial condition of certain power generating and marketing participants, we decided to discontinue our power development activities. We currently have ownership interests in two natural gas-fired electric generation facilities in Colorado, one natural gas-fired electric generation facility in Michigan and one natural gas-fired electric generation facility in Arkansas. One of the Colorado facilities is operated as an independent power producer, with both a long-term power sales agreement and gas supply contract. The other Colorado facility and the Michigan and Arkansas facilities are operated under tolling agreements. We also have a net profits interest in a third natural gas-fired electric generation facility in Colorado. Kinder Morgan Power operates the Michigan facility for which it receives operating fees. Under the tolling agreements, purchasers of the electrical output take the commodity benefits and risks in the marketplace. Kinder Morgan Power's customers include power marketers and utilities. During 2003, approximately 30% of Power's operating revenues were electric sales revenues from XCEL Energy's Public Service Company of Colorado under a long-term contract,

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25% were for operating the Jackson, Michigan Power facility, and 21% were revenues related to the construction of the Jackson, Michigan power facility.

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 acquired the interests in three Colorado natural gas-fired electric generating facilities discussed above, which have a combined 380 megawatts of electric generation capacity. Kinder Morgan Power used the LM knowledge to develop its proprietary "Orion" technology. Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, in December 2003, we increased our investment in the Thermo Companies by issuing 1.8 million of Kinder Morgan Management shares to an entity controlled by the former Thermo owners. For further information regarding this incremental investment, see "Power" 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 in Wrightsville, Arkansas, utilizing Kinder Morgan Power's Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Kinder Morgan Power made an investment in the project company, comprised primarily of preferred stock. This facility has not been dispatched significantly since July 1, 2002. In October 2003, the project company was included in Mirant Corporation's bankruptcy filing. In the fourth quarter of 2003, we wrote off our remaining investment in the Wrightsville power facility, as further discussed in Note 6 of the accompanying Notes to Consolidated Financial Statements.

In February 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 of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC valued at approximately $105 million; and, (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. 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: With respect to the electric generating facilities acquired from 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 or generated for the local electric utility under long-term contracts. With respect to Power's investment in the Jackson, Michigan facility, the principal impact of competition is the level of dispatch of the plant and the related (but minor) effect on profitability.

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

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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.

On July 17, 2000, Natural Gas Pipeline Company of America filed its compliance plan, including pro forma tariff sheets, pursuant to FERC 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 these 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 relate 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. On May 14, 2003, the FERC issued an order accepting most of Natural Gas Pipeline Company of America's compliance filing, but requiring additional changes, particularly regarding the designation of additional primary points for a segmented release. This order also established an effective date for Natural Gas Pipeline Company of America's Order 637 provisions of December 1, 2003. Natural Gas Pipeline Company of America made its further compliance filing on June 13, 2003. Limited protests have been filed. The Order No. 637 tariff provisions for Natural Gas Pipeline Company of America became effective on December 1, 2003, although certain aspects of these provisions are subject to FERC review of the most recent compliance filing, which is still pending FERC action.

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 and (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. On January 29, 2004, the FERC issued an order denying rehearing and reaffirming these rulings.

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

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regulated subsidiary to a non-regulated parent company. Natural Gas Pipeline Company of America filed comments on August 28, 2002. On June 26, 2003, the FERC issued an interim rule to be effective in August 2003, under which regulated companies are required to document cash management arrangements and transactions. The FERC eliminated the proposal that, as a prerequisite to participation in cash management programs, regulated companies must maintain a 30 percent equity balance and investment grade credit rating. On October 22, 2003, the FERC issued its final rule amending its regulations effective November 2003 which, among other things, requires FERC-regulated entities to file their cash management agreements with the FERC and to notify the FERC within 45 days after the end of the quarter when their proprietary capital ratio drops below 30 percent, and when it subsequently returns to or exceeds 30 percent. In compliance with the final rule, Natural Gas Pipeline Company of America and TransColorado submitted their cash management agreements to the FERC in December 2003. On February 11, 2004, the FERC eliminated the notification requirement discussed preceding as part of issuing Order No. 646, which requires quarterly financial reporting.

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 November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate pipeline must file a compliance plan by that date and must be in full compliance with the Standards of Conduct by June 1, 2004. The primary change from existing regulation is to make such standards applicable to an interstate pipeline's interaction with many more affiliates (termed "Energy Affiliates"), including intrastate/Hinshaw pipelines, processors and gatherers and any company involved in gas or electric markets (such as electric generators and electric or gas marketers) even if they do not ship on the affiliated interstate pipeline. Local distribution companies are excluded, however, if they do not make sales to customers not situated on their gas distribution system. The Standards of Conduct require, inter alia, separate staffing of interstate pipelines and their Energy Affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from the interstate pipeline to an Energy Affiliate. Natural Gas Pipeline Company of America filed for clarification and rehearing of Order No. 2004 on December 29, 2003, and numerous other rehearing requests have been submitted. In the request for rehearing, Natural Gas Pipeline Company of America asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of Energy Affiliates.To date the FERC has not acted on these hearing requests. On February 9, 2004, Natural Gas Pipeline Company of America, TransColorado Gas Transmission Company, Canyon Creek Compression Company and Horizon Pipeline Company filed their compliance plans under Order No. 2004. In addition, on February 19, 2004, all of these interstate pipelines filed a joint request with the interstate pipelines owned by Kinder Morgan Energy Partners asking that their interaction with intrastate/Hinshaw pipeline affiliates be exempted from the Standards of Conduct. For us, the mandated separation from these entities would be the most burdensome requirement of the new rules.

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.

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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 Public Utilities Commission for the State of Colorado as a public utility with respect to its natural gas transportation and sales services within the state. Rocky Mountain Natural Gas Company also performs certain natural gas transportation services in interstate commerce pursuant to Section 311 of the Natural Gas Policy Act of 1978. The Public Utilities Commission for the State of Colorado 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 also 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 result in an 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, Nebraska and Wyoming are under the regulatory authority of each respective state's utility commission. 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, Nebraska 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 and is now available to all 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 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

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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, for which compliance is often costly 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 us, 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 toward 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, 2003 of approximately $14.5 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 currently 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

1.

We are highly dependent upon the earnings and distributions of Kinder Morgan Energy Partners. For 2003, approximately 45% of our total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners was attributable to our general and limited partner interests in Kinder Morgan Energy Partners. 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 these earnings and cash distributions, please see Kinder Morgan Energy Partners' 2003 Annual Report on Form 10-K.

2.

Competition could ultimately lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation capacity at favorable rates. For 2003, approximately 42% of our total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners were attributable to the results of operations of Natural Gas Pipeline Company of America, an interstate natural gas 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 expiringtransportation capacity at favorable rates could be impaired. Contracts representing approximately 10% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 7, 2004 are scheduled to expire during 2004.

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3.	Our large amount of floating rate debt makes us vulnerable to increases in interest rates. At December 31, 2003, we had approximately $1.628 billion of debt subject to floating interest rates. Approximately $1.5 billion of this debt was long-term debt converted to floating rates through the use of interest rate swaps. 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 natural gas 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 FERC or other regulatory agencies having jurisdiction could adversely impact our income and 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.

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8. 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.

9. 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 2003, 2002, and 2001 on research and development activities were not material. We employed 5,530 people at December 31, 2003, including employees of our indirect subsidiary KMGP Services Company, Inc., who are dedicated to the operations of Kinder Morgan Energy Partners.

KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, a subsidiary of Kinder Morgan Management, provides centralized payroll and employee benefits services to Kinder Morgan Management, Kinder Morgan Energy Partners and Kinder Morgan Energy Partners' operating partnerships and subsidiaries (collectively, "the Group"). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse 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. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, 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 the limited partnership agreement, Kinder Morgan Energy Partners provides reimbursement for its share of these administrative costs and such reimbursements are accounted for as described above. Kinder Morgan Energy Partners reimburses Kinder Morgan Management with respect to the costs incurred or allocated to Kinder Morgan Management in accordance with Kinder Morgan Energy Partners' limited partnership agreement, the Delegation of Control Agreement among Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy Partners and others, and Kinder Morgan Management's limited liability company agreement. Our named executive officers and other employees that provide management or services to both us and the Group are employed by us. Additionally, other of our employees assist Kinder Morgan Energy

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Partners in the operation of its Natural Gas Pipeline assets. These employees' expenses are allocated without a profit component between us and the appropriate members of the Group.

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.

(E) Available Information

We make available free of charge on or through our internet website, at http://www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Also, we make available free of charge within the "Investors" section of our internet website, at www.kindermorgan.com, and in print to any shareholder who requests, the governance guidelines, the charters of the audit committee, compensation committee and nominating and governance committee, and our code of business conduct and ethics (which applies to senior financial officers and the chief executive officer, among others). Requests for copies may be directed to Investor Relations, Kinder Morgan, Inc., 500 Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We intend to disclose any amendments to our code of business conduct and ethics, and any waiver from a provision of that code granted to our Chief Executive Officer, Chief Financial Officer or Vice President and Controller, on our internet website within five business days following such amendment or waiver. The information contained on or connected to our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the Securities and Exchange Commission.

Item 3.Legal Proceedings.

The reader is directed to Note 9(B) of the accompanying Notes to Consolidated Financial Statements, which is incorporated herein by reference.

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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	59	Director, Chairman and Chief Executive Officer
Michael C. Morgan	35	Director and President
C. Park Shaper	35	Vice President and Chief Financial Officer
David D. Kinder	29	Vice President, Corporate Development
Joseph Listengart	35	Vice President, General Counsel and Secretary
Deborah A. Macdonald	52	President, Natural Gas Pipelines
James E. Street	47	Vice President, Human Resources and Administration
Daniel E. Watson	45	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.

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C. Park Shaper is Director, Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and Vice President 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, and served as Treasurer of Kinder Morgan Management, LLC from February 2001 to January 2004. He has served as Treasurer of Kinder Morgan, Inc. from April 2000 to January 2004 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, and served as Treasurer of Kinder Morgan G.P., Inc. from April 2000 to January 2004. 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. 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 President, Natural Gas Pipelines in June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company of America from October 1999 to March 2003. 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.,

22

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.

23

PART II

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

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. In January 2004, we increased our quarterly common dividend to $0.5625 per share.

	Market Price Per Share
	2003		2002
	Low	High	Low	High
Quarter Ended:
March 31	$42.25	$46.85	$36.81	$57.50
June 30	$44.00	$56.97	$37.11	$52.62
September 30	$51.45	$54.97	$33.10	$44.02
December 31	$51.72	$59.27	$30.05	$42.98

	Dividends Paid Per Share
	2003	2002
Quarter Ended:
March 31	$0.15	$0.05
June 30	$0.15	$0.05
September 30	$0.40	$0.10
December 31	$0.40	$0.10
Stockholders as of February 12, 2004	38,000 (approximately)

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

Information required by this item is contained under the caption "Equity Compensation Plan Information" in our Proxy Statement related to the 2004 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.

Our Purchases of Our Common Stock

Period	Total Number of Shares Purchased1	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs2	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to   October 31, 2003	95,800	$ 53.95	8,941,800	$52,120,437
		=======	=========	===========
November 1 to   November 30, 2003	91,000	$ 52.60	9,032,800	$47,332,244
		=======	=========	===========
December 1 to   December 31, 2003	-	$     -	9,032,800	$47,332,244
		=======	=========	===========
Total	186,800	$ 53.23	9,032,800	$47,332,244
	=======	=======	=========	===========

1	All purchases were made pursuant to our repurchase plan.
2	On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million and $500 million in February 2002, July 2002 and November 2003, respectively.

24

Item 6.Selected Financial Data.

Five-Year Review
Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2003	2002	2001	2000	19991
	(In thousands except per share amounts)
Operating Revenues	$1,097,897	$1,015,255	$1,054,907	$2,678,956	$1,834,094
Gas Purchases and Other Costs of Sales	354,261	311,224	339,301	1,925,971	1,052,654
Other Operating Expenses2	387,543	467,364	331,287	357,842	485,738
Operating Income	356,093	236,667	384,319	395,143	295,702
Other Income and (Expenses)3	270,211	206,063	308	(87,977)	(81,151)
Income from Continuing Operations
Before Income Taxes	626,304	442,730	384,627	307,166	214,551
Income Taxes	244,600	135,019	159,557	123,017	79,124
Income from Continuing Operations	381,704	307,711	225,070	184,149	135,427
Loss from Discontinued Operations,
Net of Tax	-	(4,986)	-	(31,734)	(395,319)
Net Income (Loss)	381,704	302,725	225,070	152,415	(259,892)
Less-Preferred Dividends	-	-	-	-	129
Less-Premium Paid on Preferred
Stock Redemption	-	-	-	-	350
Earnings (Loss) Available for
Common Stock	$  381,704	$  302,725	$  225,070	$  152,415	$ (260,371)
	==========	==========	==========	==========	==========
Basic Earnings (Loss) Per Common Share:
Continuing Operations	$     3.11	$     2.52	$     1.95	$     1.62	$     1.68
Discontinued Operations	-	(0.04)	-	(0.28)	(4.92)
Total Basic Earnings (Loss)
Per Common Share	$     3.11	$     2.48	$     1.95	$     1.34	$    (3.24)
	==========	==========	==========	==========	==========
Number of Shares Used in Computing
Basic Earnings (Loss) Per Common Share	122,605	122,184	115,243	114,063	80,284
	==========	==========	==========	==========	==========
Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$     3.08	$     2.49	$     1.86	$     1.61	$     1.68
Discontinued Operations	-	(0.04)	-	(0.28)	(4.92)
Total Diluted Earnings (Loss) Per
Common Share	$     3.08	$     2.45	$     1.86	$     1.33	$    (3.24)
	==========	==========	==========	==========	==========
Number of Shares Used in Computing
Diluted Earnings (Loss) Per
Common Share	123,824	123,402	121,326	115,030	80,358
	==========	==========	==========	==========	==========
Dividends Per Common Share	$     1.10	$     0.30	$     0.20	$     0.20	$     0.65
	==========	==========	==========	==========	==========
Capital Expenditures4	$  160,804	$  174,953	$  124,171	$   85,654	$   92,841
	==========	==========	==========	==========	==========

1	Reflects the acquisition of Kinder Morgan (Delaware), Inc. on October 7, 1999.
2	Includes charges of $44.5 million and $134.5 million in 2003 and 2002, respectively, to reduce the carrying value of certain power assets; see Note 6 of the accompanying Notes to Consolidated Financial Statements.
3	Includes significant impacts from sales of assets. See Note 1 (Q) of the accompanying Notes to Consolidated Financial Statements.
4	Capital Expenditures shown are for continuing operations only.

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

	As of December 31,
	2003		2002		2001		2000		1999
	(In thousands except per share amounts)
Total Assets	$10,036,711		$10,102,750		$9,513,121		$8,396,678		$9,393,834
	===========		===========		==========		==========		==========
Capitalization:
Common Equity	$ 2,666,117	39%	$ 2,354,997	37%	$2,259,997	39%	$1,777,624	39%	$1,649,615	32%
Deferrable Interest   Debentures1	283,600	4%	-	-	-	-	-	-	-	-
Preferred Capital   Trust Securities1	-	-	275,000	4%	275,000	5%	275,000	6%	275,000	5%
Minority Interests	1,010,140	15%	967,802	15%	817,513	14%	4,910	-	9,523	-
Outstanding Notes   and Debentures2	2,837,487	42%	2,852,181	44%	2,409,798	42%	2,478,983	55%	3,293,326	63%
Total Capitalization	$ 6,797,344	100%	$ 6,449,980	100%	$5,762,308	100%	$4,536,517	100%	$5,227,464	100%
	===========	===	===========	===	==========	===	==========	===	==========	===
Book Value Per
Common Share	$     21.62		$     19.35		$    18.24		$    15.53		$    14.64
	===========		===========		==========		==========		==========

1	As a result of a recent change in accounting standards, the subsidiary trusts associated with these securities are no longer consolidated, effective December 31,  2003. See Note 20 of the accompanying Notes to Consolidated Financial Statements.
2	Excluding the value of interest rate swaps. See Note 14 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 (i) intangible assets acquired individually or with a group of other assets (but not those acquired in a business combination) at acquisition and (ii) 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,
	2003	2002	2001	2000	1999
	(In thousands, except per share amounts)
Reported Net Income (Loss)	$381,704	$302,725	$225,070	$152,415	$(259,892)
Add Back: Goodwill Amortization,
Net of Related Tax Benefit	-	-	16,198	17,368	5,449
Adjusted Net Income (Loss)	$381,704	$302,725	$241,268	$169,783	$(254,443)
	========	========	========	========	=========
Reported Earnings (Loss) per Diluted Share	$   3.08	$   2.45	$   1.86	$   1.33	$   (3.24)
	========	========	========	========	=========
Earnings (Loss) per Diluted Share, as Adjusted	$   3.08	$   2.45	$   1.99	$   1.48	$   (3.17)
	========	========	========	========	=========

26

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 7 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.

We are a provider of energy and related services through our direct ownership and operation of energy-related assets, and through our ownership interests in and operation of Kinder Morgan Energy Partners, a publicly traded master limited partnership. Our energy-related assets owned and operated directly (which, during 2004, are budgeted to contribute approximately 48% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners) include natural gas pipelines, natural gas storage facilities, retail natural gas distribution facilities and a relatively small investment in natural gas-fired power generation facilities. Our investment in Kinder Morgan Energy Partners, (which, during 2004, is budgeted to contribute approximately 52% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners) includes ownership of the general partner interest, as well as ownership of limited partner units and shares of Kinder Morgan Management, LLC.

As described under "Business Strategy" elsewhere in this report, our strategy and focus continues to be on ownership of fee-based energy-related assets which are core to the energy infrastructure of the country and serve growing markets. These assets tend to have relatively stable cash flows while presenting us with opportunities to expand our facilities to serve additional customers and nearby markets. We evaluate the performance of our investment in these assets using, among other measures, segment earnings and return on investment. We will define these measures and then present them by segment in the analysis of our results of operations that follows.

The variability of our operating results is attributable to a number of factors including (i) national and local markets for energy and related services, including the effects of competition, (ii) the impact of regulatory proceedings, (iii) the effect of weather on customer energy and related services usage, as well as our operation and construction activities, (iv) increases or decreases in interest rates, (v) the degree of our success in controlling costs and identifying and carrying out profitable expansion projects and (vi) changes in taxation policy or rates. Certain of these factors are beyond our direct control, but we operate a structured risk management program to mitigate certain of the risks associated with changes in the price of natural gas, interest rates and weather (relative to historical norms). The remaining risks are primarily mitigated through our strategic and operational planning and monitoring processes. See "Risk Factors" elsewhere in this report.

After the divestitures discussed above, our remaining businesses (apart from our investment in Kinder Morgan Energy Partners) 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

27

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 2003-2004 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 system, a 300-mile natural gas pipeline and related facilities extending from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico, (ii) our retail distribution of natural gas to approximately 241,000 customers in Colorado, Wyoming and Nebraska and (iii) our investment in, in some cases, operation of, and in previous periods construction of electric power generation facilities. The TransColorado 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 TransColorado that we did not already own from Questar Corp. in the fourth quarter of 2002 and have announced plans to expand the system (see "TransColorado" following and Note 4 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. We also revalued certain of our power assets during the fourth quarter of 2003. See "Power" following and Note 6 of the accompanying Notes to Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and results of 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. Certain of these accounting estimates 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 of 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

28

meters and, together with weather-related data that is indicative of natural gas demand, we are able to make reasonable 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.

With respect to the amount of income or expense we recognize in association with our 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. The selection of these assumptions is discussed in Note 15 of the accompanying Notes to Consolidated Financial Statements. While we believe our choices for these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of retiree medical funding, (i) a change of 1% in the long-term return assumption would increase (decrease) our annual retiree medical expense by approximately $5,680 ($5,234) in comparison to that recorded in 2003 and (ii) a 1% change in the discount rate would increase (decrease) our accumulated postretirement benefit obligation by $83,546 ($77,626) compared to those balances as of December 31, 2003.

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" in Item 7A of this report, we enter into derivative contracts (natural gas futures, swaps and options) solely for the purpose of mitigating risks that accompany our

29

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,
	2003	2002	2001
	(In thousands except per share amounts)
Operating Revenues	$1,097,897	$1,015,255	$1,054,907
Gas Purchases and Other Costs of Sales	354,261	311,224	339,301
General and Administrative Expenses	71,741	73,496	73,319
Other Operating Expenses1	315,802	393,868	257,968
Operating Income	356,093	236,667	384,319
Other Income and (Expenses)	270,211	206,063	308
Income Taxes	244,600	135,019	159,557
Income from Continuing Operations	381,704	307,711	225,070
Loss on Disposal of Discontinued Operations, Net of Tax	-	(4,986)	-
Net Income	$  381,704	$  302,725	$  225,070
	==========	==========	==========
Diluted Earnings Per Common Share:
Income from Continuing Operations	$     3.08	$     2.49	$     1.86
Loss on Disposal of Discontinued Operations	-	(0.04)	-
Total Diluted Earnings Per Common Share	$     3.08	$     2.45	$     1.86
	==========	==========	==========
Number of Shares Used in Computing Diluted Earnings     Per Common Share	123,824	123,402	121,326
	==========	==========	==========

¹ Includes charges of $44.5 million and $134.5 million in 2003 and 2002, respectively, to reduce the carrying value of certain power assets as discussed under "Power" following.

Our income from continuing operations increased from $307.7 million in 2002 to $381.7 million in 2003, an increase of $74.0 million (24.0%). This increase is comprised of increases of $119.4 million in operating income and $64.1 million in net other income and expenses, partially offset by an increase of $109.6 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 2003, in comparison to 2002, reflect increases of $82.6 million (8.1%) in operating revenues and $119.4 million (50.4%) in operating income. The increase in operating revenues was attributable to increased revenues in our Natural Gas Pipeline Company of America and TransColorado business segments, partially offset by decreased revenues in our Power and Kinder Morgan Retail business segments (see the individual business segment discussions following for additional 

30

information). Operating income was positively impacted in 2003, relative to 2002, by (i) a decrease of $90.0 million in 2003 for charges to reduce the carrying value of certain Power assets (see "Power" following), (ii) increased 2003 segment earnings from our Natural Gas Pipeline Company of America, TransColorado and Kinder Morgan Retail business segments, (iii) the inclusion in 2002 results of a $12.7 million charge related to certain long-term natural gas purchase contracts (see Note 1(N) of the accompanying Notes to Consolidated Financial Statements) and (iv) decreased 2003 general and administrative expenses. These positive impacts were partially offset by decreased 2003 segment earnings from our Power business segment.

Below the operating income line, net other income and expenses increased from income of $206.1 million in 2002 to income of $270.2 million in 2003, an increase of $64.1 million (31.1%). This increase reflected (i) increased equity in earnings of Kinder Morgan Energy Partners in 2003 due principally to the improved performance from the assets held by Kinder Morgan Energy Partners and (ii) decreased 2003 interest expense resulting principally from our lower debt balances. These positive impacts were partially offset by (i) an increase of $8.1 million in minority interest expense attributable to the minority interests in Kinder Morgan Management, LLC and (ii) a $17.4 million decrease in net gains from asset sales in 2003 (see Note 1(Q) of the accompanying Notes to Consolidated Financial Statements).

Our income from continuing operations increased from $225.1 million in 2001 to $307.7 million in 2002, an increase of $82.6 million (36.7%). This increase is comprised of a decrease of $147.7 million in operating income, an increase of $205.8 million in net other income and expenses and a decrease of $24.5 million in income tax expense. The $39.7 million decrease in operating revenues from 2001 to 2002 was attributable to decreased revenues in our Power and Kinder Morgan Retail business segments, partially offset by increased revenues in our Natural Gas Pipeline Company of America and TransColorado segments. Operating income was negatively impacted in 2002, relative to 2001, by (i) decreased earnings from our Power business segment, including a $134.5 million charge in 2002 to revalue certain investments (see "Power" following), (ii) a $12.7 million charge in 2002 related to certain long-term natural gas purchase contracts (see Note 1(N) of the accompanying Notes to Consolidated Financial Statements) and (iii) an increase of $5.0 million in general and administrative expenses principally due to increased employee benefit costs, exclusive of a 2001 charge related to Enron Corp. as discussed below. These negative impacts were partially offset by (i) increased earnings from our Natural Gas Pipeline Company of America, TransColorado 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 14 of the accompanying Notes to Consolidated Financial Statements).

Below the operating income line, net other income and expenses increased from income of $0.3 million in 2001 to income of $206.1 million in 2002, an increase of $205.8 million. This increase reflected (i) increased equity in earnings of Kinder Morgan Energy Partners in 2002 due, in part, to the improved 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(O) of the accompanying Notes to Consolidated Financial Statements), (ii) increased equity in earnings of other equity investments in 2002 (which are principally included in business segment earnings), (iii) decreased 2002 interest expense reflecting lower 2002 interest rates and borrowed balances and (iv) the inclusion, in 2001 results, of $20.3 million in expense related to the early extinguishment of debt (see Note 12(B) of the accompanying Notes to Consolidated Financial Statements). 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 net gains from asset sales in 2002 (see Note 1(Q) of the accompanying Notes to Consolidated Financial Statements).

31

Diluted earnings per share increased from $2.45 in 2002 to $3.08 in 2003, an increase of $0.63 (25.7%) reflecting, in addition to the financial and operating impacts discussed preceding, an increase of 0.4 million (0.3%) in average shares outstanding. Excluding the impact of discontinued operations in 2002, diluted earnings per share from continuing operations increased from $2.49 in 2002 to $3.08 in 2003, an increase of $0.59 (23.7%). Income from continuing operations included (i) pre-tax charges of $44.5 million and $134.5 million in 2003 and 2002, respectively, to reduce the carrying value of certain Power assets (see "Power" following), (ii) income tax adjustments that reduced 2002 income tax expense by approximately $42 million (see "Income Taxes - Continuing Operations" following), (iii) a $2.3 million pre-tax loss on early extinguishment of debt in 2002 and (iv) other non-recurring items aggregating $1.4 million in pre-tax charges in each of 2003 and 2002.

Diluted earnings per share increased from $1.86 in 2001 to $2.45 in 2002, an increase of $0.59 (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 impact of discontinued operations in 2002, diluted earnings per share from continuing operations increased from $1.86 in 2001 to $2.49 in 2002, an increase of $0.63 (33.9%). Income from continuing operations included (i) a pre-tax charge of $134.5 million in 2002 to reduce the carrying value of certain Power assets (see "Power" following), (ii) income tax adjustments that reduced 2002 income tax expense by approximately $42 million (see "Income Taxes - Continuing Operations" following), (iii) pre-tax losses on early extinguishment of debt of $2.3 million and $22.6 million in 2002 and 2001, respectively, and (iv) other non-recurring items aggregating $1.4 million in pre-tax charges in 2002 and $2.5 million in pre-tax income in 2001.

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 four business segments. In addition, we derive a substantial portion of earnings from our investment in Kinder Morgan Energy Partners, which is discussed under "Earnings from Investment in Kinder Morgan Energy Partners" following.

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
Retail Natural Gas Distribution	The regulated sale and transportation of natural gas to residential, commercial and industrial customers (including a small distribution system in Hermosillo, Mexico) and the sales of natural gas to certain utility customers under the Choice Gas program	Kinder Morgan Retail

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Power Generation

The operation and, in previous periods, construction of natural gas-fired electric generation facilities Power

In the fourth quarter of 2002, as further discussed under "Power" following, we decided to discontinue the development portion of our power generation business and decreased the carrying value of certain of our power assets. An additional reduction in the carrying value of certain power assets was made in the fourth quarter of 2003. 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'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 earnings 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. 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. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

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

	Year Ended December 31,
	2003	2002	2001
	(In thousands except systems throughput)
Operating Revenues	$  784,732	$  699,998	$  646,804
	==========	==========	==========
Gas Purchases and Other Costs of Sales	$  226,599	$  160,849	$  131,444
	==========	==========	==========
Segment Earnings	$  372,017	$  359,911	$  346,569
	==========	==========	==========
Systems Throughput (Trillion Btus)	1,508.5	1,480.5	1,398.9
	==========	==========	==========

Natural Gas Pipeline Company of America's segment earnings increased from $359.9 million in 2002 to $372.0 million in 2003, an increase of $12.1 million (3.4%). The increase in operating revenues, which was largely offset by a corresponding increase in cost of sales, was due to increased revenues from 2003 operational natural gas sales and increased transportation and storage revenues, largely due to expansions/extensions of pipeline and storage facilities. Segment earnings for 2003 were positively impacted, relative to 2002, by (i) increased margin from transportation and storage services, including operational natural gas sales, primarily resulting from expansion and extension projects coming on line since the end of the second quarter of last year as discussed below and (ii) increased margin associated with a regulatory matter that was recently concluded. These positive impacts were partially offset by (i)

33

increased depreciation expense related to the expansion and extension projects and (ii) increased ad valorem taxes. Natural Gas Pipeline Company of America's segment results for 2003 do not include a reduction of $4.1 million in interest expense attributable to the final settlement of a regulatory matter, which amount is included in "Interest Expense, Net" as discussed elsewhere herein. System throughput increased by 28.0 trillion Btus (1.9%) from 2002 to 2003 due, in part, to colder than normal weather in this segment's principal market areas, partially offset by lower volumes on the short-haul Louisiana Line caused by reduced eastern market demand off this part of the system. The increase in system throughput in 2003 did not have a significant direct impact on revenues 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.

Horizon Pipeline Company, which provides natural gas transportation capacity to the growing northern Illinois market, began service in the second quarter of 2002. Horizon Pipeline Company is a joint venture with Nicor Inc. Natural Gas Pipeline Company of America's lateral extension into the eastern portion of the St. Louis metropolitan area began service in the third quarter of 2002. During April 2003, Natural Gas Pipeline Company of America began construction of 10.7 Bcf of storage service expansion at its existing North Lansing storage facility in east Texas, all of which is fully subscribed under long-term contracts. Although construction on this approximately $38 million project is not expected to be completed until May 2004, the service is available at this time.

Natural Gas Pipeline Company of America's segment earnings increased from $346.6 million in 2001 to $359.9 million in 2002, an increase of $13.3 million (3.8%). The increase in operating revenues, which was largely offset by a corresponding increase in cost of sales, was due to increased revenues from 2002 operational natural gas sales and increased transportation and storage revenues, largely due to expansions/extensions of pipeline systems coming on line in 2002. Segment earnings 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 into the eastern portion of the St. Louis metropolitan area, (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 direct impact on revenues or segment earnings due to the "demand" component of transportation contracts, as discussed previously.

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 67% of the total transportation volume committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts in effect on January 7, 2004 had remaining terms of less than three years. Contracts representing approximately 10% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 7, 2004 are scheduled to expire during 2004. Natural Gas Pipeline Company of America continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts. 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 2004, we currently expect that Natural Gas Pipeline Company of America will experience 3%

34

growth in segment earnings in comparison to 2003. This increase in earnings is expected to be derived primarily from (i) the impact of having a full year of earnings from the North Lansing storage expansion project, and (ii) transportation revenue increases resulting from higher rates being contracted for on base transport business. 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" in Item 7A of this report and in Note 14 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

	Year Ended December 31,
	2003	2002	2001
	(In thousands except systems throughput)
Operating Revenues	$  32,197	$   7,818	$       -
	=========	=========	=========
Gas Purchases and Other Costs of Sales	$     608	$       -	$       -
	=========	=========	=========
Segment Earnings (Losses)	$  23,112	$  12,648	$  (5,268)
	=========	=========	=========
Systems Throughput (Trillion Btus)	168.9	155.8	103.1
	=========	=========	=========

TransColorado 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'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. TransColorado's segment earnings increased from $12.6 million in 2002 to $23.1 million in 2003. Results for 2003, relative to 2002, reflected, in addition to a full year at the increased level of ownership, the favorable impact of wide basis differentials on certain transportation contracts. These basis differentials have narrowed since mid 2003. As a result of its contracting activities as discussed below, the contractual volume of activity that is suject to changes in basis differentials has decreased.

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The significant improvement in TransColorado's operating results from 2001 to 2002, apart from the change in our ownership percentage, resulted 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 and the limited pathways for this natural gas to get to markets both east and west of these production areas. Due in large part to this increased demand, TransColorado has sold out its available firm capacity through October 2004.

On September 25, 2003, we announced that we had signed a 10-year, firm natural gas transportation contract with an undisclosed shipper that will allow us to construct facilities that will result in a 125,000 dekatherm per day expansion of capacity on the TransColorado system. The facilities consist of three new compressor stations and modifications at two existing compressor stations, which will increase compression by more than 20,000 horsepower. On October 31, 2003, we filed with the FERC for authority to construct the facilities and place them into service. Subject to appropriate regulatory approvals, we expect to place the facilities into service during the third quarter of 2004.

The TransColorado open season for various supply laterals, mainline capacity expansion and mainline extension proposals ended April 30, 2003. Post open season negotiations successfully led to the filing discussed above of the mainline capacity expansion application with the FERC. Negotiations with prospective shippers regarding the proposed mainline extension were primarily linked to downstream capacity negotiations on Kinder Morgan Energy Partners' proposed Silver Canyon Pipeline project. Accordingly, Kinder Morgan Energy Partners is now negotiating with prospective shippers on the proposed Silver Canyon Pipeline to include previously identified TransColorado mainline extension facilities as part of the Silver Canyon Pipeline project.

For 2004, we currently expect that TransColorado will experience 13% growth in segment earnings in comparison to 2003. This earnings increase is expected to be driven by incremental revenues from the expansion and contract renewals at higher transport rates. However, certain market factors are largely beyond our control and, as discussed following, TransColorado is subject to federal regulation. For these and other reasons, its actual future results may differ significantly from our projections. In addition, we and Kinder Morgan Energy Partners have announced that we are considering the transfer of TransColorado to Kinder Morgan Energy Partners, subject to various factors, including obtaining fairness opinions with respect to any such transaction for both us and Kinder Morgan Energy Partners.

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 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.

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Kinder Morgan Retail

	Year Ended December 31,
	2003	2002	2001
	(In thousands except systems throughput)
Operating Revenues	$   249,119	$   259,748	$   290,344
	===========	===========	===========
Gas Purchases and Other Costs of Sales	$   122,204	$   133,857	$   177,675
	===========	===========	===========
Segment Earnings	$    65,482	$    64,056	$    56,696
	===========	===========	===========
Systems Throughput (Trillion Btus)	48.0	42.4	42.0
	===========	===========	===========

Kinder Morgan Retail's segment earnings increased from $64.1 million in 2002 to $65.5 million in 2003, an increase of $1.4 million (2.2%). The decrease in operating revenues in 2003, relative to 2002, principally resulted from a full year of our Choice Gas Program in certain of our service territories. The Choice Gas Program allows competing commodity natural gas providers to sell natural gas to customers connected to our natural gas distribution system, which decreases our revenues from natural gas sales (accompanied by a corresponding decrease in gas purchase costs), although we continue to receive the same margin for transporting the gas. The increase in throughput volumes in 2003 was the result of (i) increased demand for natural gas used in space heating as a result of colder weather and (ii) continued customer growth, partially offset by lower irrigation season demand. Segment earnings were positively impacted in 2003, relative to 2002, by (i) increased margins resulting from a full year of our Choice Gas commodity program in certain of our service territories, (ii) continued customer growth in existing service territories, particularly Colorado, and (iii) reduced operations and maintenance expenses. These positive impacts were partially offset by (i) reduced demand during irrigation season, (ii) increased depreciation expense resulting from asset additions and (iii) the inclusion in 2002 results of a $1.6 million ad valorem tax refund from an affiliated shipper. Our weather hedging program continued to contribute to stability in Kinder Morgan Retail's earnings pattern by reducing the impact of weather-related demand fluctuations (see Note 14 of the accompanying Notes to Consolidated Financial Statements).

Kinder Morgan Retail's segment earnings increased from $56.7 million in 2001 to $64.1 million in 2002, an increase of $7.4 million (13.1%). The decrease in operating revenues in 2002, relative to 2001, was principally due to lower natural gas prices in 2002 and was offset by lower costs for natural gas purchases. Segment earnings 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 the 2002 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. These positive impacts were partially offset by higher operations, maintenance and depreciation expenses in 2002 principally attributable to the newly acquired facilities.

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 2004, we currently expect that Kinder Morgan Retail will experience approximately 5% 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

37

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. For these and other reasons, 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 each respective state's utility commission 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

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Operating Revenues	$    31,849	$    47,784	$   119,832
	===========	===========	===========
Gas Purchases and Other Costs of Sales	$     4,850	$     3,943	$    32,255
	===========	===========	===========
Segment Earnings1	$    22,076	$    36,673	$    65,983
	===========	===========	===========

¹ Excludes charges of $44.5 million and $134.5 million in 2003 and 2002, respectively, to reduce the carrying value of certain assets, and a loss of $2.9 million in 2003 resulting from the sale of natural gas reserves by an equity-method investee. These charges are discussed below.

Beginning with 2002, results for this segment include only the results of our Power business. Segment revenues and segment earnings, as reported above, decreased by $15.9 million and $14.6 million, respectively, from 2003 to 2002. These decreases were expected, and principally resulted from reduced development fees due to the 2002 completed construction of the Jackson, Michigan and Wrightsville, Arkansas power plants, as well as our decision to exit the power development business. This decision is discussed below, as well as the reductions we recorded during 2002 and 2003 in the carrying value of certain of our power investments.

Excluding the operating results of the Wattenberg facilities that were sold in 2001 as discussed below, segment revenues, and segment earnings decreased by $9.1 million and $8.1 million, respectively, from 2001 to 2002. Power's reduced 2002 earnings reflected 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(O) of the accompanying Notes to Consolidated Financial Statements). Operating results of this segment for 2001 included $62.9 million of revenue 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.

In February 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

38

1, 2002, construction of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC valued at approximately $105 million; and, (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. 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. 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 2004 from this preferred investment. Due to a recent change in accounting standards, effective December 31, 2003, we began consolidating Triton Power Company, LLC (see Note 20 of the accompanying Notes to Consolidated Financial Statements).

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 in Wrightsville, Arkansas, utilizing Kinder Morgan Power's Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Kinder Morgan Power made an investment in the project company, comprised primarily of preferred stock. This facility has not been dispatched significantly since July 1, 2002. During the third quarter of 2003, we announced that Mirant had placed the Wrightsville, Arkansas plant in bankruptcy in October, and we would assess the long-term prospects for this facility during the fourth quarter. In December 2003, we completed our analysis and determined that it was no longer appropriate to assign any carrying value to our investment in this facility and recorded a $44.5 million pre-tax charge, effectively writing off our remaining investment in the Wrightsville power facility.

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 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 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.

Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, in December 2003, we made an additional investment in our Colorado power businesses in the form of approximately 1.8 million Kinder Morgan Management shares that we owned. We delivered these shares to an entity controlled by the former Thermo owners, which entity is required to retain the shares until they vest (400,000 shares will vest each January 1 of 2004, 2005 and 2006, with the remainder vesting on January 1, 2007). We will continue to receive distributions made by Kinder Morgan Management attributable to the unvested shares. We recorded our increased investment based on the third-party-determined $56.1 million fair value of the shares as of the contribution date, with a corresponding liability representing our obligation to deliver vested shares in the future. The effect of

39

this incremental investment will be to increase our ownership interest in the Thermo entities beginning in 2010.

We expect that 2004 segment earnings from Power will decline by approximately 39% due to discontinuing power plant development. Actual future results may differ significantly from our projections.

Earnings from Investment in Kinder Morgan Energy Partners

The impact on our pre-tax earnings from our investment in Kinder Morgan Energy Partners, was as follows:

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
General Partner Interest, Including Minority    Interest in the Operating Limited Partnerships	$333,675	$277,024	$206,705
Limited Partner Units (Kinder Morgan    Energy Partners)	36,516	42,920	42,397
Limited Partner i-units (Kinder Morgan Management)	94,776	72,191	28,402
	464,967	392,135	277,504
Amortization of Equity-method Goodwill	-	-	(25,644)
Pre-tax Minority Interest in Kinder Morgan    Management	(66,642)	(53,631)	(23,980)
Pre-tax Earnings from Investment in Kinder        Morgan Energy Partners	$398,325	$338,504	$227,880
	========	========	========

For 2004, pre-tax earnings attributable to our investment in Kinder Morgan Energy Partners are expected to increase by approximately 15% due to, among other factors, improved performance from 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. Additional information on Kinder Morgan Energy Partners is contained in its Annual Report on Form 10-K for the year ended December 31, 2003.

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Other Income and (Expenses)

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Interest Expense, Net	$  (139,588)	$  (161,935)	$  (216,200)
Interest Expense - Capital Trust Securities1	(10,956)	-	-
Equity in Earnings of Kinder Morgan Energy Partners:
Equity in Earnings	464,967	392,135	277,504
Amortization of Equity-method Goodwill	-	-	(25,644)
Equity in Earnings of Power Segment2	8,839	7,674	5,299
Equity in Earnings of Horizon Pipeline	1,501	1,316	-
Equity in Earnings (Losses) of TransColorado	-	3,980	(5,268)
Other Equity in Earnings (Losses)3	(2,889)	(179)	214
Minority Interests	(52,493)	(55,720)	(36,740)
Net Gains (Losses) from Sales of Assets	(4,423)	13,030	22,621
Other, Net	5,253	8,111	1,131
Loss on Early Extinguishment of Debt	-	(2,349)	(22,609)
	$   270,211	$   206,063	$       308
	===========	===========	===========

1	Prior to July 1, 2003, expenses associated with these securities are included under "Minority Interests."
2	Excludes a loss of $2.9 million in 2003 resulting from the sale of natural gas reserves by an equity-method investee.
3	Includes a loss of $2.9 million in 2003 resulting from the sale of natural gas reserves by an equity-method investee.

"Other Income and (Expenses)" increased from income of $206.1 million in 2002 to income of $270.2 million in 2003, an increase of $64.1 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 (ii) decreased interest expense, reflecting reduced interest rates and reduced debt outstanding. These positive impacts were partially offset by (i) a $17.5 million decrease in 2003 gains from sales of assets and (ii) a $4.0 million decrease in equity in earnings of TransColorado, which is now 100% owned by us.

"Other Income and (Expenses)" increased from income of $308,000 in 2001 to income of $206.1 million in 2002, an increase of $205.8 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(O) of the accompanying Notes to Consolidated Financial Statements), (ii) decreased interest expense, reflecting reduced interest rates and reduced debt outstanding, (iii) increased earnings from other equity investments, principally TransColorado and (iv) the inclusion in 2001 of a $22.6 million loss on early extinguishment of debt. 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.

Income Taxes - Continuing Operations

The income tax provision increased from $135.0 million in 2002 to $244.6 million in 2003, an increase of $109.6 million (81.2%) due mainly to an increase of $183.6 million in income from continuing operations before income taxes. In addition, the income tax provision for 2002 was lower due to the combined impacts of (i) a decrease of approximately $21.0 million due to the impact of the lower effective tax rate on previously recorded deferred tax liabilities, (ii) 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

41

those previously accrued and (iii) a decrease of approximately $3.6 million due to the impact of a dividends received deduction.

The income tax provision increased from $159.6 million in 2001 to $135.0 million in 2002, a decrease of $24.6 million (15.4%) despite an increase of $58.1 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 and (ii) decreases in the 2002 tax provision as mentioned above.

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 in Hermosillo, Mexico) which, in the fourth quarter of 2000, we decided to retain. 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 $5.4 million at December 31, 2003 associated with these discontinued operations, due to an indemnification obligation. We do not expect significant additional financial impacts associated with these matters. Note 7 of the accompanying Notes to Consolidated Financial Statements contains certain additional financial information with respect to these discontinued operations.

Liquidity and Capital Resources

Primary Cash Requirements

Our primary cash requirements, in addition to normal operating, general and administrative expenses, are for debt service, capital expenditures, common stock repurchases and quarterly cash dividends to our common shareholders. Our capital expenditures other than sustaining capital expenditures, our common stock repurchases and our quarterly cash dividends to our common shareholders are discretionary. We expect to fund these expenditures with existing cash and cash flows from operating activities. In addition to utilizing cash generated from operations, we could meet these cash requirements through borrowings under our credit facilities, issuing short-term commercial paper, long-term notes or additional shares of common stock.

Invested Capital

The following table illustrates the sources of our invested capital. Our ratio of total debt to total capital has declined significantly since 2001, and even more significantly in comparison to earlier periods. This decline has resulted from a number of factors, including our increased cash flows from operations as discussed under "Cash Flows" following. In recent periods, we have significantly increased our dividends per share and have announced our intention to consider further increases on an annual basis, and we maintain an ongoing program to repurchase outstanding shares of our common stock. For these reasons, among others, any declines in our ratio of total debt to total capital in the future may be smaller.

In addition to the direct sources of debt and equity financing shown in the following table, we obtain financing indirectly through our ownership interests in unconsolidated entities as shown under

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"Significant Financing Transactions" following. Our largest such unconsolidated investment is in Kinder Morgan Energy Partners. See "Investment in Kinder Morgan Energy Partners" following. In addition to our results of operations, these balances are affected by our financing activities as discussed following.

	December 31,
	2003	2002	2001
	(Dollars in thousands)
Long-term Debt:
Outstanding Notes and Debentures	$ 2,837,487	$ 2,852,181	$ 2,409,798
Deferrable Interest Debentures Issued to Subsidiary Trusts1	283,600	-	-
Value of Interest Rate Swaps2	88,242	139,589	(4,831)
	3,209,329	2,991,770	2,404,967
Minority Interests	1,010,140	967,802	817,513
Common Equity	2,666,117	2,354,997	2,259,997
Capital Trust Securities1	-	275,000	275,000
	6,885,586	6,589,569	5,757,477
Less Value of Interest Rate Swaps	(88,242)	(139,589)	4,831
Capitalization	6,797,344	6,449,980	5,762,308
Short-term Debt, Less Cash and Cash Equivalents3	121,824	465,614	613,918
Invested Capital	$ 6,919,168	$ 6,915,594	$ 6,376,226
	===========	===========	===========
Capitalization:
Outstanding Notes and Debentures	41.7%	44.2%	41.8%
Minority Interests	14.9%	15.0%	14.2%
Common Equity	39.2%	36.5%	39.2%
Capital Trust Securities	-	4.3%	4.8%
Deferrable Interest Debentures Issued to Subsidiary Trusts	4.2%	-	-
Invested Capital:
Total Debt4	42.8%	48.0%	47.4%
Equity, Including Capital Trust Securities, Deferrable        Interest Debentures Issued to Subsidiary Trusts and        Minority Interests	57.2%	52.0%	52.6%

1	As a result of a recent change in accounting standards effective December 31, 2003, the subsidiary trusts associated with these securities are no longer consolidated. See Note 20.
2	See "Significant Financing Transactions" following.
3	Cash and cash equivalents netted against short-term debt were $11,076, $35,653 and $16,134 for December 31, 2003, 2002 and 2001, respectively.
4	Outstanding notes and debentures plus short-term debt, less cash and cash equivalents.

Short-term Liquidity

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, 2003, we had available a $445 million 364-day facility dated October 14, 2003, and a $355 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, 2003 and February 12, 2004, we had $127.9 million and $128.4 million, respectively, of commercial paper issued and outstanding. After inclusion of applicable letters of credit, the remaining available borrowing capacity under the bank facilities was $641.7 million and $637.3 million at December 31, 2003 and February 12, 2004, respectively. 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

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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 $5.0 million at December 31, 2003 consisted of current maturities of our $50 million of 6.50% Series Debentures due September 1, 2013. Apart from our notes payable and current maturities of long-term debt, our current liabilities, net of our current assets, represents an additional short-term obligation of approximately $67.1 million at December 31, 2003. 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.

Significant Financing Transactions

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. We recorded a 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 "Other, Net" in the accompanying Consolidated Statements of Operations for 2002.

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. We issued these Floating Rate Notes on October 10, 2001. Effective September 1, 2002, we retired our $24 million of 7.85% Series Debentures due September 1, 2022 at par. We recorded a 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 November 18, 2002, we completed 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 we also exchanged for registered securities pursuant to our currently effective registration statement on Form S-4, in an exchange offer that was completed on March, 21, 2003.

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 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

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Debentures due 2020, utilizing a combination of cash and incremental short-term borrowings. In conjunction with these early extinguishments of debt, we recorded losses of $13.6 million (net of associated tax benefit of $9.0 million). These losses are included under the caption, "Other, Net" in the accompanying Consolidated Statements of Operations for 2001.

On August 14, 2001, we announced a program to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million and $500 million in February 2002, July 2002 and November 2003, respectively. As of December 31, 2003, we had repurchased a total of approximately $452.7 million (9,032,800 shares) of our outstanding common stock under the program, of which $38.0 million (724,600 shares) and $144.3 million (3,013,400 shares) were repurchased in the years ended December 31, 2003 and 2002, respectively. In January 2003, our board of directors approved a plan to purchase shares of Kinder Morgan Management on the open market. During 2003 we repurchased $0.9 million (29,000 shares) of Kinder Morgan Management stock.

As further described under "Risk Management" in Item 7A of this report, we had outstanding fixed-to-floating interest rate swap agreements with a notional principal amount of $1.5 billion at December 31, 2003. These agreements, entered into in August 2001, September 2002 and November 2003, effectively convert the interest expense associated with our 7.25% Debentures due in 2028 and our 6.50% Senior Notes due in 2012 from fixed to floating rates based on the three-month London Interbank Offered Rate ("LIBOR") plus a credit spread. These swaps are accounted for as fair value hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

On March 3, 2003, we terminated the interest rate swap agreements associated with our 6.65% Senior Notes due in 2005 and received $28.1 million. We are amortizing this amount (as a reduction to interest expense) over the remaining period the 6.65% Senior Notes are outstanding. The unamortized balance of $16.4 million at December 31, 2003 is included in the caption "Value of Interest Rate Swaps" under the heading "Long-term Debt" in the accompanying Consolidated Balance Sheet.

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 of $991.9 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. 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. 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. 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, we purchased 10 percent of Kinder Morgan Management's shares, 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 2003 and 2002, in order to maintain our one percent general

45

partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $1.8 million and $3.4 million, respectively. The earnings recorded by Kinder Morgan Management that are attributable to its shares held by the public are reported as "Minority Interests" 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 2003 Annual Report on Form 10-K.

We have invested in entities that are not consolidated in our financial statements. Additional information regarding the nature and business purpose of these investments is included in Notes 2 and 5 of the accompanying Notes to Consolidated Financial Statements. Our obligations with respect to these investments are summarized following.

Off-Balance Sheet Arrangements

	At December 31, 2003
Entity	Investment Amount	Investment Percent	Entity Assets1	Entity Debt	Incremental Investment Obligation	Our Debt Responsibility
	(Millions of Dollars)

Ft. Lupton Power Plant	$  142.42	49.5%	$  151.2	$  115.23	-	$      -
Horizon Pipeline
Company	19.3	50.0%	90.2	49.53	-	-
Kinder Morgan Energy
Partners	3,053.9	19.0%	9,139.2	4,440.45	-4	522.75

1	At recorded value, in each case consisting principally of property, plant and equipment.
2	Does not include any portion of the goodwill recognized in conjunction with the 1998 acquisition of the Thermo Companies.
3	Debtors have recourse only to the assets of the entity, not to the owners.
4	When Kinder Morgan Energy Partners issues additional equity, we are required to contribute an amount to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships. See "Investment in Kinder Morgan Energy Partners" following.
5	We would only be obligated if Kinder Morgan Energy Partners and/or its assets cannot satisfy its obligations. In addition, Kinder Morgan G.P., Inc., our subsidiary that is the general partner of 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.

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Aggregate Contractual 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	$3,126.6	$    5.0	$  510.0	$  310.0	$2,301.6
Operating Leases1	585.9	31.1	60.4	56.4	438.0
Gas Purchase Contracts2	26.9	7.8	13.4	5.7	-
Discontinued Operations Indemnification3	5.4	0.6	3.4	1.4	-
Pension and Postretirement Benefit Plans4
Total Contractual Cash Obligations	$3,744.8	$   44.5	$  587.2	$  373.5	$2,739.6
	========	========	========	========	========
Other Commercial Commitments:
Standby Letters of Credit5	$   30.4	$   30.4	$      -	$      -	$      -
	========	========	========	========	========
Capital Expenditures6	$   75.6	$   75.6	$      -	$      -	$      -
	========	========	========	========	========

1	Approximately $540.9 million, $21.7 million, $40.6 million, $41.0 million and $437.6 million in each respective column is attributable to the lease obligation associated with the Jackson, Michigan power generation facility. The project company that is the lessee of this facility is now consolidated as a result of the adoption of a recent accounting pronouncement; see "Recent Accounting Pronouncements" elsewhere in this report.
2	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(N) of the accompanying Notes to Consolidated Financial Statements.
3	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 $4.9 million as of December 31, 2003 will be settled as these volumes are sold and the indemnification payments are made.
4	We currently do not expect to make significant contributions to these plans in the next few years, although we could elect or be required to make such contributions depending on, among other factors, the return generated by plan assets and changes in actuarial assumptions.
5	The $30.4 million in letters of credit outstanding at December 31, 2003 consisted of the following: (i) four letters of credit, totaling $8.0 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 $1.0 million letter of credit supporting a utility service contract between Entergy Gulf States, Inc. and Natural Gas Pipeline Company of America, (iv) a $6.6 million letter of credit associated with the outstanding debt of Thermo Cogeneration Partnership, L.P., the entity responsible for the operation of our Colorado power generation assets and (v) a $1.8 million letter of credit supporting Thermo Cogeneration Partnership, L.P.'s performance under its contract with Public Service Company of Colorado, the principal customer of our Colorado power generation assets.
6	The 2004 capital expenditure budget totals approximately $163.6 million. Approximately $75.6 million of this amount had been committed for the purchase of plant and equipment at December 31, 2003.

We expect to have sufficient liquidity to satisfy our near-term obligations through the combination of free cash flow and our credit facilities totaling $800 million.

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Contingent Liabilities:	Contingency	Amount of Contingent Liability at December 31, 2003
Guarantor of the Bushton Gas   Processing Plant Lease1	Default by ONEOK, Inc.	Total $210 million; Averages $23 million per year through 2012
Jackson, Michigan Power Plant    Incremental Investment	Operational Performance	$3 to 8 million per year for 15 years
Jackson, Michigan Power Plant    Incremental Investment	Cash Flow Performance	Up to a total of $25 million beginning in the 17th year following commercial operations

¹ 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.

Investment in Kinder Morgan Energy Partners

At December 31, 2003, 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 32.8 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 14.5 million i-units, represent approximately 17.4 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 19.0 percent of Kinder Morgan Energy Partners' total equity interests at December 31, 2003. 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 2003 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.

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.

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.

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Net Cash Flows from Operating Activities

"Net Cash Flows Provided by Operating Activities" increased from $443.0 million in 2002 to $587.1 million in 2003, an increase of $144.1 million (32.5%). This positive variance is principally due to (i) a $58.7 million increase in cash distributions received in 2003 attributable to our interests in Kinder Morgan Energy Partners (see the discussion following), (ii) $28.1 million of cash proceeds received in 2003 from termination of an interest rate swap, (iii) an increase of $44.8 million in cash inflows from gas in underground storage during 2003 (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), (iv) a $13.6 million decrease in cash outflows during 2003 for pension contributions in excess of expense and (v) the fact that cash flows in 2002 included $22.1 million of cash outflows for a litigation settlement. These positive impacts were partially offset by an increase of $12.8 million in 2003 cash outflows for deferred purchased gas costs.

"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. 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 the Employee Retirement Income Security Act of 1974, as amended, minimum contribution guidelines.

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 2003, 2002 and 2001 reflect the receipt of $369.0 million, $310.3 million and $238.8 million, respectively, of cash distributions from Kinder Morgan Energy Partners for (i) the fourth quarter of 2002 and the first nine months of 2003, (ii) the fourth quarter of 2001 and the first nine months of 2002 and (iii) the fourth quarter of 2000 and the first nine months of 2001, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2003 total $101.4 million and $383.5 million, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2002 total $86.9 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 increases in distributions during 2003 and 2002 reflect, 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 $835.3 million in 2002 to $157.3 million in 2003, a decrease of $678.0 million (81.2%). This decreased use of cash is principally due to the fact that 2002 included (i) a $331.9 million investment in i-units of Kinder Morgan Energy Partners, (ii) a $183.6 million cash outflow for investments in power plant facilities, (iii) payment of $95.6 million (net

49

of cash acquired) for the acquisition of the remaining 50% interest in the TransColorado system, (iv) $38.4 million in capital expenditures for the Natural Gas Pipeline Company of America pipeline extension to East St. Louis, Illinois, (v) $25 million for acquisition of the Sayre natural gas storage facility and (vi) a $16.5 million investment in Horizon Pipeline Company.

"Net Cash Flows Used in Investing Activities" decreased from $1,274.7 million 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 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).

Total proceeds received in 2001 from asset sales were $32.8 million, of which $25.7 million represented proceeds from the 2000 sale to ONEOK of our gathering and processing businesses in Oklahoma, Kansas and West Texas as well as our marketing and trading business.

Net Cash Flows from Financing Activities

"Net Cash Flows (Used in) Provided by Financing Activities" decreased from a source of $411.8 million in 2002 to a use of $454.4 million in 2003, an increased net cash use of $866.2 million. This increased net use of cash was principally due to (i) $500 million of cash used in 2003 to retire our $500 million 6.45% Senior Notes, (ii) an increase of $98.6 million paid in 2003 for dividends, principally due to the increased dividends declared per share (see discussion following in this section) and (iii) the fact that 2002 included proceeds, net of issuance costs, of $328.6 million from the issuance of Kinder Morgan Management shares and $995.6 million of net proceeds from the issuance of our 6.50% Senior Notes due September 1, 2012. Partially offsetting these factors were (i) a $551.7 million increase during 2003 in cash flows related to short-term borrowing, (ii) the fact that 2002 included cash used for repayment of $200 million of Floating Rate Notes and $60.5 million 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 12 of the accompanying Notes to Consolidated Financial Statements), (iii) a $111.1 million decreased use of cash during 2003 to repurchase shares and (iv) a $108.9 million increased source of cash from net repayment of short-term advances to unconsolidated affiliates during 2003.

"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 million, 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 12 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 12 of the accompanying Notes to Consolidated Financial Statements) and (iii) a reduction of $116.6 million in 2002 purchases of treasury stock.

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Total cash payments for dividends were $135.3 million, $36.7 million and $22.9 million in 2003, 2002 and 2001, respectively. The increases in these amounts are principally due to increases in the dividends declared per common share and, to a minor extent, to increased shares outstanding. In January 2004, we increased our quarterly common dividend to $0.5625 per share ($2.25 annualized) and announced our expectation for annual increases in the dividend in the future. On February 13, 2004, we paid a dividend at the increased rate of $0.5625 per share to shareholders of record as of January 30, 2004.

Litigation and Environmental

Our anticipated environmental capital costs and expenses for 2004, including expected costs for remediation efforts, are approximately $5.7 million, compared to approximately $2.3 million of such costs and expenses incurred in 2003. 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 $14.4 million at December 31, 2003, 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 9(A) and 9(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

On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to govern interactions between interstate natural gas pipelines and their affiliates. These affiliates include intrastate/Hinshaw pipelines, processors and gatherers and any company involved in gas or electric markets, even if they do not ship on the affiliated interstate pipeline. On February 9, 2004, Natural Gas Pipeline Company of America, TransColorado Gas Transmission Company, Canyon Creek Compression Company and Horizon Pipeline Company filed their compliance plans under Order No. 2004. In addition, on February 19, 2004, all of these interstate pipelines filed a joint request with the interstate pipelines owned by Kinder Morgan Energy Partners asking that their interaction with intrastate/Hinshaw pipeline affiliates be exempted from the Standards of Conduct. We expect the one-time costs of compliance with the Order, assuming the request to exempt intrastate pipeline affiliates is granted, to range from $600,000 to $700,000, to be shared between us and Kinder Morgan Energy Partners.

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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.

See Note 8 of the accompanying Notes to Consolidated Financial Statements and "Business and Properties - Regulation" in Items 1 and 2 for additional information regarding regulatory matters.

Recent Accounting Pronouncements

Refer to Note 20 of the accompanying Notes to Consolidated Financial Statements for information regarding recent accounting pronouncements.

Information Regarding Forward-looking Statements

This filing includes forward-looking statements 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, future 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 and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, electricity, coal and other bulk materials and chemicals 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 and our ability to acquire new businesses and assets and

52

	integrate those operations into existing operations, as well as the ability to make expansions to our respective facilities;
•	difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from Kinder Morgan Energy Partners' terminals or pipelines or our pipelines;
•	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, ports, utilities, military bases or other businesses that use Kinder Morgan Energy Partners' or our services or provide services or products to Kinder Morgan Energy Partners or us;
•	changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;
•	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 our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;
•	acts of nature, sabotage, terrorism or other acts causing damage greater than our insurance coverage limits;
•	capital market conditions;
•	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;
•	inflation;
•	interest rates;
•	the pace of deregulation of retail natural gas and electricity;
•	foreign exchange fluctuations;
•	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.  

53

See Items 1 and 2 "Business and Properties - Risk Factors" for a more detailed description of these and other factors that may affect the forward-looking statements. Our future results also could be adversely impacted by unfavorable results of litigation and the fruition of contingencies referred to in Note 9 "Environmental and Legal Matters" to the Consolidated Financial Statements included elsewhere in this report. When considering forward-looking statements, one should keep in mind the risk factors described in "Risk Factors" above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Risk Management

The following discussion should be read in conjunction with Note 14 of the accompanying Notes to Consolidated Financial Statements, which contains additional information on our risk management activities. Our derivative activities are accounted for in accordance with 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," which we adopted January 1, 2001.

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 will continue to 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

54

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, utilizing financial derivative products.

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.

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 2003, Value-at-Risk reached a high of $11.7 million and a low of $4.5 million. Value-at-Risk at December 31, 2003, was $11.7 million and, based on quarter-end values, averaged $8.0 million for 2003.

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

55

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 the three years ended December 31, 2003, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized a pre-tax gain of approximately $56,000 in 2003 and pre-tax losses of approximately $46,000 and $5,000 in 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. There was no component of these 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 2004, substantially all of the $7.2 million balance in accumulated other comprehensive income representing unrecognized net losses on derivative activities at December 31, 2003. During the three years ended December 31, 2003, 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.

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.

We have outstanding fixed-to-floating interest rate swap agreements with a notional principal amount of $1.5 billion at December 31, 2003. These agreements, entered into in August 2001, September 2002 and November 2003, effectively convert the interest expense associated with our 7.25% Debentures due in 2028 and our 6.50% Senior Notes due in 2012 from fixed rates to floating rates based on the three-month London Interbank Offered Rate ("LIBOR") plus a credit spread. These swaps have been designated as fair value hedges and we have accounted for them utilizing the "shortcut" method prescribed for qualifying fair value hedges under Statement 133. Accordingly, the carrying value of the swap is adjusted to its fair value as of the end of each reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. The fair value of these swaps of $71.8 million at December 31, 2003 is included in the caption "Deferred Charges and Other Assets" in the accompanying Consolidated Balance Sheet. 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 swaps discussed above and our outstanding commercial paper balance at December 31, 2003, the market risk related to a one percent change in interest rates would result in a $16.3 million annual impact on pre-tax income.

On March 3, 2003, we terminated the interest rate swap agreements associated with our 6.65% Senior Notes due in 2005 and received $28.1 million. We are amortizing this amount (reducing interest expense) over the remaining period the 6.65% Senior Notes are outstanding. The unamortized balance of $16.4 million at December 31, 2003 is included in the caption "Value of Interest Rate Swaps" under the heading "Long-term Debt" in the accompanying Consolidated Balance Sheet.

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Item 8. Financial Statements and Supplementary Data.

INDEX

	Page
Report of Independent Auditors	58
Consolidated Statements of Operations	59
Consolidated Statements of Comprehensive Income	60
Consolidated Balance Sheets	61
Consolidated Statements of Stockholders' Equity	62
Consolidated Statements of Cash Flows	63
Notes to Consolidated Financial Statements	64-110
Selected Quarterly Financial Data (unaudited)	111-112

57

Report of Independent Auditors

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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 12(C) and Note 20 to the consolidated financial statements, the Company changed its method of accounting for its Capital Trust Securities effective December 31, 2003.

As discussed in Note 20 to the consolidated financial statements, the Company changed its method of accounting for its investment in Triton Power Company LLC effective December 31, 2003.

As discussed in Note 1(O) 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 14 to the consolidated financial statements, the Company changed its method of acounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Houston, Texas
March 3, 2004

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CONSOLIDATED STATEMENTS OF OPERATIONS
Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2003	2002	2001
	(In thousands except per share amounts)
Operating Revenues:
Natural Gas Transportation and Storage	$   689,566	$   628,172	$   645,369
Natural Gas Sales	351,349	312,764	301,994
Other	56,982	74,319	107,544
Total Operating Revenues	1,097,897	1,015,255	1,054,907
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales	354,261	311,224	339,301
Operations and Maintenance	123,188	125,565	126,553
General and Administrative	71,741	73,496	73,319
Depreciation and Amortization	117,528	106,496	105,680
Taxes, Other Than Income Taxes	30,573	27,282	25,735
Revaluation of Power Investments	44,513	134,525	-
Total Operating Costs and Expenses	741,804	778,588	670,588
Operating Income	356,093	236,667	384,319
Other Income and (Expenses):
Kinder Morgan Energy Partners:
Equity in Earnings	464,967	392,135	277,504
Amortization of Equity-method Goodwill	-	-	(25,644)
Equity in Earnings of Other Equity Investments	7,451	12,791	245
Interest Expense, Net	(139,588)	(161,935)	(216,200)
Interest Expense - Capital Trust Securities	(10,956)	-	-
Minority Interests	(52,493)	(55,720)	(36,740)
Other, Net	830	18,792	1,143
Total Other Income and (Expenses)	270,211	206,063	308
Income from Continuing Operations Before Income    Taxes	626,304	442,730	384,627
Income Taxes	244,600	135,019	159,557
Income from Continuing Operations	381,704	307,711	225,070
Loss on Disposal of Discontinued Operations, Net of Tax	-	(4,986)	-
Net Income	$   381,704	$   302,725	$   225,070
	===========	===========	===========
Basic Earnings (Loss) Per Common Share:
Income from Continuing Operations	$      3.11	$      2.52	$      1.95
Loss on Disposal of Discontinued Operations	-	(0.04)	-
Total Basic Earnings Per Common Share	$      3.11	$      2.48	$      1.95
	===========	===========	===========
Number of Shares Used in Computing Basic
Earnings (Loss) Per Common Share	122,605	122,184	115,243
	===========	===========	===========
Diluted Earnings (Loss) Per Common Share:
Income from Continuing Operations	$      3.08	$      2.49	$      1.86
Loss on Disposal of Discontinued Operations	-	(0.04)	-
Total Diluted Earnings Per Common Share	$      3.08	$      2.45	$      1.86
	===========	===========	===========
Number of Shares Used in Computing Diluted
Earnings (Loss) Per Common Share	123,824	123,402	121,326
	===========	===========	===========
Dividends Per Common Share	$      1.10	$      0.30	$      0.20
	===========	===========	===========

The accompanying notes are an integral part of these statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Net Income	$  381,704	$  302,725	$  225,070
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes
(Net of Tax Benefit of $16,251, $23,880 and Tax of $24,068,         respectively)	(26,515)	(36,837)	36,102
Reclassification of Change in Fair Value of Derivatives to Net Income
(Net of Tax of $24,680, $4,467 and Tax Benefit of $9,567,         respectively)	40,267	6,031	(14,351)
Adjustment to Recognize Minimum Pension Liability
(Net of Tax of $10,865 and Tax Benefit of $10,865)	17,727	(17,727)	-
Equity in Other Comprehensive Loss of Equity Method
Investees (Net of Tax Benefit of $15,897 and $5,996, respectively)	(25,935)	(9,784)	-
Minority Interest in Other Comprehensive Loss of Equity
Method Investees	13,492	3,730	-
Cumulative Effect of Transition Adjustment (Net of
Tax Benefit of $7,922)	-	-	(11,883)
Total Other Comprehensive Income (Loss)	19,036	(54,587)	9,868
Comprehensive Income	$  400,740	$  248,138	$  234,938
	==========	==========	==========

The accompanying notes are an integral part of these statements.

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CONSOLIDATED BALANCE SHEETS
Kinder Morgan, Inc. and Subsidiaries

	December 31,
	2003	2002
	(In thousands)
ASSETS:
Current Assets:
Cash and Cash Equivalents	$    11,076	$    35,653
Restricted Deposits	17,158	2,783
Accounts Receivable, Net:
Trade	75,903	82,258
Related Parties	1,584	48,054
Inventories	22,096	62,760
Gas Imbalances	33,320	32,033
Other	115,183	157,454
	276,320	420,995
Investments:
Kinder Morgan Energy Partners	2,106,312	2,034,160
Goodwill	972,380	990,878
Other	208,860	285,883
	3,287,552	3,310,921
Property, Plant and Equipment, Net	6,083,937	6,048,107
Deferred Charges and Other Assets	388,902	322,727
Total Assets	$10,036,711	$10,102,750
	===========	===========
LIABILITIES AND STOCKHOLDERS' EQUITY:
Current Liabilities:
Current Maturities of Long-term Debt	$     5,000	$   501,267
Notes Payable	127,900	-
Accounts Payable:
Trade	61,385	88,227
Related Parties	10,632	50
Accrued Interest	68,596	80,158
Accrued Taxes	35,795	27,355
Gas Imbalances	38,494	50,394
Other	128,559	119,081
	476,361	866,532
Other Liabilities and Deferred Credits:
Deferred Income Taxes	2,477,329	2,435,780
Other	197,435	210,869
	2,674,764	2,646,649
Long-term Debt:
Outstanding Notes and Debentures	2,837,487	2,852,181
Deferrable Interest Debentures Issued to Subsidiary Trusts	283,600	-
Value of Interest Rate Swaps	88,242	139,589
	3,209,329	2,991,770
Kinder Morgan-Obligated Mandatorily Redeemable Preferred Capital Trust    Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan	-	275,000
Minority Interests in Equity of Subsidiaries	1,010,140	967,802
Commitments and Contingent Liabilities (Notes 3, 9 and 17)
Stockholders' Equity:
Preferred Stock (Note 13)	-	-
Common Stock-
Authorized - 150,000,000 Shares, Par Value $5 Per Share; Outstanding - 132,229,622    and 129,861,650 Shares, Respectively, Before Deducting 8,912,660 and 8,168,241    Shares Held in Treasury	661,148	649,308
Additional Paid-in Capital	1,780,761	1,681,042
Retained Earnings	732,492	486,062
Treasury Stock	(446,095)	(406,630)
Deferred Compensation	(36,506)	(10,066)
Accumulated Other Comprehensive Loss	(25,683)	(44,719)
Total Stockholders' Equity	2,666,117	2,354,997
Total Liabilities and Stockholders' Equity	$10,036,711	$10,102,750
	===========	===========

The accompanying notes are an integral part of these statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2003		2002		2001
	Shares	Amount	Shares	Amount	Shares	Amount
	(Dollars in thousands)
Common Stock:
Beginning Balance	129,861,650	$   649,308	129,092,689	$   645,463	114,578,800	$   572,894
Conversion of Premium Equity
Participating Security Units (PEPS)	-	-	-	-	13,382,474	66,912
Employee Benefit Plans	2,367,972	11,840	768,961	3,845	1,131,415	5,657
Ending Balance	132,229,622	661,148	129,861,650	649,308	129,092,689	645,463
Additional Paid-in Capital:
Beginning Balance		1,681,042		1,652,846		1,189,270
Revaluation of Kinder     Morgan Energy Partners     (KMP) Investment (Note 5)		(4,070)		(29,350)		28,322
Gain on KMP Units Exchanged    for Kinder Morgan Management    (KMR) Shares (Note 3)		-		35,720		15,722
Conversion of PEPS		-		-		393,446
Employee Benefit Plans		71,531		22,025		31,210
Tax Benefits from Employee     Benefit Plans		29,974		-		-
Other		2,284		(199)		(5,124)
Ending Balance		1,780,761		1,681,042		1,652,846
Retained Earnings:
Beginning Balance		486,062		219,995		17,787
Net Income		381,704		302,725		225,070
Cash Dividends, Common Stock		(135,274)		(36,658)		(22,862)
Ending Balance		732,492		486,062		219,995
Treasury Stock at Cost:
Beginning Balance	(8,168,241)	(406,630)	(5,165,911)	(263,967)	(96,140)	(2,327)
Treasury Stock Acquired	(724,600)	(37,988)	(3,013,400)	(144,269)	(5,294,800)	(270,410)
Treasury Stock Issued	-	-	17,827	889	-	-
Employee Benefit Plans	(19,819)	(1,477)	(6,757)	717	225,029	8,770
Ending Balance	(8,912,660)	(446,095)	(8,168,241)	(406,630)	(5,165,911)	(263,967)
Deferred Compensation Plans:
Beginning Balance		(10,066)		(4,208)		-
Current Year Activity [Note 1(S)]		(26,440)		(5,858)		(4,208)
Ending Balance		(36,506)		(10,066)		(4,208)
Accumulated Other    Comprehensive Income (Loss)    (Net Of Tax):
Beginning Balance		(44,719)		9,868		-
Unrealized Gain (Loss) on Derivatives
Utilized for Hedging Purposes		13,752		(30,806)		21,751
Adjustment to Recognize Minimum
Pension Liability		17,727		(17,727)		-
Equity in Other Comprehensive
Loss of Equity Method Investees		(25,935)		(9,784)		-
Minority Interest in Other
Comprehensive Loss of
Equity Method Investees		13,492		3,730		-
Cumulative Effect Transition
Adjustment		-		-		(11,883)
Ending Balance		(25,683)		(44,719)		9,868
Total Stockholders' Equity	123,316,962	$ 2,666,117	121,693,409	$ 2,354,997	123,926,778	$ 2,259,997
	===========	===========	===========	===========	===========	===========

The accompanying notes are an integral part of these statements.

62

CONSOLIDATED STATEMENTS OF CASH FLOWS
Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
Cash Flows from Operating Activities:
Net Income	$  381,704	$  302,725	$   225,070
Adjustments to Reconcile Net Income to Net Cash Flows
from Operating Activities:
Loss on Disposal of Discontinued Operations, Net of Tax	-	4,986	-
Loss from Revaluation of Power Investments	44,513	134,525	-
Loss on Early Extinguishment of Debt	-	2,349	22,609
Depreciation and Amortization	117,528	106,496	105,680
Deferred Income Taxes	29,330	55,748	129,911
Equity in Earnings of Kinder Morgan Energy Partners	(464,967)	(392,135)	(251,860)
Distributions from Kinder Morgan Energy Partners	369,022	310,290	238,775
Equity in Earnings of Other Investments	(7,451)	(12,791)	(245)
Minority Interests in Income of Consolidated Subsidiaries	41,537	33,808	14,827
Deferred Purchased Gas Costs	(20,636)	(7,792)	23,499
Net (Gains) Losses on Sales of Assets	4,423	(2,566)	(22,621)
Gain from Settlement of Orcom Note	(2,917)	-	-
Litigation Settlement and Escrow Deposit	-	(22,050)	-
Pension Contribution in Excess of Expense	(5,101)	(18,700)	-
Changes in Gas in Underground Storage	50,075	5,291	(63,804)
Changes in Working Capital Items [Note 1(R)]	44,838	(40,525)	18,298
Proceeds from Termination of Interest Rate Swap	28,147	-	-
Other, Net	(21,171)	(11,685)	900
Net Cash Flows Provided by Continuing Operations	588,874	447,974	441,039
Net Cash Flows Used in Discontinued Operations	(1,743)	(4,930)	(3,737)
Net Cash Flows Provided by Operating Activities	587,131	443,044	437,302
Cash Flows from Investing Activities:
Capital Expenditures	(160,804)	(174,953)	(124,171)
Acquisition of TransColorado	-	(95,560)	-
Other Acquisitions	-	(35,838)	(23,899)
Investment in Kinder Morgan Energy Partners (Note 2)	(1,784)	(331,912)	(1,003,585)
Other Investments	(11,329)	(200,958)	(155,903)
Exchange of Kinder Morgan Management Shares	-	(69)	-
Proceeds from Settlement of Orcom Note	2,727	-	-
Proceeds from Sales of Assets	13,853	3,949	7,077
Net Cash Flows Used in Continuing Investing Activities	(157,337)	(835,341)	(1,300,481)
Net Cash Flows Provided by Discontinued Investing Activities	-	-	25,742
Net Cash Flows Used in Investing Activities	(157,337)	(835,341)	(1,274,739)
Cash Flows from Financing Activities:
Short-term Debt, Net	127,900	(423,785)	323,785
Floating Rate Notes Issued	-	-	200,000
Long-term Debt Issued	-	1,000,000	-
Long-term Debt Retired	(511,083)	(265,292)	(872,185)
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	47,686	15,558	31,184
Premiums Paid on Early Extinguishment of Debt	-	(1,461)	(30,694)
Short-term Advances (To) From Unconsolidated Affiliates	55,864	(53,003)	7,951
Repurchase of Kinder Morgan Management Shares	(928)	-	-
Treasury Stock Issued	-	1,701	2,464
Treasury Stock Acquired	(37,988)	(149,062)	(265,706)
Cash Dividends, Common Stock	(135,274)	(36,658)	(22,862)
Minority Interests, Net	(548)	(384)	375
Premium Equity Participating Securities Contract Fee	-	-	(10,931)
Debt Issuance Costs	-	(4,357)	(225)
Securities Issuance Costs	-	(14,611)	(54,480)
Net Cash Flows Provided by (Used in) Financing Activities	(454,371)	411,816	711,648
Net Increase (Decrease) in Cash and Cash Equivalents	(24,577)	19,519	(125,789)
Cash and Cash Equivalents at Beginning of Year	35,653	16,134	141,923
Cash and Cash Equivalents at End of Year	$   11,076	$   35,653	$    16,134
	==========	==========	===========

The accompanying notes are an integral part of these statements.

63

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. Our business activities include: (i) storing, transporting and selling natural gas, (ii) providing retail natural gas distribution services, and (iii) operating and, in previous periods, constructing 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. (Delaware), 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 7.

(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(T). 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

64

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,
	2003	2002
	(In thousands)
REGULATORY ASSETS:
Employee Benefit Costs	$   1,791	$   6,362
Debt Refinancing Costs	876	1,064
Deferred Income Taxes	14,843	15,681
Purchased Gas Costs	49,386	33,439
Plant Acquisition Adjustments	454	454
Rate Regulation and Application Costs	2,876	3,585
Total Regulatory Assets	70,226	60,585
REGULATORY LIABILITIES:
Employee Benefit Costs	3,009	5,967
Deferred Income Taxes	20,797	23,554
Purchased Gas Costs	6,926	19,195
Total Regulatory Liabilities	30,732	48,716
NET REGULATORY ASSETS	$  39,494	$  11,869
	=========	=========

The December 31, 2003 purchased gas costs balance of $49.4 million shown above as a regulatory asset includes $30.2 million in litigated gas costs. See Note 8 for additional information regarding this matter. As of December 31, 2003, $68.0 million of our regulatory assets and $27.7 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, for which title has passed but 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'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

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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.

	2003	2002	2001
	(In thousands)
Weighted Average Common Shares Outstanding	122,605	122,184	115,243
Premium Equity Participating Security Units	-	-	4,328
Dilutive Common Stock Options	1,219	1,218	1,755
Shares Used to Compute Diluted Earnings Per Common Share	123,824	123,402	121,326
	========	========	========

Weighted-average stock options outstanding totaling 1.7 million for 2003, 2.5 million for 2002 and 9,200 for 2001 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 units 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 12(B) contains more information regarding premium equity participating security units, while Note 16 contains more information regarding stock options.

(F) Restricted Deposits

Restricted Deposits consist of restricted funds on deposit with brokers in support of our risk management activities; see Note 14.

(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 $8.1 million and $13.5 million at December 31, 2003 and 2002, respectively, included with other current liabilities in the accompanying Consolidated Balance Sheets. The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2003, 2002 and 2001.

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Allowance for Doubtful Accounts

	Year Ended December 31,
	2003	2002	2001
	(In millions)
Beginning Balance	$   4.9	$   3.4	$   2.3
Additions: Charged to Cost and Expenses	1.9	5.2	6.7
Deductions: Write-off of Uncollectible Accounts	(1.6)	(3.7)	(5.6)
Ending Balance	$   5.2	$   4.9	$   3.4
	=======	=======	=======

(H) Inventories

	December 31,
	2003	2002
	(In thousands)
Gas in Underground Storage (Current)	$   8,306	$  49,106
Materials and Supplies	13,790	13,654
	$  22,096	$  62,760
	=========	=========

Inventories are accounted for using the following methods, with the percent of the total dollars at December 31, 2003 shown in parentheses: average cost (97.45%) and first-in, first-out (2.55%). All non-utility inventories held for resale are valued at the lower of cost or market. 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,
	2003	2002
	(In thousands)
Assets Held for Sale - Turbines and Boilers	$  73,453	$  82,000
Interest Receivable - Interest Rate Swaps	17,693	19,993
Income Tax Overpayments	-	32,389
Prepaid Expenses	14,223	11,176
Other	9,814	11,896
	$ 115,183	$ 157,454
	=========	=========

In December 2003, we received $8.5 million from the sale of one natural gas turbine.

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(J) Goodwill

	Kinder Morgan Energy Partners		Power Segment	Total
	(In thousands)
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
Change in ownership percentage of Kinder   Morgan Energy Partners related to Kinder   Morgan Energy Partners common unit issuances		(21,682)	-	(21,682)
Other		-	3,184	3,184
Balance as of December 31, 2003		$  947,548	$   24,832	$  972,380
		==========	==========	==========

(K) Other Investments

	December 31,
	2003	2002
	(In thousands)
Power Investments:
Thermo Companies	$  177,269	$  122,879
Wrightsville/Jackson Plant Investments1	-	137,205
Horizon Pipeline Company	19,317	17,816
Subsidiary Trusts Holding Solely Debentures of     Kinder Morgan2	8,600	-
Other	3,674	7,983
	$  208,860	$  285,883
	==========	==========

1	As of December 31, 2003, we (i) began consolidating our investment in the Jackson, Michigan plant (see Note 20) and (ii) determined that it was no longer appropriate to assign any carrying value to the Wrightsville, Arkansas plant (see Note 6).
2	As a result of a recent change in accounting standards effective December 31, 2003, the subsidiary trusts associated with these securities are no longer consolidated. See Note 20.

Investments consist primarily of equity method investments in unconsolidated subsidiaries and joint ventures, and include ownership interests in net profits. We own 49.5% interests in Thermo Cogeneration Partnership, L.P. and Cogeneration Holdings, LLC, which are accounted for under the equity method. Our investment in Horizon Pipeline Company, in which we own a 50% interest, is also accounted for under the equity method. At December 31, 2002, "Other" included an investment in Igasamex USA, Ltd. of approximately $6 million (this investment was sold in 2003, see Note 5) 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.

68

As discussed under (H) preceding, we maintain gas in underground storage as part of our inventory. This component of our inventory represents the portion of gas stored in an underground storage facility generally known as "working gas," and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal to meet demand. In addition to this working gas, underground gas storage reservoirs contain injected gas which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as "cushion gas," is divided into the categories of "recoverable cushion gas" and "unrecoverable cushion gas," based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of the cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself (thus, part of our Property, Plant & Equipment balance) and is depreciated over the facility's estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

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 quarters of 2003 and 2002, we recorded impairments of certain assets associated with our power business; see Note 6.

(M) Asset Retirement Obligations

We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. This statement changed the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated retirement costs. The 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 impact of the adoption of this statement on us is discussed below by segment.

In general, Natural Gas Pipeline Company of America's system is composed of underground piping, compressor stations and associated facilities, natural gas storage facilities and certain other facilities and equipment. Except as discussed following, we have no plans to abandon any of these facilities, the majority of which have been providing utility service for many years, making it impossible to determine the timing of any potential retirement expenditures. Notwithstanding our current intentions, in general, if we were to cease utility operations in total or in any particular area, we would be permitted to abandon the underground piping in place, but would have to remove our surface facilities from land belonging to our customers or others. We would generally have no obligations for removal or remediation with respect to equipment and facilities, such as compressor stations, located on land we own.

Natural Gas Pipeline Company of America has various condensate drip tanks located throughout the system, storage wells located within the storage fields, laterals no longer integral to the overall mainline transmission system, compressor stations which are no longer active, and other miscellaneous facilities, all of which have been officially abandoned. For these facilities, it is possible to reasonably estimate the timing of the payment of obligations associated with their retirement. The recognition of these obligations has resulted in a liability and associated asset of approximately $2.8 million as of January 1, 2003, representing the present value of those future obligations for which we are able to make reasonable estimations of the current fair value due to, as discussed above, our ability to estimate the timing of the incurrence of the expenditures. The remainder of Natural Gas Pipeline Company of America's asset retirement obligations have not been recorded due to our inability, as discussed above, to reasonably estimate when they will be settled in cash. We will record liabilities for these obligations when we are able to reasonably estimate their fair value.

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In general, our retail natural gas distribution system is composed of town border stations, regulator stations, underground piping and delivery meters. In addition, we have (i) certain other associated surface equipment, (ii) gas storage facilities in Colorado and Wyoming and (iii) one producing gas field in Colorado. Except as discussed following, we have no plans to abandon any of these facilities, the majority of which have been providing utility service for many years, making it impossible to determine the timing of any potential retirement expenditures. Notwithstanding our current intentions, if we were to cease utility operations in any particular area, we would be permitted to abandon the underground piping in place, but would have to remove our surface facilities at customer delivery points. We would be under no obligation to remove town border stations, odorization or other miscellaneous facilities located on our property.

In our Kinder Morgan Retail storage field operations we would, upon abandonment, be required to plug and abandon the wells and to remove our surface wellhead equipment and compressors. We currently have two small sites in Wyoming that are no longer being used as active storage facilities and estimate that, in 2013, we will incur approximately $200,000 in costs to fulfill these retirement obligations. We have no plans to cease using any of our other storage facilities as they are expected to, for the foreseeable future, provide critical deliverability to our customers in severe cold weather situations. With respect to our small natural gas production field in Colorado, we will be required, upon cessation of commercial operations, to plug and abandon the natural gas wells, remove surface equipment and remediate the well sites. We have estimated that this process will start in 2005 and continue through 2013 for a total cost of $240,000, with approximately half the total being spent in the final two years. The recognition of these obligations has resulted in a liability and associated asset of approximately $0.3 million as of January 1, 2003, representing the present value of those future obligations for which we are able to make reasonable estimations of the current fair value due to, as discussed above, our ability to estimate the timing of the incurrence of the expenditures. The remainder of our asset retirement obligations have not been recorded due to our inability to reasonably estimate when they will be settled in cash. We will record liabilities for these obligations when we are able to reasonably estimate their fair value.

The facilities utilized in our power generation activities fall into two general categories: those that we own and those that we do not own. With respect to those facilities that we do not own but either operate or maintain a preferred interest in, principally the Jackson, Michigan and Wrightsville, Arkansas power plants, we have no obligation for any asset retirement obligation that may exist or arise. With respect to the Colorado power generation assets that we do own, we have no asset retirement obligation with respect to those facilities located on land that we also own, and no direct responsibility for assets in which we own an interest accounted for under the equity method of accounting. Thus, our power generation activities do not give rise to any asset retirement obligations.

We have not presented prior period information on a pro forma basis to reflect the implementation of SFAS No. 143 because the impact in total and on each individual period is immaterial.

(N) 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

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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 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 liability was approximately $11 million at December 31, 2003 and is expected to result in a credit to earnings in an amount approximating $3.5 million per year for the next three years as gas volumes are purchased and resold.

(O) 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 4 to 30 3 to 56

In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 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 (Delaware) was not amortized beginning January 1, 2002. Had the provisions of this statement been in effect during 2001, our reported earnings and earnings per share would have been as follows:

	Year Ended December 31,
	2001
	(In thousands, except per share amounts)
Reported Net Income		$ 225,070
Add Back: Goodwill Amortization, Net of Related Tax Benefit		16,198
Adjusted Net Income		$ 241,268
		=========
Reported Earnings per Diluted Share		$    1.86
		=========
Earnings per Diluted Share, as Adjusted		$    1.99
		=========

(P) Interest Expense, Net

"Interest Expense, Net" as presented in the accompanying Consolidated Statements of Operations is net of the debt component of the allowance for funds used during construction ("AFUDC - Interest") as shown following.

	Year Ended December 31,
	2003	2002	2001
	(In millions)
Interest Expense	$  140.2	$  163.7	$  221.0
AFUDC - Interest	(0.6)	(1.8)	(4.8)
Interest Expense, Net	$  139.6	$  161.9	$  216.2
	========	========	========

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(Q) Other, Net

"Other, Net" as presented in the accompanying Consolidated Statements of Operations includes $(4.4) million, $13.0 million and $22.6 million in 2003, 2002 and 2001, respectively, attributable to net gains/(losses) from sales of assets. These transactions are discussed in Note 5.

(R) 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, including, in 2003, amortization of the gain realized on the termination of interest rate swap agreements; see Note 14.

ADDITIONAL CASH FLOW INFORMATION:

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

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Accounts Receivable	$   11,830	$   45,111	$  (18,794)
Materials and Supplies Inventory	(136)	1,854	(1,512)
Other Current Assets	17,356	(43,217)	21,270
Accounts Payable	(10,147)	(62,449)	33,375
Other Current Liabilities	25,935	18,176	(16,041)
	$   44,838	$  (40,525)	$   18,298
	==========	==========	==========

Supplemental Disclosures of Cash Flow Information:

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Cash Paid for:
Interest (Net of Amount Capitalized)	$  169,931	$  147,088	$  225,327
	==========	==========	==========
Distributions on Capital Trust Securities1	$   10,956	$   21,913	$   21,913
	==========	==========	==========
Income Taxes Paid (Net of Refunds)	$  151,104	$  114,264	$   27,524
	==========	==========	==========

¹ Beginning with the third quarter of 2003, these distributions are included in "Interest."

As discussed in Note 1(S) following, during 2003, 2002 and 2001, we made non-cash grants of restricted shares of common stock. In addition, we made an investment in our Colorado power businesses in the form of Kinder Morgan Management shares. See Note 5.

(S)Stock-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-based compensation plans. As allowed under SFAS No. 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

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share would have been reduced to the pro forma amounts shown in the table below. Because the SFAS No. 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 $1.0 million, $1.1 million and $1.0 million related to the purchase discount offered under the employee stock purchase plan for 2003, 2002 and 2001, respectively. Note 16 contains information regarding our common stock option and purchase plans.

	Year Ended December 31,
	2003	2002	2001
	(In thousands except per share amounts)
Net Income As Reported	$  381,704	$  302,725	$  225,070
Add: Stock-based employee compensation expense     included in reported Net Income, net of related tax     effects	2,107	868	390
Deduct: Total stock-based employee compensation     expense determined under fair value based     method for all awards, net of related tax effects	(16,468)	(15,365)	(16,046)
Pro Forma Net Income	$  367,343	$  288,228	$  209,414
	==========	==========	==========
Basic Earnings Per Common Share:
As Reported	$     3.11	$     2.48	$     1.95
	==========	==========	==========
Pro Forma	$     3.00	$     2.36	$     1.81
	==========	==========	==========
Diluted Earnings Per Common Share:
As Reported	$     3.08	$     2.45	$     1.86
	==========	==========	==========
Pro Forma	$     2.97	$     2.33	$     1.73
	==========	==========	==========

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,
	2003	2002	2001
Risk-free Interest Rate (%)	3.37-3.641	4.01	4.30
Expected Weighted-average Life	6.3 years1	6.0 years2	6.5 years
Volatility	0.38-0.451	0.392	0.343
Expected Dividend Yield (%)	1.33-2.971	0.71	0.36

1	The assumptions used for employee options granted in 2003 varied based on date of grant. For options granted under the 1992 Directors' Plan, the expected weighted-average life was 4.1 years and the volatility assumption was 0.45.
2	For options granted under the 1992 Directors' Plan, the expected weighted-average life was 4.0 years and the volatility assumption was 0.45.
3	The volatility assumption for the options issued under the 1992 Directors' Plan was 0.44.

During 2003, 2002 and 2001, we made restricted common stock grants of 575,000, 162,250 and 112,500 shares, respectively. These grants are valued at $34.0 million, $9.2 million and $5.6 million, respectively, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. The restricted common stock grants made in 2003 are accounted for as variable awards, and therefore are valued based on the closing market price at December 31, 2003 because the grant price had not been fixed as of the end of the year. The 2003 restricted stock grants vest during a five year period and the 2002 and 2001 grants vest over a four year period. Expense related to restricted grants is recognized on a straight-line basis over the respective vesting periods. During 2003, 2002 and 2001, we amortized $3.4 million, $1.4 million and $0.6 million, respectively, related to restricted stock grants. The unamortized value of restricted stock grants is shown in the equity section of our Consolidated Balance Sheets under the caption, "Deferred Compensation."

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(T) 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 (or acquisition cost) 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. Three 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 Parties and Accounts Payable, Related Parties balances shown in the Consolidated Balance Sheets are 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.

Related-party operating revenues, primarily from Horizon Pipeline Company and entities owned by Kinder Morgan Energy Partners, are included in the accompanying Consolidated Statements of Operations as follows:

	Year Ended December 31,
	2003	2002	2001
	(In millions)
Natural Gas Transportation and Storage	$ 5.2	$ 2.0	$ 0.3
Natural Gas Sales	5.4	-	-
Other Revenues	1.0	0.1	0.1
Total Related-party Operating Revenues	$11.6	$ 2.1	$ 0.4
	=====	=====	=====

The caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statements of Operations includes related-party costs totaling $36.8 million, $22.3 million and $47.4 million for the years 2003, 2002 and 2001, respectively, primarily for natural gas transportation and storage services and natural gas provided by entities owned by Kinder Morgan Energy Partners.

(U) 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. In addition, we utilize weather derivatives to reduce the variability in the earnings from our natural gas distribution activities. Our accounting policy for these activities is in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which became effective for us on January 1, 2001. This policy is described in detail in Note 14.

(V) 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

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11 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.

(W) 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 probable 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. 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 39 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 52 liquid and bulk terminal facilities and approximately 57 rail transloading facilities located throughout the United States, handling nearly 60 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 55 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 has over 1,100 miles of pipelines and transports, markets and produces carbon dioxide for use in enhanced oil recovery operations and owns interests in and/or operates six oil fields in West Texas, all of which are using or have used carbon dioxide injection operations.

At December 31, 2003, 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 32.8 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 14.5 million i-units, represent approximately 17.4 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 and the July 2001 two-for-one split that affected both the common units and the 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 represented approximately 19.0 percent of Kinder Morgan Energy Partners' total equity interests at December 31, 2003. 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 quarterly distributions above $0.23375 per limited partner unit. Including both our general and limited partner interests in Kinder Morgan Energy Partners, at the 2003 distribution level, we received approximately 51% of all quarterly distributions by Kinder Morgan Energy Partners, of which

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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.

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 2003 Annual Report on Form 10-K.

	Summarized Income Statement Information Year Ended December 31,
	2003	2002	2001
	(In thousands)
Operating Revenues	$ 6,624,322	$ 4,237,057	$ 2,946,676
Operating Expenses	5,817,633	3,512,759	2,382,848
Operating Income	$   806,689	$   724,298	$   563,828
	===========	===========	===========
Income Before Cumulative Effect of a   Change in Accounting Principle	$   693,872	$   608,377	$   442,343
	===========	===========	===========
Net Income	$   697,337	$   608,377	$   442,343
	===========	===========	===========

	Summarized Balance Sheet Information As of December 31,
	2003	2002
	(In thousands)
Current Assets	$    705,522	$    669,390
	============	============
Noncurrent Assets	$  8,433,660	$  7,684,186
	============	============
Current Liabilities	$    804,379	$    813,327
	============	============
Noncurrent Liabilities	$  4,783,812	$  4,082,287
	============	============
Minority Interest	$     40,064	$     42,033
	============	============

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 of $991.9 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. 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. 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. 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 Kinder Morgan Management shareholder

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(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 our (i) additional paid-in capital by $35.7 million and (ii) associated income taxes payable by $21.9 million and decreasing (i) investment in Kinder Morgan Energy Partners by $150.1 million and (ii) minority interests by $207.7 million.

In the initial public offering, Kinder Morgan Management issued a total of 29,750,000 shares, of which we purchased 2,975,000 shares (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 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 2003 and 2002, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $1.8 million and $3.4 million, respectively. At December 31, 2003, we owned approximately 14.5 million (29.7%) 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. In accordance with our policy, we 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, 2003, Kinder Morgan Management paid a share distribution of 811,625 of its shares to shareholders of record as of October 31, 2003, based on the $0.66 per common unit distribution declared by Kinder Morgan Energy Partners. On February 13, 2004, Kinder Morgan Management made a distribution totaling 778,309 of its shares to shareholders of record as of January 30, 2004, based on the $0.68 per common unit distribution declared by Kinder Morgan Energy Partners. These distributions are paid in the form of additional shares or fractions thereof calculated by dividing the Kinder Morgan Energy Partners' cash distribution per common unit by the average market price of a Kinder Morgan Management 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 3,342,417, 2,538,785 and 886,361 shares in the years ended December 31, 2003 and 2002 and the period from February 14, 2001 (inception) through December 31, 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.

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4.Business Combinations

TransColorado Gas Transmission Company, referred to herein as "TransColorado," was formed to construct and operate a 300-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 to include its transactions and balances in our consolidated financial statements 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. The purchase price was allocated as follows (in millions):

Cash	$   6.0
Other Current Assets	1.6
Net Property, Plant and Equipment	123.1
Other Assets	0.1
Current Liabilities	(2.2)
Deferred Credits	(21.0)
Total Purchase Price	$ 107.6
	=======

5.  Investments and Sales

Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, in December 2003, we made an additional investment in our Colorado power businesses in the form of approximately 1.8 million Kinder Morgan Management shares that we owned. We recorded our increased investment based on the third-party-determined $56.1 million fair value of the shares as of the contribution date, with a corresponding liability representing our obligation to deliver vested shares in the future.

In December 2003, we received $8.5 million from the sale of one natural gas turbine.

In June 2003, Kinder Morgan Energy Partners issued 4.6 million common units in a public offering at a price of $39.35 per common unit, receiving total net proceeds (after underwriting discount) of $173.3 million. We did not acquire any of these common units. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners from approximately 19.28% to approximately 18.86% and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $14.9 million and reducing our (i) equity method goodwill in Kinder Morgan Energy Partners by $21.4 million, (ii) associated accumulated deferred income taxes by $2.5 million and (iii) paid-in capital by $4.0 million. In addition, in June 2003, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made a contribution of approximately $1.8 million; see Note 1(T).

On June 30, 2003, we received $3.8 million from the sale of our interest in Igasamex USA Ltd. We recorded a pre-tax loss of $4.3 million in conjunction with the sale.

78

On March 6, 2000, we received a promissory note from Orcom Solutions, Inc. as partial consideration for the sale of our en• able joint venture, which note was carried at nominal value due to concerns as to recoverability. During 2003, we received $5.4 million in settlement of this note, of which $2.7 million was paid to PacifiCorp reflecting its 50% interest in en•able. In conjunction with this settlement, we recorded a pre-tax gain of $2.9 million.

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 our (i) equity method goodwill 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. In addition, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made a contribution of approximately $3.4 million; see Notes 1(T) and 3.

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 in Wrightsville, Arkansas, utilizing Kinder Morgan Power's Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Kinder Morgan Power made an investment in the project company, comprised primarily of preferred stock. This facility has not been dispatched significantly since July 1, 2002. In October 2003, the project company was included in Mirant Corporation's bankruptcy filing. In the fourth quarter of 2003, we wrote off our remaining investment in the Wrightsville power facility.

In February 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 of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC valued at approximately $105 million; and, (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. 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.

In May 2002, 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. 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

79

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 in conjunction with this sale, included 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. These 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 our (i) 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 our (i) equity method goodwill in Kinder Morgan Energy Partners by $97.9 million and (ii) monthly amortization of the equity method goodwill by $192,000 (which amortization ended January 1, 2002; see Note 1(O)). In addition, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made a contribution of approximately $11.7 million; see Notes 1(T) and 3.

In December 2000, we contributed certain assets to Kinder Morgan Energy Partners effective December 31, 2000. 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 and $9.9 million. A final pre-tax adjustment of $10.4 million was made at December 31, 2002, the expiration of the indemnification obligations. In each case these amounts were adjusted for our continuing interest in the assets transferred.

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. During the fourth quarter of 2003, we announced that, due principally to the fact that Mirant had placed the Wrightsville, Arkansas plant in bankruptcy during October, we would be assessing the long-term prospects for this facility during the fourth quarter and that a reduction in the plant's carrying value was possible. During the fourth quarter of 2003 we completed our analysis and determined that it was no longer appropriate to assign any carrying value to our investment in this facility and recorded a $44.5 million pre-tax charge. We are engaged in ongoing efforts to sell our remaining turbines and associated equipment. During 2003, we sold one turbine; see Note 5.

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7.  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 for all periods presented. 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 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.

With the exception of our international operations, which we decided to retain, we completed the divestiture of our discontinued operations by December 31, 2000. In the fourth quarter of 2002, we recorded an incremental loss of approximately $5.0 million (net of tax benefit of $3.1 million) to increase previously recorded liabilities to reflect updated estimates. We had a remaining liability of approximately $5.4 million at December 31, 2003 associated with these discontinued operations, representing an indemnification obligation associated with our sale of assets to ONEOK, Inc. ("ONEOK").

8.  Regulatory Matters

On July 17, 2000, Natural Gas Pipeline Company of America filed its compliance plan, including pro forma tariff sheets, pursuant to the Federal Energy Regulatory Commission's ("FERC") 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 these 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 relate 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. On May 14, 2003, the FERC issued an order accepting most of Natural Gas Pipeline Company of America's compliance filing, but requiring additional changes, particularly regarding the designation of additional primary points for a segmented release. This order also established an effective date for Natural Gas Pipeline Company of America's Order 637 provisions of December 1, 2003. Natural Gas Pipeline Company of America made its further compliance filing on

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June 13, 2003. Limited protests have been filed. The Order No. 637 tariff provisions for Natural Gas Pipeline Company of America became effective on December 1, 2003, although certain aspects of these provisions are subject to FERC review of the most recent compliance filing, which is still pending FERC action.

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 and (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. On January 29, 2004, the FERC issued an order denying rehearing and reaffirming these rulings.

On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate pipeline must file a compliance plan by that date and must be in full compliance with the Standards of Conduct by June 1, 2004. The primary change from existing regulation is to make such standards applicable to an interstate pipeline's interaction with many more affiliates (termed "Energy Affiliates"), including intrastate/Hinshaw pipelines, processors and gatherers and any company involved in gas or electric markets (such as electric generators and electric or gas marketers) even if they do not ship on the affiliated interstate pipeline. Local distribution companies are excluded, however, if they do not make off-system sales. The Standards of Conduct require, inter alia, separate staffing of interstate pipelines and their Energy Affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from the interstate pipeline to an Energy Affiliate. Natural Gas Pipeline Company of America and Kinder Morgan Interstate Gas Transmission LLC, a subsidiary of Kinder Morgan Energy Partners, filed for clarification and rehearing of Order No. 2004 on December 29, 2003, and numerous other rehearing requests have been submitted. In the request for rehearing, Natural Gas Pipeline Company of America and Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of Energy Affiliates.To date the FERC has not acted on these hearing requests. On February 9, 2004, Natural Gas Pipeline Company of America, TransColorado Gas Transmission Company, Canyon Creek Compression Company and Horizon Pipeline Company filed their compliance plans under Order No. 2004. In addition, on February 19, 2004, all of these interstate pipelines filed a joint request with the interstate pipelines owned by Kinder Morgan Energy Partners asking that their interaction with intrastate/Hinshaw pipeline affiliates be exempted from the Standards of Conduct. Separation from these entities would be the most burdensome requirement of the new rules for us.

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

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filed comments on August 28, 2002. On June 26, 2003, the FERC issued an interim rule to be effective in August 2003, under which regulated companies are required to document cash management arrangements and transactions. The FERC eliminated the proposal that, as a prerequisite to participation in cash management programs, regulated companies must maintain a 30 percent equity balance and investment grade credit rating. On October 22, 2003, the FERC issued its final rule amending its regulations effective November 2003 which, among other things, requires FERC-regulated entities to file their cash management agreements with the FERC and to notify the FERC within 45 days after the end of the quarter when their proprietary capital ratio drops below 30 percent, and when it subsequently returns to or exceeds 30 percent. In compliance with the final rule, Natural Gas Pipeline Company of America and TransColorado submitted their cash management agreements to the FERC in December 2003. On February 11, 2004, the FERC eliminated the notification requirement discussed preceding as part of issuing Order No. 646, which requires quarterly financial reporting.

On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, we will no longer be permitted to use commodity price indices to structure transactions on our FERC regulated natural gas pipelines. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. Price indexed contracts currently constitute an insignificant portion of our contracts on our FERC regulated natural gas pipelines; consequently, we do not believe that this Modification to Policy Statement will have a material impact on our operations, financial results or cash flows. Rehearing on this aspect of the Modification to Policy Statement has been sought by Natural Gas Pipeline Company of America and others, but the FERC has not yet acted on rehearing.

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 $16.8 million from us (including forgiveness of a $10.4 million obligation owing from Mr. Grynberg) and an additional $15.6 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 (the "CPUC"). Rocky Mountain Natural Gas Company and Kinder Morgan, Inc. made regulatory filings with the CPUC 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 CPUC 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. An uncontested Stipulation and Settlement Agreement was filed with the CPUC on June 20, 2003, providing for full rate recovery by Rocky Mountain Natural Gas Company and Kinder Morgan, Inc. of $30,173,472 of gas cost payments to Mr. Grynberg. It also provided for $14,451,528 of allowable interest recovery to Rocky Mountain Natural Gas Company and Kinder Morgan, Inc. The total settlement amount of $44,625,000 will be recovered through a special rate rider over a fifteen year period which commenced on November 1, 2002. Following a hearing on July 14, 2003, the presiding administrative law judge issued a recommended decision on September 15, 2003, approving the settlement without modification. That recommended decision became the decision of the Commission by operation of law and is now in effect. The time for appealing the CPUC's decision expired on November 6, 2003, and $13,281,250, plus interest, was released from escrow for disbursement to Mr. Grynberg, and $2,343,750, plus interest, was released from escrow for disbursement to us.

The Wyoming Choice Gas program, under which our customers are permitted to select their own supplier of natural gas, was reviewed by the Wyoming Public Service Commission to determine whether

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the existing program should continue and whether any program modifications should be made. A hearing was conducted in February 2003 and a decision was issued on March 11, 2003, authorizing the Choice Gas program to continue with several modifications. The traditional regulated pass-on rate must continue to be offered with the Choice Gas program. Customers who do not return a Choice Gas selection form will be assigned to the pass-on tariff rate. The $1 per month Choice Gas customer charge will not be applied to pass-on tariff customers.

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.

9.  Environmental and Legal Matters

(A) Environmental Matters

We have an established environmental reserve of approximately $14.4 million at December 31, 2003 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

United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claims Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The complaint asks to recover all royalties the Government allegedly should have received had the volume and heating content of the natural gas been valued properly, along with treble damages and civil penalties as provided for in the False Claims Act. Mr. Grynberg, as relator, seeks his statutory share of any recovery, plus expenses and attorney fees and costs. 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 the plaintiff's valuation claims has been granted by the Court. Mr. Grynberg has appealed that dismissal to the 10^th 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

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jurisdiction, arising out of the False Claims Act. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to CO₂ production. Defendants have filed briefs opposing leave to amend.

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 Claims Act cases, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg 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 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. 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 April 10, 2003, the Court issued its decision denying plaintiffs' motion for class certification. The plaintiffs moved the Court for permission to amend the complaint. On July 8, 2003, a hearing was held on the motion to amend. On July 28, 2003, the Court granted leave to amend the complaint. The amended complaint does not list us or any of our affiliates as defendants. Additionally, a new complaint was filed but that complaint does not list us or any of our affiliates as defendants. We will continue to monitor these matters.

Adams vs. Kinder Morgan, Inc., et al., Civil Action No. 00-M-516, filed in the United States District Court for the District of Colorado. The case was originally filed on March 8, 2000 and is a purported class action. As of this date no class has been certified. Plaintiffs seek compensatory damages against all defendants jointly and severally, together with interest, attorney fees and expenses. The plaintiffs brought claims alleging securities fraud under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 on behalf of all people who purchased the common stock of Kinder Morgan during the class period from October 30, 1997 to June 21, 1999. The class period occurred prior to the installation of our current management team in October 1999. The complaint centers on allegations of misleading statements concerning operations of the Bushton Processing Plant and certain contracts, as well as allegations of overstatement of income in violation of accounting principles generally accepted in the United States of America during the class period. 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 federal district court dismissed the Adams plaintiffs' second amended complaint with prejudice. On May 2, 2002, the Adams plaintiffs appealed the dismissal to the 10^th Circuit Court of Appeals. In a published decision, on August 11, 2003, the 10^th Circuit Court of Appeals reversed the

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district court's dismissal, but upheld the dismissal of Mr. Kinder, our Chairman and Chief Executive Officer, from this action. The mandate from the 10^th Circuit Court of Appeals was issued on October 17, 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. The 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. in Carson and Gray counties and other surrounding Texas counties. The plaintiff claims that American Processing (and subsequently ONEOK, which purchased American Processing from us in 2000) improperly allocated liquids and gas proceeds to the producers. In particular, among other claims, the plaintiff challenges the methods and assumptions used at the plants to allocate liquids 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. The plaintiff has alleged generally in the petition that damages are "not to exceed $200 million" plus attorney's fees, costs and interest. The 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. The 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. Class discovery is proceeding. The defendants expect to assert objections to class certification upon the completion of class discovery.

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. The plaintiff filed suit in late 1999 and alleges that American Processing (and subsequently ONEOK) improperly allocated liquids and gas proceeds. The defendants filed a counterclaim for overpayments to the plaintiff. 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. The parties recently completed fact and expert discovery. Cross motions for summary judgment are pending and trial is scheduled to occur in 2004. Based on information obtained in discovery, we believe plaintiff's alleged damages (which are in dispute) are less than $1.0 million such that an adverse judgment, if any, would not have a material adverse effect on our business. Barring unforeseen developments, future reports will not include a summary description of this matter.

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. The 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 have been 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 pertinent

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assets on March 1, 2000. On or about October 1, 2003, the plaintiff and ONEOK settled claims that relate to the period after March 1, 2000. Notwithstanding such settlement, the plaintiff continues to assert and we continue to defend against claims that relate to the period before March 1, 2000. In an amended petition filed in mid-2002, the plaintiff alleged damages in excess of $12 million. The 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 to complete fact discovery and trial. We believe that the resolution of the 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 business, 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 investigation and experience to date, that the ultimate resolution of such items will not have a material adverse impact on our business, cash flows, financial position or results of operations.

10.  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, 2003
	Property, Plant and Equipment	Accumulated D&A	Net
	(In thousands)
Natural Gas Pipelines	$  6,106,668	$    384,680	$  5,721,988
Retail Natural Gas Distribution	343,665	133,998	209,667
Electric Power Generation	39,220	6,861	32,359
General and Other	192,331	72,408	119,923
PP&E Related to Continuing Operations	$  6,681,884	$    597,947	$  6,083,937
	============	============	============
	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
	============	============	============

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11. 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,
	2003	2002	2001
	(Dollars in thousands)
Current Tax Provision:
Federal	$ 187,460	$  61,108	$  (4,184)
State	27,810	17,270	24,786
	215,270	78,378	20,602
Deferred Tax Provision:
Federal	30,287	85,026	128,266
State	(957)	(28,385)	10,689
	29,330	56,641	138,955
Total Tax Provision	$ 244,600	$ 135,019	$ 159,557
	=========	=========	=========
Effective Tax Rate	39.1%	30.5%	41.4%
	=====	=====	=====

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

	Year Ended December 31,
	2003	2002	2001
Federal Income Tax Rate	35.0%	35.0%	35.0%
Increase (Decrease) as a Result of:
State Income Tax, Net of Federal Benefit	2.8%	3.0%	5.7%
Kinder Morgan Management Minority Interest	2.5%	2.8%	1.4%
Deferred Tax Rate Change	-	(4.9%)	-
Prior Year Adjustments	-	(1.9%)	-
Resolution of Internal Revenue Service Audit	-	(2.0%)	-
Other	(1.2%)	(1.5%)	(0.7%)
Effective Tax Rate	39.1%	30.5%	41.4%
	=====	=====	=====

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

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Continuing Operations	$ 244,600	$ 135,019	$ 159,557
Discontinued Operations	-	(3,056)	-
Cumulative Effect of Transition Adjustment	-	-	(7,922)
Equity Items	(38,468)	(44,867)	43,866
Total	$ 206,132	$  87,096	$ 195,501
	=========	=========	=========

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Deferred tax assets and liabilities result from the following:

	December 31,
	2003	2002
	(In thousands)
Deferred Tax Assets:
Postretirement Benefits	$   14,262	$   14,011
Gas Supply Realignment Deferred Receipts	6,275	6,766
State Taxes	102,357	101,846
Book Accruals	42,903	93,819
Derivatives	26,298	18,829
Discontinued Operations	21,370	2,618
Capital Loss Carryforwards	6,930	-
Other	10,176	8,958
Total Deferred Tax Assets	230,571	246,847
Deferred Tax Liabilities:
Property, Plant and Equipment	2,145,518	1,983,060
Investments	523,932	696,251
Prepaid Pension Costs	21,233	178
Rate Matters	13,153	-
Other	4,064	3,138
Total Deferred Tax Liabilities	2,707,900	2,682,627
Net Deferred Tax Liabilities	$2,477,329	$2,435,780
	==========	==========

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. Also, during 2002, we resolved certain issues with the Internal Revenue Service at amounts less than those previously accrued.

12. Financing

(A) Notes Payable

At December 31, 2003, we had available a $445 million 364-day credit facility dated October 14, 2003, and a $355 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 2003 and 2002 were $1.3 million and $1.0 million, respectively. At December 31, 2003 and 2002, 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 2003, all commercial paper was redeemed within 83 days, with interest rates ranging from 1.03 percent to 1.60 percent. Commercial paper outstanding at December 31, 2003 was $127.9 million. No commercial paper was outstanding at December 31, 2002. Average short-term borrowings outstanding during 2003 and 2002 were $190.4 million and $415.2 million, respectively. During 2003 and 2002, the weighted-average interest rates on short-term borrowings outstanding were 1.30 percent and 2.07 percent, respectively.

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(B) Long-term Debt

	December 31,
	2003	2002
	(In thousands)
Debentures:
6.50% Series, Due 2013	$   50,000	$   50,000
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
Senior Notes:
6.45% Series, Due 2003	-	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	1,000,000
Other	-	11,083
Deferrable Interest Debentures Issued to Subsidiary Trusts1:
8.56% Junior Subordinated Deferrable Interest Debentures Due 2027	103,100	-
7.63% Junior Subordinated Deferrable Interest Debentures Due 2028	180,500	-
Carrying Value Adjustment for Interest Rate Swaps2	71,823	139,589
Unamortized Gain on Termination of Interest Rate Swap	16,419	-
Unamortized Premium on Long-term Debt	3,798	4,237
Unamortized Debt Discount	(4,311)	(4,872)
Current Maturities of Long-term Debt	(5,000)	(501,267)
Total Long-term Debt	$3,209,329	$2,991,770
	==========	==========

1	As a result of a recent change in accounting standards, the subsidiary trusts associated with these securities are no longer consolidated, effective December 31, 2003. See Note 20.
2	Adjustment of carrying value of long-term securities subject to outstanding interest rate swaps; see Note 14.

Maturities of long-term debt (in thousands) for the five years ending December 31, 2008 are $5,000, $505,000, $5,000, $5,000, and $305,000, 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. The Junior Subordinated Deferrable Interest Debentures are redeemable in whole or in part, (i) at our option after April 14, 2007 and (ii) at any time in certain limited circumstances upon the occurrence of certain events and at prices, all defined in the associated prospectus supplements. Upon redemption by us or at maturity of the Junior Subordinated Deferrable Interest Debentures, we must use the proceeds to make redemptions of the Capital Trust Securities on a pro rata basis.

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 a 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 "Other, Net" in the accompanying Consolidated Statement of Operations for 2002.

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. We issued these Floating Rate Notes on

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October 10, 2001. Effective September 1, 2002, we retired our $24 million of 7.85% Series Debentures due September 1, 2022 at par. We recorded a 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 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 November 18, 2002, we completed 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 we also exchanged for registered securities pursuant to our currently effective registration statement on Form S-4, in an exchange offer that was completed on March 21, 2003.

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 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 losses of $13.6 million (net of associated tax benefit of $9.0 million). These losses are included under the caption, "Other, Net" in the accompanying Consolidated Statement of Operations for 2001.

At December 31, 2003 and 2002, the carrying amount of our long-term debt was $3.2 billion and $3.5 billion, respectively. The estimated fair values of our long-term debt at December 31, 2003 and 2002 are shown in Note 18.

(C) Capital Trust Securities

Our 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. As a result of adopting a recent accounting pronouncement, (see Note 20), effective December 31, 2003, we (i) no longer include the transactions and balances of K N Capital Trust I and K N Capital Trust III in our consolidated financial statements and (ii) began including our Junior Subordinated Deferrable Interest Debentures issued to the Capital Trusts in a separate caption under the heading "Long-term Debt" in our Consolidated Balance Sheets. In addition, effective July 1, 2003 we (i) reclassified our trust preferred securities to the debt portion of our balance sheet and (ii) began classifying payments made by us in conjunction with the trust preferred securities as interest expense, rather than minority interest. For periods and dates prior to July 1, 2003, the Capital Securities are 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," and periodic payments made to the holders of these securities are classified under "Minority Interests" in our Consolidated Statements of Operations. See Note 18 for the fair value of these securities.

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(D) Common Stock

On February 13, 2004, we paid a cash dividend on our common stock of $0.5625 per share to stockholders of record as of January 30, 2004.

On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million and $500 million in February 2002, July 2002 and November 2003, respectively. As of December 31, 2003, we had repurchased a total of approximately $452.7 million (9,032,800 shares) of our outstanding common stock under the program, of which $38.0 million (724,600 shares) and $144.3 million (3,013,400 shares) were repurchased in the years ended December 31, 2003 and 2002, 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 of $991.9 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. 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 an additional 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. During 2003 we purchased $0.9 million (29,000 shares) of Kinder Morgan Management stock.

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 additional i-units from Kinder Morgan Energy Partners. We did not purchase any of the offered shares.

13. 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, 2003, 2002 and 2001, we did not have any outstanding shares of preferred stock.

14. 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

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Balance Sheet as of December 31, 2003, includes, exclusive of amounts related to interest rate swaps as discussed below, balances of approximately $7.4 million, $41 thousand, $17.7 million and $51 thousand 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.

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. However, we experienced a loss during 2001 as discussed following.

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.

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

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(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.

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.

During the three years ended December 31, 2003, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized a pre-tax gain of approximately $56,000 in 2003 and pre-tax losses of approximately $46,000 and $5,000 in 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. There was no component of these 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 2004, substantially all of the accumulated other comprehensive income balance of $7.2 million at December 31, 2003, representing unrecognized net losses on derivative activities. During the three years ended December 31, 2003, 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.

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.

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Our outstanding fixed-to-floating interest rate swap agreements had a notional principal amount of $1.5 billion at December 31, 2003. These agreements, entered into in August 2001, September 2002 and November 2003, effectively convert the interest expense associated with our 7.25% Debentures due in 2028 and our 6.50% Senior Notes due in 2012 from fixed rates to floating rates based on the three-month London Interbank Offered Rate ("LIBOR") plus a credit spread. These swaps have been designated as fair value hedges and we have accounted for them utilizing the "shortcut" method prescribed for qualifying fair value hedges under Statement 133. Accordingly, the carrying value of the swap is adjusted to its fair value as of the end of each reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. The fair value of the swaps of $71.8 million at December 31, 2003 is included in the caption "Deferred Charges and Other Assets" in the accompanying Consolidated Balance Sheet. 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 swaps discussed above and our $127.9 million of outstanding commercial paper at December 31, 2003, the market risk related to a one percent change in interest rates would result in a $16.3 million annual impact on pre-tax income.

On March 3, 2003, we terminated the interest rate swap agreements associated with our 6.65% Senior Notes due in 2005 and received $28.1 million in cash. We are amortizing this amount (reducing interest expense) over the remaining period the 6.65% Senior Notes are outstanding. The unamortized balance of $16.4 million at December 31, 2003 is included in the caption "Value of Interest Rate Swaps" under the heading "Long-term Debt" in the accompanying Consolidated Balance Sheet.

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

	December 31, 2003
	Commodity Contracts	Over-the-Counter Swaps and Options		Total
	(Dollars in thousands)
Deferred Net Loss	$  (2,868)		$  (6,951)	$  (9,819)
Contract Amounts - Gross	$ 102,953		$ 124,246	$ 227,199
Contract Amounts - Net	$ (65,828)		$ (29,691)	$ (95,519)
	(Number of Contracts1)
Notional Volumetric Positions: Long	337		785
Notional Volumetric Positions: Short	(1,612)		(1,457)
Net Notional Totals To Occur in 2004	(1,275)		(672)
Net Notional Totals To Occur in 2005 and Beyond	-		-

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. At December 31, 2003, we were not owed money by any counterparties, and therefore have no credit exposure.

15. 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

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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 $20.4 million and $14.3 million as of December 31, 2003 and 2002, respectively. The measurement date for our retirement plans is December 31.

Net periodic pension cost includes the following components:

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Service Cost	$    8,133	$    7,121	$    5,329
Interest Cost	11,118	10,484	9,421
Expected Return on Assets	(13,282)	(15,665)	(15,145)
Net Amortization and Deferral	1,625	21	(1,282)
Settlement Loss	-	76	-
Net Periodic Pension (Benefit) Cost	$    7,594	$    2,037	$   (1,677)
	==========	==========	==========

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

	2003	2002
	(In thousands)
Benefit Obligation at Beginning of Year	$ (162,181)	$ (140,767)
Service Cost	(8,133)	(7,121)
Interest Cost	(11,118)	(10,484)
Actuarial (Gain) Loss	(8,416)	(6,629)
Benefits Paid	8,986	9,021
Settlement Loss	-	(70)
Plan Amendments	-	(1,482)
Business Combinations/Mergers	-	(4,649)
Benefit Obligation at End of Year	$ (180,862)	$ (162,181)
	==========	==========

The accumulated benefit obligation through December 31, 2003 and 2002 was $170.9 million and $153.4 million, respectively.

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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,
	2003	2002
	(In thousands)
Fair Value of Plan Assets at Beginning of Year	$  147,591	$  149,477
Actual Return on Plan Assets During the Year	37,971	(17,739)
Contributions by Employer	9,034	20,238
Benefits Paid During the Year	(8,986)	(9,021)
Business Combinations/Mergers	-	4,636
Fair Value of Plan Assets at End of Year	185,610	147,591
Benefit Obligation at End of Year	(180,862)	(162,181)
Plan Assets in Excess of (Less Than) Projected Benefit Obligation	4,748	(14,590)
Unrecognized Net (Gain) Loss	19,802	37,683
Prior Service Cost Not Yet Recognized in Net Periodic Pension Costs	2,017	2,195
Unrecognized Net Asset at Transition	(196)	(358)
Prepaid Pension Cost Prior to Adjustment to Recognize
Minimum Liability	26,371	24,930
Adjustment to Recognize Minimum Liability	-	(30,787)
Prepaid /(Accrued) Pension Cost After Adjustment to Recognize
Minimum Liability	$   26,371	$   (5,857)
	==========	==========

For 2004, we do not expect to make any contributions to the Plan.

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 2002, this minimum liability amounted to $5.9 million. At December 31, 2003, the fair value of plan assets exceeded the accumulated benefit obligation; therefore, no minimum liability was recognized. Prepaid pension cost as of December 31, 2003 is recognized under the caption, "Current Assets: Other" in the accompanying 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.

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

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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 2003, 2002 and 2001 was $11.5 million $11.4 million and $9.5 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. The measurement date for our postretirement plan is December 31.

Net periodic postretirement benefit cost includes the following components:

	Year Ended December 31,
	2003	2002	2001
	(In thousands)
Service Cost	$      406	$      419	$      340
Interest Cost	6,968	7,251	7,266
Expected Return on Assets	(5,450)	(6,721)	(5,431)
Net Amortization and Deferral	3,333	2,352	1,501
Net Periodic Postretirement Benefit Cost	$    5,257	$    3,301	$    3,676
	==========	==========	==========

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

	2003	2002
	(In thousands)
Benefit Obligation at Beginning of Year	$ (105,278)	$ (101,063)
Service Cost	(406)	(419)
Interest Cost	(6,968)	(7,251)
Actuarial Gain (Loss)	(6,151)	(9,304)
Benefits Paid	15,510	16,440
Retiree Contributions	(3,646)	(3,681)
Benefit Obligation at End of Year	$ (106,939)	$ (105,278)
	==========	==========

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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,
	2003	2002
	(In thousands)
Fair Value of Plan Assets at Beginning of Year	$    65,084	$    80,098
Actual Return on Plan Assets	6,382	(2,522)
Contributions by Employer	5,000	-
Retiree Contributions	3,637	4,715
Benefits Paid	(17,410)	(11,332)
Asset Value Adjustment	-	(5,875)
Fair Value of Plan Assets at End of Year	62,693	65,084
Benefit Obligation at End of Year	(106,939)	(105,278)
Excess of Projected Benefit Obligation Over Plan Assets	(44,246)	(40,194)
Unrecognized Net (Gain) Loss	54,283	49,284
Unrecognized Net Obligations at Transition	8,361	9,291
Unrecognized Prior Service Cost	2,329	2,567
Prepaid Expense	$    20,727	$    20,948
	===========	===========

We do not expect to make any significant contributions to the plan in 2004.

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 2003 net periodic postretirement benefit cost by approximately $5,680 ($5,234) and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2003 by approximately $83,546 ($77,626).

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 ("the Act") was signed into law. In January 2004, the FASB issued Staff Position FAS 106-1 to provide guidance on accounting and disclosure for the Act as it pertains to postretirement benefit plans (see Note 20). The amounts presented for accumulated benefit obligation and net periodic postretirement benefit cost do not include the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy included in the Act is pending and that guidance, when issued, could require restatement of these amounts.

(C) Actuarial Assumptions

The assumptions used to determine benefit obligations for the pension and postretirement benefit plans were:

	December 31,
	2003	2002	2001
Discount Rate	6.50%	7.00%	7.25%
Expected Long-term Return on Assets	9.0%	9.0%	9.5%
Rate of Compensation Increase (Pension Plan Only)	3.5%	3.5%	3.5%

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The assumptions used to determine net periodic benefit cost for the pension and postretirement benefits were:

	Year Ended December 31,
	2003	2002	2001
Discount Rate	7.0%	7.25%	7.75%
Expected Long-term Return on Assets	9.0%	9.5%	9.5%
Rate of Compensation Increase (Pension Plan Only)	3.5%	3.5%	3.5%

The assumed healthcare cost trend rates for the postretirement plan were:

	December 31,
	2003	2002	2001
Healthcare Cost Trend Rate Assumed for Next Year	3.0%	3.0%	3.0%
Rate to which the Cost Trend Rate is Assumed to     Decline (Ultimate Trend Rate)	3.0%	3.0%	3.0%
Year the Rate Reaches the Ultimate Trend Rate	2003	2002	2001

(D) Plan Investment Policies

The investment policies and strategies for the assets of our pension and retiree life and medical plans are established by the plans' Fiduciary Committee (the "Committee"). The stated philosophy of the Committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans' obligations will be met. The objectives of the investment management program are to (1) ultimately achieve and maintain a fully funded status based on relevant actuarial assumptions, (2) have the ability to pay all plan obligations when due, (3) as a minimum, meet or exceed actuarial return assumptions and (4) earn the highest possible rate of return consistent with established risk tolerances. In seeking to meet these objectives, the Committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee has adopted a strategy of using multiple asset classes. As of December 31, 2003, the following target asset allocation ranges were in effect (Minimum/Target/Maximum): Cash - 0%/0%/5%; Fixed Income - 20%/30%/40% and Equity - 60%/70%/80%. In order to achieve enhanced diversification, the equity category is further subdivided into sub-categories with respect to Kinder Morgan Stock, small cap vs. large cap, value vs. growth and international vs. domestic, each with its own target asset allocation (in the case of Kinder Morgan Stock, the allocation range was 5%/10%/15% at December 31, 2003).

In implementing its investment policies and strategies, the Committee has engaged a professional investment advisor to assist with its decision making process and has engaged professional money managers to manage plan assets. The Committee believes that such active investment management will achieve superior returns with comparable risk in comparison to passive management. Consistent with its goal of reasonable diversification, no manager of an equity portfolio for the plan is allowed to have more than 10% of the market value of the portfolio in a single security or weight a single economic sector more than twice the weighting of that sector in the appropriate market index. Finally, investment managers are not permitted to invest or engage in the following unless specific permission is given in writing (which permission has not been requested or granted by the Committee to-date): derivative instruments, except for the purpose of asset value protection (such as writing covered calls), direct ownership of letter stock, restricted stock, limited partnership units (unless the security is registered and listed on a domestic exchange), venture capital, short sales, margin purchases or borrowing money, stock loans and commodities. Certain other types of investments such as hedge funds and land purchases are not prohibited as a matter of policy but have not, as yet, been adopted as an asset class or received any allocation of fund assets.

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(E) Return on Plan Assets

At December 31, 2002, our pension and retiree life and medical fund assets consisted of approximately 63.9% equity, 32.3% debt and 3.8% cash and cash equivalents. At December 31, 2003, the corresponding amounts were approximately 71.9% equity, 25.6% debt and 2.5% cash and cash equivalents. 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%, indicating that a long-term expected return predicated on the asset allocation as of December 31, 2003 would be approximately 8.8% 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 0.7% to 1.15% due to active management. Our historical premium over a balanced index was 3.08%, 2.77% and 3.92% for the 1-year, 3-year and 5-year periods ended December 31, 2003, respectively. Therefore, using the low end of the range for the expected active management premium, we arrive at an overall expected return of 9.45%, which we have lowered slightly to 9% for purposes of making the required calculations.

16. Common Stock Option and Purchase Plans

We have the following stock option plans: 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) 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(S).

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. On July 16, 2003, approximately 706 thousand shares were granted to employees under the Long-term Incentive Plan. These shares will vest 100 percent after three years and have a 7-year life. It is anticipated that options with similar terms will be granted in future years under the 1999 stock option plan.

Under all plans, except the Long-term Incentive 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 $3.4 million, $1.4 million and $0.6 million

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for 2003, 2002 and 2001, respectively, relating to restricted stock grants awarded under the plans.

Plan Name	Shares Subject to the Plan	Option Shares Granted Through December 31, 2003	Vesting Period	Expiration Period
1992 Directors' Plan	1,025,000	617,875	0 - 6 Months	10 Years
Long-term Incentive Plan	5,700,000	4,285,487	0 - 5 Years	5 - 10 Years
1999 Plan	10,500,000	7,514,677	4 Years	10 Years

A summary of the status of our stock option plans at December 31, 2003, 2002 and 2001, and changes during the years then ended is presented in the table and narrative below:

	2003		2002		2001
	Shares	Wtd. Avg. Exercise Price	Shares	Wtd. Avg. Exercise Price	Shares	Wtd. Avg. Exercise Price
Outstanding at Beginning
of Year	7,480,915	$ 35.94	6,975,717	$ 33.12	6,093,819	$ 26.05
Granted	1,019,700	$ 50.42	1,231,525	$ 47.76	2,140,200	$ 51.17
Exercised	(1,653,991)	$ 26.25	(519,091)	$ 23.46	(899,664)	$ 25.36
Forfeited	(347,117)	$ 36.54	(207,236)	$ 38.64	(358,638)	$ 35.14
Outstanding at End of Year	6,499,507	$ 35.45	7,480,915	$ 35.94	6,975,717	$ 33.12
	==========	=======	==========	=======	==========	=======
Exercisable at End of Year	3,918,118	$ 35.46	3,978,017	$ 31.93	2,922,471	$ 29.93
	==========	=======	==========	=======	==========	=======
Weighted-Average Fair
Value of Options Granted		$ 16.60		$ 19.36		$ 21.31
		=======		=======		=======

The following table sets forth our common stock options outstanding at December 31, 2003, 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	70,250	$ 22.12	3.80 years	70,250	$ 22.12
$23.81 - $23.81	1,518,486	$ 23.81	5.77 years	1,518,486	$ 23.81
$24.04 - $39.12	1,564,873	$ 33.88	6.44 years	961,024	$ 32.27
$39.38 - $52.10	1,514,973	$ 48.73	7.51 years	864,627	$ 49.35
$53.20 - $56.99	1,830,925	$ 54.55	7.23 years	503,731	$ 54.65
	6,499,507	$ 35.45	6.73 years	3,918,118	$ 35.46
	==========			==========

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 95,997 shares, 127,425 shares and 88,333 shares for plan years 2003, 2002 and 2001, 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 2003, 2002 and 2001 was $9.67, $9.60 and $10.66, respectively.

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17. Commitments and Contingent Liabilities

(A) Leases and Guarantee

Expenses incurred under operating leases were $6.4 million in 2003, $8.1 million in 2002 and $7.1 million in 2001. Future minimum commitments under major operating leases as of December 31, 2003 are as follows:

Year	Commitment
	(In thousands)
2004	$   31,106
2005	30,197
2006	30,231
2007	29,088
2008	27,260
Thereafter	438,032
Total	$  585,914
	==========

Included in the future minimum commitments shown in the preceding table is the lease obligation associated with the Jackson, Michigan power generation facility. The project company that is the lessee of this facility is now consolidated as a result of the adoption of a recent accounting pronouncement. The facility is subject to a long-term tolling agreement, and the lease obligation is without recourse to the project investors. See Note 20 for additional information regarding this matter.

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 $210 million at December 31, 2003, 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 $75.6 million of our consolidated capital expenditure budget for 2004 had been committed for the purchase of plant and equipment at December 31, 2003.

(C) Commitments for Incremental Investment

We could be obligated (i) based on operational performance of the equipment at our Jackson, Michigan power generation facility to invest up to an additional $3 to $8 million per year for the next 15 years and (ii) based on cash flows generated by the facility, to invest up to an additional $25 million beginning in 2018, in each case in the form of an incremental preferred interest.

(D) Standby Letters of Credit

Letters of credit totaling $30.4 million outstanding at December 31, 2003 consisted of the following: (i) four letters of credit, totaling $8.0 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 $1.0 million

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letter of credit supporting a utility service contract between Entergy Gulf States, Inc. and Natural Gas Pipeline Company of America, (iv) a $6.6 million letter of credit associated with the outstanding debt of Thermo Cogeneration Partnership, L.P., the entity responsible for the operation of our Colorado power generation assets and (v) a $1.8 million letter of credit supporting Thermo Cogeneration Partnership, L.P.'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(N) and Note 7.

18. 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,
	2003		2002
	Carrying Value	Fair Value	Carrying Value	Fair Value
	(In millions)
Financial Liabilities:
Long-term Debt	$ 3,198.41	$ 3,495.41	$ 3,493.71	$ 3,632.81
Capital Securities	$       -	$       -	$   275.0	$   280.6
Energy Financial Instruments, Net	$    (9.8)	$    (9.8)	$   (20.6)	$   (20.6)
Outstanding Interest Rate Swaps	$   (71.8)	$   (71.8)	$  (139.6)	$  (139.6)

1 Includes an adjustment exactly offsetting the fair value of the outstanding interest rate swaps. See Note 14.

19. 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, 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 in Hermosillo, Mexico) and the sales of natural gas to certain utility customers under the Choice Gas Program and (4) Power, the operation and, in previous periods, construction of natural gas-fired electric generation facilities. In previous periods, we owned and operated other lines of business that we discontinued during 1999.

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

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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 2003, approximately 43 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 2003, approximately 54 percent of its operating revenues from tariff services were attributable to its eight largest customers. TransColorado'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 2003, 46 percent of TransColorado's transport business was with producers or their own marketing affiliates, 44 percent was with third-party marketers and the remaining 10 percent was primarily with gathering companies. Approximately 36 percent of TransColorado's transport business in 2003 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. During 2003, approximately 30% of Power's operating revenues were electric sales revenues from XCEL Energy's Public Service Company of Colorado under a long-term contract, 25% were for operating the Jackson, Michigan power facility, and 21% were revenues related to the construction of the Jackson, Michigan power facility.

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 2003, 2002 and 2001, we did not have revenues from any single customer that exceeded 10 percent of our consolidated operating revenues.

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Business Segment Information

	Year Ended December 31, 2003					December 31, 2003
	Segment Earnings	Revenues From External Customers	Intersegment Revenues	Depreciation And Amortization	Capital Expenditures	Segment Assets
	(In thousands)
Natural Gas Pipeline
Company of America	$ 372,017	$  784,732	$      -	$  92,193	$ 114,504	$ 5,551,595
TransColorado1	23,112	32,197	-	4,224	14,841	267,597
Kinder Morgan Retail	65,482	249,119	-	16,197	28,816	423,138
Power	22,076	31,849	-	4,914	2,643	450,799
Segment Totals	482,687	$1,097,897	$      -	$ 117,528	$ 160,804	6,693,129
		==========	========	=========	=========
Earnings from Investment
in Kinder Morgan Energy				Investment In Kinder Morgan
Partners	464,967			Energy Partners		2,106,312
General and Administrative				Goodwill		972,380
Expenses	(71,741)			Other2		264,890
Other Income and				Consolidated		$10,036,711
(Expenses)	(249,609)					===========
Income from
Continuing Operations
Before Income Taxes	$ 626,304
	=========

	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
TransColorado1	12,648	7,725	93	1,062	325	258,627
Kinder Morgan Retail	64,056	259,748	-	15,044	25,395	406,797
Power	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				Investment In Kinder Morgan
Partners	392,135			Energy Partners		2,034,160
General and Administrative				Goodwill		990,878
Expenses	(73,496)			Other2		393,337
Other Income and				Consolidated		$10,102,750
(Expenses)	(349,197)					===========
Income from
Continuing Operations
Before Income Taxes	$ 442,730
	=========

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	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
TransColorado1	(5,268)	-	-	-	-	134,256
Kinder Morgan Retail	56,696	290,300	44	12,590	35,629	380,339
Power	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				Investment In Kinder Morgan
Partners	251,860			Energy Partners		1,772,027
General and Administrative				Goodwill		1,055,767
Expenses	(73,319)			Other2		244,672
Other Income and				Consolidated		$ 9,513,121
(Expenses)	(257,894)					===========
Income from
Continuing Operations
Before Income Taxes	$ 384,627
	=========

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	Includes, as applicable to each particular year, the 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.

20. Recent Accounting Pronouncements

In January 2004, the FASB issued FASB Staff Position ("FSP") FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act"). This FSP permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act. Regardless of whether a company elects that deferral, the FSP requires certain disclosures pending further consideration of the underlying accounting issues. We have elected to defer accounting for the effects of the act and have applied the disclosure provisions of the FSP effective December 31, 2003, [see Note 15(B)].

In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. This interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of certain variable interest entities.

This interpretation explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. It requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. Variable interest entities that effectively disperse risks will not be consolidated unless a single party holds an interest or combination of interests that effectively recombines risks that were previously dispersed.

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An enterprise that consolidates a variable interest entity is the primary beneficiary of the variable interest entity. The primary beneficiary of a variable interest entity is the party that absorbs a majority of the entity's expected losses, receives a majority of its expected residual returns, or both, as a result of holding variable interests, which are the ownership, contractual, or other monetary interests in an entity that change with changes in the fair value of the entity's net assets excluding variable interests. This interpretation requires the primary beneficiary of a variable interest entity, and an enterprise that holds significant variable interests in a variable interest entity but is not the primary beneficiary, to make certain disclosures about the variable interest entity.

Application of this interpretation is required in financial statements of public entities that have interests in variable interest entities or potential variable interest entities commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application by public entities (other than small business issuers) for all other types of entities is required in financial statements for periods ending after March 15, 2004.

The principal impact of this interpretation on us is that, effective December 31, 2003, we began 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 are including the lease obligation on the Jackson plant in our consolidated financial statements. The total remaining lease payments at December 31, 2003 are $540.9 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 addition, as a result of the implementation of this interpretation, effective December 31, 2003, we (i) no longer include the transactions and balances of our business trusts, K N Capital Trust I and K N Capital Trust III, in our consolidated financial statements and (ii) began including our Junior Subordinated Deferrable Interest Debentures issued to the Capital Trusts in a separate caption under the heading "Long-term Debt" in our Consolidated Balance Sheets.

In December 2003, the FASB issued SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits. The statement revises employers' financial statement disclosures about defined benefit pension plans and other postretirement benefit plans. The statement does not change the measurement or recognition of those plans and retains the disclosures required by the original SFAS No. 132, which standardized the disclosure requirements for pensions and other postretirement benefits to the extent practicable and required additional information on changes in the benefit obligations and fair values of plans assets.

The revised statement requires additional disclosures to those in the original SFAS No. 132 about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The revised statement also requires interim disclosures.

This revised statement is effective for financial statements with fiscal years ending after December 15, 2003. The interim period disclosures required by this statement are effective for interim periods beginning after December 15, 2003. Disclosure of estimated future benefit payments required by portions of this revised statement is effective for fiscal years ending after June 15, 2004. We adopted SFAS No. 132 (revised 2003) effective December 31, 2003.

In December 2003, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin No. 104, Revenue Recognition, which updates and revises the staff's interpretive guidance to

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make it consistent with current accounting guidance related to multiple element revenue arrangements. The issuance of this bulletin has had no impact on our revenue recognition policies.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity.

SFAS No. 150 requires an issuer to classify the following instruments as liabilities (or assets in some circumstances):

• a financial instrument issued in the form of shares that is mandatorily redeemable - that embodies an unconditional obligation requiring the issuer to redeem it by transferring its assets at a specified or determinable date (or dates) or upon an event that is certain to occur;

• a financial instrument, other than an outstanding share, that, at inception, embodies an obligation to repurchase the issuer's equity shares, or is indexed to such an obligation, and that requires or may require the issuer to settle the obligation by transferring assets (for example, a forward purchase contract or written put option on the issuer's equity shares that is to be physically settled or net cash settled); and

• a financial instrument that embodies an unconditional obligation, or a financial instrument other than an outstanding share that embodies a conditional obligation, that the issuer must or may settle by issuing a variable number of its equity shares, if, at inception, the monetary value of the obligation is based solely or predominantly on any of the following:

• a fixed monetary amount known at inception, for example, a payable settleable with a variable number of the issuer's equity shares;

• variations in something other than the fair value of the issuer's equity shares, for example, a financial instrument indexed to the Standard & Poor's 500 and settleable with a variable number of the issuer's equity shares; or

• variations inversely related to changes in the fair value of the issuer's equity shares, for example, a written put option that could be net share settled.

The requirements of this statement apply to issuers' classification and measurement of freestanding financial instruments, including those that comprise more than one option or forward contract. This statement does not apply to features that are embedded in a financial instrument that is not a derivative in its entirety. It also does not affect the classification or measurement of convertible bonds, puttable stock, or other outstanding shares that are conditionally redeemable. This statement also does not address certain financial instruments indexed partly to the issuer's equity shares and partly, but not predominantly, to something else.

This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003, except for mandatorily redeemable financial instruments of nonpublic entities. It is to be implemented by reporting the cumulative effect of a change in accounting principle for financial instruments created before the issuance date of the statement and still existing at the beginning of the interim period of adoption. Restatement is not permitted. We adopted SFAS No. 150 effective July 1, 2003. As a result, during the period from July 1, 2003 until their deconsolidation as a result of our adoption of

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Interpretation No. 46 on December 31, 2003 (see discussion preceding), we (i) reclassified our trust preferred securities to the debt portion of our balance sheet and (ii) classified payments made by us in conjunction with the trust preferred securities as interest expense, rather than minority interest.

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. We applied the disclosure provisions of SFAS No. 148 effective December 31, 2002.

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. We adopted Interpretation No. 45 effective December 31, 2002. For more information, see Note 17.

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, are no longer classified as extraordinary items but are, instead, reported as part of income from continuing operations and separately described, if material.

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SELECTED QUARTERLY FINANCIAL DATA
KINDER MORGAN, INC. AND SUBSIDIARIES
Quarterly Operating Results for 2003

	Three Months Ended
	March 31	June 30	September 30	December 31
	(In thousands except per share amounts)
	(Unaudited)
Operating Revenues	$  318,868	$  251,865	$  246,983	$  280,181
Gas Purchases and Other Costs of Sales	112,955	79,852	72,515	88,939
Other Operating Expenses	83,108	86,765	86,888	130,7821
Operating Income	122,805	85,248	87,580	60,460
Other Income and (Expenses)	59,079	68,787	69,323	73,022
Income Before Income Taxes	181,884	154,035	156,903	133,482
Income Taxes	70,814	59,841	61,273	52,672
Net Income	$  111,070	$   94,194	$   95,630	$   80,810
	==========	==========	==========	==========
Basic Earnings Per Common Share	$     0.91	$     0.77	$     0.78	$     0.66
	==========	==========	==========	==========
Number of Shares Used in Computing
Basic Earnings Per Common Share	121,877	122,218	123,109	123,196
	==========	==========	==========	==========
Diluted Earnings Per Common Share	$     0.90	$     0.76	$     0.77	$     0.65
	==========	==========	==========	==========
Number of Shares Used in Computing
Diluted Earnings Per Common Share	123,078	123,474	124,345	124,365
	==========	==========	==========	==========

1  Includes a charge of $44.5 million to revalue certain of our Power assets; see Note 6.

111

SELECTED QUARTERLY FINANCIAL DATA
KINDER MORGAN, INC. AND SUBSIDIARIES
Quarterly Operating Results for 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
Other Operating Expenses	81,799	83,553	83,154	218,8581
Operating Income (Loss)	108,355	76,871	84,666	(33,225)
Other Income and (Expenses)	43,711	46,293	53,632	62,427
Income from Continuing Operations
Before Income Taxes	152,066	123,164	138,298	29,202
Income Taxes (Benefit)	63,678	50,712	57,895	(37,266)
Income from Continuing Operations	88,388	72,452	80,403	66,468
Loss on Disposal of Discontinued   Operations, Net of Tax	-	-	-	(4,986)
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	$     0.55
Loss on Disposal of Discontinued Operations	-	-	-	(0.04)
Total Basic Earnings Per Common Share	$     0.72	$     0.59	$     0.66	$     0.51
	==========	==========	==========	==========
Number of Shares Used in Computing
Basic Earnings Per Common 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	$     0.54
Loss on Disposal of Discontinued Operations	-	-	-	(0.04)
Total Diluted Earnings Per Common Share	$     0.71	$     0.59	$     0.66	$     0.50
	==========	==========	==========	==========
Number of Shares Used in Computing
Diluted Earnings Per Common 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.

112

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

None.

Item 9A. Controls and Procedures.

As of December 31, 2003, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures in accordance with Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required. There has been no change in our internal control over financial reporting during the three months ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 2004 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference. For information regarding our current executive officers, see "Executive Officers of the Registrant" in Part I.

Item 11. Executive Compensation.

Information required by this item is contained in our Proxy Statement related to the 2004 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.

Information required by this item is contained in our Proxy Statement related to the 2004 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 13. Certain Relationships and Related Transactions.

Information required by this item is contained in our Proxy Statement related to the 2004 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.

113

Item 14. Principal Accounting Fees and Services.

Information required by this item is contained in our Proxy Statement related to the 2004 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.

114

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 91 through 162 of Kinder Morgan Energy Partners' Annual Report on Form 10-K for the year ended December 31, 2003.

(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 K N Energy, Inc.'s 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 K N Energy, Inc.'s 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 Kinder Morgan, Inc.'s 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 Kinder Morgan, Inc.'s 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)

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Exhibit Number	Description
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*	By-Laws of Kinder Morgan, Inc., as amended to January 2004
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 Kinder Morgan, Inc.'s 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 to the Registration Statement on Form S-3 (File No. 33-45091) of K N Energy, Inc. filed on January 17, 1992)
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 Kinder Morgan, Inc.'s 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 to the Registration Statement on Form S-3 (File No. 33-51115) of K N Energy, Inc. filed on November 19, 1993) 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*	$445,000,000 Amended and Restated 364-Day Credit Agreement among Kinder Morgan, Inc., certain banks listed therein and Wachovia Bank, National Association and JPMorgan Chase Bank, as Co-Syndication Agents, dated October 14, 2003
Exhibit 4.6	Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. dated May 18, 2001 (Exhibit 4.7 to Kinder Morgan, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2002)
Exhibit 4.7	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 (File No. 1-6446))
Exhibit 4.8	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 K N Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-6446))

116

Exhibit Number	Description
Exhibit 4.9	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 4.10	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 Kinder Morgan, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2001)
Exhibit 4.11	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.'s Registration Statement on Form S-4 (File No. 333-100338) filed on October 4, 2002)
Exhibit 4.12	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.'s Registration Statement on Form S-4 (File No. 333-102873) filed on January 31, 2003)
Exhibit 4.13	Form of 6.50% Note (contained in the Indenture incorporated by reference to Exhibit 4.12 hereto)
Exhibit 4.14	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.'s Registration Statement on Form S-4 (File No. 333-102873) filed on January 31, 2003)
Exhibit 4.15	Form of certificate representing the common stock of Kinder Morgan, Inc. (filed as Exhibit 4.1 to Kinder Morgan, Inc.'s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003)
Exhibit 4.16	Form of Senior Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan, Inc.'s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003)
Exhibit 4.17	Form of Senior Note of Kinder Morgan, Inc. (included in the Form of Senior Indenture incorporated by reference to Exhibit 4.16 hereto)
Exhibit 4.18	Form of Subordinated Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.4 to Kinder Morgan, Inc.'s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003)
Exhibit 4.19	Form of Subordinated Note of Kinder Morgan, Inc. (included in the Form of Subordinated Indenture incorporated by reference to Exhibit 4.18 hereto)

   117

Exhibit Number	Description
Exhibit 10.1	1994 Amended and Restated Kinder Morgan, Inc. Long-term Incentive Plan (Appendix A to Kinder Morgan, Inc.'s 2000 Proxy Statement on Schedule 14A)
Exhibit 10.2	Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan (Exhibit 10.2 to Kinder Morgan, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2002)
Exhibit 10.3	Kinder Morgan, Inc. Amended and Restated 1992 Stock Option Plan for Nonemployee Directors (Appendix A to Kinder Morgan, Inc.'s 2001 Proxy Statement on Schedule 14A)
Exhibit 10.4	2000 Annual Incentive Plan of Kinder Morgan, Inc. (Appendix D to Kinder Morgan, Inc.'s 2000 Proxy Statement on Schedule 14A)
Exhibit 10.5	Kinder Morgan, Inc. Employees Stock Purchase Plan (Appendix E to Kinder Morgan, Inc.'s 2000 Proxy Statement on Schedule 14A)
Exhibit 10.6	Form of Nonqualified Stock Option Agreement (Exhibit 10(f) to Kinder Morgan, Inc.'s 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 Kinder Morgan, Inc.'s 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 K N Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-6446))
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 November 16, 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	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 31.1*	Section 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Exhibit 31.2*	Section 13a-14(a)/15d-14(a) Certification of Chief Financial Officer

   118

Exhibit
Number Description

Exhibit 32.1*	Section 1350 Certification of Chief Executive Officer
Exhibit 32.2*	Section 1350 Certification of Chief Financial Officer
Exhibit 99.1*	The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries included on pages 91 through 162 on the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2003

*  Filed herewith.

(b)   Reports on Form 8-K

(1) Current Report on Form 8-K dated October 21, 2003 was furnished on October 21, 2003 pursuant to Item 9 of that form.

We announced that on October 20, 2003, Michael C. Morgan, President of Kinder Morgan, Inc., completed a net investment of approximately $2.68 million by exercising options to purchase 140,000 shares of our common stock into directly held outstanding shares and provided details of the transactions. We disclosed that after these transactions, Mr. Morgan held 230,003 shares of our common stock, including 112,500 shares of restricted stock.

(2) Current Report on Form 8-K dated October 21, 2003 was furnished on October 21, 2003 pursuant to Item 9 of that form.

We announced (i) that representatives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC intended to discuss and answer questions relating to Kinder Morgan Energy Partners, L.P.'s CO₂ business in a live webcast on that date and (ii) the ability of interested parties to access the audio webcast, both live and on-demand.

(3) Current Report on Form 8-K dated December 8, 2003 was furnished on December 8, 2003 pursuant to Item 9 of that form.

We announced (i) that representatives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC intended to make presentations on December 9, 2003, at the Wachovia Securities Pipeline Conference to discuss the financials, business plans and objectives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC and (ii) the availability of materials to be presented at the conference on our website.

(4) Current Report on Form 8-K dated January 22, 2004 was furnished on January 23, 2004 pursuant to Item 9 of that form.

We announced (i) that representatives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC intended to make presentations on January 23, 2004, at the Kinder Morgan Analyst Conference to address the fiscal year 2003 results, the fiscal year 2004 outlook and other business information about us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC, (ii) the availability of materials to be presented at the conference on our website and (iii) the ability of interested parties to access the audio webcast, both live and on-demand.

   119

(5) Current Report on Form 8-K dated January 21, 2004 was furnished on January 28, 2004 pursuant to Item 7 and Item 12 of that form.

Pursuant to Item 12 of that form, we disclosed that on January 21, 2004 we issued a press release regarding our financial results for the quarter and year ended December 31, 2003, and held a webcast conference call on January 21, 2004 discussing those results.

Pursuant to Item 7 of that form, we filed our press release dated January 21, 2004 and an unedited transcript of the webcast conference call, prepared by an outside vendor, as exhibits.

120

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 and Chief Financial Officer
Date: March 5, 2004

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

/s/ 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 and Chief Financial Officer
C. Park Shaper	(Principal Financial and Accounting Officer)
/s/ H. A. TRUE, III	Director

H. A. True, III

121

EX-3.4

Exhibit 3.4

KINDER MORGAN, INC.


B Y - L A W S


As Amended to January 2004

ARTICLE 1

OFFICES

Section 1.Offices.  The registered office shall be at 200 SW 30th Street, Topeka, Kansas 66611. The corporation's principal executive office shall be at 500 Dallas, Suite 1000, Houston, Texas 77002.

Section 2.Additional Offices.The corporation may also have offices at such other places both within and without the State of Kansas as the Board of Directors may from time to time determine or the business of the corporation may require.

ARTICLE II

MEETING OF STOCKHOLDERS

Section 1.Time and Place.  The annual meeting of the stockholders for the election of directors and all special meetings of stockholders for that or for any other purpose may be held at such time and place within or without the State of Kansas as shall be stated in the notice of the meeting, or in a duly executed waiver of notice thereof.

Section 2.Annual Meeting.  The annual meeting of the stockholders shall be held each year at a time to be determined by the Board of Directors, at which meeting the stockholders shall elect a Board of Directors, and transact such other business as may be properly brought before the meeting.

Section 3.Special Meetings.  Special meetings of the stockholders, for any purpose or purposes, unless otherwise prescribed by statute may be called by the Chairman of the Board, if any, the President or the Board of Directors, and shall be called by the President or the Secretary at the request in writing of a majority of the directors, or at the request in writing of stockholders owning at least fifty-one percent (51%) in amount of the shares of the corporation issued and outstanding and entitled to vote. Such request shall state the purpose or purposes of the proposed meeting.

Section 4.Notice.  Written notice of the place, date and hour of any annual or special meeting of stockholders shall be given personally or by mail to each stockholder entitled to vote thereat, not less than ten (10) nor more than sixty (60) days prior to the meeting. The notice shall state in addition, the purpose or purposes for which the meeting is called, and by, or at whose direction it is being issued.

Section 5.Quorum.  Except as otherwise provided by the Articles of Incorporation, the holders of a majority of the shares of the corporation issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall be necessary to and shall constitute a quorum for the transaction of business at all meetings of the stockholders.

If, however, such quorum shall not be present or represented at any meeting of the stockholders, the stockholders entitled to vote thereat present in person or represented by proxy shall have power to adjourn the meeting from time to time, but not for more than thirty (30) days,

-1-

until a quorum shall be present or represented. At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally noticed.

Section 6.Voting.  At any meeting of the stockholders every stockholder having the right to vote shall be entitled to vote in person, or by proxy. Except as otherwise provided by law or the Articles of Incorporation, each stockholder of record shall be entitled, as to each proposal, to one vote for each share of stock standing in his name on the books of the corporation on the date fixed as the record date for the determination of its stockholders entitled to vote. Unless otherwise provided by the Articles of Incorporation, all elections of directors shall be by written ballot and shall be determined by a plurality vote, and, except as otherwise provided by law or the Articles of Incorporation, all other matters shall be determined by vote of a majority of the shares present or represented by proxy at such meeting and entitled to vote on such matters.

Section 7.Proxies.  Every proxy may be executed in writing by the stockholder or by his attorney-in-fact or the stockholder may authorize another person to act as proxy by transmitting, or authorizing the transmission of, a telegram, cablegram, or other means of electronic transmission, including telephonic transmission, to the person authorized to act as proxy or to a proxy solicitation firm, proxy support service organization, or other person authorized by the person who will act as proxy to receive the transmission, provided that any such electronic transmission must either contain or be accompanied by information from which it can be determined that the stockholder authorized the transmission. A copy or facsimile of any writing or electronic transmission authorizing another person to act as proxy may be substituted for the original writing or transmission for any purpose for which the original writing or transmission could be used. No proxy shall be valid after the expiration of eleven (11) months from the date thereof, unless otherwise provided in the proxy. Every proxy shall be revocable at the pleasure of the stockholder executing it, except in those cases where an irrevocable proxy is permitted by law.

Section 8.Consents.  Whenever by any provision of law or of the Articles of Incorporation, the vote of stockholders at a meeting thereof is required or permitted to be taken in connection with any corporate action, the meeting and vote of stockholders may be dispensed with, if all the stockholders who would have been entitled to vote upon the action if such meeting were held shall consent in writing to such corporate action being taken.

Section 9.Presiding Officer.  Meetings of the stockholders shall be presided over by the Chairman of the Board, if any, or if he is not present, by the President, or, if he is not present, by a Vice President or, if neither the Chairman of the Board, the President nor a Vice President is present, by a chairman to be chosen at the meeting. The Secretary of the corporation or, if he is not present, an Assistant Secretary of the corporation or, if neither the Secretary nor an Assistant Secretary is present, a secretary to be chosen at the meeting, shall act as secretary of the meeting.

Section 10.Notice of Stockholder Business.  At an annual meeting of stockholders, only such business shall be conducted as shall have been properly brought before the meeting (a) by or at the direction of the Board of Directors or (b) by a stockholder who is a stockholder of record at the time of giving notice of such business, as required below, who shall be entitled to vote at such meeting and who complies with the notice procedures set forth in this Section. For

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business to be properly brought before an annual meeting by a stockholder, the stockholder must have given timely notice thereof in writing to the Secretary. To be timely, a stockholder's notice must be delivered to or mailed and received at the principal executive offices of the corporation, not less than 45 days before the month and day in the current year corresponding to the date on which the corporation first mailed its proxy materials for the prior year's annual meeting of stockholders. A stockholder's notice to the Secretary shall set forth as to each matter the stockholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the name and address, as they appear on the corporation's books, of the stockholder proposing such business, (c) the class and number of shares of the corporation which are beneficially owned by the stockholder, and (d) any material interest of the stockholder in such business. Nothwithstanding anything in these By-Laws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section. The Chairman of an annual meeting shall, if the facts warrant, determine and declare to the meeting that business was not properly brought before the meeting and in accordance with the provisions of this Section, and if he should so determine, he shall so declare to the meeting and any such business not properly brought before the meeting shall not be transacted. Notwithstanding the foregoing provisions of this Section, a stockholder shall also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended and the rules and regulations thereunder with respect to the matters set forth in this Section.

ARTICLE III

DIRECTORS

Section 1.Number and Tenure.  The whole Board of Directors of the corporation shall consist of ten members. The directors shall be classified with respect to the time for which they shall severally hold office by dividing them into three classes. Each director shall hold office until his successor is duly elected and qualified or until his resignation in writing has been filed with the corporation. At each annual election, the successors of the class of directors whose terms shall expire that year shall be elected to hold office for a term of three years, so that the term of office of one class of directors shall expire in each year, except where the Board of Directors determines that a newly elected director shall be elected by the stockholders to fill a vacancy of a directorship created subsequent to the previous annual meeting, such director shall be elected to hold office for the balance of the term of the class of directors of which he is to be a member, as determined by the Board of Directors, and until his successor is elected and qualified.

Section 2.Vacancies.  A vacancy on the Board of Directors or a newly created directorship may be filled by a majority of the remaining directors, though less than a quorum, or by the sole director, by election of a new director, who at the time of his election shall be designated as a member of one of the classes of directors and shall hold office until the next election of the class of which he has become a member, unless his term of office is terminated by death, resignation, or otherwise.

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Section 3.Resignation, Retirement; Removal.  Any director may resign at any time. The stockholders entitled to vote for the election of directors may remove a director, with cause as provided in the Articles of Incorporation.

Section 4.Advisory Directors and Directors Emeritus.  The Board of Directors by a vote of a majority of the directors present and entitled to vote, at any regular or special meeting at which a quorum is present, may designate such number of persons as it may from time to time determine, as an "Advisory Director" or may designate a former member of the Board as a "Director Emeritus," if such former member is willing to so serve. Each Advisory Director and each Director Emeritus shall serve, subject to the pleasure of the regular Board of Directors, until the next succeeding annual meeting of the regular Board of Directors, following the annual meeting of the stockholders, at which such regular directors are elected, unless he shall have resigned. Each Advisory Director and each Director Emeritus shall be notified of all regular or special meetings of the regular Board of Directors, shall be entitled to attend and participate therein, but shall not be entitled to vote. Each Advisory Director and each Director Emeritus shall be reimbursed for any necessary expenses of attending directors' meetings.

Section 5.Nomination of Director Candidates.

(a)Eligibility to Make Nominations.  Nominations of candidates for election as directors of the corporation at any meeting of stockholders called for election of directors, in whole or in part (an "Election Meeting"), may be made by the Board of Directors or by any stockholder who is a stockholder of record at the time of giving notice, who shall be entitled to vote at such Election Meeting and who complies with the notice procedures set forth in this Section.

(b)Procedure for Nominations by Stockholders.  Nominations, other than those made by the Board of Directors, shall be made pursuant to timely notice in writing to the Secretary. To be timely, stockholder's notice shall be delivered to or mailed and received at the principal executive offices of the corporation not less than 75 days prior to the date of the Election Meeting. Such stockholder's notice shall set forth (i) the name, age, business address and residence address of such stockholder and of each nominee proposed in such notice, (ii) the principal occupation or employment of each such nominee, (iii) the number of shares of capital stock of the corporation which are beneficially owned by each such nominee, (iv) a description of all arrangements or understandings between such stockholder and each nominee nominated by the stockholder and any other person or persons, identifying such person or persons, pursuant to which the nomination has been made by the stockholder and (v) such other information concerning each such nominee as would be required, under the rules of the Securities and Exchange Commission, in a proxy statement soliciting proxies for the election of such nominees. Such notice shall include a signed consent to serve as a director of the corporation, if elected, of each such nominee. Such notice shall also set forth as to the stockholder giving the notice (i) the name and address, as they appear on the corporation's books, of such stockholder and (ii) the class and number of shares of the corporation which are beneficially owned by such stockholder.

(c)Meeting Procedures.  No person shall be eligible for election as a director of the corporation unless nominated in accordance with the procedures set forth in this Section. The Chairman of the meeting shall, if the facts warrant, determine and declare to the meeting that a

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nomination was not made in accordance with the procedures prescribed by this Section 5, and if he should so determine, he shall so declare to the meeting and the defective nomination shall be disregarded.

(d)Substitution of Nominees.  In the event that a person is validly designated as a nominee to the Board and shall thereafter become unable or unwilling to stand for election to the Board of Directors, the Board of Directors or the stockholder who proposed such nominee, as the case may be, may designate a substitute nominee.

(e)Securities Exchange Act of 1934.  Notwithstanding the foregoing provisions of this Section, a stockholder shall also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended and the rules and regulations thereunder with respect to the matters set forth in this Section.

ARTICLE IV

MEETINGS OF THE BOARD OF DIRECTORS

Section 1.Place.  The Board of Directors of the corporation may hold meetings, both regular and special, either within or without the State of Kansas.

Section 2.Regular Meetings.  Regular meetings of the Board of Directors may be held without notice at such time and at such place as shall from time to time be determined by the Board.

Section 3.Special Meetings.  Special meetings of the Board of Directors may be called by the Chairman of the Board, if any, or by the President on two days' notice to each director, either personally, by mail, by facsimile or by telegram; special meetings shall be called by the Chairman, President or Secretary in like manner and on like notice on the written request of two directors.

Section 4.Quorum.  At all meetings of the Board of Directors a majority of the entire Board shall constitute a quorum for the transaction of business and the act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute or by the Articles of Incorporation. If a quorum shall not be present at any meeting of the Board of Directors the directors present thereat may adjourn the meeting from time to time until a quorum shall be present. Notice of such adjournment shall be given to any directors who were not present and, unless announced at the meeting, to the other directors.

Section 5.Consents.  Unless otherwise restricted by the Articles of Incorporation or these By-Laws, any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof may be taken without a meeting, if all members of the Board or of such committee as the case may be, consent thereto in writing and such written consent is filed with the minutes of the Board or committee. Such consents may be in counterpart so that each member will have signed a consent, but all members need not sign the same document.

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Section 6.Compensation.  Directors, as such, shall not receive any stated salary for their services, but, by resolution of the Board of Directors an annual fee, plus a fee and expenses for attendance at meetings may be allowed, provided that nothing herein contained shall be construed to preclude any director from serving the corporation in any other capacity and receiving compensation therefor.

Section 7.Presiding Officer.  Meetings of the Board of Directors shall be presided over by the Chairman of the Board, if any, or, if he is not present, by the President or, if he is not present, by a chairman to be chosen at the meeting. The Secretary of the corporation, or, if he is not present, an Assistant Secretary of the corporation, or, if neither the Secretary nor an Assistant Secretary is present, a secretary to be chosen at the meeting, shall act as secretary of the meeting.

ARTICLE V

COMMITTEES OF DIRECTORS

Section 1.Designation.  The Board of Directors, by resolution adopted by a majority of the whole Board, may designate from among its members one or more committees, each consisting of two or more directors, each of which, to the extent provided in such resolution, shall have and may exercise the powers of the Board of Directors in the business and affairs of the corporation, and may authorize the seal of the corporation to be affixed to all papers which may require it.

The Board may designate one or more directors as alternate members of any committee who may replace any absent or disqualified member at any meeting of the committee.

Section 2.Tenure; Reports.  Each such committee shall serve at the pleasure of the Board. It shall keep minutes of its meetings and report the same to the Board.

ARTICLE VI

NOTICES

Section 1.Form; Delivery.  Notices to directors and stockholders shall be in writing and delivered personally or mailed to the directors or stockholders at their addresses appearing on the books of the corporation. Notice by the corporation by mail shall be deemed to be given at the time when the same shall be mailed. Notice to directors may also be given by telegram or facsimile.

Section 2.Waiver.  Whenever any notice is required to be given under the provisions of the statutes or of the Articles of Incorporation or of these By-Laws, a waiver thereof in writing, signed by the person or persons entitled to said notice, whether before or after the time stated therein, shall be deemed equivalent thereto. In addition, any stockholder attending a meeting of stockholders in person or by proxy without protesting at the beginning of the meeting the lack of notice thereof to him, and any director attending a meeting of the Board of Directors without protesting prior to the meeting or at its commencement such lack of notice, shall be conclusively deemed to have waived notice of such meeting.

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ARTICLE VII

OFFICERS

Section 1.Executive Officers.  The officers of the corporation shall be a President and one or more Vice Presidents, a Secretary, a Treasurer and may include a Chairman of the Board and such other officers as the Board of Directors may from time to time elect.

Section 2.Designation; Term of Office; Removal.  All officers shall be elected by the Board of Directors and shall hold office for such term as may be prescribed by the Board or until their successors are chosen and qualified or until their resignation is filed in the office of the Secretary, whichever first occurs. Any officer elected by the Board may be removed with or without cause at any time by the Board.

Section 3.Authority and Duties.  All officers, as between themselves and the corporation, shall have such authority and perform such duties in the management of the corporation as may be provided in these By-Laws, or, to the extent not so provided, by the Board of Directors.

Section 4.Compensation.  The compensation of all officers of the corporation shall be fixed by the Board of Directors, or any duly authorized committee thereof, and the compensation of agents shall either be so fixed or shall be fixed by officers thereunto duly authorized.

Section 5.Vacancies.  If an office becomes vacant for any reason, the Board of Directors shall fill such vacancy. Any officer so elected by the Board shall serve only until such time as the unexpired term of his predecessor shall have expired unless re-elected or reappointed by the Board.

Section 6.The Chairman of the Board.  The Chairman of the Board of Directors, if there be a Chairman, shall preside at all meetings of the stockholders and of the Board of Directors and shall have such other powers and duties as may from time to time be assigned by the Board including designation as Chief Executive Officer if the President is not so designated.

Section 7.The President.  The President shall be the Chief Executive Officer of the corporation unless the Chairman of the Board is so designated, in which event the President shall be Chief Operating Officer of the corporation. In the absence of the Chairman of the Board, or if there be no Chairman, he shall preside at all meetings of the stockholders and of the Board of Directors. The Chief Executive Officer, whether the Chairman of the Board or the President, shall have general and active management and control of the business and affairs of the corporation subject to the control of the Board of Directors, and shall see that all orders and resolutions of the Board are carried into effect.

Section 8.Vice Presidents.  The Vice Presidents in the order of their seniority or in any other order determined by the Board shall in the absence or disability of the President, perform the duties and exercise the powers of the President, and shall generally assist the President and perform such other duties as the Board of Directors or the President shall prescribe.

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Section 9.The Secretary.  The Secretary shall attend all meetings of the Board and all meetings of the stockholders and record all votes and the minutes of all proceedings in a book to be kept for that purpose and shall perform like duties for the standing committees when required. He shall give, or cause to be given, notice of all meetings of the stockholders and special meetings of the Board of Directors, and shall perform such other duties as may be prescribed by the Board of Directors or President, under whose supervision he shall act. He shall keep in safe custody the seal of the corporation and, when authorized by the Board, affix the same to any instrument requiring it and, when so affixed, it shall be attested by his signature or by the signature of the Treasurer or an Assistant Secretary or Assistant Treasurer. He shall keep in safe custody the certificate books and stockholder records and such other books and records as the Board may direct and shall perform all other duties incident to the office of the Secretary.

Section 10.Assistant Secretaries.  The Assistant Secretaries, if any, in order of their seniority or in any other order determined by the Board shall, in the absence or disability of the Secretary, perform the duties and exercise the powers of the Secretary and shall perform such other duties as the Board of Directors or the Secretary shall prescribe.

Section 11.The Treasurer.  The Treasurer shall have the custody of the corporate funds and securities and shall keep full and accurate accounts of receipts and disbursements in books belonging to the corporation and shall deposit all moneys and other valuable effects in the name and to the credit of the corporation in such depositories as may be designated by the Board of Directors. He shall disburse the funds of the corporation as may be ordered by the Board of Directors, taking proper vouchers for such disbursements, and shall render to the President and the Board of Directors at its regular meetings, or when the Board of Directors so requires, an account of all his transactions as Treasurer and of the financial condition of the corporation. He shall establish and execute programs for the provision of the capital required by the corporation, including negotiating the procurement of capital and maintaining the required financial arrangements. He shall maintain banking arrangements to receive, have custody of and disburse the corporation's moneys and securities.

Section 12.Assistant Treasurers.  The Assistant Treasurers, if any, in the order of their seniority or in any other order determined by the Board, shall in the absence or disability of the Treasurer, perform the duties and exercise the power of the Treasurer and shall perform such other duties as the Board of Directors or the Treasurer shall prescribe.

ARTICLE VIII

CERTIFICATE OF SHARES

Section 1.Form; Signature.  The certificates for shares of the corporation shall be in such form as shall be determined by the Board of Directors and shall be numbered consecutively and entered in the books of the corporation as they are issued. Each certificate shall exhibit the registered holder's name and the number and class of shares, and shall be signed by the President or a Vice President and the Treasurer or an Assistant Treasurer or the Secretary or an Assistant Secretary, and shall bear the seal of the corporation or a facsimile thereof. Where any such certificate is countersigned by a transfer agent or by a registrar other than the corporation, the signature of any such officer may be a facsimile signature. In case any officer who signed, or

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whose facsimile signature or signatures were placed on any such certificate shall have ceased to be such officer before such certificate is issued, it may nevertheless be issued by the corporation with the same effect as if he were such officer at the date of issue.

Section 2.Lost Certificates.  The Board of Directors may direct a new share certificate or certificates to be issued in place of any certificate or certificates theretofore issued by the corporation alleged to have been lost or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate to be lost or destroyed. When authorizing such issue of a new certificate or certificates, the Board of Directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost or destroyed certificate or certificates, or his legal representative, to give the corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the corporation with respect to the certificate alleged to have been lost or destroyed.

Section 3.Registration of Transfer.  Upon surrender to the corporation or any transfer agent of the corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment or authority to transfer, it shall be the duty of the corporation, or such transfer agent to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books.

Section 4.Registered Stockholders.  Except as otherwise provided by law, the corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends or other distributions, and to vote as such owner, and shall not be bound to recognize any equitable or legal claim to or interest in such share or shares on the part of any other person.

Section 5.Record Date.  For the purpose of determining the stockholders entitled to notice of or to vote at any meeting of stockholders or any adjournment thereof, or to express consent to or dissent from any proposal without a meeting, or for the purpose of determining stockholders entitled to receive payment of any dividend or the allotment of any rights, or for the purpose of any other action affecting the interests of stockholders, the Board of Directors may fix, in advance, a record date. Such date shall not be more than sixty (60) nor less than ten (10) days before the date of any such meeting, nor more than sixty (60) days prior to any other action.

In each such case, except as otherwise provided by law, only such persons as shall be stockholders of record on the date so fixed shall be entitled to notice of, and to vote at, such meeting and any adjournment thereof, or to express such consent or dissent, or to receive payment of such dividend, or such allotment of rights, or otherwise to be recognized as stockholders for the related purpose, notwithstanding any registration of transfer of shares on the books of the corporation after any such record date so fixed.

ARTICLE IX

GENERAL PROVISIONS

Section 1.Dividends.  Subject to the provisions of the Articles of Incorporation, if any, dividends upon the outstanding shares of the corporation may be declared by the Board of

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Directors at any regular or special meeting, pursuant to law and may be paid in cash, in property, or in shares of the corporation.

Section 2.Reserves.  Before payment of any dividends, there may be set aside out of any funds of the corporation available for dividends such sum or sums as the directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the corporation, or for such other purpose as the directors shall think conducive to the interest of the corporation, and the directors may modify or abolish any such reserve in the manner in which it was created.

Section 3.Instruments Under Seal.  All deeds, bonds, mortgages, contracts, and other instruments requiring a seal may be signed in the name of the corporation by the President or by any other officer authorized to sign such instrument by the President or the Board of Directors.

Section 4.Checks.  All checks or demands for money and notes or other instrument evidencing indebtedness or obligation of the corporation shall be signed by such officer or officers or such other person or persons as the Board of Directors may from time to time designate.

Section 5.Fiscal Year.  The fiscal year of the corporation shall begin on the first day of January of each year and shall end on the thirty-first day of December following.

Section 6.Seal.  The corporate seal shall have inscribed thereon the name of the corporation and the words "Corporate Seal, Kansas 1927." The seal may be used by causing it or a facsimile thereof to be impressed or affixed or reproduced or otherwise.

Section 7.Amendments.  These By-Laws may be altered or repealed at any regular meeting of the Board of Directors, or at any special meeting of the Board of Directors if notice of such alteration or repeal be contained in the notice of such special meeting.

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EX-4.5

Exhibit 4.5

EXECUTION COPY

$445,000,000

AMENDED AND RESTATED 364-DAY CREDIT AGREEMENT


dated as of

October 14, 2003

among

KINDER MORGAN, INC.


The Lenders Party Hereto



CITIBANK, N.A.,
as Administrative Agent

WACHOVIA BANK, NATIONAL ASSOCIATION and JPMORGAN CHASE BANK,
as Co-Syndication Agents

and

THE BANK OF NOVA SCOTIA,
as Documentation Agent

_________________________

WACHOVIA CAPITAL MARKETS, LLC and CITIGROUP GLOBAL MARKETS 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 11

SECTION 2.01	Commitments	11
SECTION 2.02	Loans and Borrowings	12
SECTION 2.03	Requests for Revolving Borrowings	12
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	17
SECTION 2.15	Increased Costs	18
SECTION 2.16	Break Funding Payments	18
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	21
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	24
SECTION 3.03	Governmental Approvals; No Conflicts	24
SECTION 3.04	Financial Condition; No Material Adverse Change	24
SECTION 3.05	Properties	25
SECTION 3.06	Litigation and Environmental Matters	25
SECTION 3.07	Compliance with Laws and Agreements	25
SECTION 3.08	Investment and Holding Company Status	25
SECTION 3.09	Taxes	25
SECTION 3.10	ERISA	26

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SECTION 3.11 Disclosure 26

ARTICLE IV Conditions 26

SECTION 4.01	Effective Date	26
SECTION 4.02	Each Credit Event	27
SECTION 4.03	Conditions Precedent to Conversions	27

ARTICLE V Affirmative Covenants 27

SECTION 5.01	Financial Statements; Ratings Change and Other Information	27
SECTION 5.02	Notices of Material Events	29
SECTION 5.03	Existence; Conduct of Business	30
SECTION 5.04	Payment of Obligations	30
SECTION 5.05	Maintenance of Properties; Insurance	30
SECTION 5.06	Books and Records; Inspection Rights	30
SECTION 5.07	Compliance with Laws	30
SECTION 5.08	Use of Proceeds	30

ARTICLE VI Negative Covenants 31

SECTION 6.01	Financial Covenants	31
SECTION 6.02	Liens	31
SECTION 6.03	Fundamental Changes	32
SECTION 6.04	Transactions with Affiliates	32
SECTION 6.05	Capital Lease Obligations	32

ARTICLE VII Events of Default	33
ARTICLE VIII The Administrative Agent	35
ARTICLE IX Miscellaneous	36

SECTION 9.01	Notices	36
SECTION 9.02	Waivers; Amendments	37
SECTION 9.03	Expenses; Indemnity; Damage Waiver	37
SECTION 9.04	Successors and Assigns	38
SECTION 9.05	Survival	41
SECTION 9.06	Counterparts; Integration; Effectiveness	41
SECTION 9.07	Severability	41
SECTION 9.08	Right of Setoff	41
SECTION 9.09	Governing Law; Jurisdiction; Consent to Service of Process	42
SECTION 9.10	WAIVER OF JURY TRIAL	42
SECTION 9.11	Headings	42
SECTION 9.12	Confidentiality	42
SECTION 9.13	Interest Rate Limitation	43

SCHEDULES:

Schedule 1.01 -- Pricing Schedule
Schedule 2.01 -- Commitments

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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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AMENDED AND RESTATED CREDIT AGREEMENT dated as of October 14, 2003, among KINDER MORGAN, INC., a Kansas corporation, the LENDERS party hereto, CITIBANK, N.A., as Administrative Agent, WACHOVIA BANK, NATIONAL ASSOCIATION and JPMORGAN CHASE BANK, as Co-Syndication Agents, and THE BANK OF NOVA SCOTIA, as Documentation Agent.

INTRODUCTORY STATEMENT

The Borrower entered into that certain 364-Day Credit Agreement, dated October 15, 2002, by and among the Borrower, the lenders party thereto, 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 "Existing 364-Day Credit Agreement").

The Borrower has requested, and the lenders and the administrative agent under the Existing 364-Day Credit Agreement have agreed, that the Existing 364-Day Credit Agreement be amended and restated in its entirety.

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 Citibank, N.A., 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 plus 1/2 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.

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"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.

"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 Revolving Credit Termination Date.

"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

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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.

"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 $445,000,000.

"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.

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"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.

"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.

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"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 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 364-Day Credit Agreement" has the meaning set forth in the Introductory Statement.

"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.

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"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 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.

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

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"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.

"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.

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"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;

(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;

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(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 Citibank, N.A. 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.

"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.

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"Revolving Credit Termination Date" means the earlier of (x) the later of (i) October 12, 2004 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.

"Three-Year Facility" means the credit facility governed by that certain Three-Year Credit Agreement, dated as of October 15, 2002, 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

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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.

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

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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.

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:

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(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, 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.

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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.

 (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.

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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.

 (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).

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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, 2003 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 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, 2003 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).

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 (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 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

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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.

 (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

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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.

 (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

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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 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

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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.

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

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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).

(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,

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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 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.

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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 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, 2002, reported on by Pricewaterhouse Coopers LLP, independent public accountants and set forth in the Borrower's 2002 Form 10-K, and (ii) as of and for the fiscal quarter and the portion of the fiscal year

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ended June 30, 2003, 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, 2002, 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 prior to the date hereof, 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 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

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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 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.

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 (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.

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 14, 2003.

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

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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 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 364-Day Credit Agreement, (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 $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;

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 (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 agree-ment 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 Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers

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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 it at 2 Penns Way, Suite 200, New Castle, Delaware 19720, Attention of Janet Wallace (Telecopy No. (212) 994-0961), with a copy to 1200 Smith Street, Suite 2000, Houston, Texas 77002, Attention of Joronne Jeter (Telecopy No. (713) 654-2849);

(iii)if to any other Lender, to it at its address (or telecopy number) set forth in its Administrative Questionnaire.

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 (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 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

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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 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

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(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.

(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

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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 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, and be indemnified under Section 9.03 as if it were a Lender. 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.

(ii)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

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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 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

-41-

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 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

-42-

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. Notwithstanding anything in this Agreement to the contrary, "Information" shall not include, and the Borrower, the Administrative Agent, each Lender and the respective Affiliates of each of the foregoing (and the respective partners, directors, officers, employees, agents, advisors and other representatives of the such Persons), and any other party, may disclose to any and all persons, without limitation of any kind (x) any information with respect to the U.S. federal and state income tax treatment of the transactions contemplated hereby and any facts that may be relevant to understanding the U.S. federal or state income tax treatment of such transactions ("tax structure"), which facts shall not include for this purpose the names of the parties or any other person named herein, or information that would permit identification of the parties or such other persons, or any pricing terms or other nonpublic business or financial information that is unrelated to such tax treatment or tax structure, and (y) all materials of any kind (including opinions or other tax analyses) that are provided to the Borrower, the Administrative Agent, or such Lender relating to such tax treatment or tax structure.

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.

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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/ JOSEPH LISTENGART
Name:	Joseph Listengart
Title:	Vice President

[KMI 364-DAY CREDIT AGREEMENT - 1]

CITIBANK, N.A., individually and as Administrative Agent,
By:	/s/ JORONNE JETER
Name:	Joronne Jeter
Title:	Attorney-in-Fact

[KMI 364-DAY CREDIT AGREEMENT - 2]

WACHOVIA BANK, NATIONAL ASSOCIATION, individually and as Co-Syndication Agent,
By:	/s/ RUSSELL CLINGMAN
Name:	RUSSELL CLINGMAN
Title:	DIRECTOR

[KMI 364-DAY CREDIT AGREEMENT - 3]

JPMORGAN CHASE BANK, individually and as Co-Syndication Agent,
By:	/s/ MICHAEL J. DEFORGE
	Michael J. DeForge
	Vice President

[KMI 364-DAY CREDIT AGREEMENT - 4]

THE BANK OF NOVA SCOTIA, individually and as Documentation Agent,
By:	/s/ A. S. NORSWORTHY
Name:	A. S. NORSWORTHY
Title:	SENIOR MANAGER

[KMI 364-DAY CREDIT AGREEMENT - 5]

BANK OF TOKYO-MITSUBISHI, LTD., HOUSTON AGENCY
By:	/s/ DONALD W. HERRICK, JR.
Name:	Donald W. Herrick, Jr.
Title:	Vice President

[KMI 364-DAY CREDIT AGREEMENT -  ]

CREDIT LYONNAIS NEW YORK BRANCH
By:	/s/ OLIVIER AUDEMARD
Name:	Olivier Audemard
Title:	Senior Vice President

[KMI 364-DAY CREDIT AGREEMENT - 7]

SUNTRUST BANK
By:	/s/ JOSEPH M. MCCREERY
Name:	Joseph M. McCreery
Title:	Vice President

[KMI 364-DAY CREDIT AGREEMENT - 8]

LEHMAN BROTHERS BANK, FSB
By:	/s/ GARY T. TAYLOR
Name:	Gary T. Taylor
Title:	Vice President

[KMI 364-DAY CREDIT AGREEMENT - 9]

BMO NESBITT BURNS FINANCING, INC.
By:	/s/ CAHAL B. CARMODY
Name:	Cahal B. Carmody
Title:	Vice President

[KMI 364-DAY CREDIT AGREEMENT - 10]

BANK ONE, N.A.
By:	/s/ SHARON K. WEBB
Name:	SHARON K. WEBB
Title:	ASSOCIATE DIRECTOR

[KMI 364-DAY CREDIT AGREEMENT - 11]

BARCLAYS BANK PLC
By:	/s/ NICHOLAS A. BELL
Name:	NICHOLAS A. BELL
Title:	DIRECTOR
	LOAN TRANSACTION MANAGEMENT

[KMI 364-DAY CREDIT AGREEMENT - 12]

COMMERZBANK AG, NEW YORK AND GRAND CAYMAN BRANCHES
By:	/s/ SUBASH R. VISWANATHAN
Name:	Subash R. Viswanathan
Title:	Senior Vice President
By:	/s/ DAVID A. BENNETT
Name:	DAVID A. BENNETT
Title:	ASSISTANT VICE PRESIDENT

[KMI 364-DAY CREDIT AGREEMENT - 13]

DEUTSCHE BANK AG NEW YORK BRANCH
By:	/s/ RICHARD HENSHELL
Name:	Richard Henshell
Title:	Director
By:	/s/ JOEL MAKOWSKY
Name:	Joel Makowsky
Title:	Director

[KMI 364-DAY CREDIT AGREEMENT - 14]

ROYAL BANK OF CANADA
By:	/s/ LORNE GARTNER
Name:	Lorne Gartner
Title:	Attorney-in-Fact

[KMI 364-DAY CREDIT AGREEMENT - 15]

THE ROYAL BANK OF SCOTLAND plc
By:	/s/ PATRICIA J. DUNDEE
Name:	PATRICIA J. DUNDEE
Title:	SENIOR VICE PRESIDENT

[KMI 364-DAY CREDIT AGREEMENT - 16]

UBS LOAN FINANCE LLC
By:	/s/ WILFRED V. SAINT
Name:	Wilfred V. Saint
Title:	Banking Products
	Services, US
By:	/s/ JUAN ZUNIGA
Name:	Juan Zuniga
Title:	Associate Director
	Banking Products Services, US

[KMI 364-DAY CREDIT AGREEMENT - 17]

WILLIAM STREET COMMITMENT CORPORATION (Recourse only to assets of William Street Commitment Corporation)
By:	/s/ JENNIFER M. HILL
Name:	Jennifer M. Hill
Title:	Vice President and CFO

[KMI 364-DAY CREDIT AGREEMENT - 18]

WELLS FARGO BANK TEXAS, N.A.
By:	/s/ RICHARD A. GOULD
Name:	Richard A. Gould
Title:	Vice President

[KMI 364-DAY CREDIT AGREEMENT - 19]

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
Citibank, N.A.	$35,500,000
Wachovia Bank, National Association	$35,500,000
JPMorgan Chase Bank	$35,500,000
The Bank of Nova Scotia	$28,000,000
Credit Lyonnais New York Branch	$26,000,000
SunTrust Bank	$26,000,000
The Bank of Tokyo-Mitsubishi, Ltd.	$25,000,000
Lehman Brothers Bank, FSB	$25,000,000
BMO Nesbitt Burns Financing, Inc.	$23,000,000
Deutsche Bank AG New York Branch	$23,000,000
Royal Bank of Canada	$23,000,000
The Royal Bank of Scotland plc	$23,000,000
UBS Loan Finance LLC	$23,000,000
Bank One, N.A.	$22,000,000
Barclays Bank PLC	$22,000,000
Commerzbank AG, New York and Grand  Cayman Branches	$22,000,000
William Street Commitment Corporation	$15,000,000
Wells Fargo Bank Texas, N.A.	$12,500,000

Schedule 2.01-1

EXHIBIT A

ASSIGNMENT AND ASSUMPTION

Reference is made to the Amended and Restated 364-Day Credit Agreement dated as of October 14, 2003 (as amended and in effect on the date hereof, the "Credit Agreement"), among Kinder Morgan, Inc., the Lenders named therein and Citibank, N.A., as Administrative Agent for the Lenders. Terms defined in the Credit Agreement are used herein with the same meanings.

The Assignor named on the reverse hereof hereby sells and assigns, without recourse, to the Assignee named on the reverse hereof, and the Assignee hereby purchases and assumes, without recourse, from the Assignor, effective as of the Assignment Date set forth on the reverse hereof, the interests set forth on the reverse hereof (the "Assigned Interest") in the Assignor's rights and obligations under the Credit Agreement, including, without limitation, the interests set forth on the reverse hereof in the Commitment of the Assignor on the Assignment Date and Loans owing to the Assignor which are outstanding on the Assignment Date, but excluding accrued interest and fees to and excluding the Assignment Date. The Assignee hereby acknowledges receipt of a copy of the Credit Agreement. From and after the Assignment Date (i) the Assignee shall be a party to and be bound by the provisions of the Credit Agreement and, to the extent of the Assigned Interest, have the rights and obligations of a Lender thereunder and (ii) the Assignor shall, to the extent of the Assigned Interest, relinquish its rights and be released from its obligations under the Credit Agreement.

This Assignment and Assumption is being delivered to the Administrative Agent together with (i) if the Assignee is a Foreign Lender, any documentation required to be delivered by the Assignee pursuant to Section 2.17(e) of the Credit Agreement, duly completed and executed by the Assignee, and (ii) if the Assignee is not already a Lender under the Credit Agreement, an Administrative Questionnaire in the form supplied by the Administrative Agent, duly completed by the Assignee. The Assignee shall pay the fee payable to the Administrative Agent pursuant to Section 9.04(b) of the Credit Agreement.

This Assignment and Assumption shall be governed by and construed in accordance with the laws of the State of New York.

Date of Assignment:

Legal Name of Assignor:

Legal Name of Assignee:

Assignee's Address for Notices:

Effective Date of Assignment
("Assignment Date"):

A-1

Facility	Principal Amount   Assigned	Percentage Assigned of   Facility/Commitment (set   forth, to at least 8 decimals, as   a percentage of the Facility   and the aggregate   Commitments of all Lenders   thereunder)
Commitment Assigned:	$	%
Loans:

The terms set forth above and on the reverse side hereof are hereby agreed to:

[Name of Assignor] , as Assignor
  
  

By:______________________________
      Name:
      Title:
  
  
[Name of Assignee] , as Assignee
  
  
By:______________________________
      Name:
      Title:

The undersigned hereby consent to the within assignment:

Kinder Morgan, Inc.,
  
  
  
By: ______________________
       Name:
       Title: Citibank, N.A.,
as Administrative Agent,
  
  
By: __________________________
       Name:
       Title:

A-2

EXHIBIT B-1

FORM OF OPINION OF BORROWER'S KANSAS COUNSEL

October 14, 2003

To the Lenders and Administrative Agent
c/o Citibank, N.A.
    as Administrative Agent
2 Penns Way, Suite 200
New Castle, DE 19720

Re:The "Credit Agreement" as hereinafter defined

Ladies and Gentlemen:

We refer to the $445,000,000 Amended and Restated 364-Day Credit Agreement, dated as of October 14, 2003 (the "Credit Agreement") between Kinder Morgan, Inc. ("Borrower"), Citibank, N.A., as Administrative Agent ("Administrative Agent"), the Lenders listed in the Credit Agreement, Wachovia Bank, National Association and JPMorgan Chase Bank, as Co-Syndication Agents, The Bank of Nova Scotia, as Documentation Agent, and Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as Joint Bookrunners and Joint Lead Arrangers. We are special Kansas counsel to Borrower. Capitalized terms not defined herein have the meanings specified in the Credit Agreement. This opinion is being rendered to you at the request of Borrower pursuant to Section 4.01(b) of the Credit Agreement.

As special Kansas counsel to Borrower and in such capacity we have only reviewed: (i) certified copies of the Articles of Incorporation of Borrower and amendments thereto dated October 9, 2003, and a Certificate of Good Standing dated October 7, 2003, both of which have been provided to us by the Secretary of State of Kansas, and the Officer’s Certificate (including the exhibits thereto) of the Secretary of Borrower dated October 14, 2003, (the "Corporate Records"); (ii) a copy of the Credit Agreement dated as of October 14, 2003; and (iii) have conducted such investigation of fact and law as we have deemed necessary or advisable for the purpose of this opinion. In reviewing such documents, Corporate Records, instruments and certificates, we have assumed the genuineness of all signatures and initials thereon, the genuineness of all notaries contained thereon, conformance of all copies with the original thereof and originals to all copies thereof, and the accuracy of all statements, representations and warranties contained therein. We have further assumed (i) that all Corporate Records, documents, instruments, and certificates dated prior to the date hereof remain accurate and correct on the date hereof; (ii) that the Credit Agreement we have reviewed has been executed and delivered by all parties thereto; and (iii) that the parties hereto, other than Borrower, are duly authorized to execute and deliver the Credit Agreement, have due corporate and other existence to do so, and the full power and legal right under all applicable laws and regulations to execute, deliver and perform all of such parties’ obligations under such documents. In addition, we do not express an opinion with respect to any federal or state securities laws, or any statutes, administrative decisions, and rules and regulations of any county, municipal or special political subdivisions. As to questions of fact material to this opinion letter, we have, without independent investigation and with your permission, relied upon and assumed to be true (a) certificates, statements and representations made to us by officers and other representatives of Borrower, (b) the

B-1-1

representations contained in or incorporated into the Credit Agreement, and (c) certain representations of public officials.

Upon the basis of the foregoing, and limited and qualified as set forth herein, we are of the opinion that:

1.Borrower is a corporation duly incorporated, validly existing and in good standing under the laws of the State of Kansas, and has all corporate powers to engage in any lawful act or activity for which corporations may be organized under the Kansas General Corporation Code.

2.The execution, delivery and performance of the Credit Agreement is within the corporate power and authority of Borrower, have been duly authorized by proper corporate proceedings on behalf of Borrower, do not require any approval or consent or other action by and no notice to or filing with any Kansas governmental authority, and do not and will not contravene, or constitute a default under, any provision of applicable law or regulation of the State of Kansas.

Our opinions and statements expressed herein are restricted to the matters governed by the laws of the State of Kansas. To the extent that the laws of any other jurisdiction apply, we express no opinion and we assume that the Credit Agreement is valid, legally binding, and enforceable under the laws of such other jurisdiction.

This opinion is being delivered solely for the benefit of the persons to whom it is addressed; accordingly, copies may not be furnished to any other person without our prior written consent except that you may furnish copies thereof: (a) to your independent auditors and attorneys; (b) to any state or federal authority having regulatory jurisdiction over you; (c) pursuant to order or legal process of any court or governmental agency; (d) in connection with any legal action to which you are a party arising out of the above transactions; (e) to any proposed participant or assignee in any Bank’s interest in any obligations under the Credit Agreement; (f) to any successor to Administrative Agent; and (g) to Bracewell & Patterson, L.L.P. We acknowledge that Bracewell & Patterson, L.L.P. is relying on the opinions herein expressed in rendering certain opinions to Administrative Agent and the Banks. This opinion may not be relied upon by you or any assignee or participant for any other purpose or relied upon by any other person without our prior written consent. The information set forth herein is as of the date of this letter, and we undertake no obligation or responsibility to update or supplement this opinion in response to or to make you aware of subsequent changes in the status of Borrower, the law, or future events, facts, or information affecting the transactions contemplated by the Credit Agreement occurring after the date of this letter.  

Very truly yours,



Polsinelli Shalton & Welte,
A Professional Corporation

B-1-2

EXHIBIT B-2

FORM OF OPINION OF BORROWER'S NEW YORK COUNSEL

October 14, 2003

To the Lenders and the Administrative Agent
c/o Citibank, N.A., as Administrative Agent
Two Penns Way, Suite 200
New Castle, Delaware 19720

Dear Sirs:

We are counsel to Kinder Morgan, Inc., a Kansas corporation (the "Borrower"), and have represented the Borrower in connection with the Amended and Restated 364-Day Credit Agreement (the "Credit Agreement") dated as of October 14, 2003 among the Borrower, the Lenders listed on the signature pages thereof, Citibank, N.A., as the Administrative Agent, Wachovia Bank, National Association and JPMorgan Chase Bank, as the Co-Syndication Agents, The Bank of Nova Scotia, as Documentation Agent, and Wachovia Capital Markets, LLC. and Citigroup Global Markets Inc., as Joint Bookrunners and Joint Lead Arrangers. This opinion is being rendered to you at the request of our client pursuant to Section 4.01(b) of the Credit Agreement. Unless otherwise defined herein, capitalized terms herein have the meanings assigned to such terms in the Credit Agreement.

In connection with this opinion, we have examined the Credit Agreement.

We have also examined originals or copies, certified or otherwise identified to our satisfaction, of such documents, corporate records, certificates of public officials, certificates or comparable documents of officers of the Borrower and other instruments and have conducted such other investigations of fact and law as we have deemed necessary or advisable for purposes of this opinion. We have assumed (a) the genuineness of all signatures (other than those of the Borrower), (b) the authenticity of all documents and records submitted to us as originals, (c) the conformity to original documents and records of all documents and records submitted to us as copies (including conformed copies), and (d) the truthfulness of all statements of fact contained therein.

Upon the basis of the foregoing, and having due regard for such legal considerations as we deem relevant, we are of the opinion that:

1. The execution, delivery and performance by the Borrower of the Credit Agreement require no action by or in respect of, or filing with, any governmental body, agency or official (other than filings of the Credit Agreement with the Securities and Exchange Commission pursuant to the reporting requirements of the Securities Exchange Act of 1934) and do not contravene, or constitute a default under, any provision of applicable law or regulation or of the articles of incorporation or by-laws of the Borrower or of any material agreement, judgment, injunction, order, decree or other instrument, known to us after due inquiry, binding upon the Borrower or any of its Subsidiaries or result in the creation or imposition of any Lien on any asset of the Borrower or any of its Subsidiaries.

2. The Credit Agreement constitutes a valid and binding agreement of the Borrower

B-2-1

enforceable against the Borrower in accordance with its terms, except as the same may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally and by general principles of equity.

3. To our knowledge after due inquiry, there is no action, suit or proceeding pending
against, or threatened against or affecting, the Borrower or any of its Subsidiaries before any court or arbitrator or any governmental body, agency or official, in which there is a reasonable possibility of an adverse decision which could materially adversely affect the business, consolidated financial position or consolidated results of operations of the Borrower and its Consolidated Subsidiaries, considered as a whole, or which in any manner draws into question the validity of the Credit Agreement.

4. The choice of New York law (other than conflict of laws rules) to govern the construction and interpretation of of the Credit Agreement should, if the issue is properly presented to a court of competent jurisdiction sitting in the State of Texas, be found by such court to be a valid choice of law under the laws of the State of Texas.

Our opinion is subject to the following:

(a)We are members of the Bar of the State of Texas and the Bar of the State of New York and the foregoing opinion is limited to the laws of the State of Texas, the laws of the State of New York and the federal laws of the United States of America. In rendering the opinion in paragraph 3 above, insofar as such opinion involves matters governed by the laws of the State of Kansas, we have relied, without independent investigation, upon the opinion of Polsinelli Shalton & Welte, P.C., delivered to you pursuant to Section 4.01(b) of each of the Credit Agreements.

(b)Our opinion in paragraph 3 above is subject to the effect of applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance, preference, liquidation, conservatorship or other similar laws affecting creditor’s rights generally.

(c)The enforceability of the Credit Agreement is subject to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law), and we express no opinion as to the availability of specific performance or any other equitable remedy.

(d)We express no opinion as to the legality, validity, binding effect or enforceability of any provision in the Credit Agreement (i) purporting to restrict access to courts or to legal or equitable remedies; (ii) purporting to establish evidentiary standards; (iii) purporting to grant a right of set-off or similar rights against moneys, securities and other properties of Persons other than the Person granting such right or purporting to permit any Person purchasing a participation to exercise a right of set-off or similar rights with respect to such participation; (iv) releasing, exculpating or exempting any Person from, or requiring indemnification of contribution of a Person for, liability for its own negligence or to the extent that the same are inconsistent with the public policy underlying any law, rule or regulation; (v) purporting to affect any right to trial by jury, venue or jurisdiction; or (vi) pertaining to subrogation rights, delay or omission of enforcement of rights or remedies, severability or marshaling of assets.

(e)We express no opinion as to the legality, validity, binding effect or enforceability of any waiver under the Credit Agreement, or any consent thereunder, relating to the rights of, or duties owing to, any Person which exist as a matter of law except to the extent such Person may legally so waive or consent and has so waived and consented.

(f)We have assumed, as to each Person (other than the Borrower) shown as being a party to the Credit Agreement, (i) that such Person is duly organized, validly existing and in good standing under

B-2-2

the laws of the jurisdiction in which it is organized; (ii) that the Credit Agreement has been duly authorized, executed and delivered by such Person; (iii) that such Person has the requisite power and authority to perform its obligations under the Credit Agreement and will perform such obligations in compliance with all laws and regulations applicable to it; (iv) that there are neither suits, actions or proceedings pending against such Person nor judicial or administrative orders, judgments or decrees binding on such Person that affect the legality, validity, binding effect or enforceability of the Credit Agreement; (v) that no consent, license, approval or authorization of, or filing or registration with, any governmental authority is required for the valid execution, delivery and performance of the Credit Agreement, and (vi) that the execution, delivery and performance of the Credit Agreement by such Person do not violate (1) any provision of any law or regulation, (2) any order, judgment, writ, injunction, award or decree of any court, arbitrator, or governmental authority, (3) the charter or bylaws of such Person, or (4) any indenture, lease or other agreement to which such Person is a party or by which such Person or any of its assets is bound; and (vii) that the Credit Agreement constitutes the legal, valid and binding obligation of such Person enforceable against such Person in accordance with its terms, subject to the type of qualifications regarding enforceability as are set forth in this opinion. We have also assumed that each Lender will make each Loan under the Credit Agreement for its own account in the ordinary course of its commercial lending business.

(g)We have assumed that the Administrative Agent and the Lenders will comply with each usury savings clause in the Credit Agreement and that none of the Administrative Agent or the Lenders has taken, reserved, charged or received interest or will take, reserve, charge or receive interest, except as provided in the Credit Agreement. We express no opinion as to the effect of the law of any jurisdiction other than the State of Texas wherein any Lender may be located or wherein enforcement of the Credit Agreement may be sought which limits the rates of interest legally chargeable or collectible.

(h)Our opinion is subject to the qualification that certain remedial provisions of the Credit Agreement are or may be unenforceable in whole or in part, but such possible unenforceability of such remedial provisions will not render the Credit Agreement inadequate for enforcing payment of the indebtedness that is evidenced by the Credit Agreement and for the practical realization of the principal rights and benefits afforded by the Credit Agreement.

(i)We have assumed that a party to the Credit Agreement is a resident of the State of New York or that a party to the Credit Agreement has its place of business or, if that party has more than one place of business, its chief executive office or an office from which it conducts a substantial part of the negotiations relating to the transaction, in the State of New York.

(j)Whenever our opinion is given "to our knowledge after due inquiry" or is based on circumstances "known to us after due inquiry", we have relied exclusively upon certificates of officers (after the discussion of the contents thereof with such officers) of the Borrower as to the existence or non-existence of the circumstances upon which such opinion is predicated. We have no reason to believe, however, that any such certificate is untrue or inaccurate in any material respect.

(k)In rendering the opinions herein relating to the absence of any litigation, investigation or administrative proceeding, we express no opinion with respect to the possible effect of any litigation, investigation or proceeding as to which the Borrower is not a named party.

You are advised that various members of this firm are stockholders of the Borrower; however, no member owns in excess of one percent of the Borrower's outstanding common stock.

This opinion is rendered solely to you and any assignee or Participant in connection with the above matter. This opinion may not be relied upon by you or any assignee or Participant for any other

B-2-3

purpose or relied upon by any other person without our prior written consent.

Very truly yours,

Bracewell & Patterson, L.L.P.

B-2-4

EX-21.1

Exhibit 21.1

KINDER MORGAN, INC.

Kinder Morgan (Delaware), Inc. - DE
Kinder Morgan G.P., Inc. - DE
Kinder Morgan Management, LLC - DE
KMGP Services Company, Inc. - DE
Kinder Morgan Services LLC - DE
KN Cogeneration, Inc. - CO
Thermo Gas Marketing, Inc. - CO
Thermo Project Management, Inc. - CO
Valley Operating, Inc. - CO
KN Thermo, L.L.C. - CO
Cogeneration Holdings LLC - DE
Cogeneration LLC - DE
Kinder Morgan Ft. Lupton Operator LLC - DE
Thermo Greeley, LLC - CO
KN Telecommunications, Inc. - CO
KN Gas Supply Services, Inc. - CO
KN Natural Gas, Inc. - CO
Red Rock Energy, LLC - DE
Interenergy Corporation - CO
Kinder Morgan Power Company - CO
KN TransColorado, Inc. - CO
KN Wattenberg Transmission Limited Liability Company - CO
Slurco Corporation - CO
Rocky Mountain Natural Gas Company - CO
Kinder Morgan Foundation (nonprofit) - CO
KN Gas Gathering, Inc. - CO
MidCon Corp. - DE
MidCon Gas Services Corp. - DE
MCN Gulf Processing Corp. - DE
Natural Gas Pipeline Company of America - DE
NGPL Canyon Compression Co. - DE
Canyon Creek Compression Company - IL
KN Management Corp. - DE
MidCon Mexico Pipeline Corp. - DE
KN Energy International, Inc. - DE
KM International Services, Inc. - DE
Lake Power L.L.C. - DE
FR Holdings L.L.C. - CO
Kinder Morgan Michigan LLC - DE
Kinder Morgan Kansas LLC - DE
Kinder Morgan Illinois, LLC - DE

Kinder Morgan Missouri, LLC - DE
Kinder Morgan Power Partners, LLC - DE
Kinder Morgan Georgia, LLC - DE
Kinder Morgan Michigan Pipeline LLC - DE
Kinder Morgan Virginia LLC - DE
Kinder Morgan Arkansas LLC - DE
Kinder Morgan Oklahoma LLC - DE
Kinder Morgan Alabama LLC - DE
KM Turbine Facility #6 LLC - DE
KM Turbine Facility #7 LLC - DE
Kinder Morgan Operator LLC - DE
Kinder Morgan Michigan Operator LLC - DE
Kinder Morgan Michigan Servicer LLC - DE
Kinder Morgan Michigan Contractor LLC - DE
Kinder Morgan Michigan Developer LLC - DE
Triton Power Company LLC - DE
Triton Power Michigan LLC - DE
KMC Thermo, L.L.C. - CO
Wildhorse Energy, LLC - DE
TransColorado Gas Transmission Company - CO
Administracion y Operacion de Infraestructura, S.A. de C.V. - Mexico
GNN Servicios, S. de R.L. de C.V. - Mexico
Gas Natural del Noroeste, S.A. de C.V. - Mexico
KN Thermo Acquisition, Inc. - CO
Kinder Morgan TransColorado LLC - DE
Kinder Morgan TransColorado, Inc. - UT
BetaGen Power LLC - DE

EX-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, 333-53908, 333-74864, and 33-46999), (iii) Form S-3 (Nos. 2-84910, 33-26314, 33-23880, 33-42698, 33-44871, 33-45091, 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 March 3, 2004 relating to the financial statements, which appears in this Form 10-K, and of our report dated March 3, 2004 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
March 4, 2004

EX-31.1

Exhibit 31.1

CERTIFICATION

	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 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 period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this 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 report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 5, 2004
	/s/ Richard D. Kinder
	Richard D. Kinder Chairman and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

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 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 period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this 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 report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;
b)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
c)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 5, 2004
	/s/ C. Park Shaper
	C. Park Shaper Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

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, 2003, 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:  March 5, 2004	/s/ Richard D. Kinder
	Richard D. Kinder Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.2

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, 2003, 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:  March 5, 2004	/s/ C. Park Shaper
	C. Park Shaper Vice President and Chief Financial Officer

EX-99.1

Exhibit 99.1

                          INDEX TO FINANCIAL STATEMENTS


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

Report of Independent Auditors........................................   92


Consolidated  Statements of Income for the years ended
December 31, 2003, 2002, and 2001.....................................   93


Consolidated  Statements of  Comprehensive  Income for the
years ended December 31, 2003, 2002, and 2001.........................   94


Consolidated Balance Sheets as of December 31, 2003 and 2002..........   95


Consolidated  Statements  of Cash Flows for the years
ended  December 31, 2003, 2002, and 2001..............................   96


Consolidated  Statements of Partners'  Capital for the
years ended December 31, 2003, 2002, and 2001.........................   97


Notes to Consolidated Financial Statements............................   98



                                       91
<PAGE>



                         Report of Independent Auditors

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, 2003 and 2002, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2003 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 4 to the consolidated financial statements, the Partnership
changed its method of accounting for asset retirement obligations effective
January 1, 2003.

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.


/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 3, 2004

                                       92
<PAGE>


<TABLE>
<CAPTION>

                    KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                                                       Year Ended December 31,
                                                               --------------------------------------
                                                                  2003          2002          2001
                                                               ----------    ----------    ----------
                                                               (In thousands except per unit amounts)
<S>                                                            <C>           <C>           <C>
   Revenues
     Natural gas sales.....................................    $4,889,235    $2,740,518    $1,627,037
     Services..............................................     1,377,745     1,272,640     1,161,643
     Product sales and other...............................       357,342       223,899       157,996
                                                               ----------    ----------    ----------
                                                                6,624,322     4,237,057     2,946,676
                                                               ----------    ----------    ----------
   Costs and Expenses
     Gas purchases and other costs of sales................     4,880,118     2,704,295     1,657,689
     Operations and maintenance............................       397,723       376,479       352,407
     Fuel and power........................................       108,112        86,413        73,188
     Depreciation and amortization.........................       219,032       172,041       142,077
     General and administrative............................       150,435       122,205       113,540
     Taxes, other than income taxes........................        62,213        51,326        43,947
                                                               ----------    ----------    ----------
                                                                5,817,633     3,512,759     2,382,848
                                                               ----------    ----------    ----------

   Operating Income........................................       806,689       724,298       563,828

   Other Income (Expense)
     Earnings from equity investments......................        92,199        89,258        84,834
     Amortization of excess cost of
       equity investments..................................        (5,575)       (5,575)       (9,011)
     Interest, net.........................................      (181,357)     (176,460)     (171,457)
     Other, net............................................         7,601         1,698         1,962
   Minority Interest.......................................        (9,054)       (9,559)      (11,440)
                                                               ----------    ----------    ----------

   Income Before Income Taxes and Cumulative
     Effect of a Change in Accounting Principle............       710,503       623,660       458,716

   Income Taxes............................................        16,631        15,283        16,373
                                                               ----------    ----------    ----------

   Income Before Cumulative Effect of a Change
   in Accounting Principle.................................       693,872       608,377       442,343

   Cumulative effect adjustment from change
     in accounting for asset retirement
     obligations...........................................         3,465             -             -
                                                               ----------    ----------    ----------

   Net Income..............................................    $  697,337    $  608,377    $  442,343
                                                               ==========    ==========    ==========

   Calculation of Limited Partners'
     Interest in Net Income:
   Income Before Cumulative Effect of a
     Change in Accounting Principle........................    $  693,872    $  608,377    $  442,343
   Less: General Partner's interest........................      (326,489)     (270,816)     (202,095)
                                                               ----------    ----------    ----------
   Limited Partners' interest..............................       367,383       337,561       240,248
   Add: Limited Partners' interest in
     Change in Accounting Principle........................         3,430             -             -
                                                               ----------    ----------    ----------
   Limited Partners' interest in Net Income................    $  370,813    $  337,561    $  240,248
                                                               ==========    ==========    ==========

   Basic and Diluted Limited Partners'
   Net Income per Unit:
   Income Before Cumulative Effect of a
     Change in Accounting Principle........................    $      1.98   $     1.96    $     1.56
   Cumulative effect adjustment from change
     in accounting for asset retirement obligations........           0.02            -             -
                                                               -----------   ----------    ----------
   Net Income..............................................    $      2.00   $     1.96    $     1.56
                                                               ===========   ==========    ==========

   Weighted average number of units used in
     computation of Limited Partners' Net
     Income per Unit:
   Basic...................................................       185,384       172,017       153,901
                                                               ==========    ==========    ==========

   Diluted.................................................       185,494       172,186       154,110
                                                               ==========    ==========    ==========
</TABLE>

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

                                       93
<PAGE>


<TABLE>
<CAPTION>

                    KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                                                 Year Ended December 31,
                                                           ----------------------------------
                                                              2003        2002        2001
                                                           ---------   ---------    ---------
                                                                     (In thousands)
<S>                                                        <C>         <C>          <C>
   Net Income..........................................    $ 697,337   $ 608,377    $ 442,343
   Cumulative effect transition adjustment.............           --          --      (22,797)
   Change in fair value of derivatives
     used for hedging purposes.........................     (192,618)   (116,560)      35,162
   Reclassification of change in fair
     value of derivatives to net income................       82,065       7,477       51,461
                                                           ---------   ---------    ---------
   Comprehensive Income................................    $ 586,784   $ 499,294    $ 506,169
                                                           =========   =========    =========
</TABLE>

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



                                       94
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                                              December 31,
                                                        -----------------------
                                                            2003        2002
                                                        ----------   ----------
                          ASSETS                         (Dollars in thousands)
 Current Assets
   Cash and cash equivalents.........................    $  23,329   $   41,088
   Accounts and notes receivable
      Trade..........................................      562,974      457,583
      Related parties................................       27,587       17,907
   Inventories
      Products.......................................        7,214        4,722
      Materials and supplies.........................       10,783        7,094
   Gas imbalances
      Trade..........................................       36,449       21,595
      Related parties................................        9,084        3,893
   Gas in underground storage........................        8,160       11,029
   Other current assets..............................       19,942      104,479
                                                        ----------   ----------
                                                           705,522      669,390
 Property, Plant and Equipment, net..................    7,091,558    6,244,242
 Investments.........................................      404,345      451,374
 Notes receivable....................................        2,422        3,823
 Goodwill............................................      729,510      716,610
 Other intangibles, net..............................       13,202       17,324
 Deferred charges and other assets...................      192,623      250,813
                                                        ----------   ----------
 Total Assets........................................   $9,139,182   $8,353,576
                                                        ==========   ==========
                     LIABILITIES AND PARTNERS' CAPITAL
 Current Liabilities
   Accounts payable
      Trade..........................................    $ 477,783   $  373,368
      Related parties................................            -       43,742
   Current portion of long-term debt.................        2,248            -
   Accrued interest..................................       52,356       52,500
   Deferred revenues.................................       10,752        4,914
   Gas imbalances....................................       49,912       40,092
   Accrued other liabilities.........................      211,328      298,711
                                                        ----------   ----------
                                                           804,379      813,327
 Long-Term Liabilities and Deferred Credits
   Long-term debt
      Outstanding....................................    4,316,678    3,659,533
      Market value of interest rate swaps............      121,464      166,956
                                                        ----------   ----------
                                                         4,438,142    3,826,489
   Deferred revenues.................................       20,975       25,740
   Deferred income taxes.............................       38,106       30,262
   Asset retirement obligations......................       34,898            -
   Other long-term liabilities and deferred credits..      251,691      199,796
                                                        ----------   ----------
                                                         4,783,812    4,082,287
 Commitments and Contingencies (Notes 13 and 16)
 Minority Interest...................................       40,064       42,033
                                                        ----------   ----------
 Partners' Capital
   Common Units (134,729,258 and 129,943,218
     units issued and outstanding as of
     December 31, 2003 and 2002,
     respectively)...................................    1,946,116    1,844,553
   Class B Units (5,313,400 and 5,313,400
     units issued and outstanding as of
     December 31, 2003 and 2002,
     respectively)...................................      120,582      123,635
   i-Units (48,996,465 and 45,654,048
     units issued and outstanding as
     of December 31, 2003 and 2002,
     respectively)...................................    1,515,659    1,420,898
   General Partner...................................       84,380       72,100
   Accumulated other comprehensive loss..............     (155,810)     (45,257)
                                                        ----------   ----------
                                                         3,510,927    3,415,929
                                                        ----------   ----------
 Total Liabilities and Partners' Capital.............   $9,139,182   $8,353,576
                                                        ==========   ==========

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

                                       95
<PAGE>

<TABLE>
<CAPTION>
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                                       Year Ended December 31,
                                                                               --------------------------------------
                                                                                  2003          2002          2001
                                                                              -----------   -----------   -----------
                                                                                           (In thousands)
<S>                                                                           <C>           <C>           <C>
Cash Flows From Operating Activities
Net income................................................................    $   697,337   $   608,377   $   442,343
Adjustments to reconcile net income to net cash provided by operating
activities:
  Cumulative effect adj. from change in accounting for asset retirement
    obligations...........................................................         (3,465)           --            --
  Depreciation, depletion and amortization................................        219,032       172,041       142,077
  Amortization of excess cost of equity investments.......................          5,575         5,575         9,011
  Earnings from equity investments........................................        (92,199)      (89,258)      (84,834)
Distributions from equity investments.....................................         83,000        77,735        68,832
Changes in components of working capital:
  Accounts receivable.....................................................       (180,632)     (177,240)      174,098
  Other current assets....................................................         (1,858)       (7,583)       22,033
  Inventories.............................................................         (2,945)       (1,713)       22,535
  Accounts payable........................................................         92,702       288,712      (183,179)
  Accrued liabilities.....................................................          9,740        26,132       (47,792)
  Accrued taxes...........................................................         (4,904)        2,379         8,679
FERC rate reparations and refunds.........................................        (44,944)           --            --
Other, net................................................................         (7,923)      (35,462)        7,358
                                                                              -----------   -----------   -----------
Net Cash Provided by Operating Activities.................................        768,516       869,695       581,161
                                                                              -----------   -----------   -----------

Cash Flows From Investing Activities
Acquisitions of assets....................................................       (349,867)     (908,511)   (1,523,454)
Additions to property, plant and equip. for expansion and maintenance
  projects................................................................       (576,979)     (542,235)     (295,088)
Sale of investments, property, plant and equipment, net of removal costs..          2,090        13,912         9,043
Acquisitions of investments...............................................        (10,000)       (1,785)           --
Contributions to equity investments.......................................        (14,052)      (10,841)       (2,797)
Other.....................................................................          5,747        (1,420)       (6,597)
                                                                              -----------   -----------   -----------
Net Cash Used in Investing Activities.....................................       (943,061)   (1,450,880)   (1,818,893)
                                                                              -----------   -----------   -----------

Cash Flows From Financing Activities
Issuance of debt..........................................................      4,674,605     3,803,414     4,053,734
Payment of debt...........................................................     (4,014,296)   (2,985,322)   (3,324,161)
Loans to related party....................................................             --            --       (17,100)
Debt issue costs..........................................................         (5,204)      (17,006)       (8,008)
Proceeds from issuance of common units....................................        175,567         1,586         4,113
Proceeds from issuance of i-units.........................................             --       331,159       996,869
Contributions from General Partner........................................          4,181         3,353        11,716
Distributions to partners:
  Common units............................................................       (340,927)     (306,590)     (268,644)
  Class B units...........................................................        (13,682)      (12,540)       (8,501)
  General Partner.........................................................       (314,244)     (253,344)     (181,198)
  Minority interest.......................................................        (10,445)       (9,668)      (14,827)
Other, net................................................................          1,231         4,429        (2,778)
                                                                              -----------   -----------   -----------
Net Cash Provided by Financing Activities.................................        156,786       559,471     1,241,215
                                                                              -----------   -----------   -----------

Increase (Decrease) in Cash and Cash Equivalents..........................        (17,759)      (21,714)        3,483
Cash and Cash Equivalents, beginning of period............................         41,088        62,802        59,319
                                                                              -----------   -----------   -----------
Cash and Cash Equivalents, end of period..................................    $    23,329   $    41,088   $    62,802
                                                                              ===========   ===========   ===========
Noncash Investing and Financing Activities:
  Assets acquired by the issuance of units................................    $     2,000   $        --    $       --
  Assets acquired by the assumption of liabilities........................         36,187       213,861       293,871
Supplemental disclosures of cash flow information:
  Cash paid (received) during the year for
  Interest (net of capitalized interest)..................................        183,908       161,840       165,357
  Income taxes............................................................           (261)        1,464         2,168
</TABLE>

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

                                       96
<PAGE>

<TABLE>
<CAPTION>
                    KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

                                                        2003                       2002                      2001
                                              -------------------------  ------------------------  --------------------------
                                                  Units        Amount        Units       Amount        Units         Amount
                                              -----------   -----------  -----------  -----------  -----------    -----------
                                                                          (Dollars in thousands)
<S>                                           <C>           <C>          <C>          <C>          <C>            <C>
    Common Units:
      Beginning Balance..................     129,943,218   $ 1,844,553  129,855,018  $ 1,894,677  129,716,218    $ 1,957,357
      Net income.........................              --       265,423           --      254,934           --        203,559
      Units issued as consideration in the
        acquisition of assets............          51,490         2,000           --           --           --             --
      Units issued for cash..............       4,734,550       175,067       88,200        1,532      138,800          2,405
      Distributions......................              --      (340,927)          --     (306,590)          --       (268,644)
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................     134,729,258     1,946,116  129,943,218    1,844,553  129,855,018      1,894,677

    Class B Units:
      Beginning Balance..................       5,313,400       123,635    5,313,400      125,750    5,313,400        125,961
      Net income.........................              --        10,629           --       10,427           --          8,335
      Units issued for cash..............              --            --           --           (2)          --            (44)
      Distributions......................              --       (13,682)          --      (12,540)          --         (8,502)
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................       5,313,400       120,582    5,313,400      123,635    5,313,400        125,750

    i-Units:
      Beginning Balance..................      45,654,048     1,420,898   30,636,363    1,020,153           --             --
      Net income.........................              --        94,761           --       72,200           --         28,354
      Units issued for cash..............              --            --   12,478,900      328,545   29,750,000        991,799
      Distributions......................       3,342,417            --    2,538,785           --      886,363             --
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................      48,996,465     1,515,659   45,654,048    1,420,898   30,636,363      1,020,153

    General Partner:
      Beginning Balance..................              --        72,100           --       54,628           --         33,749
      Net income.........................              --       326,524           --      270,816           --        202,095
      Units issued for cash..............              --            --           --           --           --            (18)
      Distributions......................              --      (314,244)          --     (253,344)          --       (181,198)
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................              --        84,380           --       72,100           --         54,628

    Accumulated other comprehensive income:
      Beginning Balance..................              --       (45,257)          --       63,826           --             --
      Cumulative effect transition adj...              --            --           --           --           --        (22,797)
      Change in fair value of derivatives
        used for hedging purposes........              --      (192,618)          --     (116,560)          --         35,162
      Reclassification of change in fair
        value of derivatives to net
        Income...........................              --        82,065           --        7,477           --         51,461
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................              --      (155,810)          --      (45,257)          --         63,826

    Total Partners' Capital..............     189,039,123   $ 3,510,927  180,910,666  $ 3,415,929  165,804,781    $ 3,159,034
                                              ===========   ===========  ===========  ===========  ===========    ===========
</TABLE>

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

                                       97
<PAGE>


              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  Organization

   General

   Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership formed
in August 1992. Unless the context requires otherwise, references to "we," "us,"
"our" or the "Partnership" are intended to mean Kinder Morgan Energy Partners,
L.P. and its consolidated subsidiaries.

   We own and manage a diversified portfolio of energy transportation and
storage assets. 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 producing, 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; 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 35,000 miles of natural gas and products
pipelines and approximately 80 terminals. At December 31, 2003, KMI and its
consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 19.0% interest in us.

   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

                                       98
<PAGE>

affairs, except that KMR cannot take certain specified actions without the
approval of our general partner. Under the delegation of control agreement, KMR
manages and controls our business and affairs and the business and affairs of
our operating limited partnerships and their subsidiaries. Furthermore, in
accordance with its limited liability company agreement, KMR's activities are
limited to being a limited partner in, and managing and controlling the business
and affairs of us, our operating limited partnerships and their subsidiaries. As
of December 31, 2003, KMR owned approximately 25.9% of our outstanding limited
partner units (which are in the form of i-units that are issued only to KMR).


2.  Summary of Significant Accounting Policies

   Basis of Presentation

   Our consolidated financial statements 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 by management, 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. These estimates and assumptions affect
the amounts we report for assets and liabilities and our disclosure of
contingent assets and liabilities at the date of the financial statements.

   Therefore, the reported amounts of our assets and liabilities 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.

   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, 2003, 2002 and 2001.



                                       99
<PAGE>

<TABLE>
<CAPTION>
                                             Valuation and Qualifying Accounts
                                                     (in thousands)

                                      Balance at        Additions         Additions                       Balance at
                                     beginning of   charged to costs  charged to other                      end of
Allowance for Doubtful Accounts         Period        and expenses       accounts(1)     Deductions(2)      period
                                     ------------   ---------------- ------------------ --------------  -------------

<S>                                     <C>              <C>               <C>              <C>             <C>
Year ended December 31, 2003....        $8,092           $1,448            $    -           $  (757)        $8,783

Year ended December 31, 2002....        $7,556           $  822            $    4           $  (290)        $8,092

Year ended December 31, 2001....        $4,151           $3,641            $1,362           $(1,598)        $7,556
</TABLE>
- ----------

(1) Amount for 2002 represents the allowance recognized when we acquired IC
    Terminal Holdings Company and Consolidated Subsidiaries. Amount for 2001
    represents 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.


   In addition, the balances of "Accrued other current liabilities" in our
accompanying consolidated balance sheets include amounts related to customer
prepayments of approximately $8.2 million as of December 31, 2003 and $38.7
million as of December 31, 2002.

   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.

   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 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 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. 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.

   Our oil and gas producing 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. In
addition, we engage in enhanced recovery techniques in which CO2 is injected
into certain producing oil reservoirs. The acquisition cost of this CO2 for the
SACROC unit is capitalized as part of our development costs when it is injected.
When CO2 is recovered in conjunction with oil production, it is extracted and
re-injected, and all of the associated costs are expensed as incurred. Proved
developed reserves are used in computing units of production rates for drilling
and development costs, and total proved reserves are used for depletion of
leasehold costs. The units-of-production rate is determined by field.

   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.

                                       100
<PAGE>

   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. 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.

   Equity Method of Accounting

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

   Excess of Cost Over Fair Value

   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 months, goodwill must be tested for impairment annually or
as changes in circumstances require. 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 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. We
have selected an impairment measurement test date of January 1 of each year and
we have determined that our goodwill was not impaired as of January 1, 2004.

   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 but not consolidated, we reported amortization of excess cost of
investments as amortization of excess cost of equity investments in our
accompanying consolidated statements of income.

                                      101
<PAGE>

   Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was approximately $729.5 million as of December 31, 2003
and $716.6 million as of December 31, 2002. Such amounts are reported as
"Goodwill" on our accompanying consolidated balance sheets. Our total
unamortized excess cost over underlying fair value of net assets accounted for
under the equity method was approximately $150.3 million as of December 31,
2003, and approximately $140.3 million as of December 31, 2002. Pursuant to SFAS
No. 142, this amount, referred to as equity method goodwill, should continue to
be recognized in accordance with Accounting Principles Board Opinion No. 18,
"The Equity Method of Accounting for Investments in Common Stock." Accordingly,
we included this amount within "Investments" on our accompanying consolidated
balance sheets.  In addition, approximately $189.7 million and $195.3 million
at December 31 2003 and 2002, respectively, representing the excess of the fair
market value of property, plant and equipment over its book value at the date of
acquisition was being amortized over a weighted average life of approximately
34 years.

   In addition to our annual impairment test of goodwill, we periodically
reevaluate the amount at which we carry the excess of cost over fair value of
net assets 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 APB Opinion No. 18. The impairment test under APB No. 18
considers whether the fair value of the equity investment as a whole, not the
underlying net assets, has declined and whether that decline is other than
temporary. As of December 31, 2003, 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 capitalized in 2003, 2002 and 2001 was $5.3
million, $5.8 million and $3.1 million, respectively.

   Unit-Based Compensation

   SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS
No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure,"
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 APB 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. No compensation expense has been
recorded since the options were granted at exercise prices equal to the market
prices at the date of grant. 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. 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

                                      102
<PAGE>

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
canreasonably 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 potential
environmental issues that could impact our assets or operations, we recognized a
$0.3 million reduction in environmental expense and in our overall accrued
environmental liability, and we included this amount within "Other, net" in our
accompanying Consolidated Statement of Income for 2002. The $0.3 million income
item resulted from 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 from a $15.7 million loss in
our Products Pipelines business segment and a $16.0 million gain in our
Terminals business segment. For more information on our environmental
disclosures, see Note 16.

   Legal

   We are subject to litigation and regulatory proceedings as the result of our
business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements. 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. For more information on our legal disclosures, see Note 16.

   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

   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.


                                      103
<PAGE>

   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 either settled in cash or made up in-kind subject to
the pipelines' various terms.

   Minority Interest

   As of December 31, 2003, 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 33 1/3% interest in International Marine Terminals, a Louisiana
     partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P.
     "C"; and

   o the approximate 31% interest in the Pecos Carbon Dioxide Company, a Texas
     general partnership owned approximately 69% and controlled by Kinder Morgan
     CO2 Company, L.P. and its consolidated subsidiaries.

   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 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, 2003, 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.
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.

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   Asset Retirement Obligations

   As of January 1, 2003, we account for asset retirement obligations pursuant
to SFAS No. 143, "Accounting for Asset Retirement Obligations." For more
information on our asset retirement obligations, see Note 4.

   Two-for-one Common Unit Split

   On July 18, 2001, KMR, the delegate of our general partner, approved a
two-for-one 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 of 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 this
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 debt obligations.

   Our derivatives are accounted for under 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 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 2001, 2002 and 2003, we completed or made adjustments for 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
preliminary allocation of assets and liabilities may be adjusted to reflect the
final determined amounts during a short period of time following the
acquisition. The results of operations from these acquisitions are included in
our consolidated financial statements from the acquisition date.

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<TABLE>
<CAPTION>

                                                                              Allocation of Purchase Price
                                                           -------------------------------------------------------------------
                                                                                     (in millions)
                                                           -------------------------------------------------------------------
                                                                                   Property    Deferred
                                                             Purchase   Current     Plant &     Charges              Minority
  Ref.   Date                Acquisition                      Price      Assets    Equipment    & Other   Goodwill   Interest
  ----- ------  ------------------------------------------  ----------  --------  ----------   --------   --------   --------
<S>      <C>    <C>                                           <C>         <C>         <C>         <C>       <C>        <C>
  (1)    1/01   GATX Domestic Pipelines and Terminals.....    $1,233.4    $ 32.3      $928.7      $ 4.8     $267.6        -
  (2)    3/01   Pinney Dock & Transport LLC...............        51.7       2.0        32.4        0.5       16.8        -
  (3)    7/01   Bulk Terminals from Vopak.................        44.3         -        44.3          -          -        -
  (4)    7/01   Kinder Morgan Texas Pipeline..............       326.1         -       326.1          -          -        -
  (5)    8/01   The Boswell Oil Company...................        22.4       1.6        13.9          -        6.9        -
  (6)    11/01  Liquid Terminals from Stolt-Nielsen.......        70.8         -        70.7          -        0.1        -
  (7)    11/01  Interests in Snyder and Diamond M Plants..        20.9         -        20.9          -          -        -
  (8)    1/02   Kinder Morgan Materials Services LLC......        12.2       0.9        11.3          -          -        -
  (9)    1/02   66 2/3% Interest in Intl. MarineTerminals.        40.5       6.6        31.8        0.1          -      2.0
  (10)   1/02   Kinder Morgan Tejas.......................       881.5      56.5       674.1          -      150.9        -
  (11)   5/02   Milwaukee Bagging Operations..............         8.5       0.1         3.1          -        5.3        -
  (12)   5/02   Trailblazer Pipeline Company..............        80.1         -        41.7          -       15.0     23.4
  (13)   9/02   Owensboro Gateway Terminal................         7.7       0.0         4.3        0.1        3.3        -
  (14)   9/02   IC Terminal Holdings Company..............        17.7       0.1        14.3        3.3          -        -
  (15)   1/03   Bulk Terminals from M.J. Rudolph..........        31.3       0.1        18.2        0.1       12.9        -
  (16)   6/03   MKM Partners, L.P.........................        25.2         -        25.2          -          -        -
  (17)   8/03   Red Cedar Gathering Company...............        10.0         -           -       10.0          -        -
  (18)   10/03  Shell Products Terminals..................        20.0         -        20.0          -          -        -
  (19)   11/03  Yates Field Unit and Carbon Dioxide Assets       259.0       3.5       255.8          -          -     (0.3)
  (20)   11/03  MidTex Gas Storage Company, LLP...........        17.5         -        11.9          -          -      5.6
  (21)   12/03  ConocoPhillips Products Terminals.........        15.1         -        15.1          -          -        -
  (22)   12/03  Tampa, Florida Bulk Terminals.............    $   29.5        $-      $ 29.5         $-         $-       $-
</TABLE>


   (1) 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.

   After the acquisitions, Kinder Morgan Liquids Terminals LLC's assets included
12 terminals, located across the United States, with storage capacity of
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.

   (2) Pinney Dock & Transport LLC

   Effective March 1, 2001, we acquired all of the equity interests in Pinney
Dock & Transport LLC, formerly Pinney Dock & Transport Company, for
approximately $51.7 million. The acquisition included 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

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<PAGE>

assumed liabilities. The $16.8 million of goodwill was assigned to our Terminals
business segment and the entire amount is expected to be deductible for tax
purposes.

   (3) 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.

   (4) 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 from a third-party
under an operating lease 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 were released from lease payments of $40 million
annually from 2002 through 2005 and $30 million annually from 2006 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.

   (5) 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. 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.

   (6) 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. 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.

   (7) 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

                                      107
<PAGE>

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 business segment.

   (8) Kinder Morgan Materials Services LLC

   Effective January 1, 2002, we acquired all of the equity interests of Kinder
Morgan Materials Services LLC for an aggregate consideration of $12.2 million,
consisting of approximately $8.9 million in cash 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.

   (9) 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 eight 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.

   (10) 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 expanded 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 combination of these
systems is part of our Texas intrastate natural gas pipeline group. Our
allocation to assets acquired and liabilities assumed was based on an appraisal
of fair market values. 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.

   (11) 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 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. 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.

   (12) 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 an
aggregate consideration of $80.1 million. We now own 100% of Trailblazer
Pipeline Company. In May 2002, we paid $68 million to an affiliate of Enron
Corp., and during the first quarter of 2002, we paid $12.1 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.


                                      108
<PAGE>

Trailblazer Pipeline Company has a current certificated capacity of 846 million
cubic feet per day of natural gas. 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.

   (13) Owensboro Gateway Terminal

   Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. In September 2002,
we paid approximately $7.2 million and established a $0.5 million purchase price
retention liability to be paid at the later of: (i) one year following the
acquisition, or (ii) the day we received consent to the assignment of a contract
between the seller and the New York Mercantile Exchange, Inc. We paid the $0.5
million liability in September 2003. 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. We
refer to the acquired terminal as our Owensboro Gateway Terminal and we include
its operations in our Terminals business segment. 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.

   (14) 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 $17.7 million, consisting of $17.4 million in cash and the
assumption of $0.3 million in liabilities. The total purchase price decreased
$0.2 million in the third quarter of 2003 primarily due to adjustments in the
amount of working capital items assumed on the acquisition date. The acquisition
included the former ICOM marine terminal in St. Gabriel, Louisiana. The St.
Gabriel facility has 400,000 barrels of liquids storage capacity and a related
pipeline network. The acquisition further expanded our terminal businesses along
the Mississippi River. The acquired terminal is referred to as the Kinder Morgan
St. Gabriel terminal, and we include its operations in our Terminals business
segment.

   (15) Bulk Terminals from M.J. Rudolph

   Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk terminal facilities at
major ports along the East Coast and in the southeastern United States. The
acquisition also included the purchase of certain assets that provide
stevedoring services at these locations. The aggregate cost of the acquisition
was approximately $31.3 million. On December 31, 2002, we paid $29.9 million for
the Rudolph acquisition and this amount was included with "Other current assets"
on our accompanying consolidated balance sheet. In the first quarter of 2003, we
paid the remaining $1.4 million and we allocated our aggregate purchase price to
the appropriate asset and liability accounts. 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 expanded our growing Terminals
business segment and complements certain of our existing terminal facilities. In
our final analysis, it was considered reasonable to allocate a portion of our
purchase price to goodwill given the substance of this transaction, including
expected benefits from integrating this acquisition with our existing assets,
and we include its operations in our Terminals business segment. The $12.9
million of goodwill was assigned to our Terminals business segment and the
entire amount is expected to be deductible for tax purposes.

   (16) MKM Partners, L.P.

   Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership
interest in the SACROC unit for an aggregate consideration of $25.2 million,
consisting of $23.3 million in cash and the assumption of $1.9 million of
liabilities. The SACROC unit is one of the largest and oldest oil fields in the
United States using carbon dioxide flooding technology. This transaction
increased our ownership interest in the SACROC unit to approximately 97%.

                                      109
<PAGE>

   On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January
1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets
consisted of a 12.75% interest in the SACROC oil field unit and a 49.9% interest
in the Yates Fieldunit, both of which are in the Permian Basin of West Texas.
The MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and
15% by Kinder Morgan CO2 Company, L.P. It was dissolved effective June 30, 2003,
and the net assets were distributed to partners in accordance with its
partnership agreement.

   (17) Red Cedar Gas Gathering Company

   Effective August 1, 2003, we acquired reversionary interests in the Red Cedar
Gas Gathering Company held by the Southern Ute Indian Tribe. Our purchase price
was $10.0 million. The 4% reversionary interests were scheduled to take effect
September 1, 2004 and September 1, 2009. With the elimination of these
reversions, our ownership interest in Red Cedar will be maintained at 49% in the
future.

   (18) Shell Products Terminals

   Effective October 1, 2003, we acquired five refined petroleum products
terminals in the western United States for approximately $20.0 million from
Shell Oil Products U.S. We plan to invest an additional $8.0 million in the
facilities. The terminals are located in Colton and Mission Valley, California;
Phoenix and Tucson, Arizona; and Reno, Nevada. Combined, the terminals have 28
storage tanks with total capacity of approximately 700,000 barrels for gasoline,
diesel fuel and jet fuel. As part of the transaction, Shell has entered into a
long-term contract to store products in the terminals. The acquisition enhances
our Pacific operations and complements our existing West Coast Terminals. The
acquired operations are included as part of our Pacific operations and our
Products Pipelines business segment.

   (19) Yates Field Unit and Carbon Dioxide Assets

   Effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation. Our purchase price
was approximately $259.0 million, consisting of $231.0 million in cash and the
assumption of $28.0 million of liabilities. The assets acquired consisted of the
following:

   o Marathon's approximate 42.5% interest in the Yates oil field unit. We
     previously owned a 7.5% ownership interest in the Yates field unit and we
     now operate the field;

   o Marathon's 100% interest in the crude oil gathering system surrounding the
     Yates field; and

   o Marathon Carbon Dioxide Transportation Company. Marathon Carbon Dioxide
     Transportation Company owns a 65% ownership interest in the Pecos Carbon
     Dioxide Pipeline Company, which owns a 25-mile carbon dioxide pipeline.

   We previously owned a 4.27% ownership interest in the Pecos Carbon Dioxide
Pipeline Company and accounted for this investment under the cost method of
accounting. After the acquisition of our additional 65% interest in Pecos, its
financial results were included in our consolidated results and we recognized
the appropriate minority interest. The acquisition complemented our existing
carbon dioxide assets in the Permian Basin, increased our working interest in
the Yates field to nearly 50% and allowed us to become the operator of the
field. The acquired operations are included as part of our CO2 business segment.
Our allocation of the purchase price to assets acquired, liabilities assumed and
minority interest is preliminary, pending final purchase price adjustments that
we expect to make in the first quarter of 2004.

   (20) MidTex Gas Storage Company, LLP

   Effective November 1, 2003, we acquired the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP from an affiliate of
NiSource Inc. Our combined purchase price was approximately $17.5 million,
including the assumption of $1.7 million of debt. The debt represented a MidTex
note payable that was to be paid by the former partner. We now own 100% of
MidTex Gas Storage Company, LLP. MidTex Gas Storage Company, LLP is a Texas
limited liability partnership that owns two salt dome natural gas storage
facilities located


                                      110
<PAGE>

in Matagorda County, Texas. The acquisition eliminated the third-party interest
in the operations of MidTex. MidTex's operations are included as part of our
Natural Gas Pipelines business segment. Our allocation of the purchase price to
assets acquired, liabilities assumed and minority interest is preliminary,
pending final purchase price adjustments that we expect to make in the first
quarter of 2004.

   (21) ConocoPhillips Products Terminals

   Effective December 11, 2003, we acquired seven refined petroleum products
terminals in the southeastern United States from ConocoPhillips Company and
Phillips Pipe Line Company. Our purchase price was approximately $15.1 million,
consisting of approximately $14.1 million in cash and $1.0 million in assumed
liabilities. The terminals are located in Charlotte and Selma, North Carolina;
Augusta and Spartanburg, South Carolina; Albany and Doraville, Georgia; and
Birmingham, Alabama. We will fully own and operate all of the terminals except
for the Doraville, Georgia facility, which is operated and owned 70% by Citgo.
We plan to invest an additional $1.3 million in the facilities. Combined, the
terminals have 35 storage tanks with total capacity of approximately 1.15
million barrels for gasoline, diesel fuel and jet fuel. As part of the
transaction, ConocoPhillips entered into a long-term contract to use the
terminals. The acquisition broadens our refined petroleum products operations in
the southeastern United States as three of the terminals are connected to the
Plantation pipeline system, which is operated and owned 51% by us. The acquired
operations are included as part of our Products Pipelines business segment. Our
allocation of the purchase price to assets acquired and liabilities assumed is
preliminary, pending final purchase price adjustments that we expect to make in
the first quarter of 2004.

   (22) Tampa, Florida Bulk Terminals

   In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.5 million, consisting of
$26.0 million in cash (including closing and related costs of approximately $1.1
million) and $3.5 million in assumed liabilities. We plan to invest an
additional $16.9 million in the facilities. The principal purchased asset was a
marine terminal acquired from a subsidiary of IMC Global, Inc. We also entered
into a long-term agreement with IMC to enable it to be the primary user of the
facility, which we will operate and refer to as the Kinder Morgan Tampaplex
terminal. The terminal sits on a 114-acre site, and serves as a storage and
receipt point for imported ammonia, as well as an export location for dry bulk
products, including fertilizer and animal feed. We closed on the Tampaplex
portion of this transaction on December 23, 2003. The second facility includes
assets from the former Nitram, Inc. bulk terminal, which we plan to use as an
inland bulk storage warehouse facility for overflow cargoes from our Port Sutton
import terminal. We closed on the Nitram portion of this transaction on December
10, 2003. The acquired operations are included as part of our Terminals business
segment and complement our existing business in the Tampa area by generating
additional fee-based income. Our allocation of the purchase price to assets
acquired and liabilities assumed is preliminary, pending final purchase price
adjustments that we expect to make in the first quarter of 2004.

   Pro Forma Information

   The following summarized unaudited pro forma consolidated income statement
information for the years ended December 31, 2003 and 2002, assumes that all of
the 2003 and 2002 acquisitions and joint ventures we have made since January 1,
2002, including the ones listed above, had occurred as of January 1, 2002. 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 2003 and 2002
acquisitions and joint ventures as of January 1, 2002 or the results that will
be attained in the future. Amounts presented below are in thousands, except for
the per unit amounts:
<TABLE>
<CAPTION>
                                                               Pro Forma Year Ended
                                                                   December 31,
                                                                2003            2002
                                                            ------------    ------------
                                                                    (Unaudited)
<S>                                                         <C>             <C>
 Revenues................................................   $  6,709,834    $  4,608,979
 Operating Income........................................        857,762         802,373
 Income Before Cumulative Effect of a Change in
  Accounting Principle...................................        736,598         673,766
 Net Income..............................................   $    740,063    $    673,766
 Basic and Diluted Limited Partners' Net Income per unit:
   Income  Before  Cumulative  Effect  of  a
    Change  in  Accounting Principle.....................   $       2.21    $       2.19
   Net Income............................................   $       2.23    $       2.19
</TABLE>

                                      111
<PAGE>

4.  Change in Accounting for Asset Retirement Obligations

   In August 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting
and reporting guidance for legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction or normal
operation of a long-lived asset. The provisions of this Statement are effective
for fiscal years beginning after June 15, 2002. We adopted SFAS No. 143 on
January 1, 2003.

   SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us will be to change the method of accruing for oil production site restoration
costs related to our CO2 business segment. Prior to January 1, 2003, we
accounted for asset retirement obligations in accordance with SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies." Under
SFAS No. 143, the fair value of asset retirement obligations are recorded as
liabilities on a discounted basis when they are incurred, which is typically at
the time the assets are installed or acquired. Amounts recorded for the related
assets are increased by the amount of these obligations. Over time, the
liabilities will be accreted for the change in their present value and the
initial capitalized costs will be depreciated over the useful lives of the
related assets. The liabilities are eventually extinguished when the asset is
taken out of service. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:

   o a liability for any existing asset retirement obligations adjusted for
     cumulative accretion to the date of adoption;

   o an asset retirement cost capitalized as an increase to the carrying amount
     of the associated long-lived asset; and

   o accumulated depreciation on that capitalized cost.

   Amounts resulting from initial application of this Statement are measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost is measured as of the date the
asset retirement obligation was incurred. Cumulative accretion and accumulated
depreciation are measured for the time period from the date the liability would
have been recognized had the provisions of this Statement been in effect to the
date of adoption of this Statement.

   The cumulative effect adjustment for this change in accounting principle
resulted in income of $3.5 million in the first quarter of 2003. Furthermore, as
required by SFAS No. 143, we recognized the cumulative effect of initially
applying SFAS No. 143 as a change in accounting principle as described in
Accounting Principles Board Opinion 20, "Accounting Changes." The cumulative
effect adjustment resulted from the difference between the amounts recognized in
our consolidated balance sheet prior to the application of SFAS No. 143 and the
net amount recognized in our consolidated balance sheet pursuant to SFAS No.
143.

   In our CO2 business segment, we are required to plug and abandon oil wells
that have been removed from service and to remove our surface wellhead equipment
and compressors. As of December 31, 2003, we have recognized asset retirement
obligations in the aggregate amount of $32.7 million relating to these
requirements at existing sites within our CO2 segment.

   In our Natural Gas Pipelines business segment, if we were to cease providing
utility services, we would be required to remove surface facilities from land
belonging to our customers and others. Our Texas intrastate natural gas pipeline
group has various condensate drip tanks and separators located throughout its
natural gas pipeline systems, as well as inactive gas processing plants,
laterals and gathering systems which are no longer integral to the overall
mainline transmission systems, and asbestos-coated underground pipe which is
being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission
system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of December 31, 2003, we have recognized
asset retirement obligations in the aggregate amount of $3.0 million relating to
the businesses within our Natural Gas Pipelines segment.

   We have included $0.8 million of our total $35.7 million asset retirement
obligations as of December 31, 2003 with "Accrued other current liabilities" in
our accompanying consolidated balance sheet. The remaining $34.9

                                      112
<PAGE>

million obligation is reported separately as a non-current liability. No assets
are legally restricted for purposes of settling our asset retirement
obligations. A reconciliation of the beginning and ending aggregate carrying
amount of our asset retirement obligations for the twelve months ended December
31, 2003 is as follows (in thousands):

        Balance as of December 31, 2002............     $       -
        Initial ARO balance upon adoption..........          14,125
        Liabilities incurred.......................          12,911
        Liabilities settled........................          (1,056)
        Accretion expense..........................           1,028
        Revisions in estimated cash flows..........           8,700
                                                        -----------
        Balance as of December 31, 2003............     $    35,708
                                                        ===========

   Pro Forma Information

   Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003,
our net income and associated per unit amounts, and the amount of our liability
for asset retirement obligations, would have been as follows (in thousands,
except per unit amounts):

<TABLE>
<CAPTION>
                                                                     Pro Forma Year Ended
                                                                          December 31,
                                                              -------------------------------------
                                                                 2003         2002         2001
                                                              -----------  -----------  -----------
                                                                           (Unaudited)
<S>                                                           <C>          <C>          <C>
Reported income before cumulative effect of a change in
  accounting principle...................................     $   693,872  $   608,377  $   442,343
Adjustments from change in accounting for asset
  retirement obligations.................................              --       (1,161)        (980)
                                                              -----------  -----------  -----------
Adjusted income before cumulative effect of a change in
  accounting principle...................................     $   693,872  $   607,216  $   441,363
                                                              ===========  ===========  ===========
Reported income before cumulative effect of a change in
  accounting principle per unit (fully diluted)..........     $      1.98  $      1.96  $      1.56
                                                              ===========  ===========  ===========
Adjusted income before cumulative effect of a change in
  accounting principle per unit (fully diluted)..........     $      1.98  $      1.95  $      1.55
                                                              ===========  ===========  ===========

                                                              Dec. 31,     Dec. 31,
                                                                2002         2001
                                                              -------      -------
Liability for asset retirement obligations.............       $14,125      $14,345
                                                              =======      =======
</TABLE>


5.  Income Taxes

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

                                     Year Ended December 31,
                                -------------------------------
                                   2003        2002       2001
                                --------    --------   --------
      Taxes currently payable:
        Federal..............   $    437    $ 15,855   $  9,058
        State................      1,131       3,116      1,192
        Foreign..............         25         147          -
                                --------    --------   --------
        Total................      1,593      19,118     10,250
      Taxes deferred:
        Federal..............     11,650      (3,280)     5,366
        State................      1,939        (555)       757
        Foreign..............      1,449           -          -
                                --------    --------   --------
        Total................     15,038      (3,835)     6,123
                                --------    --------   --------
      Total tax provision....   $ 16,631    $ 15,283   $ 16,373
                                ========    ========   ========
      Effective tax rate.....        2.3%        2.4%       3.5%

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

                                      113
<PAGE>

<TABLE>
<CAPTION>

                                                                    Year Ended December 31,
                                                                   2003       2002      2001
                                                                ---------  --------- -------
<S>                                                                <C>        <C>       <C>
    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..........        0.5%       0.6%      1.3%
      Income tax expense attributable to corporate equity           1.5%       1.6%      1.8%
    earnings................................................
      Income tax expense attributable to foreign corporate          0.2%       -         -
    earnings................................................
      State taxes...........................................        0.1%       0.2%      0.4%
                                                                --------   --------  --------
    Effective tax rate......................................        2.3%       2.4%      3.5%
                                                                ========   ========  ========
</TABLE>

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

                                                           December 31,
                                                        -----------------
                                                          2003     2002
                                                        -------  --------
 Deferred tax assets:
   Book accruals....................................    $ 1,424  $     97
   Net Operating Loss/Alternative minimum tax credits    10,797     3,556
                                                        -------  --------
 Total deferred tax assets..........................     12,221     3,653
 Deferred tax liabilities:
   Property, plant and equipment....................     50,327    33,915
                                                        -------  --------
 Total deferred tax liabilities.....................     50,327    33,915
                                                        -------  --------
 Net deferred tax liabilities.......................    $38,106  $ 30,262
                                                        =======  ========

   We had available, at December 31, 2003, approximately $0.3 million of
alternative minimum tax credit carryforwards, which are available indefinitely,
and $10.5 million of net operating loss carryforwards, which will expire between
the years 2004 and 2023. 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):
<TABLE>
<CAPTION>
                                                                         December 31,
                                                                       2003         2002
<S>                                                                <C>          <C>
  Natural gas, liquids and carbon dioxide pipelines...........     $ 3,458,736  $ 2,544,987
  Natural  gas,  liquids  and  carbon  dioxide  pipeline
   station equipment..........................................       2,908,273    2,801,729
  Coal and bulk tonnage transfer, storage and services........         359,088      281,713
  Natural gas and transmix processing.........................         100,778       98,094
  Other.......................................................         330,982      292,881
  Accumulated depreciation and depletion......................        (641,914)    (452,408)
                                                                   -----------  -----------
                                                                     6,515,943    5,566,996
  Land and land right-of-way..................................         339,579      340,507
  Construction work in process................................         236,036      336,739
                                                                   -----------  -----------
                                                                   $ 7,091,558  $ 6,244,242
                                                                   ===========  ===========
</TABLE>

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

                                                   2003       2002     2001
                                                ---------  --------- ------
        Depreciation and depletion expense..    $ 217,401  $171,461  $126,641


7.  Investments

   Our significant equity investments at December 31, 2003 consisted of:

   o Plantation Pipe Line Company (51%);

   o Red Cedar Gathering Company (49%);

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

                                      114
<PAGE>

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

   o Cortez Pipeline Company (50%); and

   o Heartland Pipeline Company (50%).

   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 a 15% ownership
interest in MKM Partners, L.P., a joint venture with Marathon Oil Company. The
MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and 15%
by Kinder Morgan CO2 Company, L.P. The joint venture assets consisted of a
12.75% interest in the SACROC oil field unit and a 49.9% interest in the Yates
field unit, both of which are in the Permian Basin of West Texas. We accounted
for our 15% investment in the joint venture under the equity method of
accounting because our ownership interest included 50% of the joint venture's
general partner interest, and the ownership of this general partner interest
gave us the ability to exercise significant influence over the operating and
financial policies of the joint venture. Effective June 1, 2003, we acquired the
MKM joint venture's 12.75% ownership interest in the SACROC unit for $23.3
million and the assumption of $1.9 million of liabilities. On June 20, 2003, we
signed an agreement with subsidiaries of Marathon Oil Corporation to dissolve
MKM Partners, L.P. The partnership's dissolution was effective June 30, 2003,
and the net assets were distributed to partners in accordance with its
partnership agreement.  Our interests in the SACROC unit and the Yates field
unit, including the incremental interest acquired in November 2003, are
accounted for using the proportional method of consolidation for oil and gas
operations.

   Finally, in September 2003, we paid $10.0 million to acquire reversionary
interests in the Red Cedar Gas Gathering Company. The 4% reversionary interests
were held by the Southern Ute Indian Tribe and were scheduled to take effect
September 1, 2004 and September 1, 2009. With the elimination of these
reversions, our ownership interest in Red Cedar will be maintained at 49% in the
future. For more information on our acquisitions, see Note 3.

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

                                                          December 31,
                                                       -------------------
                                                         2003       2002
                                                       --------   --------
  Plantation Pipe Line Company.....................    $219,349   $212,300
  Red Cedar Gathering Company......................     114,176    106,422
  Thunder Creek Gas Services, LLC..................      37,245     36,921
  Coyote Gas Treating, LLC.........................      13,502     14,435
  Cortez Pipeline Company..........................      12,591     10,486
  Heartland Pipeline Company.......................       5,109      5,459
  MKM Partners, L.P................................           -     60,795
  All Others.......................................       2,373      4,556
                                                       --------   --------
  Total Equity Investments.........................    $404,345   $451,374
                                                       ========   ========

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

                                      115
<PAGE>

                                                Year Ended December 31,
                                            -------------------------------
                                              2003       2002        2001
                                            --------   --------    --------
   Plantation Pipe Line Company........     $ 27,983   $ 26,426    $ 25,314
   Cortez Pipeline Company.............       32,198     28,154      25,694
   Red Cedar Gathering Company.........       18,571     19,082      18,814
   MKM Partners, L.P...................        5,000      8,174       8,304
   Coyote Gas Treating, LLC............        2,608      2,651       2,115
   Thunder Creek Gas Services, LLC.....        2,833      2,154       1,629
   Heartland Pipeline Company..........          973        998         882
   All Others..........................        2,033      1,619       2,082
                                            --------   --------    --------
   Total...............................     $ 92,199   $ 89,258    $ 84,834
                                            ========   ========    ========
   Amortization of excess costs........     $ (5,575)  $ (5,575)   $ (9,011)
                                            ========   ========    ========

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

                                                               Year Ended December 31,
                                                          ---------------------------------
            Income Statement                                 2003        2002        2001
    -------------------------------                       ---------   ---------   ---------
<S>                                                       <C>         <C>         <C>
    Revenues..........................................    $ 467,871   $ 505,602   $ 449,259
    Costs and expenses.................................     295,931     309,291     280,100
                                                          ---------   ---------   ---------
    Earnings before extraordinary items and
      cumulative effect of a change in accounting
      principle........................................     171,940     196,311     169,159
                                                          =========   =========   =========
    Net income.........................................   $ 168,167   $ 196,311   $ 169,159
                                                          =========   =========   =========

</TABLE>
                                                December 31,
                   Balance Sheet               2003        2002
              ---------------------        ----------- --------
              Current assets............   $   93,709  $   83,410
              Non-current assets........      684,754   1,101,057
              Current liabilities.......      377,535     243,636
              Non-current liabilities...      209,468     374,132
              Partners'/owners' equity..   $  191,460  $  566,699



8.  Intangibles

   Under ABP No. 18, any premium paid by an investor, which is analogous to
goodwill, must be identified. Under prior rules, excess cost over underlying
fair value of net assets accounted for under the equity method, referred to as
equity method goodwill, would have been amortized, however, under SFAS No. 142,
equity method goodwill is not subject to amortization but rather to impairment
testing pursuant to ABP No. 18. The impairment test under APB No. 18 considers
whether the fair value of the equity investment as a whole, not the underlying
net assets, has declined and whether that decline is other than temporary. This
test requires equity method investors to continue to assess impairment of
investments in investees by considering whether declines in the fair values of
those investments, versus carrying values, may be other than temporary in
nature. The caption "Investments" in our accompanying consolidated balance
sheets includes $150.3 million and $140.3 million of equity method goodwill at
December 31, 2003 and 2002, respectively.

   Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. Following
is information related to our intangible assets still subject to amortization
and our goodwill (in thousands):

                                             December 31,
                                        ---------------------
                                           2003        2002
                                        ---------   ---------
         Goodwill
         Gross carrying amount......    $ 743,652   $ 730,752
         Accumulated amortization...      (14,142)    (14,142)
                                        ---------   ---------
         Net carrying amount........      729,510     716,610
                                        ---------   ---------

         Lease value
         Gross carrying amount......        6,592       6,592
         Accumulated amortization...         (888)       (748)
                                        ---------   ---------
         Net carrying amount........        5,704       5,844
                                        ---------   ---------

                                      116
<PAGE>

                                             December 31,
                                        ---------------------
                                           2003        2002
                                        ---------   ---------
         Contracts and other
         Gross carrying amount......        7,801      11,719
         Accumulated amortization...         (303)       (239)
                                        ---------   ---------
         Net carrying amount........        7,498      11,480
                                        ---------   ---------

         Total intangibles, net.....    $ 742,712   $ 733,934
                                        =========   =========

Changes in the carrying amount of goodwill for each of the two years ended
December 31, 2002 and 2003 are summarized as follows (in thousands):
<TABLE>
<CAPTION>

                                   Products     Natural Gas         CO2
                                  Pipelines      Pipelines     Pipelines     Terminals       Total
                                  -----------   -----------    -----------   -----------   -----------
<S>                               <C>           <C>            <C>           <C>           <C>
   Balance as of Dec. 31, 2001    $   262,765   $    87,452    $    46,101   $   150,416   $   546,734
     Goodwill acquired                    417       165,906              -         3,553       169,876
     Impairment losses                      -             -              -             -             -
                                  -----------   -----------    -----------   -----------   -----------
   Balance as of Dec. 31, 2002    $   263,182   $   253,358    $    46,101   $   153,969   $   716,610
                                  ===========   ===========    ===========   ===========   ===========
     Goodwill acquired                      -             -              -        12,900        12,900
     Impairment losses                      -             -              -             -             -
                                  -----------   -----------    -----------   -----------   -----------
   Balance as of Dec. 31, 2003    $   263,182   $   253,358    $    46,101   $   166,869   $   729,510
                                  ===========   ===========    ===========   ===========   ===========
</TABLE>

   Amortization expense on intangibles consists of the following (in thousands):

                                         Year Ended December 31,
                                          2003      2002      2001
                                        --------  --------  ------
            Goodwill.................   $      -  $      -  $13,416
            Lease value..............        140       140    4,999
            Contracts and other......         64        40       60
                                        --------  --------  -------
            Total amortization.......   $    204  $    180  $18,475
                                        ========  ========  =======

   As of December 31, 2003, our weighted average amortization period for our
intangible assets is approximately 40 years. Our estimated amortization expense
for these assets for each of the next five fiscal years is approximately $0.2
million.

   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):

<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                                              ------------------------------------
                                                                 2003         2002          2001
                                                              ---------     ---------    ---------
<S>                                                           <C>           <C>          <C>
Reported limited partners' interest in net income             $ 370,813     $ 337,561    $ 240,248
Add: limited partners' interest in goodwill amortization             --            --       13,280
                                                              ---------     ---------    ---------

Adjusted limited partners' interest in net income             $ 370,813     $ 337,561    $ 253,528
                                                              =========     =========    =========
Basic limited partners' net income per unit:
  Reported net income                                         $    2.00     $    1.96    $    1.56
  Goodwill amortization                                              --            --         0.09
                                                              ---------     ---------    ---------
  Adjusted net income                                         $    2.00     $    1.96    $    1.65
                                                              =========     =========    =========

Diluted limited partners' net income per unit:
  Reported net income                                         $    2.00     $    1.96    $    1.56
  Goodwill amortization                                              --            --         0.09
                                                              ---------     ---------    ---------
  Adjusted net income                                         $    2.00     $    1.96    $    1.65
                                                              =========     =========    =========

</TABLE>

9.  Debt

   Our debt and credit facilities as of December 31, 2003, consisted primarily
of:

   o a $570 million unsecured 364-day credit facility due October 12, 2004;

   o a $480 million unsecured three-year credit facility due October 15, 2005;

                                      117
<PAGE>

   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  $25 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 $500 million of 5.00% Senior Notes due December 15, 2013;

   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 $1.05 billion 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 as of December 31, 2003 was $430.3 million.
The balance consisted of:

   o $426.1 million of commercial paper borrowings;

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

   o an offset of $0.8 million (which represents the net of other borrowings and
     the accretion of discounts on our senior note issuances).

   As of December 31, 2003, we intend and have the ability to refinance $428.1
million of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amount has been classified as
long-term debt in our accompanying consolidated balance sheet. Currently, we
believe our liquidity to be adequate.

                                      118
<PAGE>

The weighted average interest rate on allof our borrowings was approximately
4.4924% during 2003 and 5.015%during 2002.

   Credit Facilities

   On February 21, 2002, we obtained an 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 Kinder Morgan Tejas. 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.
The two credit facilities consisted of a $530 million unsecured 364-day credit
facility due October 14, 2003, and a $445 million unsecured three-year credit
facility due October 15, 2005. There were no borrowings under either credit
facility as of December 31, 2002.

   On May 5, 2003, we increased the borrowings available under our two credit
facilities by $75 million as follows:

   o our $530 million unsecured 364-day credit facility was increased to $570
     million; and

   o our $445 million unsecured three-year credit facility was increased to
     $480 million.

   Our $570 million unsecured 364-day credit facility expired October 14, 2003.
On that date, we obtained a new $570 million unsecured 364-day credit facility
due October 12, 2004. As of December 31, 2003, we had two credit facilities:

   o a $570 million unsecured 364-day credit facility due October 12, 2004; and

   o a $480 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. There were no borrowings under either credit facility at
December 31, 2003. 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.

   The amount available for borrowing under our credit facilities at December
31, 2003 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);

   o a $0.2 million letter of credit entered into on June 4, 2002 that supports
     a workers' compensation insurance policy; and

   o our outstanding commercial paper borrowings.

   In addition to our letters of credit outstanding as of December 31, 2003, in
early 2004 we issued a $50 million letter of credit to Morgan Stanley in support
of our hedging activities.

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<PAGE>


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

   Our credit facilities included the following restrictive covenants as of
December 31, 2003:

   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 $2.1 billion; and

     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.

   Senior Notes

   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% senior notes and $248.3 million for the 5.35% senior 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.

   On November 21, 2003, we closed a public offering of $500 million in
principal amount of 5% senior notes due December 15, 2013 at a price to the
public of 99.363% per note. In the offering, we received proceeds, net of
underwriting discounts and commissions, of approximately $493.6 million. We used
the proceeds to reduce our outstanding balance on our commercial paper
borrowings.

   As of December 31, 2003, our liability balance due on the various series of
our senior notes was as follows (in millions):

          8.00% senior notes due March 15, 2005......  $   199.9
          5.35% senior notes due August 15, 2007.....      249.9
          6.30% senior notes due February 1, 2009....      249.6
          7.50% senior notes due November 1, 2010....      248.9
          6.75% senior notes due March 15, 2011......      698.5
          7.125% senior notes due March 15, 2012.....      448.3
          5.00% senior notes due December 15, 2013...      496.8

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<PAGE>

          7.40% senior notes due March 15, 2031......      299.3
          7.75% senior notes due March 15, 2032......      298.6
          7.30% senior notes due August 15, 2033.....      499.0
                                                       ---------
            Total....................................  $ 3,688.8
                                                       =========

   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, 2003, we have entered into interest rate swap agreements with a
notional principal amount of $2.1 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.

   These 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. 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. For more information on our interest rate swaps, see Note 14.

   Commercial Paper Program

   On February 21, 2002, we increased our commercial paper program to provide
for the issuance of up to $1.8 billion. We entered into a $750 million 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
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. As of December 31,
2002, we had $220.0 million of commercial paper outstanding with an average
interest rate of 1.58%. On May 5, 2003, we increased the program to allow for
the borrowing of up to $1.05 billion of commercial paper. As of December 31,
2003, we had $426.1 million of commercial paper outstanding with an average
interest rate of 1.1803%.

   The borrowings under our commercial paper program were used to finance
acquisitions made during 2002 and 2003. The borrowings under our commercial
paper program reduce the borrowings allowed under our credit facilities.

   SFPP, L.P. Debt

   In December 2003, SFPP, L.P. prepaid the $37.1 million balance outstanding
under the Series F notes, plus $2.0 million for interest, as a result of its
taking advantage of certain optional prepayment provisions without penalty in
1999 and 2000.

   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 was
10.70%, the maturity was December 2004, and interest was payable semiannually in
June and December. We had 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 were collateralized by mortgages on substantially all of the
properties of SFPP, L.P. and contained 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.

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<PAGE>

   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, 2003, the
interest rate was 0.9606%. 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 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. As of December 31, 2002, Central Florida's
outstanding balance under the senior notes was $30.0 million. In July 2003, we
made an annual repayment of $5.0 million and as of December 31, 2003, Central
Florida's outstanding balance under the senior notes was $25.0 million.

   Trailblazer Pipeline Company Debt

   As of December 31, 2001, Trailblazer Pipeline Company had a two-year
unsecured revolving credit facility with a bank syndicate. The facility 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. As of December 31, 2001, the outstanding balance
under Trailblazer's two-year revolving credit facility was $55.0 million, with a
weighted average interest rate of 2.875%, which reflected 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.

   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 2003, the weighted-average interest
rate on these bonds was 1.05% per annum, and at December 31, 2003, the interest
rate was 1.20%. 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.


                                      122
<PAGE>

   International Marine Terminals Debt

   Since February 1, 2002, we have 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, as of December 31, 2003, are summarized as follows (in
thousands):

                      2004........    $  430,348
                      2005........       204,349
                      2006........        43,903
                      2007........       253,917
                      2008........         3,940
                      Thereafter..     3,382,469
                                      ----------
                      Total.......    $4,318,926
                                      ==========

   Of the $430.3 million scheduled to mature in 2004, we intend and have the
ability to refinance $428.1 million on a long-term basis under our unsecured
long-term credit facility. Accordingly, this amount has been classified as
long-term debt in our accompanying consolidated balance sheet as of December 31,
2003.

   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 as
of December 31, 2003 and December 31, 2002 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, 2003          December 31, 2002
                    -------------------------    -------------------------
                      Carrying      Estimated     Carrying      Estimated
                        Value      Fair Value       Value      Fair Value
                    -----------   -----------    -----------   -----------
                                        (In thousands)
      Total Debt    $ 4,318,926   $ 4,889,478    $ 3,659,533   $ 4,475,058


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 certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and Kinder
Morgan Bulk Terminals. We also provide the same benefits to former salaried
employees of SFPP. Additionally, we will continue to fund these costs for those
employees currently in the plan during their retirement years. SFPP's
post-retirement benefit plan is frozen and no additional participants may join
the plan.

   The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the 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.

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<PAGE>

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.

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

                                             Other Post-retirement Benefits
                                            -------------------------------
                                             2003         2002        2001
                                            ------       ------      ------
       Net periodic benefit cost
       Service cost......................   $   41       $  165      $  120
       Interest cost.....................      807          906         804
       Expected return on plan assets....       --           --          --
       Amortization of prior service cost     (622)        (545)       (545)
       Actuarial gain....................        -            -         (27)
                                            ------       ------      ------
       Net periodic benefit cost.........   $  226       $  526      $  352
                                            ======       ======      ======

       Additional amounts recognized
         Curtailment (gain) loss.........   $   --       $   --      $   --
       Weighted-average assumptions as of
         December 31:
       Discount rate.....................     6.00%        6.50%       7.00%
       Expected return on plan assets....       --           --          --
       Rate of compensation increase.....      3.9%         3.9%         --

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

                                               Other Post-retirement
                                                      Benefits
                                             --------------------------
                                               2003              2002
                                             --------          --------
   Change in benefit obligation
   Benefit obligation at Jan. 1........      $ 13,275          $ 13,368
   Service cost........................            41               165
   Interest cost.......................           807               906
   Participant contributions...........           144               143
   Amendments..........................          (190)             (493)
   Actuarial (gain) loss...............        (7,456)             (264)
   Benefits paid from plan assets......          (445)             (550)
                                             --------          --------
   Benefit obligation at Dec. 31.......      $  6,176          $ 13,275
                                             ========          ========

   Change in plan assets
   Fair value of plan assets at Jan. 1.      $     --          $     --
   Actual return on plan assets........            --                --
   Employer contributions..............           301               407
   Participant contributions...........           144               143
   Benefits paid from plan assets......          (445)             (550)
                                             --------          --------
   Fair value of plan assets at Dec. 31      $     --          $     --
                                             ========          ========

                                               Other Post-retirement
                                                      Benefits
                                             --------------------------
                                               2003              2002
                                             --------          --------
   Funded status.......................      $ (6,176)         $(13,275)
   Unrecognized net actuarial (gain)
   loss................................        (6,728)              729
   Unrecognized prior service (benefit)          (627)           (1,059)
   Adj. for 4th qtr. Employer
   contributions.......................            72               105
                                             --------          --------
   Accrued benefit cost................      $(13,459)         $(13,500)
                                             ========          ========

   The unrecognized prior service credit is amortized on a straight-line basis
over the average future lifetime until full eligibility for benefits. For
measurement purposes, an 11% annual rate of increase in the per capita cost of
covered health care benefits was assumed for 2004. The rate was assumed to
decrease gradually to 5% by 2010 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 (in thousands):


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<PAGE>

                                             1-Percentage     1-Percentage
                                            Point Increase   Point Decrease
                                            --------------   --------------
 Effect on total of service and
        interest cost components.........     $   78           $  (66)
 Effect on postretirement benefit
        obligation.......................     $  689           $ (575)

   Amounts recognized in our consolidated balance sheets consist of (in
thousands):

                                                     As of December 31,
                                                   2003             2002
                                               ------------     ------------
 Prepaid benefit cost......................              -                -
 Accrued benefit liability.................         (13,459)         (13,500)
 Intangible asset..........................              -                -
 Accumulated other comprehensive income....              -                -
                                               ------------     ------------
   Net amount recognized as of Dec. 31.....         (13,459)         (13,500)
                                               ============     ============

   We expect to contribute approximately $0.3 million to our post-retirement
benefit plans in 2004. The following benefit payments, which reflect expected
future service, as appropriate, are expected to be paid (in thousands):

              Other Post-retirement Benefits
             -------------------------------
             2004........        $       445
             2005........                445
             2006........                445
             2007........                445
             2008........                445
             2009-2013...              2,225
                                 -----------
             Total.......        $     4,450
                                 ===========

   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 $4.9 million for the year ended
2003 and $1.3 million for the year ended 2002.

   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 between 1% and 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 employer
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 2004, no discretionary
contributions were made to individual accounts for 2003. The total amount
charged to expense for our Savings Plan was $5.9 million during 2003 and $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 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 Cash Balance Retirement Plan.
Employees with prior service and not grandfathered converted to the Cash Balance
Retirement Plan and were credited with the current fair value of any benefits
they had previously accrued through the defined benefit plan. Under the plan, we
make contributions on behalf of participating 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. No additional contributions were
made for 2003 performance. Interest will be credited to the personal


                                      125
<PAGE>

retirement accounts at the 30-year U.S. Treasury bond rate, or an approved
substitute, in effect each year. Employees become fully vested in the plan after
five years, and they may take a lump sum distribution upon termination of
employment or retirement.


11.  Partners' Capital

   As of December 31, 2003, our partners' capital consisted of:

   o 134,729,258 common units;

   o 5,313,400 Class B units; and

   o 48,996,465 i-units.

   Together, these 189,039,123 units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights. As of December 31, 2003, our
common unit total consisted of 121,773,523 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.

   As of 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.

   Our total common units outstanding at December 31, 2002, 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.

   In June 2003, we issued in a public offering an additional 4,600,000 of our
common units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $173.3 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.

   On February 3, 2004, we announced that we had priced the public offering of
an additional 5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We also granted to the underwriters an
option to purchase up to 795,000 additional common units to cover
over-allotments. On February 9, 2004, 5,300,000 common units were issued. We
received net proceeds of $237.8 million for the issuance of these common units
and we used the proceeds to reduce the borrowings under our commercial paper
program.

   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 us,
our operating limited partnerships and their subsidiaries.

   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

                                      126
<PAGE>

commissions and underwriting expenses. The net proceeds from the offering were
used to buy additional 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 debt we incurred in our acquisition of Kinder Morgan Tejas during the
first quarter of 2002.

   Through the combined effect of the provisions in our partnership agreement
and the provisions of KMR's limited liability company agreement, the number of
outstanding KMR shares and the number of i-units will at all times be equal.
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 cashwe 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 cash to the holders of our i-units
but will retain the cash for use in our business. If additional units are
distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on the
preceding, KMR received a distribution of 811,625 i-units on November 14, 2003.
These additional i-units distributed were based on the $0.66 per unit
distributed to our common unitholders on that date. During the year ended
December 31, 2003, KMR received distributions of 3,342,417 i-units. These
additional i-units distributed were based on the $2.575 per unit distributed to
our common unitholders during 2003.

   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, 2003, 2002 and 2001, we declared
distributions of $2.63, $2.435 and $2.15 per unit, respectively. Our
distributions to unitholders for 2003, 2002 and 2001 required incentive
distributions to our general partner in the amount of $322.8 million, $267.4
million and $199.7 million, respectively. The increased incentive distributions
paid for 2003 over 2002 and 2002 over 2001 reflect the increase in amounts
distributed per unit as well as the issuance of additional units.

   On January 21, 2004, we declared a cash distribution of $0.68 per unit for
the quarterly period ended December 31, 2003. This distribution was paid on
February 13, 2004, to unitholders of record as of January 30, 2004. 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 $0.68
distribution per common unit. The number of i-units distributed was 778,309. For
each outstanding i-unit that KMR held, a fraction of an i-unit (0.015885) was
issued. The fraction was determined by dividing:

   o $0.68, the cash amount distributed per common unit

by

   o $42.807, the average of KMR's limited liability shares' closing market
     prices from January 13-27, 2004, the ten consecutive trading days preceding
     the date on which the shares began to trade ex-dividend under the rules of
     the New York Stock Exchange.

   This February 13, 2004 distribution required an incentive distribution to our
general partner in the amount of $85.8 million. Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2003 balance sheet as a Distribution Payable.


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12.  Related Party Transactions

   General and Administrative Expenses

   KMGP Services Company, Inc., a subsidiary of our general partner, provides
employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR,
provides centralized payroll and employee benefits services to us, our operating
partnerships 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 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. Additionally,
we reimburse KMR with respect to costs incurred or allocated to KMR in
accordance with our limited partnership agreement, the delegation of control
agreement among our general partner, KMR, us and others, and KMR's limited
liability company agreement.

   The named executive officers of our general partner and KMR and other
employees that provide management or services to both KMI and the Group are
employed by KMI. Additionally, other KMI employees assist in the operation of
our Natural Gas Pipeline assets. 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 us, and a direct 1.0101% ownership interest in each of our five
operating partnerships. Collectively, our general partner owns an effective 2%
interest in our operating partnerships, excluding incentive distributions rights
as follows:

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

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

   As of December 31, 2003, our general partner owned 1,724,000 common units,
representing approximately 0.91% 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.

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   Typically, 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. 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 closing price of
KMR's 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 for purposes of determining the distributions
to our general partner. We do not distribute cash to i-unit owners but retain
the cash for use in our business.

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

   Available cash for each quarter is distributed:

   o first, 98% to the owners of all classes of units pro rata and 2% to our
     general partner until the owners of all classes of units have received a
     total of $0.15125 per unit in cash or equivalent i-units for such quarter;

   o second, 85% of any available cash then remaining to the owners of all
     classes of units pro rata and 15% to our general partner until the owners
     of all classes of units have received a total of $0.17875 per unit in cash
     or equivalent i-units for such quarter;

   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, 2003, 2002 and 2001 were $322.8
million, $267.4 million and $199.7 million, respectively.

   Kinder Morgan, Inc.

   KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole
stockholder of our general partner. As of December 31, 2003, KMI directly owned
8,838,095 common units and 5,313,400 Class B units, indirectly owned 4,117,640
common units owned by its consolidated affiliates, including our general partner
and owned 14,531,495 KMR shares, representing an indirect ownership interest of
14,531,495 i-units. Together, these units represent approximately 17.4% of our
outstanding limited partner units. Including both its general and limited
partner interests in us, at the 2003 distribution level, KMI received
approximately 51% of all quarterly distributions from us, of which approximately
41% is attributable to its general partner interest and 10% 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

   As of December 31, 2003, KMR, our general partner's delegate, remains the
sole owner of our 48,996,465 i-units.


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   Asset Acquisitions

   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 have developed 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 as the Monterrey pipeline. The Monterrey pipeline 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 pipeline to explore the feasibility of and to
obtain permits for the Mexican portion of the pipeline. Following 1998, the
Monterrey pipeline 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 pipeline,
the Monterrey pipeline 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 pipeline
and determined that the Monterrey pipeline was an economically feasible pipeline
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 pipeline between 1996 and 1998.

   KMI Asset Contributions

   In conjunction with our acquisition of Natural Gas Pipelines assets from KMI
on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7
million of our debt. This amount has not changed as of December 31, 2003. KMI
would be obligated to perform under this guarantee only if we and/or our assets
were unable to satisfy our obligations.

   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 other agreements between KMI and us. 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. On January
1, 2003, KMI began operating additional pipeline assets, including our North
System and Cypress pipeline, which are part of our Products Pipelines business
segment. The amounts paid to KMI for corporate general and administrative costs,
including amounts related to Trailblazer Pipeline Company, were $8.7 million of
fixed costs and $10.8 million of actual costs incurred for 2003, and $13.3
million of fixed costs and $2.8 million of actual costs incurred for 2002. We
estimate the total reimbursement for corporate general and administrative costs
to be paid to KMI in respect of all pipeline assets operated by KMI and its
subsidiaries for us for 2004 will be approximately $19.8 million, which includes
$8.7 million of fixed costs (adjusted for inflation) and $11.1 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 fixed amounts that were agreed upon at
the time the contracts were entered into were reasonable estimates of the
corporate general and administrative expenses to be

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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.

   Retention Agreement

   Effective January 17, 2002, KMI entered into a retention agreement with Mr.
C. Park Shaper, an officer of KMI, Kinder Morgan G.P., Inc. (our general
partner) and its delegate, KMR. Pursuant to the terms of the agreement, Mr.
Shaper obtained a $5 million personal loan guaranteed by KMI and us. Mr. Shaper
was required to purchase and did purchase KMI common stock and our common units
in the open market with the loan proceeds. The Sarbanes-Oxley Act of 2002 does
not allow companies to issue or guarantee new loans to executives, but it
"grandfathers" loans that were in existence prior to the act. Regardless, Mr.
Shaper, KMI and we agreed that in today's business environment it would be
prudent for him to repay the loan. In conjunction with this decision, Mr. Shaper
sold 37,000 of KMI shares and 82,000 of our common units. He used the proceeds
to repay the $5 million personal loan guaranteed by KMI and us, thereby
eliminating KMI's and our guarantee of this loan. Mr. Shaper instead
participates in KMI's restricted stock plan with other senior executives. The
retention agreement was terminated accordingly.

   Lines of Credit

   As of December 31, 2002, we had agreed to guarantee potential borrowings
under lines of credit available from Wachovia Bank, National Association,
formerly known as First Union National Bank, to Messrs. Thomas Bannigan, C. Park
Shaper, Joseph Listengart and James Street and Ms. Deborah Macdonald. Each of
these officers was primarily liable for any borrowing on his or her line of
credit, and if we made any payment with respect to an outstanding loan, the
officer on behalf of whom payment was made was required to surrender a
percentage of his or her options to purchase KMI common stock. Our obligations
under the guaranties, on an individual basis, generally did not exceed $1.0
million and such obligations, in the aggregate, did not exceed $1.9 million. As
of October 31, 2003, we had made no payments with respect to these lines of
credit and each line of credit was either terminated or refinanced without a
guarantee from us. We have no further guaranteed obligations with respect to any
borrowings by our officers.

   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, 2003, Coyote's balance sheet has current notes
payable to each partner in the amount of $17.1 million. These notes are due on
June 30, 2004. At that time, the partners can either renew the notes or make
capital contributions which will 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 our unitholders for
actions taken that might, without such limitations, constitute breaches of
fiduciary duty.

   The partnership agreements provide that in the absence of bad faith by KMR,
the resolution of a conflict by KMR will not be a breach of any duties. The duty
of the 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.


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13.  Leases and Commitments

   Operating Leases

   Including probable elections to exercise renewal options, the remaining terms
on our operating leases range from one to 39 years. Future commitments related
to these leases as of December 31, 2003 are as follows (in thousands):

                      2004......................   $  17,076
                      2005......................      14,955
                      2006......................      12,825
                      2007......................      11,623
                      2008......................      10,834
                      Thereafter................      35,440
                                                   ---------
                      Total minimum payments....   $ 102,753
                                                   =========

   We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $1.1 million. Total lease and rental expenses,
including related variable charges were $25.3 million for 2003, $21.6 million
for 2002 and $41.1 million for 2001.

   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 authorized
under the option plan is 500,000. The option plan terminates in March 2008. 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.

   As of December 31, 2002, outstanding options for 263,600 common units had
been granted at an average exercise price of $17.25 per unit. Outstanding
options for 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s three non-employee directors at an average exercise price of $20.58 per
unit. As of December 31, 2003, outstanding options for 129,050 common units had
been granted at an average exercise price of $17.46 per unit. Outstanding
options for 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s three non-employee directors at an average exercise price of $20.58 per
unit.

   During 2002, 88,200 common unit options were exercised at an average price of
$17.77 per unit. The common units underlying these options had an average fair
market value of $34.24 per unit. During 2003, 134,550 common unit options were
exercised at an average price of $17.06 per unit. The common units underlying
these options had an average fair market value of $38.85 per unit.

   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, we record
expense for our common unit option plan equal to the excess of the market price
of the underlying common units at the date of grant over the exercise price of
the common unit award, if any. Such excess is commonly referred to as the
intrinsic value. All of our common unit options were issued with the exercise
price equal to the market price of the underlying common units at the grant date
and therefore, no compensation expense has been recorded. 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 material.

   Directors' Unit Appreciation Rights Plan

   On April 1, 2003, KMR's compensation committee established the Directors'
Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR's three
non-employee directors is eligible to receive common unit appreciation rights.
The primary purpose of this plan is to promote the interests of our unitholders
by aligning the compensation of the non-employee members of the board of
directors of KMR with unitholders' interests. Secondly, since KMR's

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success is dependent on its operation and management of our business and our
resulting performance, the plan is expected to align the compensation of the
non-employee members of the board with the interests of KMR's shareholders.

   Upon the exercise of unit appreciation rights, we will pay, within thirty
days of the exercise date, the participant an amount of cash equal to the
excess, if any, of the aggregate fair market value of the unit appreciation
rights exercised as of the exercise date over the aggregate award price of the
rights exercised. The fair market value of one unit appreciation right as of the
exercise date will be equal to the closing price of one common unit on the New
York Stock Exchange on that date. The award price of one unit appreciation right
will be equal to the closing price of one common unit on the New York Stock
Exchange on the date of grant. Each unit appreciation right granted under the
plan will be exercisable only for cash and will be evidenced by a unit
appreciation rights agreement.

   All unit appreciation rights granted vest on the six-month anniversary of the
date of grant. If a unit appreciation right is not exercised in the ten year
period following the date of grant, the unit appreciation right will expire and
not be exercisable after the end of such period. In addition, if a participant
ceases to serve on the board for any reason prior to the vesting date of a unit
appreciation right, such unit appreciation right will immediately expire on the
date of cessation of service and may not be exercised. The plan is administered
by KMR's compensation committee. The total number of unit appreciation rights
authorized under the plan is 500,000. KMR's board has sole discretion to
terminate the plan at any time with respect to unit appreciation rights which
have not previously been granted to participants.

   On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors were granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights will be granted to each of KMR's three
non-employee directors during the first meeting of the board each January.
Accordingly, each non-employee director received an additional 10,000 unit
appreciation rights on January 21, 2004. As of December 31, 2003, 52,500 unit
appreciation rights had been granted. No unit appreciation rights were exercised
during 2003.

   Contingent Debt

   We apply the disclosure provisions of FASB Interpretation (FIN) No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" to our agreements that contain
guarantee or indemnification clauses. These disclosure provisions expand those
required by FASB No. 5, "Accounting for Contingencies," by requiring a guarantor
to disclose certain types of guarantees, even if the likelihood of requiring the
guarantor's performance is remote. The following is a description of our
contingent debt agreements.

   Cortez Pipeline Company Debt

   Pursuant to a certain Throughput and Deficiency Agreement, the 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.

   As of December 31, 2003, the debt facilities of Cortez Capital Corporation
consisted of:

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   o $95 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 22, 2004
     (to support the above-mentioned $175 million commercial paper program).

   As of December 31, 2003, Cortez Capital Corporation had $135.7 million of
commercial paper outstanding with an interest rate of 1.12%, the average
interest rate on the Series D notes was 7.04% and there were no borrowings
under the credit facility.

   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 as of December 31, 2003.

   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 collateralized 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 under joint and several liability. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. The $55 million is outstanding as of December 31,
2003.

   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 LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC and became
guarantor under the letter of credit agreement. In December 2002, we issued a
$28 million letter of credit under our credit facilities and the former letter
of credit guarantee was terminated.


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

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

   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.

   Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows. Accordingly, as of December 31, 2003, no financial
instruments were used to limit the effects of foreign exchange rate fluctuations
on our financial results. In February 2004, we entered into a single $17.0
million foreign currency call option that expires on December 31, 2004.

   Our derivatives hedge our commodity price risks involving our normal business
activities, which include the sale of natural gas, natural gas liquids, oil and
carbon dioxide, and these derivatives have been designated by us as cash flow
hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge 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 is reclassified into earnings when the forecasted transaction
affects earnings. To be considered effective, changes in the value of the
derivative or its resulting cash flows must substantially offset changes in the
value or cash flows of the item being hedged. The ineffective portion of the
gain or loss is reported in earnings immediately.

   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
(loss)" in the accompanying consolidated balance sheets are reclassified into
earnings as the hedged sales and purchases take place. Approximately $65.4
million of the Accumulated other comprehensive loss balance of $155.8 million
representing unrecognized net losses on derivative activities as of December 31,
2003 is expected to be reclassified into earnings during the next twelve months.
During the twelve months ended December 31, 2003, we reclassified $82.1 million
of Accumulated other comprehensive income into earnings. This amount includes
the balance of $45.3 million representing unrecognized net losses on derivative
activities as of December 31, 2002. For each of the years ended December 31,
2003, 2002 and 2001, 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 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 $10.3 million as of
December 31, 2003 and $1.9 million as of December 31, 2002. Our margin deposits
associated with over-the-counter swap partners were $7.7 million as of December
31, 2003 and $0.0 million as of December 31, 2002.

                                      135
<PAGE>

   We recognized a gain of $0.5 million during 2003, a gain of $0.7 million
during 2002 and a loss of $1.3 million during 2001 as a result of ineffective
hedges. All of these amounts are reported within the captions "Gas purchases and
other costs of sales" or "Operations and maintenance" in our accompanying
Consolidated Statements of Income. For each of the years ended December 31,
2003, 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 included within
"Other current assets", "Accrued other current liabilities", "Deferred charges
and other assets" and "Other long-term liabilities and deferred credits" in our
accompanying consolidated balance sheets. As of December 31, 2003, the balance
in "Other current assets" on our consolidated balance sheet included $18.2
million related to risk management hedging activities, and the balance in
"Accrued other current liabilities" included $90.4 million related to risk
management hedging activities. As of December 31, 2002, the balance in "Other
current assets" on our consolidated balance sheet included $57.9 million related
to risk management hedging activities, and the balance in "Accrued other current
liabilities" included $101.3 million related to risk management hedging
activities. As of December 31, 2003, the balance in "Deferred charges and other
assets" included $2.7 million related to risk management hedging activities, and
the balance in "Other long-term liabilities and deferred credits" included
$101.5 million related to risk management hedging activities. As of December 31,
2002, the balance in "Deferred charges and other assets" included $5.7 million
related to risk management hedging activities, and the balance in "Other
long-term liabilities and deferred credits" included $8.5 million related to
risk management hedging activities.

   Given our portfolio of businesses as of December 31, 2003, our principal uses
of derivative energy 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, 2003, 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 2009.

   As of December 31, 2003, 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........................     $    5,261    $(178,480)  $ (173,219)
  Contract Amounts-- Gross........................     $   68,934    $ 954,313   $1,023,247
  Contract Amounts-- Net..........................     $   (3,687)   $(890,105)  $ (893,792)

                                                               (Number of contracts(1))
  Natural Gas
    Notional Volumetric Positions: Long...........            663          588        1,251
    Notional Volumetric Positions: Short..........           (670)      (2,369)      (3,039)
    Net Notional Totals to Occur in 2004..........             (7)      (1,756)      (1,763)
    Net Notional Totals to Occur in 2005 and Beyond            --          (25)         (25)
  Crude Oil
    Notional Volumetric Positions: Long...........             --          336          336
    Notional Volumetric Positions: Short..........             --      (37,418)     (37,418)
    Net Notional Totals to Occur in 2004..........             --      (10,854)     (10,854)
    Net Notional Totals to Occur in 2005 and Beyond            --      (26,228)     (26,228)
  Natural Gas Liquids
    Notional Volumetric Positions: Long...........             --           --           --
    Notional Volumetric Positions: Short..........             --         (460)        (460)
    Net Notional Totals to Occur in 2004..........             --         (336)        (336)
    Net Notional Totals to Occur in 2005 and Beyond            --         (124)        (124)
</TABLE>
- ----------

                                      136
<PAGE>

(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, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments; however, as of December 31, 2003 we had
virtually no amounts owed to us from other parties. 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. While we enter into derivative transactions
principally with investment grade counterparties and actively monitor their
credit ratings, it is nevertheless possible that from time to time losses will
result from counterparty credit risk in the future.

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

   o ceased to account for those derivatives as hedges;

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

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

   o recognized a $6.0 million loss (included with "General and administrative
     expenses" in our 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.

   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, 2003 and December 31, 2002, we were a party to interest rate swap
agreements with a notional principal amount of $2.1 billion and $1.95 billion,
respectively, for the purpose of hedging the interest rate risk associated with
our fixed and variable rate debt obligations.

   As of December 31, 2003, a notional principal amount of $2.0 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 $250 million principal amount of our 5.0% senior notes due December 15,
     2013;

   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.

                                      137
<PAGE>

   These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of December 31, 2003,
the maximum length of time over which we have hedged a portion of 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% 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, 2003, we also had swap agreements that effectively convert
the interest expense associated with $100 million of our variable rate debt to
fixed rate debt. Half of these agreements, converting $50 million of our
variable rate debt to fixed rate debt, mature on August 1, 2005, and the
remaining half mature on September 1, 2005. Prior to March 2002, this swap was
designated a hedge of our $200 million Floating Rate Senior Notes, which were
retired (repaid) 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 $100 million of our portfolio of commercial paper.

   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. As of December 31, 2003, we
recognized an asset of $129.6 million and a liability of $8.1 million for the
$121.5 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 our 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 our accompanying balance sheet. As of 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 our 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 our
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 primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.


15.  Reportable Segments

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

   o Products Pipelines;

   o Natural Gas Pipelines;


                                      138
<PAGE>

   o CO2; 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
principally 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 and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the transmission, storage,
gathering and sale of natural gas. Our CO2 segment derives its revenues
primarily from the transportation and marketing of carbon dioxide used as a
flooding medium for recovering crude oil from mature oil fields, and from the
production and sale 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):
                                                2003       2002        2001
                                             ---------- ----------- ----------
          Revenues
            Products Pipelines.............  $  585,376 $  576,542  $  605,392
            Natural Gas Pipelines..........   5,316,853  3,086,187   1,869,315
            CO2............................     248,535    146,280     122,094
            Terminals......................     473,558    428,048     349,875
                                             ---------- ----------- ----------
            Total consolidated revenues....  $6,624,322 $4,237,057  $2,946,676
                                             ========== ==========  ==========

       Operating expenses(a)
         Products Pipelines................  $  169,526 $  169,782  $  240,537
         Natural Gas Pipelines.............   4,967,531  2,784,278   1,665,852
         CO2...............................      82,055     50,524      44,973
         Terminals.........................     229,054    213,929     175,869
                                             ---------- ----------  ----------
         Total consolidated operating
          expenses.........................  $5,448,166 $3,218,513  $2,127,231
                                             ========== ==========  ==========
(a)Includes natural gas purchases and other costs of sales, operations and
   maintenance expenses, fuel and power expenses and taxes, other than income
   taxes.

        Earnings from equity investments
          Products Pipelines...............  $   30,948 $   28,998   $  28,278
          Natural Gas Pipelines............      24,012     23,887      22,558
          CO2..............................      37,198     36,328      33,998
          Terminals........................          41         45          --
                                             ---------- ----------  ----------
          Total consolidated equity
            earnings.......................  $   92,199 $   89,258  $   84,834
                                             ========== ==========  ==========
          Amortization of excess cost of equity investments
            Products Pipelines.............  $    3,281 $    3,281  $    5,592
            Natural Gas Pipelines..........         277        277       1,402
            CO2............................       2,017      2,017       2,017
            Terminals......................          --         --          --
                                             ---------- ----------  ----------
            Total consol. amortization of    $    5,575 $    5,575  $    9,011
                                             ========== ==========  ==========
          excess cost of invests...........

        Other, net-income (expense)(a)
          Products Pipelines...............  $    6,471 $  (14,000) $      440
          Natural Gas Pipelines............       1,082         36         749
          CO2..............................         (40)       112         547
          Terminals........................          88     15,550         226
                                             ---------- ----------  ----------
          Total consolidated Other,
           net-income (expense)............  $    7,601 $    1,698  $    1,962
                                             ========== ==========  ==========
(a) 2002 amounts include 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.

                                      139
<PAGE>

      Income tax benefit (expense)
        Products Pipelines.................  $  (11,669)$  (10,154) $   (9,653)
        Natural Gas Pipelines..............      (1,066)      (378)         --
        CO2................................         (39)        --          --
        Terminals..........................      (3,857)    (4,751)     (6,720)
                                             ---------- ----------  ----------
        Total consolidated income tax
         benefit (expense).................  $  (16,631)$  (15,283) $  (16,373)
                                             ========== ==========  ==========
      Segment earnings before
      depreciation, depletion,
      amortization and amortization of
      excess cost of equity investments
        Products Pipelines.................  $   441600 $  411,604  $  383,920
        Natural Gas Pipelines..............     373,350    325,454     226,770
        CO2................................     203,599    132,196     111,666
        Terminals..........................     240,776    224,963     167,512
                                             ---------- ----------  ----------
        Total  segment  earnings  before
         DD&A(a)...........................   1,259,325  1,094,217     889,868
        Consolidated depreciation and
         amortization......................    (219,032)  (172,041)   (142,077)
        Consolidated amortization of
         excess cost of invests............      (5,575)    (5,575)     (9,011)
        Interest and corporate
         administrative expenses(b)........    (337,381)  (308,224)   (296,437)
                                             ---------- ----------  ----------
        Total consolidated net income......  $  697,337 $  608,377  $  442,343
                                             ========== ==========  ==========

(a)  Includes revenues, earnings from equity investments, income taxes and
     other, net, less operating expenses.
(b)  Includes interest and debt expense, general and administrative expenses,
     minority interest expense and cumulative effect adjustment from a change in
     accounting principle (2003 only).

<TABLE>
<CAPTION>
<S>                                                 <C>             <C>             <C>
Segment earnings
  Products Pipelines.............................   $     370,974   $     343,935   $     312,464
  Natural Gas Pipelines..........................         319,288         276,766         193,804
  CO2............................................         140,755         100,983          92,087
  Terminals......................................         203,701         194,917         140,425
                                                    -------------   -------------   -------------
  Total segment earnings.........................       1,034,718         916,601         738,780
  Interest and corporate administrative expenses.        (337,381)       (308,224)       (296,437)
                                                    -------------   -------------   -------------
  Total consolidated net income..................   $     697,337   $     608,377   $     442,343
                                                    =============   =============   =============

   Assets at December 31
     Products Pipelines..........................   $   3,198,107   $   3,088,799   $   3,095,899
     Natural Gas Pipelines.......................       3,253,792       3,121,674       2,058,836
     CO2.........................................       1,177,645         613,980         503,565
     Terminals...................................       1,368,279       1,165,096         990,760
                                                    -------------   ------------    -------------
     Total segment assets........................       8,997,823       7,989,549       6,649,060
     Corporate assets(a).........................         141,359         364,027          83,606
                                                    -------------   ------------    -------------
     Total consolidated assets...................   $   9,139,182   $   8,353,576   $   6,732,666
                                                    =============   =============   =============
(a) Includes cash, cash equivalents and certain unallocable deferred charges.

Depreciation, depletion and amortization
  Products Pipelines...........................     $      67,345   $      64,388   $      65,864
  Natural Gas Pipelines........................            53,785          48,411          31,564
  CO2..........................................            60,827          29,196          17,562
  Terminals....................................            37,075          30,046          27,087
                                                    -------------   -------------   -------------
  Total consol. depreciation, depletion and
   amortiz.....................................     $     219,032   $     172,041   $     142,077
                                                    =============   =============   =============
Investments at December 31
  Products Pipelines...........................     $     226,680   $     220,203   $     225,561
  Natural Gas Pipelines........................           164,924         157,778         146,566
  CO2..........................................            12,591          71,283          68,232
  Terminals....................................               150           2,110             159
                                                    -------------   -------------   -------------
  Total consolidated investments...............     $     404,345   $     451,374   $     440,518
                                                    =============   =============   =============

Capital expenditures
  Products Pipelines...........................     $      94,727   $      62,199   $      84,709
  Natural Gas Pipelines........................           101,679         194,485          86,124
  CO2..........................................           272,177         163,183          65,778
  Terminals....................................           108,396         122,368          58,477
                                                    -------------   -------------   -------------
  Total consolidated capital expenditures......     $     576,979   $     542,235   $     295,088
                                                    =============   =============   =============
</TABLE>

                                      140
<PAGE>

   We do not attribute interest income or interest expense to any of our
reportable business segments. For each of the years ended December 31, 2003,
2002 and 2001, we reported (in thousands) total consolidated interest revenue of
$1,420, $1,819 and $4,473, respectively. For each of the years ended December
31, 2003, 2002 and 2001, we reported (in thousands) total consolidated interest
expense of $182,777, $178,279 and $175,930, respectively.

   Our total operating revenues are derived from a wide customer base. For each
of the years ended December 31, 2003, 2002 and 2001, one customer accounted for
more than 10% of our total consolidated revenues. Total transactions within our
Natural Gas Pipelines segment in 2003 and 2002 with CenterPoint Energy accounted
for 16.84% and 15.6% of our total consolidated revenues during 2003 and 2002,
respectively. 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.


16.  Litigation and Other Contingencies

   The tariffs we charge for transportation on our interstate common carrier
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, 2003, 2002 and 2001, the application of the indexing methodology
did not significantly affect tariff rates on our interstate petroleum products
pipelines.

   SFPP, L.P.

   Federal Energy Regulatory Commission Proceedings

   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 in the proceedings before the FERC 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." If SFPP rates previously "grandfathered"
under the Energy Policy Act lose their "grandfathered" status and are found to
be unjust and unreasonable, shippers may be entitled to prospective rate
reductions and complainants may be entitled to reparations for periods from the
date of their respective complaint to the date of the implementation of the new
rates.

   On June 24, 2003, a non-binding, phase one initial decision was issued by an
administrative law judge hearing a FERC case on the rates charged by SFPP on the
interstate portion of its pipelines (see OR96-2 section below for further
discussion). In his phase one initial decision, the administrative law judge
recommended that the FERC "ungrandfather" SFPP's interstate rates and found most
of SFPP's rates at issue to be unjust and unreasonable. The administrative law
judge has indicated that a phase two initial decision will address prospective
rates and whether reparations are necessary.

                                      141
<PAGE>

   Initial decisions have no force or effect and must be reviewed by the FERC.
The FERC is not obliged to follow any of the administrative law judge's findings
and can accept or reject this initial decision in whole or in part. In addition,
as stated above, the facts are complex, the rules and regulations in this area
are vague and little precedent exists. The FERC is now considering the phase one
initial decision and will consider the phase two initial decision when it is
issued and briefed by the parties. If the FERC ultimately finds, after reviewing
both initial decisions, that these rates should be "ungrandfathered" and are
unjust and unreasonable, they could be lowered prospectively and complaining
shippers could be entitled to reparations for prior periods. We do not expect
any impact on our rates relating to this matter before early 2005.

   We currently believe that these FERC complaints seek approximately $154
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million. As
the length of time from the filing of the complaints increases, the amounts
sought by complainants in tariff reparations will likewise increase until a
determination of reparations owed is made by the FERC. We are not able to
predict with certainty the final outcome of the pending FERC proceedings
involving SFPP, should they be carried through to their conclusion, or whether
we can reach a settlement with some or all of the complainants. The
administrative law judge's initial decision does not change our estimate of what
the complainants seek. Furthermore, 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, results of operations or cash flows.

   OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in those proceedings.

   A FERC administrative law judge held hearings in 1996, and issued an initial
decision in September 1997. The initial decision held that all but one of SFPP's
West Line rates were "grandfathered" under the Energy Policy Act of 1992 and
therefore deemed to be just and reasonable; it further held that complainants
had failed to prove "changed circumstances" with respect to those rates and that
they therefore could not be challenged in the Docket No. OR92-8 et al.
proceedings, either for the past or prospectively. However, the initial decision
also made rulings generally adverse to SFPP on certain cost of service issues
relating to the evaluation of East Line rates, which are not "grandfathered"
under the Energy Policy Act. Those issues included the capital structure to be
used in computing SFPP's "starting rate base," the level of income tax allowance
SFPP may include in rates and the recovery of civil and regulatory litigation
expenses and certain pipeline reconditioning costs incurred by SFPP. The initial
decision also held SFPP's Watson Station gathering enhancement service was
subject to FERC jurisdiction and ordered SFPP to file a tariff for that service.

   The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.

   The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "changed circumstances" necessary to challenge those rates. The
FERC further held that the one West Line rate that was not grandfathered did not
need to be reduced. The FERC consequently dismissed all complaints against the
West Line rates in Docket Nos. OR92-8 et al. without any requirement that SFPP
reduce, or pay any reparations for, any West Line rate.

   The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made

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certain modifications to the calculation of the income tax allowance and other
cost of service components, generally to SFPP's disadvantage.

   On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.

   While the FERC initially permitted SFPP to recover certain of its litigation,
pipeline reconditioning and environmental costs, either through a surcharge on
prospective rates or as an offset to potential reparations, it ultimately
limited recovery in such a way that SFPP was not able to make any such surcharge
or take any such offset. Similarly, the FERC initially ruled that SFPP would not
owe reparations to any complainant for any period prior to the date on which
that party's complaint was filed, but ultimately held that each complainant
could recover reparations for a period extending two years prior to the filing
of its complaint (except for Navajo, which was limited to one month of
pre-complaint reparations under a settlement agreement with SFPP's predecessor).
The FERC also ultimately held that SFPP was not required to pay reparations or
refunds for Watson Station gathering enhancement fees charged prior to filing a
FERC tariff for that service.

   In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made payments of $44.9 million in 2003 for
reparations and refunds under order from the FERC.

   Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case through November 2001 and severed petitions regarding
later FERC orders. The severed orders were held in abeyance for later
consideration.

   Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. The Court of Appeals is expected to
issue its decision in the first or second quarter of 2004.

   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 claimed that the
rate for that service was unlawful. Several other West Line shippers filed
similar complaints and/or motions to intervene.

   Following a hearing in March 1997, a FERC administrative law 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 pre-existing
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 set a hearing to determine
whether SFPP possessed market power in the origin market.

   Following a hearing, on December 21, 2000, an administrative law judge found
that SFPP possessed market power over the Sepulveda origin market. On February
28, 2003, the FERC issued an order upholding that decision. SFPP filed a request
for rehearing of that order on March 31, 2003. The FERC denied SFPP's request
for rehearing on July 9, 2003.

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   As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda line is just and reasonable. That issue is currently
pending before the administrative law judge in the Docket No. OR96-2, et al.
proceeding. The procedural schedule in this remanded matter is currently
suspended pending issuance of the phase two initial decision in the Docket No.
OR96-2, et al. proceeding (see below).

   OR96-2; 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. The FERC accepted the complaints and consolidated them into
one proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a
FERC decision on review of the initial decision in Docket Nos. OR92-8, et al.

   In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000.

   In August 2000, Navajo and 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. These complaints were
consolidated with the ongoing proceeding in Docket No. OR96-2, et al.

   A hearing in this consolidated proceeding was held from October 2001 to March
2002. A FERC administrative law judge issued his initial decision on June 24,
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable. The initial decision indicated that
a phase two initial decision will address prospective rates and whether
reparations are necessary. Issuance of the phase two initial decision is
expected sometime in the first quarter of 2004.

   SFPP has filed a brief on exceptions to the FERC that contests the findings
in the initial decision. SFPP's opponents have responded to SFPP's brief. The
FERC is now considering the phase one initial decision and will consider the
phase two initial decision when it is issued and briefed by the parties. If the
FERC ultimately finds, after reviewing both initial decisions, that these rates
should be "ungrandfathered" and are unjust and unreasonable, they could be
lowered prospectively and complaining shippers could be entitled to reparations
for prior periods. We do not expect any impact on our rates relating to this
matter before early 2005.

   OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the
Docket No. OR96-2, et al. proceeding, filed a complaint against SFPP in Docket
No. OR02-4 along with a motion to consolidate the complaint with the Docket No.
OR96-2, et al. proceeding. On May 21, 2002, the FERC dismissed Chevron's
complaint and motion to consolidate. Chevron filed a request for rehearing,
which the FERC dismissed on September 25, 2002. In October 2002, Chevron filed a
request for rehearing of the FERC's September 25, 2002 Order, which the FERC
denied on May 23, 2003. On July 1, 2003, Chevron filed a petition for review of
this denial at the U.S. Court of Appeals for the District of Columbia Circuit.
On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition on the
basis that Chevron lacks standing to bring its appeal and that the case is not
ripe for review. Chevron answered on September 10, 2003. SFPP's motion was
pending, when the Court of Appeals, on December 8, 2003, granted Chevron's
motion to hold the case in abeyance pending the outcome of the appeal of the
Docket No. OR92-8, et al. proceeding. On January 8, 2004, the Court of Appeals
granted Chevron's motion to have its appeal of the

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FERC's decision in Docket No. OR03-5 (see below) consolidated with Chevron's
appeal of the FERC's decision in the Docket No. OR02-4 proceeding. Chevron
continues to participate in the Docket No. OR96-2 et al. proceeding as an
intervenor.

   OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against
SFPP - substantially similar to its previous complaint - and moved to
consolidate the complaint with the Docket No. OR96-2, et al. proceeding. This
complaint was docketed as Docket No. OR03-5. Chevron requested that this new
complaint be treated as if it were an amendment to its complaint in Docket No.
OR02-4, which was previously dismissed by the FERC. By this request, Chevron
sought to, in effect, back-date its complaint, and claim for reparations, to
February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing
Chevron's requests for consolidation and for the back-dating of its complaint.
On October 28, 2003 , the FERC accepted Chevron's complaint, but held it in
abeyance pending the outcome of the Docket No. OR96-2, et al. proceeding. The
FERC denied Chevron's request for consolidation and for back-dating. On November
21, 2003, Chevron filed a petition for review of the FERC's October 28, 2003
Order at the Court of Appeals for the District of Columbia Circuit. On January
8, 2004, the Court of Appeals granted Chevron's motion to have its appeal
consolidated with Chevron's appeal of the FERC's decision in the Docket No.
OR02-4 proceeding and to have the two appeals held in abeyance pending outcome
of the appeal of the Docket No. OR92-8, et al. proceeding.

   California Public Utilities Commission Proceeding

   ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the State of California and requests prospective
rate adjustments. On October 1, 1997, the complainants filed testimony seeking
prospective rate reductions aggregating approximately $15 million per year.

   On August 6, 1998, the CPUC issued its decision dismissing the complainants'
challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited
rehearing of its August 1998 decision for the purpose of addressing the proper
ratemaking treatment for partnership tax expenses, the calculation of
environmental costs and the public utility status of SFPP's Sepulveda Line and
its Watson Station gathering enhancement facilities. In pursuing these rehearing
issues, complainants sought prospective rate reductions aggregating
approximately $10 million per year.

   On March 16, 2000, SFPP filed an application with the CPUC seeking authority
to justify its rates for intrastate transportation of refined petroleum products
on competitive, market-based conditions rather than on traditional,
cost-of-service analysis.

   On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.

   The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and
resolution of these submitted matters is anticipated within the third quarter of
2004.

   The CPUC subsequently issued a resolution approving a 2001 request by SFPP to
raise its California rates to reflect increased power costs. The resolution
approving the requested rate increase also required SFPP to submit cost data for
2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's
overall rates for California intrastate transportation services are reasonable.
The resolution reserves the right to require refunds, from the date of issuance
of the resolution, to the extent the CPUC's analysis of cost data to be
submitted by SFPP demonstrates that SFPP's California jurisdictional rates are
unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data
required by the CPUC, which submittal was protested by Valero Marketing and
Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil
Corporation and Chevron Products Company. Issues raised by the protest,
including the reasonableness of SFPP's existing intrastate transportation rates,
were the subject of evidentiary hearings conducted in December 2003 and are
expected to be resolved by the CPUC by the third quarter of 2004.

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   We currently believe the CPUC complaints seek approximately $15 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $31 million. There is no
way to quantify the potential extent to which the CPUC could determine that
SFPP's existing California rates are unreasonable. With regard to the amount of
dollars potentially subject to refund as a consequence of the CPUC resolution
requiring the provision by SFPP of cost-of-service data, such refunds could
total about $6 million per year from October 2002 to the anticipated date of a
CPUC decision during the third quarter of 2004.

   SFPP believes the submission of the required, representative cost data
required by the CPUC indicates that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.

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

   Trailblazer Pipeline Company

   As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at the 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 sought rehearing of the FERC order with respect to the refund
condition on the rate decrease. On April 15, 2003, the FERC granted
Trailblazer's rehearing request to remove the refund condition that had been
imposed in the December 31, 2002 Order. Certain intervenors have sought
rehearing as to the FERC's acceptance of certain non-rate tariff provisions. A
prehearing conference on the rate issues was held on January 16, 2003, where a
procedural schedule was established.

   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.

   Comments on these issues as discussed at the technical conference were filed
by parties in March 2003. On May 23, 2003, FERC issued an order deciding
non-rate tariff issues and denying rehearing of its prior order. In the May 23,
2003 order, FERC:

   o accepted Trailblazer's proposed capacity award procedures with very limited
     changes;

   o accepted Trailblazer's credit procedures subject to very extensive changes,
     consistent with numerous recent orders involving other pipelines;

   o accepted a compromise agreed to by Trailblazer and the active parties under
     which existing shippers must match competing bids in the right of first
     refusal process for up to 10 years (in lieu of the current 5 years); and

   o accepted Trailblazer's withdrawal of daily imbalance charges.

   The referenced order did the following:

   o allowed shortened notice periods for suspension of service, but required at
     least 30 days notice for service termination;


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   o limited prepayments and any other assurance of future performance, such as
     a letter of credit, to three months of service charges except for new
     facilities;

   o required the pipeline to pay interest on prepayments or allow those funds
     to go into an interest-bearing escrow account; and

   o required much more specificity about credit criteria and procedures in
     tariff provisions.

   Certain shippers and Trailblazer have sought rehearing of the May 23, 2003
order. Trailblazer made its compliance filing on June 20, 2003. Under the May
23, 2003 order, these tariff changes are effective as of May 23, 2003, except
that Trailblazer has filed to make the revised credit procedures effective
August 15, 2003.

   With respect to the on-going rate review phase of the case, direct testimony
was filed by FERC Staff and Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by Indicated Shippers on June 19, 2003.
Trailblazer's answering testimony was filed on July 29, 2003.

   On September 22, 2003, Trailblazer filed an offer of settlement with the
FERC. Under the settlement, if approved by the FERC, Trailblazer's rate would be
reduced effective January 1, 2004, from about $0.12 to $0.09 per dekatherm of
natural gas, and Trailblazer would file a new rate case to be effective January
1, 2010.

   On January 23, 2004, the FERC issued an order approving, with modification,
the settlement that was filed on September 22, 2003. The FERC modified the
settlement to expand the scope of severance of contesting parties to present and
future direct interests, including capacity release agreements. The settlement
had provided the scope of the severance to be limited to present direct
interests. On February 20, 2004, Trailblazer filed a letter with the FERC
accepting the modifications to the settlement. As of March 1, 2004, all members
of the Indicated Shippers group opposing the settlement had filed to withdraw
their opposition. We do not expect the settlement to have a material effect on
our consolidated revenues in 2004 or in subsequent periods.

   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 the 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 the 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 the 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. 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 the 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.

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   On May 22, 2003, KMIGT received an Order on Rehearing and Compliance Filing
(May 2003 Order) from the FERC, addressing KMIGT's November 19, 2001 filed
request for rehearing and filing to comply with the directives of the October
19, 2001 Order. The May 2003 Order granted in part and denied in part KMIGT's
request for rehearing, and directed KMIGT to file certain revised tariff sheets
consistent with the May 2003 Order's directives. On June 20, 2003, KMIGT
submitted its compliance filing reflecting revised tariff sheets in accordance
with the FERC's directives. Consistent with the May 2003 Order, KMIGT's
compliance filing reflected tariff sheets with proposed effective dates of June
1, 2003 and December 1, 2003. Those sheets with a proposed effective date of
December 1, 2003 concern tariff provisions necessitating computer system
modifications.

   On November 21, 2003, KMIGT received a Letter Order (November 21 Order) from
the FERC accepting the tariff sheets submitted in the June 20, 2003 compliance
filing. In accordance with the November 21 Order, KMIGT commenced full
implementation of Order No. 637 on December 1, 2003. KMIGT's actual operating
experience under the full requirements of Order No. 637 is limited. However, we
believe that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.

   Separately, numerous petitioners, including KMIGT, have filed appeals in
respect 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 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
     forwardhaul and backhaul transactions to the same point.

   On December 23, 2002, KMIGT filed revised tariff provisions (in a separate
docket) in compliance with the October 31, 2002 Order concerning the elimination
of the right of first refusal five-year term matching cap. In an order issued
January 22, 2003, the FERC approved such revised tariff provisions to be
effective January 23, 2003.

   Trailblazer Pipeline Company

   On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
the 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;

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   o operational flow orders;

   o penalty revenue crediting; and

   o right of first refusal language.

   On October 15, 2001, the FERC issued its order on Trailblazer's Order No. 637
 compliance filing. The FERC approved Trailblazer's proposed language regarding
 operational flow orders and rights 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 and also filed for rehearing of the October 15,
2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's
compliance filing and rehearing order. The FERC denied Trailblazer's requests
for rehearing and approved the compliance filing subject to modifications that
must be made within 30 days of the order.

   Trailblazer made those modifications in a further compliance filing on May
 16, 2003. Certain shippers have filed a limited protest regarding that
 compliance filing. That filing is pending FERC action. Under the FERC orders,
 limited aspects of Trailblazer's plan (revenue crediting) were effective as of
 May 1, 2003. The entire plan went into effective on December 1, 2003.

   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, 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 natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between Kinder Morgan Interstate Gas Transmission LLC,
Trailblazer and their respective affiliates. In addition, the Notice could be
read to require separate staffing of Kinder Morgan Interstate Gas Transmission
LLC and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties,
including Kinder Morgan Interstate Gas Transmission LLC, have filed comment on
the Proposed Standards of Conduct Rulemaking. On May 21, 2002, the FERC held a
technical conference dealing with the FERC's proposed changes in the Standard of
Conduct Rulemaking. On June 28, 2002, Kinder Morgan Interstate Gas Transmission
LLC and numerous other parties filed additional written comments under a
procedure adopted at the technical conference.

   On July 25, 2003, the FERC issued a Modification to Policy Statement stating
that FERC regulated natural gas pipelines will, on a prospective basis, no
longer be permitted to use gas basis differentials to price negotiated rate
transactions. Effectively, we will no longer be permitted to use commodity price
indices to structure transactions on our FERC regulated natural gas pipelines.
Negotiated rates based on commodity price indices in existing contracts will be
permitted to remain in effect until the end of the contract period for which
such rates were negotiated. Price indexed contracts currently constitute an
insignificant portion of our contracts on our FERC regulated natural gas
pipelines; consequently, we do not believe that this Modification to Policy
Statement will have a material impact on our operations, financial results or
cash flows.

   On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate pipeline must
file a compliance plan by that date and must be in full compliance with the
Standards of Conduct by June 1, 2004. The primary change from existing
regulation is to make such standards applicable to an interstate pipeline's
interaction with many more affiliates (referred to as "energy affiliates"),
including intrastate/Hinshaw pipelines, processors and gatherers and any company
involved in natural gas or electric markets (including natural gas marketers)
even if they do not ship on the affiliated interstate pipeline. Local
distribution companies are excluded, however, if they do not make off-system
sales. The Standards of Conduct require, among other things, separate staffing
of interstate pipelines and their energy affiliates (but support functions and
senior management at the central corporate level may be shared) and strict
limitations on communications from the interstate pipeline to an energy
affiliate.

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   Kinder Morgan Interstate Gas Transmission LLC filed for clarification and
rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing,
Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw
pipeline affiliates not be included in the definition of energy affiliates. To
date the FERC has not acted on these hearing requests. On February 19, 2004,
Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company
filed exemption requests with the FERC. The pipelines seek a limited exemption
from the requirements of Order No. 2004 for the purpose of allowing their
affiliated Hinshaw and intrastate pipelines, which are subject to state
regulation and do not make any off-system sales, to be excluded from the rule's
definition of energy affiliate. We expect the one-time costs of compliance with
the Order, assuming the request to exempt intrastate pipeline affiliates is
granted, to range from $600,000 to $700,000, to be shared between us and KMI.

   On February 11, 2004, the FERC approved a final rule in Docket No. RM03-8-000
requiring jurisdictional entities to file quarterly financial reports with the
FERC. Electric utilities, natural gas companies, and licensees will file Form
3-Q, while oil pipeline companies will submit Form 6-Q. The final rule also
adopts some minimal changes to the annual financial reports filed with the FERC.
The final rule modifies the Notice of Proposed Rulemaking by eliminating the
management discussion and analysis section from both the quarterly and annual
reports, and eliminating the use of fourth quarter data in the annual report. In
addition, the final rule eliminates the cash management notification requirement
adopted in FERC Order No. 634-A. The FERC said it will also use the quarterly
financial information when reviewing the adequacy of traditional cost-based
rates. The first quarterly reports for major public utilities, licensees, and
natural gas companies will be due on July 9, 2004. The first quarterly reports
for non-major public utilities, licensees, natural gas companies, and all oil
pipeline companies will be due on July 23, 2004. After the transition period,
major public utilities, licensees and natural gas companies will file quarterly
reports 60 days after the end of the quarter; non-major public utilities,
licensees, natural gas companies, and all oil pipeline companies will file 70
days after the end of the quarter.

   Cash Management

   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. On June 26, 2003, FERC
issued an interim rule to be effective August 7, 2003, under which regulated
companies are required to document cash management arrangements and
transactions. The interim rule does not include a proposed rule that would have
required regulated companies, as a prerequisite to participation in cash
management programs, to maintain a proprietary capital ratio of 30% and an
investment grade credit rating. On October 22, 2003, the FERC issued its final
rule amending its regulations effective November 2003 which, among other things,
requires FERC-regulated entities to file their cash management agreements with
the FERC and to notify the FERC within 45 days after the end of the quarter when
their proprietary capital ratio drops below 30%, and when it subsequently
returns to or exceeds 30%. KMIGT and Trailblazer filed their cash management
agreements with the FERC on or before the deadline, which was December 10, 2003.
We believe that these matters, as finally adopted, will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.

   Other Regulatory

   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, results of
operations or cash flows.

   Southern Pacific Transportation Company Easements

   SFPP, L.P. 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
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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). In the second quarter
of 2003, the trial court set the rent at approximately $5.0 million per year as
of January 1, 1994. SPTC has appealed the matter to the California Court of
Appeals.


   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, has been
named as a defendant with several others in a series of lawsuits in the United
States District Court in Denver, Colorado and certain state courts in Colorado
and Texas. The plaintiffs include several private royalty, overriding royalty
and working interest owners at the McElmo Dome (Leadville) Unit in southwestern
Colorado. Plaintiffs in the Colorado state court action also are overriding
royalty interest owners in the Doe Canyon Unit. Plaintiffs seek to also
represent classes of claimants composed of all private and governmental royalty,
overriding royalty and working interest owners, and governmental taxing
authorities who have an interest in the carbon dioxide produced at the McElmo
Dome Unit. Plaintiffs claim they and the members of any classes that might be
certified have been damaged because the defendants have maintained a low price
for carbon dioxide in the enhanced oil recovery market in the Permian Basin and
maintained a high cost of pipeline transportation from the McElmo Dome Unit to
the Permian Basin. Plaintiffs claim breaches of contractual and potential
fiduciary duties owed by defendants and also allege other theories of liability
including:

   o common law fraud;

   o fraudulent concealment; and

   o negligent misrepresentation.

   In addition to actual or compensatory damages, certain plaintiffs are seeking
punitive or trebled damages as well as declaratory judgment for various forms of
relief, including the imposition of a constructive trust over the defendants'
interests in the Cortez Pipeline and the Partnership. 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); 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, and
Ainsworth 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. On March 24, 2003, the plaintiffs' counsel in the Shores
matter filed a Petition for Writ of Certiorari in the United States Supreme
Court seeking to have the Court review and overturn the decision of the 10th
Circuit Court of Appeals. On June 9, 2003, the United States Supreme Court
denied the Writ of Certiorari. On July 16, 2003, the settlement in the CO2
Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth cases became
final. 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 of those matters. 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

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on behalf of the County of Zapata, State of Texas and Zapata County Independent
School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in
addition to 15 other defendants, including two other Kinder Morgan affiliates.
Certain entities we acquired in the Kinder Morgan Tejas acquisition are also
defendants in this matter. The Petition alleges that these taxing units relied
on the reported volume and analyzed heating content of natural gas produced from
the wells located within the appropriate taxing jurisdiction in order to
properly assess the value of mineral interests in place. The suit further
alleges that the defendants undermeasured the volume and heating content of that
natural gas produced from privately owned wells in Zapata County, Texas. The
Petition further alleges that the County and School District were deprived of ad
valorem tax revenues as a result of the alleged undermeasurement of the natural
gas by the defendants. On December 15, 2001, the defendants filed motions to
transfer venue on jurisdictional grounds. On June 12, 2003, plaintiff served
discovery requests on certain defendants. On July 11, 2003, defendants moved to
stay any responses to such discovery.

   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. 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 pending. 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 April 10, 2003, the court issued its decision
denying plaintiffs' motion for class certification. On July 8, 2003, a hearing
was held on the motion to amend the complaint. On July 28, 2003, the Court
granted leave to amend the complaint. The amended complaint does not list us or
any of our affiliates as defendants. Additionally, a new complaint was filed and
that complaint does not list us or any of our affiliates as defendants. We will
continue to monitor these matters.

   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

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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 Claims Act. On May 7, 2003, Grynberg
sought leave to file a Third Amended Complaint, which adds allegations of
undermeasurement related to CO2 production. Defendants have filed briefs
opposing leave to amend.

   Mel R. Sweatman and Paz Gas Corporation v. 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 tortious 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 to receive 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 not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.

   The parties have engaged in some discovery and depositions. At this stage of
discovery, we believe that our actions were justified and defensible under
applicable Texas law and that the decision not to renew the underlying gas sales
agreements was made unilaterally by persons acting on behalf of Entex. The
plaintiffs have moved for summary judgment asking the court to declare that a
fiduciary relationship existed for purposes of Sweatman's claims. We have moved
for summary judgment on the grounds that:

   o there is no cause-in-fact of the gas sales nonrenewals attributable to us;
     and

   o the defense of legal justification applies to the claims for tortuous
     interference.

   In September 2003 and then again in November 2003, Sweatman and Paz filed
their third and fourth amended petitions, respectively, asserting all of the
claims for relief described above. In addition, the plaintiffs asked that the
court impose a constructive trust on (i) the proceeds of the sale of Tejas and
(ii) any monies received by any Kinder Morgan entity for sales of gas to any
Entex/Reliant entity following June 30, 2002 that replaced volumes of gas
previously sold under contracts to which Sweatman and Paz had a participating
interest pursuant to the joint venture agreement between Tejas, Sweatman and
Paz. In October 2003, the court granted, and then rescinded its order after a
motion to reconsider heard on February 13, 2004, a motion for partial summary
judgment on the issue of the existence of a fiduciary duty. We believe this suit
is without merit and we intend to defend the case 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

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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."

   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"); Frankie Sue Galaz, et al v. United States
of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation,;
Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las
Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan
Services LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial
District Court, State of Nevada, County of Washoe) ("Galaz II); Frankie Sue
Galaz, et al v. The United States of America, the City of Fallon, Exxon Mobil
Corporation,; Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc.,
Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D",
Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC
(United States District Court, District of Nevada)("Galaz III)

   On July 9, 2002, we were served with a purported Complaint for Class Action
in the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the 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.

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   On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz I matter asserting the same claims in the same Court on
behalf of the same purported class against virtually the same defendants,
including us. On February 10, 2003, the defendants filed Motions to Dismiss the
Galaz I Complaint on the grounds that it also fails to state a claim upon which
relief can be granted. This motion to dismiss was granted as to all defendants
on April 3, 2003. Plaintiffs have filed a Notice of Appeal to the United States
Court of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit
dismissed the appeal, upholding the District Court's dismissal of the case.

   On June 20, 2003, plaintiffs filed an additional Complaint for Class Action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the
Galaz II Complaint along with a Motion for Sanctions. On October 4, 2003,
plaintiffs' counsel agreed in writing to dismiss the Galaz II matter, but has
since withdrawn his agreement without explanation. The Kinder Morgan defendants'
Motion to Dismiss and Motion for Sanctions are currently pending.

   Also on June 20, 2003, the plaintiffs in the Galaz matters filed yet another
Complaint for Class Action in the United States District Court for the District
of Nevada (the "Galaz III" matter) asserting the same claims in United States
District Court for the District of Nevada on behalf of the same purported class
against virtually the same defendants, including us. The Kinder Morgan
defendants filed a Motion to Dismiss the Galaz III matter on August 15, 2003. On
October 3, 2003, the plaintiffs filed a Motion for Withdrawal of Class Action,
which voluntarily drops the class action allegations from the matter and seeks
to have the case proceed on behalf of the Galaz family only. On December 5,
2003, the District Court granted the Kinder Morgan defendants' Motion to
Dismiss, but granted plaintiff leave to file a second Amended Complaint.
Plaintiff filed a Second Amended Complaint on December 13, 2003, and a Third
Amended Complaint on January 5, 2004. The Kinder Morgan defendants filed a
Motion to Dismiss the Third Amended Complaint on January 13, 2003, which Motion
is currently pending.

   Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482
(Second Judicial District Court, State of Nevada, County of Washoe) ("Jernee").

   On May 30, 2003, a separate group of plaintiffs, individually and on behalf
of Adam Jernee, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia
that, in turn, is believed to be due to exposure to industrial chemicals and
toxins." Plaintiffs purport to assert claims for wrongful death, premises
liability, negligence, negligence per se, intentional infliction of emotional
distress, negligent infliction of emotional distress, assault and battery,
nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified
special, general and punitive damages. The Kinder Morgan defendants filed
Motions to Dismiss the complaint on November 20, 2003, which Motions are
currently pending.

   Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").

   On August 28, 2003, a separate group of plaintiffs, represented by the
counsel for the plaintiffs in the Jernee matter, individually and on behalf of
Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court
against us and several Kinder Morgan related entities and individuals and
additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim
that defendants negligently and intentionally failed to inspect, repair and
replace unidentified segments of their pipeline and facilities, allowing
"harmful substances and emissions and gases" to damage "the environment and
health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death
was caused by leukemia that, in turn, is believed to be due to exposure to
industrial chemicals and toxins. Plaintiffs purport to assert claims for
wrongful death, premises liability, negligence, negligence per se, intentional
infliction of emotional distress, negligent infliction of emotional distress,
assault and battery, nuisance, fraud, strict liability, and aiding and abetting,
and seek unspecified special, general and punitive damages. The Kinder Morgan
defendants

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were served with the Complaint on January 10, 2004, and are planning to file a
Motion to Dismiss on February 26, 2004.

   Based on the information available to date, our own preliminary
investigation, and the positive results of investigations conducted by State and
Federal agencies, we believe that the claims against us in the Snyder matter,
the three Galaz matters, the Jernee matter and the Sands matter are without
merit and intend to defend against them vigorously.

   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.

   A settlement has been reached between most of the plaintiffs and Plantation.
It is anticipated that all of the proceedings to complete the settlement will be
completed by the end of the first quarter of 2004. We believe that the ultimate
resolution of these Marion County, Mississippi cases will not have a material
effect on our business, financial position, results of operations or cash flows.

   Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals,
Inc. and ST Services, Inc.

   On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the
Superior Court of New Jersey, Gloucester County. We filed our answer to the
Complaint on June 27, 2003, in which we denied ExxonMobil's claims and
allegations as well as included counterclaims against ExxonMobil. The lawsuit
relates to environmental remediation obligations at a Paulsboro, New Jersey
liquids terminal owned by ExxonMobil from the mid-1950s through November 1989,
by GATX Terminals Corp. from 1989 through September 2000, and owned currently by
ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil
performed an environmental site assessment of the terminal required prior to
sale pursuant to state law. During the site assessment, ExxonMobil discovered
items that required remediation and the New Jersey Department of Environmental
Protection issued an order that required ExxonMobil to perform various
remediation activities to remove hydrocarbon contamination at the terminal.
ExxonMobil, we understand, is still remediating the site and has not been
removed as a responsible party from the state's cleanup order; however,
ExxonMobil claims that the remediation continues because of GATX Terminals'
storage of a fuel additive, MTBE, at the terminal during GATX Terminals'
ownership of the terminal. When GATX Terminals sold the terminal to ST Services,
the parties indemnified one another for certain environmental matters. When GATX
Terminals was sold to us, GATX Terminals' indemnification obligations, if any,
to ST Services may have passed to us. Consequently, at issue is any
indemnification obligations we may owe to ST Services in respect to
environmental remediation of MTBE at the terminal. The Complaint seeks any and
all damages related to remediating MTBE at the terminal, and, according to the
New Jersey Spill Compensation and Control Act, treble damages may be available
for actual dollars incorrectly spent by the successful party in the lawsuit for
remediating MTBE at the terminal.  The parties are currently involved in
discovery.

   Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in
interest for Enron Helium Company, a division of Enron Corp., Enron Liquids
Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder
Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th
Judicial District Court, Harris County, Texas)

   On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron
Helium Company. Plaintiff added Enron Corp. as party in interest for Enron
Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a
Defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a Gas Processing Agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at

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the Bushton Plant, a natural gas processing facility located in Kansas.
Plaintiff also asserts claims relating to the Helium Extraction Agreement
entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil
Corporation dated March 14, 1988. Plaintiff alleges that Defendants failed to
deliver propane and to allocate plant products to Plaintiff as required by the
Gas Processing Agreement and originally sought damages of approximately $5.9
million.

   Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third
Amended Petition, Plaintiff alleges claims for breach of the Gas Processing
Agreement and the Helium Extraction Agreement, requests a declaratory judgment
and asserts claims for fraud by silence/bad faith, fraudulent inducement of the
1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach
of a duty of good faith and fair dealing, negligent misrepresentation and
conversion. As of April 7, 2003, Plaintiff alleged economic damages for the
period November 1987 through March 1997 in the amount of $30.7 million. On May
2, 2003, Plaintiff added claims for the period April 1997 through February 2003
in the amount of $12.9 million. On June 23, 2003, plaintiff filed a Fourth
Amended Petition that reduced its total claim for economic damages to $30.0
million. On October 5, 2003, plaintiff filed a Fifth Amended Petition that
purported to add a cause of action for embezzlement. On February 10, 2004,
plaintiff filed its Eleventh Supplemental Responses to Requests for Disclosure
that restated its alleged economic damages for the period of November 1987
through December 2003 as approximately $37.4 million. The parties have completed
discovery and the matter is scheduled for trial on April 26, 2004. Based on the
information available to date in our investigation, the Kinder Morgan Defendants
believe that the claims against them 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
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.

   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,
terminal and carbon dioxide field and oil field operations, and there can be no
assurance that we will not incur significant costs and liabilities. Moreover, it
is possible that other developments, such as increasingly stringent
environmental laws, regulations and enforcement policies thereunder, and claims
for damages to property or persons resulting from our operations, could result
in substantial costs and liabilities to us.

   We are currently involved in 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;

   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.

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   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, results of operations or
cash flows. As of December 31, 2003, we have recorded a total reserve for
environmental claims in the amount of $39.6 million. However, 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, results of
operations or cash flows.


17.  New Accounting Pronouncements

   FIN 46 (revised December 2003)

   In December 2003, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 46 (revised December 2003), "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, which have one or more of the
following characteristics:

   o the equity investment at risk is not sufficient to permit the entity to
     finance its activities without additional subordinated financial support
     provided by any parties, including the equity holders;

   o the equity investors lack one or more of the following essential
     characteristics of a controlling financial interest:

     o the direct or indirect ability to make decisions about the entity's
       activities thorough voting rights or similar rights;

     o the obligation to absorb the expected losses of the entity; and

     o the right to receive the expected residual returns of the entity; and

   o the equity investors have voting rights that are not proportionate to their
     economic interests, and the activities of the entity involve or are
     conducted on behalf of an investor with a disproportionately small voting
     interest.

   The objective of this Interpretation is not to restrict the use of variable
interest entities but to improve financial reporting by enterprises involved
with variable interest entities. The FASB believe that if a business enterprise
has a controlling financial interest in a variable interest entity, the assets,
liabilities, and results of the activities of the variable interest entity
should be included in consolidated financial statements with those of the
business enterprise.

   This Interpretation explains how to identify variable interest entities and
how an enterprise assesses its interests in a variable interest entity to decide
whether to consolidate that entity. It requires existing unconsolidated variable
interest entities to be consolidated by their primary beneficiaries if the
entities do not effectively disperse risks

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among parties involved. Variable interest entities that effectively disperse
risks will not be consolidated unless a single party holds an interest or
combination of interests that effectively recombines risks that were previously
dispersed.

   An enterprise that consolidates a variable interest entity is the primary
beneficiary of the variable interest entity. The primary beneficiary of a
variable interest entity is the party that absorbs a majority of the entity's
expected losses, receives a majority of its expected residual returns, or both,
as a result of holding variable interests, which are the ownership, contractual,
or other monetary interests in an entity that change with changes in the fair
value of the entity's net assets excluding variable interests. The primary
beneficiary of a variable interest entity is required to disclose:

   o the nature, purpose, size and activities of the variable interest entity;

   o the carrying amount and classification of consolidated assets that are
     collateral for the variable interest entity's obligations; and

   o any lack of recourse by creditors (or beneficial interest holders) of a
     consolidated variable interest entity to the general credit of the primary
     beneficiary.

   In addition, an enterprise that holds significant variable interests in a
variable interest entity but is not the primary beneficiary is required to
disclose:

   o the nature, purpose, size and activities of the variable interest entity;

   o its exposure to loss as a result of the variable interest holder's
     involvement with the entity; and

   o the nature of its involvement with the entity and date when the involvement
     began

   Application of this Interpretation is required in financial statements of
public entities that have interests in variable interest entities or potential
variable interest entities commonly referred to as special-purpose entities for
periods ending after December 15, 2003. Application by public entities (other
than small business issuers) for all other types of entities is required in
financial statements for periods ending after March 15, 2004. We continue to
evaluate the effect from the adoption of this Statement on our consolidated
financial statements.

   SFAS No. 132 (revised 2003)

   In December 2003, the Financial Accounting Standards Board issued SFAS No.
132 (revised 2003), "Employers' Disclosures about Pensions and Other
Postretirement Benefits." The Statement revises and improves employers'
financial statement disclosures about defined benefit pension plans and other
postretirement benefit plans. The Statement does not change the measurement or
recognition of those plans and retains the disclosures required by the original
SFAS No. 132, which standardized the disclosure requirements for pensions and
other postretirement benefits to the extent practicable and required additional
information on changes in the benefit obligations and fair values of plans
assets.

   The revised Statement requires additional disclosures to those in the
original SFAS No. 132 about the assets, obligations, cash flows, and net
periodic benefit cost of defined benefit pension plans and other defined benefit
postretirement plans. The additional disclosures have been added in response to
concerns expressed by users of financial statements; those disclosures include
information describing the types of plan assets, investment strategy,
measurement date(s), plan obligations, cash flows, and components of net
periodic benefit cost recognized during annual and interim periods.

   Specifically, the additional requirements improve disclosures of relevant
accounting information by providing more information about the plan assets
available to finance benefit payments, the obligations to pay benefits, and an
entity's obligation to fund the plan, thus improving the information's
predictive value. Due to certain similarities between defined benefit pension
arrangements and arrangements for other postretirement benefits, the revised
Statement requires similar disclosures about postretirement benefits other than
pensions.

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   Some of the required disclosures include the following:

   o plan assets by category (i.e., debt, equity, real estate);
   o investment policies and strategies;

   o target allocation percentages or target ranges for plan asset categories;

   o projections of future benefit payments;

   o estimates of future contributions to fund pension and other postretirement
     benefit plans; and

   o interim disclosures of items such as (1) net periodic benefit cost
     recognized during the period, including service cost, interest cost,
     expected return on plan assets, prior service cost, and gain/loss due to
     settlement or curtailment and (2) employer contributions paid and expected
     to be paid, if significantly revised from the amounts previously disclosed.

   This revised statement is effective for financial statements with fiscal
years ending after December 15, 2003. The interim period disclosures required by
this Statement are effective for interim periods beginning after December 15,
2003. Disclosure of estimated future benefit payments required by portions of
this revised Statement is effective for fiscal years ending after June 15, 2004.
The disclosures for earlier annual periods presented for comparative purposes
should be restated for:

   o the percentages of each major category of plan assets held;

   o the accumulated benefit obligation; and

   o the assumptions used in the accounting for the plans.

   However, if obtaining this information relating to earlier periods in not
practicable, the notes to the financial statements should include all available
information and identify the information not available. We do not expect the
adoption of this Statement to have any immediate effect on our consolidated
financial statements.

   SFAS No. 149

   In April 2003, the Financial Accounting Standards Board issued SFAS No. 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging Activities."
This Statement amends and clarifies accounting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133.

   The new guidance amends SFAS No. 133 for decisions made:

   o as part of the Derivatives Implementation Group process that effectively
     required amendments to SFAS No. 133;

   o in connection with other Board projects dealing with financial instruments;
     and

   o regarding implementation issues raised in relation to the application of
     the definition of a derivative, particularly regarding the meaning of an
     "underlying" and the characteristics of a derivative that contains
     financing components.

   The amendments set forth in SFAS No. 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, this Statement clarifies under what
circumstances a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133. In addition, it
clarifies when a derivative contains a financing component that warrants special

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reporting in the statement of cash flows. SFAS No. 149 amends certain other
existing pronouncements. These changes are intended to result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting.

   This Statement is effective for contracts entered into or modified after June
30, 2003, except as stated below and for hedging relationships designated after
June 30, 2003. We will apply this guidance prospectively. We do not expect the
adoption of this Statement to have any immediate effect on our consolidated
financial statements.

   We will continue to apply the provisions of this Statement that relate to
SFAS No. 133 Implementation Issues that have been effective for fiscal quarters
that began prior to June 15, 2003, in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when-issued" securities or other securities that do not yet exist, will be
applied to existing contracts as well as new contracts entered into after June
30, 2003.

   SFAS No. 150

   In May 2003, the Financial Accounting Standards Board issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This Statement establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as equity.

   SFAS No. 150 requires an issuer to classify the following instruments as
liabilities (or assets in some circumstances):

   o a financial instrument issued in the form of shares that is mandatorily
     redeemable - that embodies an unconditional obligation requiring the issuer
     to redeem it by transferring its assets at a specified or determinable date
     (or dates) or upon an event that is certain to occur;

   o a financial instrument, other than an outstanding share, that, at
     inception, embodies an obligation to repurchase the issuer's equity shares,
     or is indexed to such an obligation, and that requires or may require the
     issuer to settle the obligation by transferring assets (for example, a
     forward purchase contract or written put option on the issuer's equity
     shares that is to be physically settled or net cash settled); and

   o a financial instrument that embodies an unconditional obligation, or a
     financial instrument other than an outstanding share that embodies a
     conditional obligation, that the issuer must or may settle by issuing a
     variable number of its equity shares, if, at inception, the monetary value
     of the obligation is based solely or predominantly on any of the following:

     o  a fixed monetary amount known at inception, for example, a payable
        settleable with a variable number of the issuer's equity shares;

     o  variations in something other than the fair value of the issuer's equity
        shares, for example, a financial instrument indexed to the Standard &
        Poor 500 and settleable with a variable number of the issuer's equity
        shares; or

     o  variations inversely related to changes in the fair value of the
        issuer's equity shares, for example, a written put option that could be
        net share settled.

   The requirements of this Statement apply to issuers' classification and
measurement of freestanding financial instruments, including those that comprise
more than one option or forward contract. This Statement does not apply to
features that are embedded in a financial instrument that is not a derivative in
its entirety. It also does not affect the classification or measurement of
convertible bonds, puttable stock, or other outstanding shares that are
conditionally redeemable. This Statement also does not address certain financial
instruments indexed partly to the issuer's equity shares and partly, but not
predominantly, to something else.


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   This Statement is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003, except for mandatorily
redeemable financial instruments of nonpublic entities. It is to be implemented
by reporting the cumulative effect of a change in accounting principle for
financial instruments created before the issuance date of the Statement and
still existing at the beginning of the interim period of adoption. Restatement
is not permitted. We will apply this guidance prospectively. We do not expect
the adoption of this Statement to have any immediate effect on our consolidated
financial statements.

   SAB No. 104

   On December 17, 2003, the staff of the Securities and Exchange Commission
issued Staff Accounting Bulletin No. 104, "Revenue Recognition," which
supersedes SAB No. 101, "Revenue Recognition in Financial Statements." SAB No.
104's primary purpose is to rescind the accounting guidance contained in SAB No.
101 related to multiple-element revenue arrangements that was superseded as a
result of the issuance of Emerging Issues Task Force Issues No. 00-21,
"Accounting for Revenue Arrangements with Multiple Deliverables." Additionally,
SAB No. 104 rescinds the SEC's related "Revenue Recognition in Financial
Statements Frequently Asked Questions and Answers" issued with SAB No. 101 that
had been codified in SEC Topic 13, "Revenue Recognition." While the wording of
SAB No. 104 has changed to reflect the issuance of EITF No. 00-21, the revenue
recognition principles of SAB No. 101 remain largely unchanged by the issuance
of SAB No. 104, which was effective upon issuance. The adoption of SAB No. 104
did not have a material effect on our financial position or results of
operations.

   Other

   In October 2003, the FASB voted to begin in 2005 requiring companies to
charge stock option costs against earnings. The new standard would mandate
expensing stock option awards just like any other form of compensation. A final
rule is expected to be formally issued in the second half of 2004. Besides the
effective date of the new rule, the FASB also decided to require companies to
use one method for making a transition toward expensing options. The transition
method decided on calls for companies to expense all at once previously granted
options as well as options issued in the year companies make the accounting
switch. In the proposed standard, companies would have the option to restate
prior results to reflect option expense. A reason for restatement would be a
company's desire for a fair year-to-year earnings comparison. If a company
chooses not to restate, it would have to recognize the cost of previously issued
but unvested options in 2005. At the current time, the FASB has not decided on
specific disclosure requirements.


18.  Subsequent Events

   On February 3, 2004, we announced that we had priced the public offering of
an additional 5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We also granted to the underwriters an
option to purchase up to 795,000 additional common units to cover
over-allotments. On February 9, 2004, 5,300,000 common units were issued. We
received net proceeds of $237.8 million for the issuance of these common units
and we used the proceeds to reduce the borrowings under our commercial paper
program.

   On February 4, 2004, we announced that we had reached an agreement with Exxon
Mobil Corporation to purchase seven refined petroleum products terminals in the
southeastern United States. The terminals are located in Collins, Mississippi,
Knoxville, Tennessee, Charlotte and Greensboro North Carolina, and Richmond,
Roanoke and Newington, Virginia. Combined, the terminals have a total storage
capacity of approximately 3.2 million barrels for gasoline, diesel fuel and jet
fuel. As part of the transaction, Exxon Mobil has entered into a long-term
contract to store products in the terminals. The acquisition enhances our
terminal operations in the Southeast and complements our December 2003
acquisition of seven products terminals from ConocoPhillips Company and Phillips
Pipe Line Company. The acquired operations will be included as part of our
Products Pipelines business segment.

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