KINDER MORGAN INC - 10-K Annual Report

For the transition period from _____to_____

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

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

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

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 [ ]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our discussion and analysis of financial condition and operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. The reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.

In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for our natural gas distribution deliveries for which meters have not yet been read, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others.

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

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

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

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. These estimates are affected by the choice of remediation methods as well as the expected timing and length of the effort. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.

We are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments

or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

proceedings challenging the rates on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face future challenges to the rates we receive for services on our pipeline systems.

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

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

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

The majority of TransColorado's system is subject to rate regulation under the jurisdiction of the Federal Energy Regulatory Commission. Currently, there are no material proceedings challenging the rates on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. TransColorado Pipeline is also subject to market variability in natural gas prices and basis differentials. Please refer to the discussion of basis differentials under the heading "Natural Gas Pipeline Company of America" in this Item.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, "Statement 133." Statement 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. Statement 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, Statement 133 allows a derivative's

gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.

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

We enter into these transactions only with counterparties whose debt securities are rated investment grade by the major rating agencies. In general, the risk of default by these counterparties is low. During the fourth quarter of 2001, however, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under Statement 133. Upon making that determination, we (i) ceased to account for those derivatives as hedges, (ii) entered into new derivative transactions with other counterparties to replace our position with Enron, (iii) designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions and (iv) recognized a $5.0 million pre-tax loss (included with "General and Administrative Expenses" in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002. The interpretive guidance incorporated from Interpretation No. 34 continues to be required for financial statements for fiscal years ending after June 15, 1981. For more information, see heading titled "Liquidity and Capital Resources" preceding and Note 18 of the accompanying Notes to Consolidated Financial Statements.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

The caption "Accounts Receivable, Net" in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts. Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. An allowance for doubtful accounts is charged to expense monthly, generally using a percentage of revenue or receivables, based on a historical analysis of uncollected amounts, adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. In support of credit extended to certain customers, we had received prepayments of $13.5 million at December 31, 2002, included with other current liabilities in the accompanying Consolidated Balance Sheet. The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2002, 2001 and 2000.

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

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

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

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

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

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:

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas and associated transportation. Prior to December 31, 2000, our accounting policy for these activities was based on a number of authoritative pronouncements including SFAS No. 80, Accounting for Futures Contracts. This policy is described in detail in Note 15, as is our present policy, which is based on SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which became effective for us on January 1, 2001.

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

On April 5, 2002, the D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C. Circuit did remand the FERC's decision to impose a 5-year cap on bids the existing shipper would have to match in the right of first refusal process. The D.C. Circuit also remanded the FERC's decision to

allow forward-hauls and backhauls to the same point. Finally, the D.C. Circuit held that several aspects of the FERC's segmentation policy and its policy on discounting at alternate points were not ripe for review. Numerous parties, including Natural Gas Pipeline Company of America, have filed comments on the remanded issues.

On October 31, 2002, the FERC issued an order in response to the D.C. Circuit's remand of certain Order 637 issues. The order: (i) eliminated the requirement of a 5-year cap on bid terms that an existing shipper would have to match in the right of first refusal process, and found that no term matching cap at all is necessary given existing regulatory controls; (ii) affirmed the FERC's policy that a segmented transaction consisting of both a forward-haul up to contract demand and a backhaul up to contract demand to the same point is permissible, and accordingly required, under Section 5 of the Natural Gas Act, pipelines that the FERC had previously found must permit segmentation on their systems to file tariff revisions within 30 days to permit such segmented forward-haul and backhaul transactions to the same point.

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

The FERC, in a Notice of Proposed Rulemaking in RM02-14-000, has proposed new regulation of cash management practices, including establishing limits on the amount of funds that can be swept from a regulated subsidiary to a non-regulated parent company. Natural Gas Pipeline Company of America filed comments on August 28, 2002. All parties are awaiting further action by the FERC.

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

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

Currently, there are no material proceedings challenging the base rates on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable statutes and regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. In addition, since many of our assets are subject to regulation, we are subject to potential future changes in

applicable rules and regulations that may have an adverse effect on our business, financial position or results of operations.

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

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

United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claim Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The MDL case is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293.

Motions to Dismiss were filed and an oral argument on the Motion to Dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases (referred to as valuation claims). Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The United States' Motion to Dismiss most of Plaintiff's valuation claims has been granted by the Court. Mr. Grynberg has appealed that dismissal to the 10th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Discovery is now underway to determine issues related to the Court's subject matter jurisdiction, arising out of the False Claim Act.

Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company et al. v. Gas Pipelines, et al.), Stevens County, Kansas District Court, Case No. 99 C 30. In May 1999, three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a purported nationwide class action in the Stevens County, Kansas District Court against some 250 natural gas pipelines and many of their affiliates. The Petition (recently amended) alleges a conspiracy to underpay royalties, taxes and producer payments by the defendants' undermeasurement of the volume and heating content of natural gas produced from nonfederal lands for more than 25 years. The named plaintiffs purport to adequately represent the interests of unnamed plaintiffs in this action who are comprised of the nation's gas producers, state taxing agencies and royalty, working and overriding interest owners. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees from the defendants, jointly and severally. This action was originally filed on May 28, 1999 in Kansas State Court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. Subsequently, one of the defendants removed the action to Kansas Federal District Court and the case was styled as Quinque Operating Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the District of Kansas. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act cases referred to above, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. The Court in Kansas has issued a case management order addressing the initial phasing of the case. In this initial phase, the court will rule on motions to dismiss (jurisdiction and sufficiency of pleadings), and if the action is not dismissed, on class certification. Merits discovery has been stayed. The defendants filed a motion to dismiss on grounds other than personal jurisdiction, which was denied by the Court in August 2002. The Motion to Dismiss for lack of Personal Jurisdiction of the nonresident defendants has been briefed and is awaiting decision. The Court has pending the Plaintiffs' Motion to certify the class. Merits discovery has been stayed. The current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the action as a named plaintiff. On January 13, 2003, a motion to certify the class was argued. A decision on this motion is pending.

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

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

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

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

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

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

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

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

In addition, we are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position or results of operations.

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

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

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

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

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

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

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

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

	Year Ended December 31,
	2002	2001	2000

Federal Income Tax Rate	35.0%	35.0%	35.0%
Increase (Decrease) as a Result of:
State Income Tax, Net of Federal Benefit	3.0%	5.7%	5.6%
Kinder Morgan Management minority interest	2.8%	1.4%	-
Deferred Tax Rate Change	(4.9%)	-	-
Prior Year Adjustments	(1.9%)	-	-
Resolution of Internal Revenue Service Audit	(2.0%)	-	-
Other	(1.5%)	(0.7%)	(0.6%)
Effective Tax Rate	30.5%	41.4%	40.0%
	=====	=====	=====

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, "Statement 133." Statement 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The accompanying Consolidated Balance Sheet as of December 31, 2002, includes, exclusive of amounts related to interest rate swaps as

discussed below, balances of approximately $9.6 million, $41 thousand, $36.9 million and $1.2 million in the captions "Current Assets: Other," "Deferred Charges and Other Assets," "Current Liabilities: Other," and "Other Liabilities and Deferred Credits: Other" respectively, related to these derivative financial instruments. Statement 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, Statement 133 allows a derivative's gains and losses to offset related results from the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.

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

During the fourth quarter of 2001, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under Statement 133. Upon making that determination, we (i) ceased to account for those derivatives as hedges, (ii) entered into new derivative transactions with other counterparties to replace our position with Enron, (iii) designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions and (iv) recognized a $5.0 million pre-tax loss (included with "General and Administrative Expenses" in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

	December 31,
	2002	2001
	(In thousands)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This Statement contains disclosure requirements that provide descriptions of asset retirement obligations and reconciliations of changes in the components of those obligations. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Earlier applications are encouraged. We have a number of assets with associated retirement obligations that are subject to the provisions of this statement. With respect to the Natural Gas Pipeline Company of America system, we have certain surface facilities that are required to be dismantled and removed, with certain site reclamation to be performed. While, in general, our right-of-way agreements do not require us to remove pipe or otherwise perform remediation upon taking the pipeline permanently out of service, some right-of-way agreements do provide for these actions. With respect to our Retail Distribution, we generally are not obligated to remove our equipment or otherwise perform remediation related to our utility assets. We do have an obligation to perform removal and remediation activities associated with certain wells utilized in conjunction with our storage facilities and otherwise. With respect to Power, we generally are not obligated to perform removal or remediation activities associated with our owned power facilities and any such obligations associated with the power facilities we do not own are the responsibility of others. We expect that we will be unable to reasonably estimate and record liabilities for the majority of our obligations that fall under the provisions of this statement because we cannot reasonably estimate when such obligations will be settled.

In November 2002, the FASB issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. This interpretation incorporates, without change, the guidance in FASB Interpretation No. 34, Disclosure of Indirect Guarantees of Indebtedness of Others, which is being superceded. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002. The interpretive guidance incorporated from Interpretation No. 34 continues to be required for financial statements for fiscal years ending after June 15, 1981. For more information, see Note 18.

SELECTED QUARTERLY FINANCIAL DATA

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

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

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

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

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

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

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

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

Exhibit Number		Description

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

Exhibit Number		Description

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

Exhibit Number		Description

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

Exhibit Number		Description

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

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.

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

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

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

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

	PART II

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

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

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

Signatures			114
Certifications			115-116

	Market Price Per Share Data
	2002		2001
	Low	High	Low	High
Quarter Ended:
March 31	$36.810	$57.500	$42.875	$60.000
June 30	$37.110	$52.620	$50.250	$59.970
September 30	$33.100	$44.020	$46.220	$57.570
December 31	$30.050	$42.980	$46.950	$57.130

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

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


	Dividends Paid Per Share
	2002	2001
Quarter Ended:
March 31	$0.05	$0.05
June 30	$0.05	$0.05
September 30	$0.10	$0.05
December 31	$0.10	$0.05

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

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

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

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

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

Business Segment	Business Conducted	Referred to As:

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

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

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

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


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

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

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

Horizon Pipeline
Company	17.8	50.0%	90.9	49.5²	-		-

Igasamex	5.9	21.0%	16.3	5.3	-		1.1

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

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


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

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

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

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

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

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

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

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

	Page

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

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

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

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

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

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

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


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


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

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



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

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

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


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

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

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

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

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

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



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

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

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

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



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

Year			Commitment
			(In thousands)

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