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SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

For the quarterly period ended September 30, 2003
or

For the transition period from _____________to_____________

Commission File Number 1-6446

Kinder Morgan, Inc.
(Exact Name of Registrant as Specified in Its Charter)

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes x  No o

The number of shares outstanding of the registrant's common stock, $5 par value, as of October 31, 2003 was 123,232,365 shares.

KINDER MORGAN, INC. AND SUBSIDIARIES
FORM 10-Q
QUARTER ENDED SEPTEMBER 30, 2003

Contents

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The accompanying notes are an integral part of these statements.

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The accompanying notes are an integral part of these statements.

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The accompanying notes are an integral part of these statements.

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For supplemental cash flow information, see Note 4.
The accompanying notes are an integral part of these statements.

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We are a provider of energy and related services and have operations in the Rocky Mountain and mid-continent regions of the United States, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma, Texas and Wyoming. We have both regulated and nonregulated operations. Our business activities include: (i) storing, transporting and selling natural gas, (ii) providing retail natural gas distribution services and (iii) operating and, in previous periods, constructing, natural gas-fired electric generation facilities. In addition, we own the general partner interest, as well as significant limited partner interests, in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership, referred to in these Notes as "Kinder Morgan Energy Partners," and receive a substantial portion of our earnings from returns on these investments. Our common stock is traded on the New York Stock Exchange under the symbol "KMI."

We have prepared the accompanying unaudited interim consolidated financial statements under the rules and regulations of the Securities and Exchange Commission. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America. We believe, however, that our disclosures are adequate to make the information presented not misleading. The consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods presented. You should read these interim consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2002 ("2002 Form 10-K"). Certain prior period amounts have been reclassified to conform to the current presentation. Unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries.

1.   Summary of Significant Accounting Policies

For a complete discussion of our significant accounting policies, see Note 1 of Notes to Consolidated Financial Statements included in our 2002 Form 10-K.

Statement of Financial Accounting Standards ("SFAS") No. 123, Accounting for Stock-Based Compensation, encourages, but does not require, entities to adopt the fair value method of accounting for stock-based compensation plans. As allowed under SFAS No. 123, we continue to apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, compensation expense is not recognized for stock options unless the options are granted at an exercise price lower than the market price on the grant date. Had compensation cost for these plans been determined consistent with SFAS No. 123, net income and diluted earnings per share would have been reduced to the pro forma amounts shown in the table below. Because the SFAS No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. Additionally, the pro forma amounts include approximately $206,000 and $291,000 for the three months ended September 30, 2003 and 2002, respectively and $706,000 and $859,000 for the nine months ended September 30, 2003 and 2002, respectively, related to the purchase discount offered under the employee stock purchase plan.

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2.   Earnings Per Share

Basic earnings per common share is computed based on the weighted-average number of common shares outstanding during each period. In recent periods, we have repurchased a significant number of our outstanding shares, see Note 12. Diluted earnings per common share is computed based on the weighted-average number of common shares outstanding during each period, increased by the assumed exercise or conversion of securities (stock options are currently the only such securities outstanding) convertible into common stock, for which the effect of conversion or exercise using the treasury stock method would be dilutive.

Weighted-average stock options outstanding totaling 1.2 million and 2.5 million for the three months ended September 30, 2003 and 2002, respectively and 2.6 million and 2.5 million for the nine months ended September 30, 2003 and 2002, respectively, were excluded from the diluted earnings per common share calculation because the effect of including them would have been antidilutive.

3.   Interest Expense, Net

"Interest Expense - All Other, Net" as presented in the accompanying interim Consolidated Statements of Operations is net of the debt component of the allowance for funds used during construction, which was $0.1 million and $0.6 million for the three months ended September 30, 2003 and 2002, respectively and $0.5 million and $1.4 million for the nine months ended September 30, 2003 and 2002, respectively.

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4.   Cash Flow Information

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Distributions received by our Kinder Morgan Management subsidiary from its investment in i-units of Kinder Morgan Energy Partners are in the form of additional i-units, while distributions made by Kinder Morgan Management to its shareholders are in the form of additional Kinder Morgan Management shares, see Note 6. "Other, Net" as presented in the accompanying interim Consolidated Statements of Cash Flows principally consists of other non-cash increases and decreases to earnings, including amortization of deferred revenue, amortization of debt discount and expense and amortization of interest rate swap proceeds previously received upon termination of the swap. For the nine months ended September 30, 2003, this line item also includes approximately $4.1 million attributable to a reduction in interest expense associated with the final settlement of a regulatory matter at Natural Gas Pipeline Company of America.

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5.   Comprehensive Income

Our comprehensive income for the three months and nine months ended September 30, 2003 and 2002 is as follows:

The Accumulated Other Comprehensive Loss of $35.5 million at September 30, 2003 consisted of (i) $17.7 million associated with recognition of a minimum pension liability, (ii) $10.3 million representing our pro rata share of the accumulated other comprehensive loss of Kinder Morgan Energy Partners and (iii) $7.5 million representing unrecognized net losses on derivative activities.

6.   Kinder Morgan Management, LLC

On August 14, 2003, Kinder Morgan Management paid a share distribution of 811,878 of its shares to shareholders of record as of July 31, 2003, based on the $0.65 per common unit distribution declared by Kinder Morgan Energy Partners. On November 14, 2003, Kinder Morgan Management will pay a share distribution of 811,626 of its shares to shareholders of record as of October 31, 2003, based on the $0.66 per common unit distribution declared by Kinder Morgan Energy Partners for the third quarter of 2003. These distributions are paid in the form of additional shares or fractions thereof calculated by dividing the Kinder Morgan Energy Partners' cash distribution per common unit by the average market price of a Kinder Morgan Management share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Kinder Morgan Management has paid share distributions totaling 2,530,792 shares in the nine months ended September 30, 2003.

7.   Investments

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

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partner interest in Kinder Morgan Energy Partners' operating partnerships we made a contribution of approximately $1.8 million.

On June 30, 2003, we received $3.8 million from the sale of our interest in Igasamex USA Ltd. We recorded a pre-tax loss of $4.3 million ($2.7 million after tax) in conjunction with the sale.

On March 6, 2000, we received a promissory note from Orcom Solutions, Inc. as partial consideration for the sale of our en•able joint venture, which note was carried at nominal value due to concerns as to recoverability. During 2003, we received $5.4 million in settlement of this note, of which $2.7 million was paid to PacifiCorp reflecting its 50% interest in en•able. In conjunction with this settlement, we recorded a pre-tax gain of $2.9 million ($1.8 million after tax).

8.   Summarized Income Statement Information for Kinder Morgan Energy Partners, L.P.

Following is summarized income statement information for Kinder Morgan Energy Partners, a publicly traded master limited partnership in which we own the general partner interest. In addition, we own limited partner interests in the form of Kinder Morgan Energy Partners common units, i-units (indirectly through Kinder Morgan Management) and Class B limited partner units. This investment, which is accounted for under the equity method of accounting, is described in more detail in our 2002 Form
10-K. Additional information on Kinder Morgan Energy Partners' results of operations and financial position are contained in its Quarterly Report on Form 10-Q for the quarter ended September 30, 2003 and in its Annual Report on Form 10-K for the year ended December 31, 2002.

9.   Discontinued Operations

During 1999, we adopted and implemented a plan to discontinue a number of lines of business. During 2000, we essentially completed the disposition of these discontinued operations. The cash flows attributable to discontinued operations included in the accompanying interim Consolidated Statements of Cash Flows under the caption "Net Cash Flows Used in Discontinued Operations" result from cash activity attributable to retained liabilities associated with these discontinued operations. Note 8 of Notes to Consolidated Financial Statements included in our 2002 Form 10-K contains additional information on these matters.

10.  Financing

We have available a $445 million 364-day credit facility dated October 14, 2003, and a $355 million three-year revolving credit agreement dated October 15, 2002. The 364-day credit facility replaces a $445 million 364-day facility dated October 15, 2002, and contains covenants and terms similar to those

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in the agreement it replaces. These bank facilities can be used for general corporate purposes, including backup for our commercial paper program and, as discussed in our 2002 Form 10-K, include covenants that are common in such arrangements. Under these bank facilities, we are required to pay a facility fee based on the total commitment, whether used or unused, at a rate that varies based on our senior debt rating. We had no borrowings under our bank facilities at September 30, 2003.

The commercial paper we issue, which is supported by the credit facilities described above, is comprised of unsecured short-term notes with maturities not to exceed 270 days from the date of issue. Commercial paper outstanding at September 30, 2003 was $191.1 million. Our weighted-average interest rate on short-term borrowings outstanding at September 30, 2003 was 1.20 percent. Average short-term borrowings outstanding during the third quarter of 2003 were $193.0 million and the weighted-average interest rate was 1.16 percent. Average short-term borrowings outstanding during the first nine months of 2003 were $192.5 million and the weighted-average interest rate was 1.35 percent.

On March 3, 2003, our $500 million 6.45% Senior Notes matured, and we paid the holders of the notes, utilizing a combination of cash and incremental short-term borrowings.

On October 15, 2003, our Board of Directors approved a cash dividend of $0.40 per common share payable on November 14, 2003 to shareholders of record as of October 31, 2003.

11.  Change in Compensation Policies

On July 16, 2003, we announced a change to our compensation policies. Chairman and Chief Executive Officer Richard D. Kinder will continue to receive $1 per year in salary with no bonuses, stock options, grants of restricted stock or other compensation. The ten most senior executives (excluding Mr. Kinder) will continue to have their base salaries capped at $200,000 per year and will continue to be eligible for annual bonuses when we and Kinder Morgan Energy Partners meet annual earnings per share and distributions per unit targets. In addition, these senior executives are not currently eligible for future stock option grants and have received grants of restricted stock totaling 575,000 shares on July 16, 2003, which will vest 25 percent on the third anniversary of the date of grant and the remaining 75 percent on the fifth anniversary of the date of grant, subject to meeting at least one of certain performance criteria set forth in the restricted stock agreements. We expect that executives will receive no further equity compensation during the five-year life of these restrictions. Other than restricted stock, executives will continue to have only those benefits that are available to all other employees. These performance-based restricted stock grants are subject to "variable plan accounting," requiring that, prior to the measurement date for accounting purposes, we estimate the ultimate compensation expense based on the then-current market price per share of our stock. For the three months ended September 30, 2003, we recognized $1.2 million in compensation expense as a result of these restricted share grants. All other employees will be eligible for annual grants of stock options, which will vest in full three years after the date of issuance. On July 16, 2003, we issued 656,450 options to purchase our common shares for $53.80 (the closing price of our common shares on that date) to eligible employees. We expect to issue to employees fewer than 700,000 options to purchase our common shares annually.

12.  Common Stock Repurchase Plan

On August 14, 2001, we announced a program to repurchase up to $300 million of our outstanding common stock, which program was increased to $400 million and $450 million at February 5, 2002 and July 17, 2002, respectively. As of September 30, 2003, we had repurchased a total of approximately $442.7 million (8,846,000 shares) of our outstanding common stock under the program, of which $25.6

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million (484,200 shares) and $28.0 million (537,800 shares) were repurchased in the three months and nine months ended September 30, 2003, respectively.

13.  Business Segments

In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business segment performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America, a major interstate natural gas pipeline and storage system; (2) TransColorado Gas Transmission Company, referred to as TransColorado Pipeline, an interstate natural gas pipeline located in western Colorado and northwest New Mexico; (3) Kinder Morgan Retail, the regulated sale and transportation of natural gas to residential, commercial and industrial customers (including a small distribution system in Hermosillo, Mexico) and the non-regulated sales of natural gas to certain utility customers under the Choice Gas Program and (4) Power, the operation and, in previous periods, construction of natural gas-fired electric generation facilities.

The accounting policies we apply in the generation of business segment information are generally the same as those described in Note 1 of Notes to Consolidated Financial Statements included in our 2002 Form 10-K, except that (i) certain items below the "Operating Income" line are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners and certain insignificant international investees, are included in segment results. These equity method earnings are included in "Other Income and (Expenses)" in the accompanying interim Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not allocated to individual business segments and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

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BUSINESS SEGMENT INFORMATION

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GEOGRAPHIC INFORMATION

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

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14.  Accounting for Asset Retirement Obligations

We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. This statement changed the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated retirement costs. The statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The impact of the adoption of this statement on us is discussed below by segment.

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

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

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

In our Kinder Morgan Retail storage field operations we would, upon abandonment, be required to plug and abandon the wells and to remove our surface wellhead equipment and compressors. We currently have two small sites in Wyoming that are no longer being used as active storage facilities and estimate that, in 2013, we will incur approximately $200,000 in costs to fulfill these retirement obligations. We have no plans to cease using any of our other storage facilities as they are expected to, for the foreseeable future, provide critical deliverability to our customers in severe cold weather situations. With respect to our small natural gas production field in Colorado, we will be required, upon cessation

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of commercial operations, to plug and abandon the natural gas wells, remove surface equipment and remediate the well sites. We have estimated that this process will start in 2005 and continue through 2013 for a total cost of $240,000, with approximately half the total being spent in the final two years. The recognition of these obligations has resulted in a liability and associated asset of approximately $0.3 million as of January 1, 2003, representing the present value of those future obligations for which we are able to make reasonable estimations of the current fair value due to, as discussed above, our ability to estimate the timing of the incurrence of the expenditures. The remainder of our asset retirement obligations have not been recorded due to our inability to reasonably estimate when they will be settled in cash. We will record liabilities for these obligations when we are able to reasonably estimate their fair value.

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

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

15.  Accounting for Derivative Instruments and Hedging Activities

Our normal business activities expose us to risks associated with changes in the market price of natural gas and associated transportation. We engage in derivative transactions for the purpose of mitigating these risks, which transactions are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and associated amendments. During the three and nine month periods ended September 30, 2003 and 2002, our derivative activities relating to the mitigation of these risks were designated and qualified as cash flow hedges, and the impact of hedge ineffectiveness, while included in our net income, was immaterial. As the hedged sales and purchases take place and we record them into earnings, we also reclassify the gains and losses included in accumulated other comprehensive income into earnings. We expect to reclassify into earnings, during the next twelve months, substantially all of our accumulated other comprehensive loss balance related to these derivatives of $7.5 million, representing unrecognized net losses on derivative activities at September 30, 2003. During the three months and nine months ended September 30, 2003 and 2002, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

We have outstanding fixed-to-floating interest rate swap agreements with a notional principal amount of $1.25 billion at September 30, 2003. These agreements 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 SFAS No. 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 carrying value of the swaps of $83.2 million at September 30, 2003 is included in the

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caption "Deferred Charges and Other Assets" in the accompanying interim Consolidated Balance Sheet. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually.

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 $19.9 million at September 30, 2003 is included in the caption "Value of Interest Rate Swaps" under the heading "Long-term Debt" in the accompanying interim Consolidated Balance Sheet.

16.  Regulatory Matters

On July 17, 2000, Natural Gas Pipeline Company of America filed its compliance plan, including pro forma tariff sheets, pursuant to the Federal Energy Regulatory Commission's ("FERC") Order Nos. 637 and 637-A. The FERC directed all interstate pipelines to file pro forma tariff sheets to comply with new regulatory requirements in the Orders regarding scheduling procedures, capacity segmentation, imbalance management services and penalty credits, or in the alternative, to explain why no changes to existing tariff provisions are necessary. On November 21, 2002, the FERC issued an order approving much of Natural Gas Pipeline Company of America's Order 637 filing, but requiring additional changes. The primary changes 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. That compliance filing is pending FERC action and the resulting tariff sheets are expected to be effective on December 1, 2003.

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

On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, we will no longer be permitted to use commodity price indices to structure transactions on our FERC regulated natural gas pipelines. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the

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contract period for which such rates were negotiated. Price indexed contracts currently constitute an insignificant portion of our contracts on our FERC regulated natural gas pipelines; consequently, we do not believe that this Modification to Policy Statement will have a material impact on our operations, financial results or cash flows.

As a part of the settlement of litigation styled, Jack J. Grynberg, individually and as general partner for the Greater Green River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and K N Energy, Inc., Case No. 90-CV-3686, in early 2002, Mr. Grynberg received $16.825 million from us (including forgiveness of a $10.4 million obligation owing from Mr. Grynberg) and an additional $15.625 million was paid into escrow. Rocky Mountain Natural Gas Company agreed to seek to recover these amounts from its customers/rate payers in a proceeding before the Public Utilities Commission for the State of Colorado (the "CPUC"). Rocky Mountain Natural Gas Company and Kinder Morgan, Inc. made regulatory filings with the CPUC on September 30, 2002, proposing recovery of these amounts as part of their annual Gas Cost Adjustment filing process. We proposed to collect these litigated gas costs, including associated carrying charges, over a 15-year amortization period. On October 30, 2002, the CPUC decided, in open meeting, to allow us to place rates in effect and begin recovery of these costs effective November 1, 2002, subject to refund pending a final determination as to our ability to recover these costs in our rates. An uncontested Stipulation and Settlement Agreement was filed with the CPUC on June 20, 2003, providing for full rate recovery by Rocky Mountain Natural Gas Company and Kinder Morgan, Inc. of $30,173,472 of gas cost payments to Mr. Grynberg. It also provided for $14,451,528 of allowable interest recovery to Rocky Mountain Natural Gas Company and Kinder Morgan, Inc. The total settlement amount of $44,625,000 will be recovered through a special rate rider over a fifteen year period which commenced on November 1, 2002. Following a hearing on July 14, 2003, the presiding administrative law judge issued a recommended decision on September 15, 2003, approving the settlement without modification. That recommended decision became the decision of the Commission by operation of law and is now in effect. Upon expiration of the time period for appeal on November 6, 2003, and if no appeals are filed, $13,281,250, plus interest, will be released from escrow for disbursement to Mr. Grynberg, and $2,343,750, plus interest, will be released from escrow for disbursement to us.

The Wyoming Choice Gas program, under which our customers are permitted to select their own supplier of natural gas, was reviewed by the Wyoming Public Service Commission to determine whether the existing program should continue and whether any program modifications should be made. A hearing was conducted in February 2003 and a decision was issued on March 11, 2003, authorizing the Choice Gas program to continue with several modifications. The traditional regulated pass-on rate must continue to be offered with the Choice Gas program. Customers who do not return a Choice Gas selection form will be assigned to the pass-on tariff rate. The $1 per month Choice Gas customer charge will not be applied to pass-on tariff customers.

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

See Note 9 of Notes to Consolidated Financial Statements included in our 2002 Form 10-K for additional information regarding regulatory matters.

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17.  Environmental and Legal Matters

(A)    Environmental Matters

We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. Additionally, we have established reserves to address known environmental remediation sites. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with these regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs.

See Note 10(A) of Notes to Consolidated Financial Statements included in our 2002 Form 10-K for additional information regarding environmental matters.

(B)    Litigation Matters

United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claims Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The MDL case is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases (referred to as valuation claims). Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The United States' motion to dismiss most of the plaintiff's valuation claims has been granted by the Court. Mr. Grynberg has appealed that dismissal to the 10^th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Discovery is now underway to determine issues related to the Court's subject matter jurisdiction, arising out of the False Claims Act. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to CO₂ production. Defendants have filed briefs opposing leave to amend.

Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company et al. v. Gas Pipelines, et al.), Stevens County, Kansas District Court, Case No. 99 C 30. In May 1999, three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a purported nationwide class action in the Stevens County, Kansas District Court against some 250 natural gas pipelines and many of their affiliates. The petition (recently amended) alleges a conspiracy to underpay royalties, taxes and producer payments by the defendants' undermeasurement of the volume and heating content of natural gas produced from nonfederal lands for more than 25 years. The named plaintiffs purport to adequately represent the interests of unnamed plaintiffs in this action who are comprised of the nation's gas producers, state taxing agencies and royalty, working and overriding interest owners. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees from the

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defendants, jointly and severally. This action was originally filed on May 28, 1999 in Kansas State Court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. Subsequently, one of the defendants removed the action to Kansas Federal District Court and the case was styled as Quinque Operating Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the District of Kansas. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claims Act cases, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. The defendants filed a motion to dismiss on grounds other than personal jurisdiction, which was denied by the Court in August 2002. The motion to dismiss for lack of personal jurisdiction of the nonresident defendants has been briefed and is awaiting decision. Merits discovery has been stayed. The current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the action as a named plaintiff. On April 10, 2003, the Court issued its decision denying plaintiffs' motion for class certification. The plaintiffs moved the Court for permission to amend the complaint. On July 8, 2003, a hearing was held on the motion to amend. On July 28, 2003, the Court granted leave to amend the complaint. The amended complaint does not list us or any of our affiliates as defendants. Additionally, a new complaint was filed but that complaint does not list us or any of our affiliates as defendants. We will continue to monitor these matters.

Adams vs. Kinder Morgan, Inc., et al., Civil Action No. 00-M-516, filed in the United States District Court for the District of Colorado. The case is a purported class action. As of this date no class has been certified. The plaintiffs brought claims alleging securities fraud under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 on behalf of all people who purchased the common stock of Kinder Morgan during the class period from October 30, 1997 to June 21, 1999. The class period occurred prior to the installation of our current management team in October 1999. The complaint centers on allegations of misleading statements concerning operations of the Bushton Processing Plant and certain contracts, as well as allegations of overstatement of income in violation of GAAP during the class period. On February 23, 2001, the federal district court dismissed several claims raised by the plaintiff, with prejudice, and dismissed the remaining claims, without prejudice. On April 27, 2001, the Adams plaintiffs filed their second amended complaint. On March 29, 2002, the federal district court dismissed the Adams plaintiffs' second amended complaint with prejudice. On May 2, 2002, the Adams plaintiffs appealed the dismissal to the 10^th Circuit Court of Appeals. In a published decision, on August 11, 2003, the 10^th Circuit Court of Appeals reversed the district court's dismissal. The 10^th Circuit upheld the dismissal of Mr. Kinder, our Chairman and Chief Executive Officer, from this action. The mandate from the 10^th Circuit Court of Appeals was issued on October 17, 2003.

Darrell Sargent d/b/a Double D Production v. Parker & Parsley Gas Processing Co., American Processing, L.P. and Cesell B. Cheatham, et al., Cause No. 878, filed in the 100th Judicial District Court, Carson County, Texas. The plaintiff filed a purported class action suit in 1999 and amended its petition in late 2002 to assert claims on behalf of over 1,000 producers who process gas through as many as ten gas processing plants formerly owned by American Processing, L.P. ("American Processing"), a former wholly owned subsidiary of Kinder Morgan, Inc. in Carson and Gray counties and other surrounding Texas counties. The plaintiff claims that American Processing (and subsequently, ONEOK, Inc. ("ONEOK"), which purchased American Processing from us in 2000) improperly allocated liquids and gas proceeds to the producers. In particular, among other claims, the plaintiff challenges the accuracy of a computer model used at the plants to allocate liquids and gas proceeds among the producers and processors. The petition asserts claims for breach of contract and Natural Resources Code violations relating to the period from 1994 to the present. To date, the plaintiff has not made a specific

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monetary demand nor produced a specific calculation of alleged damages. The plaintiff has alleged generally in the petition that damages are "not to exceed $200 million" plus attorney's fees, costs and interest. The defendants have filed a counterclaim for overpayments made to producers.

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

The purported class has not been certified. Class discovery is proceeding. The defendants expect to assert objections to class certification upon the completion of class discovery.

Manna Petroleum Services, L.P., et al. v. American Processing, L.P. and Cesell B. Cheatham, et al., Cause No. 31,485, filed in the 223rd Judicial District Court of Gray County, Texas. The plaintiff filed suit in late 1999 and alleges that American Processing (and subsequently ONEOK) improperly allocated liquids and gas proceeds. This suit, which was filed by the same attorney who represents the purported class in the Sargent case discussed above, involves similar allegations as those presented in Sargent except this suit is not styled as a class action. See the discussion of Sargent above for further details. The defendants have filed a counterclaim for overpayments to the plaintiff. The parties are presently engaged in fact and expert discovery, with trial presently scheduled to occur in 2004.

Energas Company, a Division of Atmos Energy Company v. ONEOK Energy Marketing and Trading Company, L.P., et al., Cause No. 2001-516,386, filed in the 72nd District Court of Lubbock County, Texas. The plaintiff is suing several ONEOK entities for alleged overcharges in connection with gas sales, transportation, and other services, and alleged misallocations and meter errors, in and around Lubbock, under three different gas contracts. While the petition is vague, it is broad enough to include claims for the period before and after March 1, 2000 when the assets in question were conveyed by us to ONEOK. We have been defending the case pursuant to an agreement whereby ONEOK is responsible for any damages that may be attributable to the period following ONEOK's acquisition of the pertinent assets on March 1, 2000. On or about October 1, 2003, the plaintiff and ONEOK settled claims that relate to the period after March 1, 2000. Notwithstanding such settlement, the plaintiff continues to assert and we continue to defend against claims that relate to the period before March 1, 2000. In an amended petition filed in mid-2002, the plaintiff alleged damages in excess of $12 million. The defendants have filed a counterclaim for offsetting damages and accounting corrections under the contracts with the plaintiff. The parties are currently engaged in an informal dispute resolution process in an attempt to resolve their accounting and other differences. In the event this process does not resolve the claims, a scheduling order will be established to complete fact discovery and trial. We believe that the resolution of the plaintiff's claims will be for amounts substantially less than the amounts sought.

We believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants and will vigorously defend against them. Based on our evaluation of the above matters, and after consideration of reserves established, we believe that the resolution of such matters will not have a material adverse effect on our business, cash flows, financial position or results of operations. In addition, we are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our investigation and experience

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to date, that the ultimate resolution of such items will not have a material adverse impact on our business, cash flows, financial position or results of operations.

18.  Recent Accounting Pronouncements

In January 2003, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 46, Consolidation of Variable Interest Entities. This interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of variable interest entities (some, but not all, of which have been referred to as "special purpose entities") with certain defined characteristics. One provision of the interpretation increases the minimum amount of third-party investment required to support non-consolidation from 3% to 10%. Certain of the disclosure provisions contained in the interpretation are effective for financial statements issued after January 31, 2003, all of the provisions are immediately applicable to variable interest entities created after January 31, 2003 and public entities with variable interests in entities created before February 1, 2003 are allowed to delay the application of the provisions (other than the transition disclosure provisions) to that entity no later than the end of the first interim or annual reporting period ending after December 15, 2003, as long as the public entities have not issued financial statements reporting that variable interest entity in accordance with Interpretation No 46.

The principal impact of this interpretation on us is that, upon implementation, we expect to begin consolidation of Triton Power Company LLC and its wholly owned subsidiary, Triton Power Michigan LLC, the lessee of the Jackson, Michigan power generation facility. We operate the Jackson facility and have a preferred interest in Triton Power Company LLC, in which the common interest is owned by others. Neither entity has debt but, as a result of this consolidation, we will include the lease obligation on the Jackson plant in our consolidated financial statements. We expect to apply the provisions of the statement as of December 31, 2003 and, at that time, the total remaining lease payments will be $540.9 million and the total annual payments will be $21.7 million, $20.3 million, $20.3 million, $20.4 million and $20.6 million for 2004 through 2008, respectively. The difference between the earnings impact under consolidation and under the currently-applied cost method is not expected to be material.

In addition, a preliminary conclusion has been reached that the trusts which are our wholly owned subsidiaries that issued our trust preferred trust securities are variable interest entities for purposes of applying this statement and, further, that upon application of this statement these trusts would no longer be consolidated. Assuming that this conclusion is not changed, we expect that, upon application of the statement, an amount equal to $283.6 million, the carrying value of our Junior Subordinated Interest Deferral Debentures, will be reported as part of long-term debt in our consolidated balance sheet in place of the $275 million of trust preferred securities currently reported and our $8.6 million investment in the common securities of the trusts will be reported as part of investments in our consolidated balance sheet.

On April 30, 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133.

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The new guidance amends SFAS No. 133 for decisions made:

The amendments set forth in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly. In particular, this statement clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative as discussed in SFAS No. 133. In addition, it clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS No. 149 amends certain other existing pronouncements. Those changes will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting.

The statement is effective for contracts entered into or modified after June 30, 2003, except as stated below and for hedging relationships designated after June 30, 2003. We will apply this guidance prospectively. We do not expect the impacts of adopting this statement on our financial position or results of operations to be material.

The provisions of this statement that relate to SFAS No. 133 implementation issues that have been effective for fiscal quarters that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. In addition, certain provisions relating to forward purchases or sales of "when-issued" securities or other securities that do not yet exist, should be applied to existing contracts as well as new contracts entered into after June 30, 2003.

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

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

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

This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003, except for mandatorily redeemable financial instruments of nonpublic entities. It is to be implemented by reporting the cumulative effect of a change in accounting principle for financial instruments created before the issuance date of the statement and still existing at the beginning of the interim period of adoption. Restatement is not permitted. We adopted SFAS No. 150 effective July 1, 2003. As a result, we (i) reclassified our trust preferred securities to the debt portion of our balance sheet and (ii) began classifying payments made by us in conjunction with the trust preferred securities as interest expense, rather than minority interest.

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The following discussion should be read in conjunction with (i) the accompanying interim Consolidated Financial Statements and related Notes and (ii) the Consolidated Financial Statements, related Notes and Management's Discussion and Analysis of Financial Condition and Results of Operations included in our 2002 Form 10-K. Due to the seasonal variation in energy demand, among other factors, the following interim results may not be indicative of the results to be expected over the course of an entire year. In this report Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership in which we own the general partner interest and significant limited partner interests, is referred to as "Kinder Morgan Energy Partners."

Net income increased from $80.4 million in the third quarter of 2002 to $95.6 million in the third quarter of 2003, an increase of $15.2 million (19%). Total diluted earnings per common share increased from $0.66 in the third quarter of 2002 to $0.77 in the third quarter of 2003, an increase of $0.11 (17%).

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Income was positively affected in the third quarter of 2003, relative to 2002, primarily by (i) increased equity in earnings of Kinder Morgan Energy Partners reflecting the strong performance from the assets owned and/or operated by Kinder Morgan Energy Partners, (ii) increased earnings from our NGPL and TransColorado business segments, as discussed in more detail in the individual business segment discussions following, (iii) reduced interest expense from notes, debentures and commercial paper as a result of lower outstanding debt and lower interest rates and (iv) a lower effective tax rate in 2003. These positive impacts were partially offset by (i) increased income tax expense due to the increased pre-tax income in 2003, (ii) increased general and administrative expenses in 2003 due principally to higher costs for employee benefits and (iii) decreased earnings from our Retail and Power business segments in 2003, as discussed in more detail in the individual business segment discussions following. The number of shares used to calculate diluted earnings per common share was approximately 1.6 million higher in the third quarter of 2003 than in the third quarter of 2002, principally due to (i) incremental shares issued under the employee stock purchase plan, (ii) newly issued restricted shares (see Note 11 of the accompanying Notes to Consolidated Financial Statements), (iii) stock options exercised and (iv) an increase in the number of dilutive stock options resulting from incremental stock option grants and an increase in the average share price for the period. These increases in the number of  shares used to calculate diluted earnings per common share were partially offset by the impact of share repurchases (see Note 12 of the accompanying Notes to Consolidated Financial Statements).

Net income increased from $241.2 million in the first nine months of 2002 to $300.9 million in the first nine months of 2003, an increase of $59.7 million (25%). Total diluted earnings per common share increased from $1.95 in the first nine months of 2002 to $2.43 in the first nine months of 2003, an increase of $0.48 (25%). Income was affected in the first nine months of 2003, relative to 2002, principally by the same factors as previously discussed for the third quarter, except that, on a year-to-date through September 30 basis, (i) segment earnings from our Retail business segment increased during 2003, and, during 2003, we recorded (ii) a $4.1 million reduction of interest expense as a result of the final settlement of a regulatory matter at Natural Gas Pipeline Company of America, (iii) a $2.9 million pre-tax gain ($1.8 million after tax) from recovery of loan principal in excess of our carrying value (see Note 7 of the accompanying Notes to Consolidated Financial Statements) and (iv) a $4.3 million pre-tax loss ($2.7 million after tax) due to the sale of our interest in the Igasamex joint venture (see Note 7 of the accompanying Notes to Consolidated Financial Statements). The number of shares used to calculate diluted earnings per common share was nearly unchanged for the first nine months of 2003, compared to the same period in 2002. On a year-to-date through September 30 basis, the impact of incremental increases in diluted shares outstanding due to (i) shares issued under the employee stock purchase plan, (ii) restricted shares issued and (iii) dilutive stock options, were essentially offset by the impact of share repurchases.

The following comparative discussion of our results of operations is by segment for factors affecting segment earnings, and on a consolidated basis for other factors.

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

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The accounting policies we apply in the generation of business segment information are generally the same as those described in Note 1 of Notes to Consolidated Financial Statements included in our 2002 Form 10-K, except that (i) certain items below the "Operating Income" line are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners and certain insignificant international investees, are included in segment results. These equity method earnings are included in "Other Income and (Expenses)" in our Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not allocated to individual business segments and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

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

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Natural Gas Pipeline Company of America's segment earnings increased by $3.5 million (4%) from the third quarter of 2002 to the third quarter of 2003. 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 as discussed following. Business segment earnings for the third quarter of 2003 were positively impacted, relative to 2002, by (i) increased margin from transportation and storage services primarily resulting from expansion and extension projects coming on line since the end of the second quarter of last year as discussed below, (ii) increased 2003 operational sales of natural gas and (iii) increased margin associated with a regulatory matter that was recently concluded. Results were also affected by increased depreciation expense related to the expansion and extension projects. System throughput decreased by 27.5 trillion Btus (8%) from the third quarter of 2002 to the third quarter of 2003 due primarily to a reduction in volumes on the short haul Louisiana Line caused by reduced eastern market demand off this part of the system. The decrease 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.

Natural Gas Pipeline Company of America's segment earnings increased by $8.3 million (3%) from the first nine months of 2002 to the first nine months of 2003. The increase in operating revenues, which was largely offset by a corresponding increase in cost of sales, was due to increased 2003 revenues from operational natural gas sales and increased revenues from transportation and storage services. Business segment earnings for the first nine months of 2003 were impacted, relative to 2002, principally by the same factors affecting the third quarter, as discussed previously. System throughput increased by 13.5 trillion Btus (1%) from the first nine months of 2002 to the first nine months of 2003 due, in part, to colder than normal weather in this segment's principal market areas during the first quarter of 2003, partially offset by lower volumes in the second and third quarters as a result of the reduction in volumes on the Louisiana Line as discussed previously. This increase did not have a significant direct impact on revenues due to the "demand" structure of transportation contracts as discussed previously. Natural Gas Pipeline Company of America's segment results for the nine months ended September 30, 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 - All Other, Net" as discussed elsewhere herein.

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,

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Natural Gas Pipeline Company of America began construction of 10.7 Bcf of storage service expansion at the existing North Lansing storage facility in east Texas, all of which is fully subscribed under long-term contracts. Although construction on the $35.6 million project won't be totally completed until early 2004, the service is available at this time. Please refer to our 2002 Form 10-K for additional information regarding Natural Gas Pipeline Company of America.

TransColorado Pipeline's segment earnings increased from $4.8 million in the third quarter of 2002 (representing a 50% equity method interest in earnings) to $4.9 million in the third quarter of 2003 (representing fully consolidated results at the 100% ownership level). This minor earnings increase, despite the significant increase in ownership, reflects the impact on certain transportation contracts of the narrowing of basis differentials in recent periods. As these basis-differential sensitive contracts are renewed or expire, the capacity is contracted for under more traditional fixed-fee arrangements. During the third quarter of 2002, TransColorado Pipeline was a joint venture in which we shared ownership equally with an affiliate of Questar Corp. We acquired full ownership through a purchase of Questar's interest effective October 2002. Long-haul capacity on TransColorado is now fully subscribed into 2004.

TransColorado Pipeline's segment earnings increased from $6.9 million in the first nine months of 2002 (representing a 50% equity method interest in earnings) to $17.5 million in the first nine months of 2003 (representing fully consolidated results at the 100% ownership level). Results for the first nine months of 2003, relative to 2002, reflected, in addition to the increased level of ownership, the favorable impact of wide basis differentials on certain transportation contracts, which basis differentials have narrowed in recent periods.

In September 2003, we announced that we had signed a 10-year, firm natural gas transportation contract with an undisclosed shipper that will support our expansion of the TransColorado Pipeline system. The expansion project will provide an additional 125,000 dekatherms per day of firm natural gas transportation capacity on the TransColorado Pipeline system from northwestern Colorado to Blanco, New Mexico. The project, which is expected to cost less than $50 million to complete, will entail the construction of three new compressor stations and the modification of equipment at two existing locations, which will increase compression by more than 20,000 horsepower. We expect to file for a Federal Energy Regulatory Commission certificate before the end of this year for the authority to construct the facilities and place them into service. Subject to appropriate regulatory approvals, the

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additional capacity is anticipated to be available during the third quarter of 2004. Please refer to our 2002 Form 10-K for additional information regarding TransColorado Pipeline.

Kinder Morgan Retail

Kinder Morgan Retail's segment earnings decreased by $0.6 million (8%) from the third quarter of 2002 to the third quarter of 2003. Segment results were negatively impacted in 2003, relative to 2002, by (i) a reduction in irrigation volumes in 2003 resulting from increased precipitation in Kinder Morgan Retail's service territory, (ii) reduced margins from commodity gas sales in 2003 due to higher gas costs and (iii) increased 2003 depreciation expense resulting from asset additions. These negative impacts were partially offset by (i) reduced 2003 operations and maintenance expenses and (ii) continued customer growth in Colorado.

Kinder Morgan Retail's segment earnings increased by $6.2 million (16%) from the first nine months of 2002 to the first nine months of 2003. Segment results were positively impacted in 2003, relative to 2002, by (i) a shift in timing of certain items affecting margin by approximately $3 million between the first and fourth quarters of 2003, (ii) reduced operations and maintenance expenses and (iii) increased system throughput volumes resulting from (1) increased space-heating demand caused by colder weather in the first quarter of 2003 (partially offset by weather-related reductions in irrigation volumes in the second and third quarters) and (2) continued customer growth in Colorado. These positive impacts were partially offset by increased depreciation expense resulting from asset additions. Our weather hedging program continued to contribute to stability in Kinder Morgan Retail's seasonal earnings pattern by reducing the impact of weather-related demand fluctuations. This hedging strategy is discussed in detail in our 2002 Form 10-K.

Kinder Morgan Retail has undertaken two expansion projects in western Colorado that are expected to contribute to future earnings growth. A mainline project from Gypsum to Dotsero has been completed and is in service. A mainline project from near Montrose to Ouray is in progress with completion expected by mid-2004. Please refer to our 2002 Form 10-K for additional information regarding Kinder Morgan Retail.

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