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For the transition period from _____to_____

Commission File Number 1-6446

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 o

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

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

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

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

We are one of the largest energy storage and transportation companies in the United States, operating, either for ourselves or on behalf of Kinder Morgan Energy Partners, L.P. ("Kinder Morgan Energy Partners"), over 35,000 miles of natural gas and petroleum products pipelines and approximately 80 terminals. We own and operate (i) Natural Gas Pipeline Company of America, a major interstate natural gas pipeline system with approximately 9,900 miles of pipelines and associated storage facilities and (ii) TransColorado Gas Transmission Company, a 300-mile interstate natural gas pipeline in western Colorado and northwest New Mexico. We own interests in and operate a retail natural gas distribution business serving approximately 241,000 customers in Colorado, Nebraska and Wyoming. We have constructed, currently operate and own interests in certain natural gas-fired electric generation facilities. These businesses are discussed in detail in the next section of this report. Our common stock is traded on the New York Stock Exchange under the symbol "KMI." Our executive offices are located at 500 Dallas Street, Suite 1000, Houston Texas 77002 and our telephone number is (713) 369-9000.

On October 7, 1999, we completed the acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and the sole stockholder of the general partner of Kinder Morgan Energy Partners. To effect that acquisition, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan (Delaware). Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan (Delaware), was named our Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. As a result of that acquisition and certain subsequent transactions, we own the general partner of, and have a significant limited partner interest in, Kinder Morgan Energy Partners, the largest publicly traded pipeline limited partnership in the United States in terms of market capitalization and the owner and operator of the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Kinder Morgan Energy Partners owns and/or operates a diverse group of assets used in the transportation, storage and processing of energy products, including refined petroleum products pipeline systems with more than 10,000 miles of products pipeline and 39 associated terminals. Kinder Morgan Energy Partners owns over 15,000 miles of natural gas transportation pipelines, plus natural gas gathering and storage facilities. Kinder Morgan Energy Partners also owns or operates approximately 52 liquid and bulk terminal facilities and approximately 57 rail transloading facilities located throughout the United States, handling nearly 60 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 55 million barrels for refined petroleum products, chemicals and other liquid products. In addition, Kinder Morgan Energy Partners owns Kinder Morgan CO₂ Company, L.P., which has over 1,100 miles of pipelines and transports, markets and produces carbon dioxide for use in enhanced oil recovery operations and owns interests in and/or operates six oil fields in West Texas, all of which are using or have used carbon dioxide injection

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

In May 2001, Kinder Morgan Management, LLC ("Kinder Morgan Management"), one of our indirect subsidiaries, issued and sold its limited liability shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the i-units, Kinder Morgan Management became a limited partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners' general partner the responsibility to manage and control the business and affairs of Kinder Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests that have been, and will be, issued only to Kinder Morgan Management. We have certain rights and obligations with respect to these securities. In addition, during 2001, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $11.7 million.

In the initial public offering, we purchased ten percent of the Kinder Morgan Management shares, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which is consolidated in our financial statements) purchased by the public created minority interest on our balance sheet of $892.7 million at the time of the transaction. The earnings recorded by Kinder Morgan Management that are attributable to its shares held by the public are reported as "minority interest" in our Consolidated Statements of Operations. On August 6, 2002, Kinder Morgan Management closed the issuance and sale of 12,478,900 limited liability shares in an underwritten public offering. The net proceeds of approximately $328.6 million from the offering were used by Kinder Morgan Management to buy additional i-units from Kinder Morgan Energy Partners. We did not purchase any of the offered shares. In addition, during 2003 and 2002, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $1.8 million and $3.4 million, respectively. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management's 2003 Annual Report on Form 10-K.

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

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

We expect to benefit from accretive acquisitions (primarily by Kinder Morgan Energy Partners) and business expansions. Kinder Morgan Energy Partners has a multi-year history of making accretive acquisitions, which benefit us through our limited and general partner interests. This acquisition strategy

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is expected to continue, with the availability of potential acquisition candidates being driven by consolidation in the energy industry, as well as realignment of asset portfolios by major energy companies, although we can provide no assurance that such acquisitions will occur in the future. In addition, we expect to expand, within strict guidelines as to risk, rate of return and timing of cash flows, both Natural Gas Pipeline Company of America's and TransColorado's pipeline systems and acquire natural gas retail distribution properties that fit well with our current profile. In addition, we and Kinder Morgan Energy Partners have announced that we are considering the transfer of TransColorado to Kinder Morgan Energy Partners for fair market value, subject to various factors, including obtaining fairness opinions with respect to any such transaction for both us and Kinder Morgan Energy Partners.

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

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Note 19 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 certain affiliates, referred to as Natural Gas Pipeline Company of America, a major interstate natural gas pipeline and storage system, (2) TransColorado Gas Transmission Company, referred to as TransColorado, an interstate natural gas pipeline located in western Colorado and northwest New Mexico, in which we increased our ownership interest from 50 percent to 100 percent effective October 1, 2002, (3) Kinder Morgan Retail, the regulated sale of natural gas to residential, commercial and industrial customers and the sales of natural gas to certain utility customers under our Choice Gas Program, a program that allows utility customers to choose their natural gas provider and (4) Power, the operation (and, in previous periods, construction) of natural gas-fired electric generation facilities.

Natural gas transportation, storage and retail sales accounted for approximately 95%, 93% and 90% of our consolidated revenues in 2003, 2002 and 2001, respectively. During 2003, 2002 and 2001, we did not have revenues from any single customer that exceeded 10 percent of our consolidated operating revenues. The operations of Kinder Morgan Energy Partners, a significant limited partnership equity-method investee in which we also hold the general partner interest, include (i) liquids and refined petroleum products pipelines, (ii) transportation and storage of natural gas, (iii) carbon dioxide production and transportation, production of oil and (iv) bulk and liquids terminals. Our equity in the earnings of Kinder Morgan Energy Partners (net of the associated amortization in periods prior to January 1, 2002) constituted approximately 60%, 65% and 40% of our income from continuing operations before interest and income taxes in 2003, 2002 and 2001, respectively. The following table gives our segment earnings, our earnings attributable to our investment in Kinder Morgan Energy Partners and the percent of the combined total each represents, for each of the last two years. In 1999, we discontinued our wholesale natural gas marketing, non-energy retail marketing services and natural gas gathering and processing businesses. Notes 5 and 19 of the accompanying Notes to Consolidated Financial Statements contain additional information on asset sales and our business segments. As discussed following, certain of our operations are regulated by various federal and state entities.

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During 2003, Natural Gas Pipeline Company of America's segment earnings of $372.0 million represented approximately 42% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and approximately 48% of our income from continuing operations before interest and income taxes. Through Natural Gas Pipeline Company of America, we own and operate approximately 9,900 miles of interstate natural gas pipelines, storage fields, field system lines and related facilities, consisting primarily of two major interconnected natural gas transmission pipelines terminating in the Chicago metropolitan area. The system is powered by 57 compressor stations in mainline and storage service having an aggregate of approximately 0.9 million horsepower. Natural Gas Pipeline Company of America's system has over 1,700 points of interconnection with 34 interstate pipelines, 19 intrastate pipelines, a number of gathering systems, and over 60 local distribution companies and other end users, thereby providing significant flexibility in the receipt and delivery of natural gas. Natural Gas Pipeline Company of America's Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 4,400 miles of mainline and various small-diameter pipelines. The other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,700 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by Natural Gas Pipeline Company of America's approximately 800-mile Amarillo/Gulf Coast pipeline. In addition, Natural Gas Pipeline Company of America owns a 50% equity interest in and operates Horizon Pipeline Company, L.L.C., a joint venture with Nicor-Horizon, a subsidiary of Nicor, Inc. This joint venture owns a natural gas pipeline in northern Illinois with a capacity of 380 MMcf per day.

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

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Company of America collects higher transportation commodity revenue, higher interruptible transportation revenue, winter-only capacity revenue and higher rates on certain contracts.

Natural Gas Pipeline Company of America's principal delivery market area encompasses the states of Illinois, Indiana and Iowa and secondary markets in portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural Gas Pipeline Company of America is the largest transporter of natural gas to the Chicago market, and we believe that its cost of service is very competitive in the region. In 2003, Natural Gas Pipeline Company of America delivered an average of 1.76 trillion Btus per day of natural gas to this market. Given its strategic location at the center of the North American natural gas pipeline grid, we believe that Chicago is likely to continue to be a major natural gas trading hub for growing markets in the Midwest and Northeast.

Substantially all of Natural Gas Pipeline Company of America's pipeline capacity is committed under firm transportation contracts ranging from one to five years. Approximately 67% of the total transportation volumes committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts as of January 7, 2004 had remaining terms of less than three years. Natural Gas Pipeline Company of America continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts, and was very successful during 2003 as discussed under "Developments During 2003" elsewhere in this report. Nicor Gas Company, Peoples Gas Light and Coke Company, and Northern Indiana Public Service Company (NIPSCO) are Natural Gas Pipeline Company of America's three largest customers in terms of operating revenues from tariff services. During 2003, approximately 54 percent of Natural Gas Pipeline Company of America's operating revenues from tariff services were attributable to its eight largest customers. Contracts representing approximately 10% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 7, 2004 are scheduled to expire during 2004.

Natural Gas Pipeline Company of America is one of the nation's largest natural gas storage operators with approximately 600 Bcf of total natural gas storage capacity, 232 Bcf of working gas capacity and up to 4.0 Bcf per day of peak deliverability from its storage facilities, which are located near the markets it serves. Natural Gas Pipeline Company of America owns and operates eight underground storage fields in four states. These storage assets complement its pipeline facilities and allow it to optimize pipeline deliveries and meet peak delivery requirements in its principal markets. Natural Gas Pipeline Company of America provides firm and interruptible gas storage service pursuant to storage agreements and tariffs. Firm storage customers pay a monthly demand charge irrespective of actual volumes stored. Interruptible storage customers pay a monthly charge based upon actual volumes of gas stored.

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

Competition:  Natural Gas Pipeline Company of America competes with other transporters of natural gas in virtually all of the markets it serves and, in particular, in the Chicago area, which is the northern terminus of Natural Gas Pipeline Company of America's two major pipeline segments and its largest market. These competitors include both interstate and intrastate natural gas pipelines and, historically, most of the competition has been from such pipelines with supplies originating in the United States. In recent years, Natural Gas Pipeline Company of America has also faced competition from additional pipelines carrying Canadian-produced natural gas into the Chicago market. The most recent example is the Alliance Pipeline, which began service during the 2000-2001 heating season. The additional pipeline capacity into the Chicago market has increased competition for transportation into the area while, at the

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same time, new pipelines, such as Vector Pipeline, have been constructed for the specific purpose of transporting gas from the Chicago area to other markets, generally further north and further east. The overall impact of the increased pipeline capacity into the Chicago area, combined with additional take-away capacity and the increased demand in the area, has created a situation that remains dynamic with respect to the ultimate impact on individual transporters such as Natural Gas Pipeline Company of America.

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

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

During 2003, TransColorado's segment earnings of $23.1 million represented approximately 3% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 3% of our income from continuing operations before interest and income taxes. Through TransColorado, we own and operate approximately 300 miles of interstate natural gas pipelines on the Western Slope of Colorado and Northwestern New Mexico. The system is powered by two compressor stations in mainline service having an aggregate of approximately 10,000 horsepower. TransColorado's system, which extends from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico, has 17 points of interconnection with five interstate pipelines, one intrastate pipeline, four gathering systems, and two local distribution companies, thereby providing relatively significant flexibility in the receipt and delivery of natural gas. Gas flowing south through the pipeline moves onto the El Paso, Transwestern and Southern Trail pipeline systems. TransColorado receives gas from two coal seam natural gas treating plants located in the San Juan Basin of Colorado and from pipeline and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. This pipeline was a 50/50 joint venture with Questar Corp. until we bought Questar's interest effective October 1, 2002, thus becoming the sole owner. As a result, our consolidated financial statements include TransColorado's results as a 50/50 equity method investment prior to October 1, 2002 and on a 100% basis as a consolidated subsidiary thereafter. As discussed under "Business Strategy" elsewhere in this report, we are considering the transfer of TransColorado to Kinder Morgan Energy Partners for fair market value.

TransColorado provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers. Pursuant to transportation agreements and Federal Energy Regulatory Commission tariff provisions, TransColorado offers its customers firm and interruptible transportation and interruptible park and loan services. Under

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TransColorado's tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. The underlying reservation and commodity charges are assessed pursuant to a "postage stamp" maximum recourse rate structure. TransColorado has the authority to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure. TransColorado's revenues have historically been higher during the second and third quarters of the calendar year, resulting from two factors: (i) winter heating market loads to the north of TransColorado and (ii) summer air conditioning market loads to the south of TransColorado.

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

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

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

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

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

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

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

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

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

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

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Kinder Morgan Retail's natural gas distribution business relies on the intrastate pipelines it operates, Kinder Morgan Interstate Gas Transmission LLC, a subsidiary of Kinder Morgan Energy Partners, and third-party pipelines for transportation and storage services required to serve its markets. The natural gas supply requirements for Kinder Morgan Retail's natural gas distribution business are met through contract purchases from third-party suppliers.

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

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

Kinder Morgan Retail currently provides unbundled natural gas services in Nebraska and Wyoming under Choice Gas Programs. These Choice Gas Programs allow competing natural gas providers to sell natural gas to approximately 64% of Kinder Morgan Retail's total customers at present. In unbundled areas, Kinder Morgan Retail competes as one of four or five natural gas marketing companies to provide the customer with natural gas commodity offerings. Kinder Morgan Retail currently provides the natural gas commodity for 52% of the end-use customers in these unbundled areas.

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

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

In 1998, Kinder Morgan Power acquired interests in the Thermo Companies, which provided us with our first electric generation assets as well as knowledge and expertise with General Electric Company jet engines (LMs) configured in a combined cycle mode. Through the Thermo Companies, Kinder Morgan Power acquired the interests in three Colorado natural gas-fired electric generating facilities discussed above, which have a combined 380 megawatts of electric generation capacity. Kinder Morgan Power used the LM knowledge to develop its proprietary "Orion" technology. Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, in December 2003, we increased our investment in the Thermo Companies by issuing 1.8 million of Kinder Morgan Management shares to an entity controlled by the former Thermo owners. For further information regarding this incremental investment, see "Power" within "Management's Discussion and Analysis of Financial Condition and Results of Operations."

In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant in Wrightsville, Arkansas, utilizing Kinder Morgan Power's Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Kinder Morgan Power made an investment in the project company, comprised primarily of preferred stock. This facility has not been dispatched significantly since July 1, 2002. In October 2003, the project company was included in Mirant Corporation's bankruptcy filing. In the fourth quarter of 2003, we wrote off our remaining investment in the Wrightsville power facility, as further discussed in Note 6 of the accompanying Notes to Consolidated Financial Statements.

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

Competition: With respect to the electric generating facilities acquired from the Thermo entities, Kinder Morgan Power does not directly face competition with respect to the sale of the power generated, as it is sold to or generated for the local electric utility under long-term contracts. With respect to Power's investment in the Jackson, Michigan facility, the principal impact of competition is the level of dispatch of the plant and the related (but minor) effect on profitability.

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

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this report, "FERC" refers to the Federal Energy Regulatory Commission.

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

On July 17, 2000, Natural Gas Pipeline Company of America filed its compliance plan, including pro forma tariff sheets, pursuant to FERC Order Nos. 637 and 637-A. The FERC directed all interstate pipelines to file pro forma tariff sheets to comply with new regulatory requirements in these Orders regarding scheduling procedures, capacity segmentation, imbalance management services and penalty credits, or in the alternative, to explain why no changes to existing tariff provisions are necessary. On November 21, 2002, the FERC issued an order approving much of Natural Gas Pipeline Company of America's Order 637 filing, but requiring additional changes. The primary changes relate to Natural Gas Pipeline Company of America's segmentation proposal, the ability of shippers to designate additional primary points on a segmented release, a shipper's rights to request discounts at alternate points and Natural Gas Pipeline Company of America's unauthorized overrun charges. Natural Gas Pipeline Company of America made its compliance filing on December 23, 2002 and filed for rehearing. Other parties have objected to certain aspects of Natural Gas Pipeline Company of America's compliance filing. On May 14, 2003, the FERC issued an order accepting most of Natural Gas Pipeline Company of America's compliance filing, but requiring additional changes, particularly regarding the designation of additional primary points for a segmented release. This order also established an effective date for Natural Gas Pipeline Company of America's Order 637 provisions of December 1, 2003. Natural Gas Pipeline Company of America made its further compliance filing on June 13, 2003. Limited protests have been filed. The Order No. 637 tariff provisions for Natural Gas Pipeline Company of America became effective on December 1, 2003, although certain aspects of these provisions are subject to FERC review of the most recent compliance filing, which is still pending FERC action.

On April 5, 2002, the D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C. Circuit did remand the FERC's decision to impose a 5-year cap on bids the existing shipper would have to match in the right of first refusal process. The D.C. Circuit also remanded the FERC's decision to allow forward-hauls and backhauls to the same point. Finally, the D.C. Circuit held that several aspects of the FERC's segmentation policy and its policy on discounting at alternate points were not ripe for review. Numerous parties, including Natural Gas Pipeline Company of America, have filed comments on the remanded issues.

On October 31, 2002, the FERC issued an order in response to the D.C. Circuit's remand of certain Order 637 issues. The order: (i) eliminated the requirement of a 5-year cap on bid terms that an existing shipper would have to match in the right of first refusal process, and found that no term matching cap at all is necessary given existing regulatory controls and (ii) affirmed the FERC's policy that a segmented transaction consisting of both a forward-haul up to contract demand and a backhaul up to contract demand to the same point is permissible, and accordingly required, under Section 5 of the Natural Gas Act, pipelines that the FERC had previously found must permit segmentation on their systems to file tariff revisions within 30 days to permit such segmented forward-haul and backhaul transactions to the same point. On January 29, 2004, the FERC issued an order denying rehearing and reaffirming these rulings.

The FERC, in a Notice of Proposed Rulemaking in RM02-14-000, has proposed new regulation of cash management practices, including establishing limits on the amount of funds that can be swept from a

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

We are also subject to the requirements of FERC Order Nos. 497, et seq., and 566, et seq., the Marketing Affiliate Rules, which prohibit preferential treatment by an interstate natural gas pipeline of its marketing affiliates and govern, in particular, the provision of information by an interstate natural gas pipeline to its marketing affiliates. On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate pipeline must file a compliance plan by that date and must be in full compliance with the Standards of Conduct by June 1, 2004. The primary change from existing regulation is to make such standards applicable to an interstate pipeline's interaction with many more affiliates (termed "Energy Affiliates"), including intrastate/Hinshaw pipelines, processors and gatherers and any company involved in gas or electric markets (such as electric generators and electric or gas marketers) even if they do not ship on the affiliated interstate pipeline. Local distribution companies are excluded, however, if they do not make sales to customers not situated on their gas distribution system. The Standards of Conduct require, inter alia, separate staffing of interstate pipelines and their Energy Affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from the interstate pipeline to an Energy Affiliate. Natural Gas Pipeline Company of America filed for clarification and rehearing of Order No. 2004 on December 29, 2003, and numerous other rehearing requests have been submitted. In the request for rehearing, Natural Gas Pipeline Company of America asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of Energy Affiliates. To date the FERC has not acted on these hearing requests. On February 9, 2004, Natural Gas Pipeline Company of America, TransColorado Gas Transmission Company, Canyon Creek Compression Company and Horizon Pipeline Company filed their compliance plans under Order No. 2004. In addition, on February 19, 2004, all of these interstate pipelines filed a joint request with the interstate pipelines owned by Kinder Morgan Energy Partners asking that their interaction with intrastate/Hinshaw pipeline affiliates be exempted from the Standards of Conduct. For us, the mandated separation from these entities would be the most burdensome requirement of the new rules.

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

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Department of Transportation is responsible for providing. Natural Gas Pipeline Company of America estimates that the average annual incremental expenditure associated with the Pipeline Safety Improvement Act of 2002 will be approximately $8 million to $10 million dollars.

We operate an intrastate pipeline in Colorado, Rocky Mountain Natural Gas Company, which is regulated by the Public Utilities Commission for the State of Colorado as a public utility with respect to its natural gas transportation and sales services within the state. Rocky Mountain Natural Gas Company also performs certain natural gas transportation services in interstate commerce pursuant to Section 311 of the Natural Gas Policy Act of 1978. The Public Utilities Commission for the State of Colorado regulates the rates, terms, and conditions of natural gas sales and transportation services performed by public utilities in the state of Colorado. During 2002, our intrastate pipeline in Wyoming, Northern Gas Company, was merged into Kinder Morgan, Inc. and is now operated as part of our retail distribution business in Wyoming pursuant to approvals received from the Wyoming Public Service Commission.

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

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

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

Our operations and properties are subject to extensive and evolving federal, state and local laws and regulations governing the release or discharge of regulated materials into the environment or otherwise relating to environmental protection or human health and safety. We have an environmental compliance

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

We had an established environmental reserve at December 31, 2003 of approximately $14.5 million, to address remediation issues associated with approximately 35 projects. These projects include several ground water and soil hydrocarbon remediation efforts under the jurisdiction and direction of various state agencies. Many of these remediation efforts are the result of historic releases from currently non-operating sites. Additionally, we are addressing impacts at several locations from the historic use of mercury and polychlorinated biphenyls. We believe that costs for environmental remediation and separately ongoing compliance with applicable environmental regulations will not have a material adverse effect on our cash flows, financial position or results of operations or materially diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, the discovery of circumstances or conditions currently unforeseen by us, or that the development of new facts or conditions will not cause us to incur significant unanticipated costs and liabilities.

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

KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, a subsidiary of Kinder Morgan Management, provides centralized payroll and employee benefits services to Kinder Morgan Management, Kinder Morgan Energy Partners and Kinder Morgan Energy Partners' operating partnerships and subsidiaries (collectively, "the Group"). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to the limited partnership agreement, Kinder Morgan Energy Partners provides reimbursement for its share of these administrative costs and such reimbursements are accounted for as described above. Kinder Morgan Energy Partners reimburses Kinder Morgan Management with respect to the costs incurred or allocated to Kinder Morgan Management in accordance with Kinder Morgan Energy Partners' limited partnership agreement, the Delegation of Control Agreement among Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy Partners and others, and Kinder Morgan Management's limited liability company agreement. Our named executive officers and other employees that provide management or services to both us and the Group are employed by us. Additionally, other of our employees assist Kinder Morgan Energy

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

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

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

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

Item 3.  Legal Proceedings.

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

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None.

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.

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C. Park Shaper is Director, Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and Vice President and Chief Financial Officer of Kinder Morgan, Inc. Mr. Shaper was elected Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its formation in February 2001, and served as Treasurer of Kinder Morgan Management, LLC from February 2001 to January 2004. He has served as Treasurer of Kinder Morgan, Inc. from April 2000 to January 2004 and Vice President and Chief Financial Officer of Kinder Morgan, Inc. since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as Treasurer of Kinder Morgan G.P., Inc. from April 2000 to January 2004. From June 1999 to December 1999, Mr. Shaper was President and Director of Altair Corporation, an enterprise focused on the distribution of web-based investment research for the financial services industry. He served as Vice President and Chief Financial Officer of First Data Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997 to June 1999. From 1995 to 1997, he was a consultant with The Boston Consulting Group. He received a Masters of Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University.

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

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

Deborah A. Macdonald is President, Natural Gas Pipelines of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. She was elected President, Natural Gas Pipelines in June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company of America from October 1999 to March 2003. Prior to joining Kinder Morgan, Ms. Macdonald worked as Senior Vice President of legal affairs for Aquila Energy Company from January 1999 to October 1999, and was engaged in a private energy consulting practice from June 1996 to December 1999. Ms. Macdonald received her Juris Doctor, summa cum laude, from Creighton University in May 1980 and received a Bachelors degree, magna cum laude, from Creighton University in December 1972.

James E. Street is Vice President, Human Resources and Administration of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P.,

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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.

None.

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Our common stock is listed for trading on the New York Stock Exchange under the symbol "KMI." Dividends paid and the price range of our common stock by quarter for the last two years are provided below. In January 2004, we increased our quarterly common dividend to $0.5625 per share.

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

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

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

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

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General

In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes. Specifically, as discussed in Notes 4, 5 and 7 of the accompanying Notes to Consolidated Financial Statements, we have engaged in acquisitions (including the October 1999 acquisition of Kinder Morgan (Delaware), Inc., the indirect owner of the general partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded master limited partnership, referred to in this report as "Kinder Morgan Energy Partners"), and divestitures (including the discontinuance of certain lines of business and the transfer of certain assets to Kinder Morgan Energy Partners) that may affect comparisons of financial position and results of operations between periods.

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

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

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

After the divestitures discussed above, our remaining businesses (apart from our investment in Kinder Morgan Energy Partners) constitute four business segments. Our largest business segment and our primary source of operating income is Natural Gas Pipeline Company of America, which owns and

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operates a major interstate natural gas pipeline system that runs from natural gas producing areas in West Texas and the Gulf of Mexico to its principal market area of Chicago, Illinois. In accordance with our strategy to increase operational focus on core assets, we have worked toward renewing existing agreements and entering into new agreements to fully utilize the transportation and storage capacity of Natural Gas Pipeline Company of America's system. As a result, Natural Gas Pipeline Company of America sold virtually all of its capacity through the 2003-2004 winter season. Natural Gas Pipeline Company of America continues to pursue opportunities to connect its system to power generation facilities and, in addition, has extended its system to East St. Louis, Illinois.

Our other business segments consist of (i) our TransColorado system, a 300-mile natural gas pipeline and related facilities extending from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico, (ii) our retail distribution of natural gas to approximately 241,000 customers in Colorado, Wyoming and Nebraska and (iii) our investment in, in some cases, operation of, and in previous periods construction of electric power generation facilities. The TransColorado system receives gas from two coal seam natural gas treating plants located in the San Juan Basin of Colorado and from pipeline and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. We purchased the remaining 50 percent interest in TransColorado that we did not already own from Questar Corp. in the fourth quarter of 2002 and have announced plans to expand the system (see "TransColorado" following and Note 4 of the accompanying Notes to Consolidated Financial Statements). Our retail natural gas distribution operations are located, in part, in areas where significant growth is occurring and we expect to participate in that growth through increased natural gas demand. Our power segment owns interests in and, in some cases, operates power generation facilities and continues to hold preferred investments in two gas-fired power plants constructed by us and placed into operation in 2002. During the fourth quarter of 2002, we announced that we were discontinuing our power development activities and we revalued certain of our power assets. We also revalued certain of our power assets during the fourth quarter of 2003. See "Power" following and Note 6 of the accompanying Notes to Consolidated Financial Statements.

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

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

In our retail natural gas distribution business, because we read customer meters on a cycle basis, we are required to estimate the amount of revenue earned as of the end of each period for which service has been rendered but meters have not yet been read. We have available historical information for these

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

With respect to the amount of income or expense we recognize in association with our retiree medical plans, we must make a number of assumptions with respect to both future financial conditions (for example, medical costs, returns on fund assets and market interest rates) as well as future actions by plan participants (for example, when they will retire and how long they will live after retirement). Most of these assumptions have relatively minor impacts on the overall accounting recognition given to these plans, but two assumptions in particular, the discount rate and the assumed long-term rate of return on fund assets, can have significant effects on the amount of expense recorded and liability recognized. The selection of these assumptions is discussed in Note 15 of the accompanying Notes to Consolidated Financial Statements. While we believe our choices for these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of retiree medical funding, (i) a change of 1% in the long-term return assumption would increase (decrease) our annual retiree medical expense by approximately $5,680 ($5,234) in comparison to that recorded in 2003 and (ii) a 1% change in the discount rate would increase (decrease) our accumulated postretirement benefit obligation by $83,546 ($77,626) compared to those balances as of December 31, 2003.

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

We are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

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

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

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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.

Our income from continuing operations increased from $307.7 million in 2002 to $381.7 million in 2003, an increase of $74.0 million (24.0%). This increase is comprised of increases of $119.4 million in operating income and $64.1 million in net other income and expenses, partially offset by an increase of $109.6 million in income tax expense. Following is a discussion of items affecting operating income and other income and expenses. Please refer to the individual business segment discussions included elsewhere herein for additional information regarding business segment results. Refer to the headings "Other Income and (Expenses)," "Income Taxes - Continuing Operations" and "Discontinued Operations" included elsewhere herein for additional information regarding these items.

Our results for 2003, in comparison to 2002, reflect increases of $82.6 million (8.1%) in operating revenues and $119.4 million (50.4%) in operating income. The increase in operating revenues was attributable to increased revenues in our Natural Gas Pipeline Company of America and TransColorado business segments, partially offset by decreased revenues in our Power and Kinder Morgan Retail business segments (see the individual business segment discussions following for additional 

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

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

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

Below the operating income line, net other income and expenses increased from income of $0.3 million in 2001 to income of $206.1 million in 2002, an increase of $205.8 million. This increase reflected (i) increased equity in earnings of Kinder Morgan Energy Partners in 2002 due, in part, to the improved performance from the assets held by Kinder Morgan Energy Partners and the cessation of amortization of equity-method goodwill related to this investment due to the adoption of SFAS No. 142 (see Note 1(O) of the accompanying Notes to Consolidated Financial Statements), (ii) increased equity in earnings of other equity investments in 2002 (which are principally included in business segment earnings), (iii) decreased 2002 interest expense reflecting lower 2002 interest rates and borrowed balances and (iv) the inclusion, in 2001 results, of $20.3 million in expense related to the early extinguishment of debt (see Note 12(B) of the accompanying Notes to Consolidated Financial Statements). These positive impacts were partially offset by (i) a $19.0 million increase in minority interest expense in 2002, principally attributable to the minority interests in Kinder Morgan Management, LLC and (ii) a $9.6 million decrease in net gains from asset sales in 2002 (see Note 1(Q) of the accompanying Notes to Consolidated Financial Statements).

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

Diluted earnings per share increased from $1.86 in 2001 to $2.45 in 2002, an increase of $0.59 (31.7%) reflecting, in addition to the financial and operating impacts discussed preceding, an increase of 2.1 million (1.7%) in average shares outstanding. Excluding the impact of discontinued operations in 2002, diluted earnings per share from continuing operations increased from $1.86 in 2001 to $2.49 in 2002, an increase of $0.63 (33.9%). Income from continuing operations included (i) a pre-tax charge of $134.5 million in 2002 to reduce the carrying value of certain Power assets (see "Power" following), (ii) income tax adjustments that reduced 2002 income tax expense by approximately $42 million (see "Income Taxes - Continuing Operations" following), (iii) pre-tax losses on early extinguishment of debt of $2.3 million and $22.6 million in 2002 and 2001, respectively, and (iv) other non-recurring items aggregating $1.4 million in pre-tax charges in 2002 and $2.5 million in pre-tax income in 2001.

We manage our various businesses by, among other things, allocating capital and monitoring operating performance. This management process includes dividing the company into business segments so that performance can be effectively monitored and reported for a limited number of discrete businesses. Currently, we manage and report our operations in four business segments. In addition, we derive a substantial portion of earnings from our investment in Kinder Morgan Energy Partners, which is discussed under "Earnings from Investment in Kinder Morgan Energy Partners" following.

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In the fourth quarter of 2002, as further discussed under "Power" following, we decided to discontinue the development portion of our power generation business and decreased the carrying value of certain of our power assets. An additional reduction in the carrying value of certain power assets was made in the fourth quarter of 2003. TransColorado Gas Transmission Company was a 50/50 joint venture with Questar Corp. until we became sole owner by purchasing Questar Corp.'s interest effective October 1, 2002. Results of operations for this segment include our 50% share of TransColorado's earnings recognized under the equity method of accounting prior to October 2002 and consolidated results at the 100% level thereafter.

The accounting policies we apply in the generation of business segment earnings are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that (i) certain items below the "Operating Income" line are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners and certain insignificant international investees, are included. These equity method earnings are included in "Other Income and (Expenses)" in our Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not allocated to individual business segments and (ii) gains and losses from incidental sales of assets are included in segment earnings. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

Following are operating results by individual business segment (before intersegment eliminations), including explanations of significant variances between the periods presented. As necessary for comparative purposes, we have reclassified prior period results and balances to conform to the current presentation.

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

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

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

Natural Gas Pipeline Company of America's segment earnings increased from $346.6 million in 2001 to $359.9 million in 2002, an increase of $13.3 million (3.8%). The increase in operating revenues, which was largely offset by a corresponding increase in cost of sales, was due to increased revenues from 2002 operational natural gas sales and increased transportation and storage revenues, largely due to expansions/extensions of pipeline systems coming on line in 2002. Segment earnings for 2002 were positively affected, relative to 2001, by (i) increased margins from natural gas transportation and storage services, including operational natural gas sales and (ii) the inclusion of earnings from our equity investment in Horizon Pipeline Company, which was placed into service during the second quarter of 2002. These positive impacts were partially offset by (i) increased operations and maintenance expenses attributable to transmission mains and underground storage facilities, (ii) increased depreciation expense due to the addition of new facilities, principally the extension of our system into the eastern portion of the St. Louis metropolitan area, (iii) increased ad valorem taxes and (iv) the fact that 2001 results include $6.3 million of pre-tax gains from incidental asset sales. Although systems throughput increased in 2002, this increase did not have a significant direct impact on revenues or segment earnings due to the "demand" component of transportation contracts, as discussed previously.

Substantially all of Natural Gas Pipeline Company of America's pipeline capacity is committed under firm transportation contracts ranging from one to five years. Under these contracts, over 90% of the revenues are derived from a demand charge and, therefore, are collected regardless of the volume of gas actually transported. The principal impact of the actual level of gas transported is on fuel recoveries, which are received in-kind as volumes move on the system. Approximately 67% of the total transportation volume committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts in effect on January 7, 2004 had remaining terms of less than three years. Contracts representing approximately 10% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 7, 2004 are scheduled to expire during 2004. Natural Gas Pipeline Company of America continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts. Nicor Gas and Peoples Energy, two local gas distribution companies in the Chicago, Illinois area, are Natural Gas Pipeline Company of America's two largest customers.

For 2004, we currently expect that Natural Gas Pipeline Company of America will experience 3%

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growth in segment earnings in comparison to 2003. This increase in earnings is expected to be derived primarily from (i) the impact of having a full year of earnings from the North Lansing storage expansion project, and (ii) transportation revenue increases resulting from higher rates being contracted for on base transport business. However, as discussed following, there are factors beyond our control that can affect our results, including developments in the regulatory arena and as yet unforeseen competitive developments. Accordingly, our actual future results may differ significantly from our projections.

Our principal exposure to market variability is related to the variation in natural gas prices and basis differentials, which can affect gross margins in our Natural Gas Pipeline Company of America segment. "Basis differential" is a term that refers to the difference in natural gas prices between two locations or two points in time. These price differences can be affected by, among other things, natural gas supply and demand, available transportation capacity, storage inventories and deliverability, prices of alternative fuels and weather conditions. In recent periods, additional competitive pressures have been generated in Midwest natural gas markets due to the introduction and planned introduction of pipeline capacity to bring additional supplies of natural gas into the Chicago market area, although incremental pipeline capacity to take gas out of the area has also been constructed. We have attempted to reduce our exposure to this form of market variability by pursuing long-term, fixed-rate type contract agreements to utilize the capacity on Natural Gas Pipeline Company of America's system. In addition, as discussed under "Risk Management" in Item 7A of this report and in Note 14 of the accompanying Notes to Consolidated Financial Statements, we utilize a comprehensive risk management program to mitigate our exposure to changes in the market price of natural gas and associated transportation.

The majority of Natural Gas Pipeline Company of America's system is subject to rate regulation under the jurisdiction of the Federal Energy Regulatory Commission. Currently, there are no material proceedings challenging the rates on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face future challenges to the rates we receive for services on our pipeline systems.

TransColorado was a 50/50 joint venture with Questar Corp. until we bought Questar's interest effective October 1, 2002, thus becoming the sole owner. As a result, TransColorado's results shown above reflect our 50% equity interest in its earnings prior to October 1, 2002 and 100% of its results on a consolidated basis thereafter. TransColorado's segment earnings increased from $12.6 million in 2002 to $23.1 million in 2003. Results for 2003, relative to 2002, reflected, in addition to a full year at the increased level of ownership, the favorable impact of wide basis differentials on certain transportation contracts. These basis differentials have narrowed since mid 2003. As a result of its contracting activities as discussed below, the contractual volume of activity that is suject to changes in basis differentials has decreased.

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The significant improvement in TransColorado's operating results from 2001 to 2002, apart from the change in our ownership percentage, resulted from the increased demand and associated increased throughput on the system. This increased demand has resulted from the incremental natural gas production available in the Rocky Mountain basins that form the principal supply area for TransColorado and the limited pathways for this natural gas to get to markets both east and west of these production areas. Due in large part to this increased demand, TransColorado has sold out its available firm capacity through October 2004.

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

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

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

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

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

Kinder Morgan Retail's segment earnings increased from $56.7 million in 2001 to $64.1 million in 2002, an increase of $7.4 million (13.1%). The decrease in operating revenues in 2002, relative to 2001, was principally due to lower natural gas prices in 2002 and was offset by lower costs for natural gas purchases. Segment earnings were positively impacted in 2002, relative to 2001, by (i) margins derived from the fourth quarter 2001 acquisition of natural gas distribution facilities from Citizens Communications Company, as described following, (ii) strong demand during the 2002 irrigation season, (iii) the addition of new customers in existing service territories and (iv) a $1.6 million ad valorem tax refund in 2002 from an affiliated shipper. These positive impacts were partially offset by higher operations, maintenance and depreciation expenses in 2002 principally attributable to the newly acquired facilities.

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

For 2004, we currently expect that Kinder Morgan Retail will experience approximately 5% growth in segment earnings. With a stable base of earnings due to regulated business, supplemented by a weather hedging program, increased earnings are expected to derive largely from the addition of new customers

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in existing service territories, especially certain high-growth areas in Colorado. However, as discussed following, there are factors beyond our control that can affect our results, including developments in the regulatory arena, currently unforeseen competitive developments and weather-related impacts outside our hedging program. For these and other reasons, our actual future results may differ significantly from our projections.

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

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

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

In February 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading agreed to supply natural gas to and market capacity for 16 years for a 550-megawatt natural gas-fired Orion technology electric power plant in Jackson, Michigan. Effective July

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1, 2002, construction of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC valued at approximately $105 million; and, (ii) Triton Power Company LLC, through its wholly owned subsidiary, Triton Power Michigan LLC, entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC. Williams Energy Marketing and Trading supplies all natural gas to and purchases all power from the power plant under a 16-year tolling agreement with Triton Power Michigan LLC. Our preferred equity interest has no management or voting rights, but does retain certain protective rights, and is entitled to a cumulative return, compounded monthly, of 9.0% per annum. No income is expected in 2004 from this preferred investment. Due to a recent change in accounting standards, effective December 31, 2003, we began consolidating Triton Power Company, LLC (see Note 20 of the accompanying Notes to Consolidated Financial Statements).

In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant in Wrightsville, Arkansas, utilizing Kinder Morgan Power's Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. Mirant Corporation operates and maintains the Wrightsville facility and manages the natural gas supply and electricity sales for the project company that owns the power plant. Kinder Morgan Power made an investment in the project company, comprised primarily of preferred stock. This facility has not been dispatched significantly since July 1, 2002. During the third quarter of 2003, we announced that Mirant had placed the Wrightsville, Arkansas plant in bankruptcy in October, and we would assess the long-term prospects for this facility during the fourth quarter. In December 2003, we completed our analysis and determined that it was no longer appropriate to assign any carrying value to our investment in this facility and recorded a $44.5 million pre-tax charge, effectively writing off our remaining investment in the Wrightsville power facility.

During 2002, we noted that a number of factors had negatively affected Power's business environment and certain of its current operations. These factors, which are currently expected to continue in the near to intermediate term, include (i) volatile and generally declining prices for wholesale electric power in certain markets, (ii) cancellation and/or postponement of the construction of a number of new power generation facilities, (iii) difficulty in obtaining air permits with acceptable operating conditions and constraints and (iv) a marked deterioration in the financial condition of a number of participants in the power generating and marketing business, including participants in the power plants in Jackson, Michigan and Wrightsville, Arkansas. During the fourth quarter of 2002, after completing an analysis of these and other factors to determine their impact on the market value of these assets and the prospects for this business in the future, we (i) determined that we would no longer pursue power development activities and (ii) recorded a $134.5 million pre-tax charge to reduce the carrying value of our investments in (i) sites for future power plant development, (ii) power plants and (iii) turbines and associated equipment.

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

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

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

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

For 2004, pre-tax earnings attributable to our investment in Kinder Morgan Energy Partners are expected to increase by approximately 15% due to, among other factors, improved performance from existing assets. However, there are factors beyond the control of Kinder Morgan Energy Partners that may affect its results, including developments in the regulatory arena and as yet unforeseen competitive developments or acquisitions. Additional information on Kinder Morgan Energy Partners is contained in its Annual Report on Form 10-K for the year ended December 31, 2003.

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

"Other Income and (Expenses)" increased from income of $308,000 in 2001 to income of $206.1 million in 2002, an increase of $205.8 million. This increase was principally due to (i) increased equity in the earnings of Kinder Morgan Energy Partners due, in part, to the strong performance from the assets held by Kinder Morgan Energy Partners and the cessation of amortization of equity-method goodwill related to this investment due to the adoption of SFAS No. 142 (see Note 1(O) of the accompanying Notes to Consolidated Financial Statements), (ii) decreased interest expense, reflecting reduced interest rates and reduced debt outstanding, (iii) increased earnings from other equity investments, principally TransColorado and (iv) the inclusion in 2001 of a $22.6 million loss on early extinguishment of debt. These positive impacts were partially offset by (i) a $19.0 million increase in minority interest expense in 2002, principally attributable to the minority interests in Kinder Morgan Management, LLC and (ii) a $9.6 million decrease in 2002 gains from sales of assets.

The income tax provision increased from $135.0 million in 2002 to $244.6 million in 2003, an increase of $109.6 million (81.2%) due mainly to an increase of $183.6 million in income from continuing operations before income taxes. In addition, the income tax provision for 2002 was lower due to the combined impacts of (i) a decrease of approximately $21.0 million due to the impact of the lower effective tax rate on previously recorded deferred tax liabilities, (ii) a decrease of approximately $17.7 million due to the resolution of certain issues with respect to prior year tax returns at amounts less than

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

The income tax provision increased from $159.6 million in 2001 to $135.0 million in 2002, a decrease of $24.6 million (15.4%) despite an increase of $58.1 million in income from continuing operations before income taxes. The income tax provision for 2002 was reduced by the combined impacts of (i) a decrease in the effective tax rate on current-year income from approximately 40% in 2001 to approximately 38% in 2002, principally due to a decrease in the provision for state income taxes and (ii) decreases in the 2002 tax provision as mentioned above.

During 1999, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing of natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids, (iii) international operations and (iv) the direct marketing of non-energy products and services. During 2000, we completed the disposition of these businesses, with the exception of international operations (principally consisting of a natural gas distribution system in Hermosillo, Mexico) which, in the fourth quarter of 2000, we decided to retain. During the fourth quarter of 2002, we recorded an incremental loss of approximately $5.0 million (net of tax benefit of $3.1 million) to adjust previously recorded liabilities to reflect current estimates of our remaining obligations. We had a remaining liability of approximately $5.4 million at December 31, 2003 associated with these discontinued operations, due to an indemnification obligation. We do not expect significant additional financial impacts associated with these matters. Note 7 of the accompanying Notes to Consolidated Financial Statements contains certain additional financial information with respect to these discontinued operations.

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

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

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

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

Our principal sources of short-term liquidity are our revolving bank facilities, our commercial paper program (which is supported by our revolving bank facilities) and cash provided by operations. As of December 31, 2003, we had available a $445 million 364-day facility dated October 14, 2003, and a $355 million three-year revolving credit agreement dated October 15, 2002. These bank facilities can be used for general corporate purposes, including as backup for our commercial paper program. At December 31, 2003 and February 12, 2004, we had $127.9 million and $128.4 million, respectively, of commercial paper issued and outstanding. After inclusion of applicable letters of credit, the remaining available borrowing capacity under the bank facilities was $641.7 million and $637.3 million at December 31, 2003 and February 12, 2004, respectively. The bank facilities include covenants that are common in such arrangements. For example, both facilities require consolidated debt to be less than 65% of consolidated capitalization. In addition, both of the bank facilities require the debt of

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consolidated subsidiaries to be less than 10% of our consolidated debt and require the consolidated debt of each material subsidiary to be less than 65% of our consolidated total capitalization. Also, both credit agreements require that our consolidated net worth (inclusive of trust preferred securities) be at least $1.7 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the third quarter of 2002.

Our current maturities of long-term debt of $5.0 million at December 31, 2003 consisted of current maturities of our $50 million of 6.50% Series Debentures due September 1, 2013. Apart from our notes payable and current maturities of long-term debt, our current liabilities, net of our current assets, represents an additional short-term obligation of approximately $67.1 million at December 31, 2003. Given our expected cash flows from operations and our unused debt capacity as discussed preceding, including our three-year revolving credit facility, and based on our projected cash needs in the near term, we do not expect any liquidity issues to arise. Our next significant debt maturities are our $500 million of 6.65% Senior Notes in 2005 and our $300 million of 6.80% Senior Notes in 2008.

On November 1, 2002, we retired the full $35 million of our 8.35% Series Sinking Fund Debentures due September 15, 2022 at a premium of 104.175% of the face amount. We recorded a loss of $1.0 million (net of associated tax benefit of $0.7 million) in connection with this early extinguishment of debt. This loss, and the loss recorded in conjunction with the early extinguishment of debt associated with the retirement of our 7.85% Series Debentures described below, are included under the caption "Other, Net" in the accompanying Consolidated Statements of Operations for 2002.

On October 10, 2002, we retired our $200 million of Floating Rate Notes due October 10, 2002, utilizing a combination of cash and incremental short-term debt. We issued these Floating Rate Notes on October 10, 2001. Effective September 1, 2002, we retired our $24 million of 7.85% Series Debentures due September 1, 2022 at par. We recorded a loss of $420,000 (net of associated tax benefit of $275,000) in conjunction with this early extinguishment of debt, consisting of the unamortized debt expense associated with these debentures.

On August 27, 2002, we issued $750 million of our 6.50% Senior Notes due September 1, 2012, in an offering made pursuant to Rule 144A of the regulations of the Securities and Exchange Commission, with registration rights. The proceeds were used to retire our short-term notes payable then outstanding, with the balance invested in short-term commercial paper and money market funds. On November 18, 2002, we completed an exchange offer to exchange these notes for our 6.50% Senior Notes due September 1, 2012, which have been registered under the Securities Act of 1933. These new notes have the same form and terms and evidence the same debt as the original notes, and were offered for exchange to satisfy our obligation to exchange the original notes for registered notes. In December 2002, we re-opened this issue and sold an additional $250 million of 6.50% Senior Notes, which we also exchanged for registered securities pursuant to our currently effective registration statement on Form S-4, in an exchange offer that was completed on March, 21, 2003.

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

On September 10, 2001, we retired our $45 million of 9.625% Series Sinking Fund Debentures due March 1, 2021, utilizing incremental short-term borrowings. In March 2001, we retired (i) our $400 million of Reset Put Securities due March 1, 2021 and (ii) our $20 million of 9.95% Series Sinking Fund

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

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

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

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

In May 2001, Kinder Morgan Management, LLC, one of our indirect subsidiaries, issued and sold its limited liability shares in an underwritten initial public offering. The net proceeds of $991.9 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. Upon purchase of the i-units, Kinder Morgan Management became a limited partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners' general partner the responsibility to manage and control the business and affairs of Kinder Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests that have been, and will be, issued only to Kinder Morgan Management. We have certain rights and obligations with respect to these securities. In addition, during 2001, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $11.7 million. By approval of Kinder Morgan Management shareholders other than us, effective at the close of business on July 23, 2002, we no longer have an obligation to, upon presentation by the holder thereof, exchange publicly held Kinder Morgan Management shares for either Kinder Morgan Energy Partners' common units that we own or, at our election, cash.

In the initial public offering, we purchased 10 percent of Kinder Morgan Management's shares, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which is consolidated in our financial statements) purchased by the public created an additional minority interest on our balance sheet of $892.7 million at the time of the transaction. On August 6, 2002, Kinder Morgan Management closed the issuance and sale of 12,478,900 limited liability shares in an underwritten public offering. The net proceeds of approximately $328.6 million from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners. We did not purchase any of the offered shares. In addition, during 2003 and 2002, in order to maintain our one percent general

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partner interest in Kinder Morgan Energy Partners' operating partnerships we made contributions totaling $1.8 million and $3.4 million, respectively. The earnings recorded by Kinder Morgan Management that are attributable to its shares held by the public are reported as "Minority Interests" in our Consolidated Statements of Operations. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management's 2003 Annual Report on Form 10-K.

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

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

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At December 31, 2003, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management, LLC we owned, approximately 32.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 13.0 million common units, 5.3 million Class B units and 14.5 million i-units, represent approximately 17.4 percent of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2 percent interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 19.0 percent of Kinder Morgan Energy Partners' total equity interests at December 31, 2003. We receive quarterly distributions on the i-units owned by Kinder Morgan Management in additional i-units and distributions on our other units in cash.

In addition to distributions received on our limited partner interests and our Kinder Morgan Management shares as discussed above, we also receive an incentive distribution from Kinder Morgan Energy Partners as a result of our ownership of the general partner interest in Kinder Morgan Energy Partners. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to unit holders exceed specified target levels as set forth in Kinder Morgan Energy Partners' partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit. Including both our general and limited partner interests in Kinder Morgan Energy Partners, at the 2003 distribution level, we received approximately 51% of all quarterly distributions made by Kinder Morgan Energy Partners, of which approximately 40% is attributable to our general partner interest and 11% is attributable to our limited partner interest. The actual level of distributions we will receive in the future will vary with the level of distributable cash determined in accordance with Kinder Morgan Energy Partners' partnership agreement.

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

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

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

"Net Cash Flows Provided by Operating Activities" increased from $437.3 million in 2001 to $443.0 million in 2002, an increase of $5.7 million (1.3%). This positive variance principally reflects a $71.5 million increase in cash distributions received in 2002 attributable to our interest in Kinder Morgan Energy Partners and a decrease of $69.1 million in cash outflows for gas in underground storage during 2002. These positive impacts were partially offset by several non-recurring cash payments and cash flow timing issues including (i) a second-quarter 2002 $22.1 million payment and escrow deposit in settlement of certain litigation involving Jack J. Grynberg, (ii) a $20 million pension contribution in 2002 of which $18.7 million was in excess of book expense, (iii) a decrease of $58.8 million in cash associated with other working capital items, primarily attributable to interest and taxes receivable and (iv) a decrease of $31.3 million in 2002 cash attributable to deferred purchased gas costs. The $20 million pension contribution made in April 2002 was deductible under Internal Revenue Service regulations but was not required to be made under the Employee Retirement Income Security Act of 1974, as amended, minimum contribution guidelines.

In general, distributions from Kinder Morgan Energy Partners are declared in the month following the end of the quarter to which they apply and are paid in the month following the month of declaration to the general partner and unit holders of record as of the end of the month of declaration. Therefore, the accompanying Statements of Consolidated Cash Flows for 2003, 2002 and 2001 reflect the receipt of $369.0 million, $310.3 million and $238.8 million, respectively, of cash distributions from Kinder Morgan Energy Partners for (i) the fourth quarter of 2002 and the first nine months of 2003, (ii) the fourth quarter of 2001 and the first nine months of 2002 and (iii) the fourth quarter of 2000 and the first nine months of 2001, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2003 total $101.4 million and $383.5 million, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2002 total $86.9 million and $326.9 million, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2001 total $70.3 million and $264.5 million, respectively. The increases in distributions during 2003 and 2002 reflect, among other factors, acquisitions made by Kinder Morgan Energy Partners and improvements in its results of operations. Summarized financial information for Kinder Morgan Energy Partners is contained in Note 2 of the accompanying Notes to Consolidated Financial Statements.

"Net Cash Flows Used in Investing Activities" decreased from $835.3 million in 2002 to $157.3 million in 2003, a decrease of $678.0 million (81.2%). This decreased use of cash is principally due to the fact that 2002 included (i) a $331.9 million investment in i-units of Kinder Morgan Energy Partners, (ii) a $183.6 million cash outflow for investments in power plant facilities, (iii) payment of $95.6 million (net

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

"Net Cash Flows Used in Investing Activities" decreased from $1,274.7 million in 2001 to $835.3 million in 2002, a decrease of $439.4 million. This decreased use of cash is principally due to the fact that 2001 included a $1.0 billion cash outflow versus a $331.9 million cash outflow during 2002 for investments in Kinder Morgan Energy Partners, principally for the purchase of i-units. This favorable variance was partially offset by (i) an increase of $132.6 million in 2002 for investments in power plants, (ii) an increase of $50.8 million in capital expenditures in 2002, principally for the Natural Gas Pipeline Company of America pipeline extension to East St. Louis, Illinois, (iii) a $16.5 million 2002 cash outflow for an investment in Horizon Pipeline Company and (iv) the fact that 2001 included $25.7 million of proceeds from discontinued operations sold during 2000. Incremental investment in the TransColorado system totaled $104.7 million in 2001 (as we retired our 50% share of its debt) and $95.6 million (net of cash acquired) in 2002 (as we acquired an incremental 50% interest).

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

"Net Cash Flows (Used in) Provided by Financing Activities" decreased from a source of $411.8 million in 2002 to a use of $454.4 million in 2003, an increased net cash use of $866.2 million. This increased net use of cash was principally due to (i) $500 million of cash used in 2003 to retire our $500 million 6.45% Senior Notes, (ii) an increase of $98.6 million paid in 2003 for dividends, principally due to the increased dividends declared per share (see discussion following in this section) and (iii) the fact that 2002 included proceeds, net of issuance costs, of $328.6 million from the issuance of Kinder Morgan Management shares and $995.6 million of net proceeds from the issuance of our 6.50% Senior Notes due September 1, 2012. Partially offsetting these factors were (i) a $551.7 million increase during 2003 in cash flows related to short-term borrowing, (ii) the fact that 2002 included cash used for repayment of $200 million of Floating Rate Notes and $60.5 million for the early retirement of our 7.85% Debentures due September 1, 2022 and our 8.35% Sinking Fund Debentures due September 15, 2022 (see Note 12 of the accompanying Notes to Consolidated Financial Statements), (iii) a $111.1 million decreased use of cash during 2003 to repurchase shares and (iv) a $108.9 million increased source of cash from net repayment of short-term advances to unconsolidated affiliates during 2003.

"Net Cash Flows Provided by Financing Activities" decreased from $711.6 million in 2001 to $411.8 million in 2002, a decrease of $299.8 million. This decrease is principally due to (i) the fact that 2001 and 2002 included proceeds, net of issuance costs, of $888.1 million and $328.6 million, respectively, from the issuance of Kinder Morgan Management shares, (ii) a $747.6 million decrease during 2002 in net short-term borrowing, (iii) the issuance of $200 million of Floating Rate Notes in 2001 and the repayment of those notes during 2002 and (iv) $60.5 million of cash used in 2002 for the early retirement of our 7.85% Debentures due September 1, 2022 and our 8.35% Sinking Fund Debentures due September 15, 2022 (see Note 12 of the accompanying Notes to Consolidated Financial Statements). Partially offsetting this net decrease in cash inflows were (i) $995.6 million of net proceeds received in 2002 from the issuance of our 6.50% Senior Notes due September 1, 2012, (ii) the fact that 2001 included a $495.7 million cash outflow for the early extinguishment of three series of debt securities (see Note 12 of the accompanying Notes to Consolidated Financial Statements) and (iii) a reduction of $116.6 million in 2002 purchases of treasury stock.

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

Our anticipated environmental capital costs and expenses for 2004, including expected costs for remediation efforts, are approximately $5.7 million, compared to approximately $2.3 million of such costs and expenses incurred in 2003. A substantial portion of our environmental costs are either recoverable through insurance and indemnification provisions or have previously recorded liabilities associated with them. We had an established environmental reserve of approximately $14.4 million at December 31, 2003, to address remediation issues associated with approximately 35 projects. This reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort and to identify if the reserve allocation is appropriately valued. In assessing environmental risks in conjunction with proposed acquisitions, we review records relating to environmental issues, conduct site inspections, interview employees, and, if appropriate, collect soil and groundwater samples. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with environmental regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new or existing facts or conditions will not cause us to incur significant unanticipated costs.

Refer to Notes 9(A) and 9(B) of the accompanying Consolidated Financial Statements for additional information on our pending environmental and litigation matters, respectively. We believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact.

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

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The Pipeline Safety Improvement Act of 2002 was signed into law on December 17, 2002, providing guidelines in the areas of testing, education, training and communication. The Act requires pipeline companies to perform integrity tests on pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within 10 years of the date of enactment and must perform subsequent integrity tests on a seven year cycle. At least 50 percent of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing will consist of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition, within one year of the law's enactment, pipeline companies must implement a qualification program to make certain that employees are properly trained, using criteria the U.S. Department of Transportation is responsible for providing. Natural Gas Pipeline Company of America estimates that the average annual incremental expenditure associated with the Pipeline Safety Improvement Act of 2002 will be approximately $8 million to $10 million dollars.

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

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

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

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

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

The following discussion should be read in conjunction with Note 14 of the accompanying Notes to Consolidated Financial Statements, which contains additional information on our risk management activities. Our derivative activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, "Statement 133," which we adopted January 1, 2001.

We enter into derivative contracts solely for the purpose of hedging exposures that accompany our normal business activities. As a result of the adoption of Statement 133, the fair value of our derivative financial instruments utilized for hedging activities as of January 1, 2001 (a loss of $11.9 million) was reported as accumulated other comprehensive income. In accordance with the provisions of Statement 133, we designated these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. We enter into these transactions only with counterparties whose debt securities are rated investment grade by the major rating agencies. In general, the risk of default by these counterparties is low. During the fourth quarter of 2001, however, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under Statement 133. Upon making that determination, we (i) ceased to account for those derivatives as hedges, (ii) entered into new derivative transactions with other counterparties to replace our position with Enron, (iii) designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions and (iv) recognized a $5.0 million pre-tax loss (included with "General and Administrative Expenses" in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron. While we will continue to enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future.

Our businesses require that we purchase, sell and consume natural gas. Specifically, we purchase, sell and/or consume natural gas (i) to serve our regulated natural gas distribution sales customers, (ii) to serve certain of our retail natural gas distribution customers in areas where regulatory restructuring has provided for competition in natural gas supply, for customers who have selected the Company as their supplier of choice under our "Choice Gas" program, (iii) as fuel in certain of our Colorado power generation facilities, (iv) as fuel for compressors located on Natural Gas Pipeline Company of America's pipeline system and (v) for operational sales of gas by Natural Gas Pipeline Company of America. With respect to item (i), we have no commodity risk because the regulated retail gas distribution regulatory structure provides that actual gas cost is "passed-through" to our customers. With

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respect to item (iii), only one of these power generation facilities is not covered by a long-term, fixed price gas supply agreement at a level sufficient for the current and projected capacity utilization. With respect to item (iv), this fuel is supplied by in-kind fuel recoveries that are part of the transportation tariff. Items (ii), (v) and the one power facility included under item (iii) that is not covered by a long-term fixed-price natural gas supply agreement, give rise to natural gas commodity price risk which we have chosen to substantially mitigate through our risk management program, utilizing financial derivative products.

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

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

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

We use a Value-at-Risk model to measure the risk of price changes in the natural gas and natural gas liquids markets. Value-at-Risk is a statistical measure of how much the marked-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We use a closed form model to evaluate risk on a daily basis. Our Value-at-Risk computations use a confidence level of 97.7 percent for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7 percent probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk amount presented. Instruments evaluated by the model include forward physical gas, storage and transportation contracts and financial products including commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. During 2003, Value-at-Risk reached a high of $11.7 million and a low of $4.5 million. Value-at-Risk at December 31, 2003, was $11.7 million and, based on quarter-end values, averaged $8.0 million for 2003.

Our calculated Value-at-Risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivatives assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. In addition, as discussed preceding, we enter into these derivatives solely for

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the purpose of mitigating the risks that accompany our normal business activities and, therefore, the change in the market value of our portfolio of derivatives is, with the exception of a minor amount of hedging inefficiency, offset by changes in the value of the underlying physical transactions.

During the three years ended December 31, 2003, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized a pre-tax gain of approximately $56,000 in 2003 and pre-tax losses of approximately $46,000 and $5,000 in 2002 and 2001, respectively, as a result of ineffectiveness of these hedges, which amounts are reported within the caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statements of Operations. There was no component of these derivative instruments' gain or loss excluded from the assessment of hedge effectiveness.

As the hedged sales and purchases take place and we record them into earnings, we will also reclassify the gains and losses included in accumulated other comprehensive income into earnings. We expect to reclassify into earnings, during 2004, substantially all of the $7.2 million balance in accumulated other comprehensive income representing unrecognized net losses on derivative activities at December 31, 2003. During the three years ended December 31, 2003, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

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

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

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

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

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57

Report of Independent Auditors

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

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan, Inc. and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 12(C) and Note 20 to the consolidated financial statements, the Company changed its method of accounting for its Capital Trust Securities effective December 31, 2003.

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

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

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

PricewaterhouseCoopers LLP

Houston, Texas
March 3, 2004

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