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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

For the quarterly period ended September 30, 2004
or

For the transition period from _____________to_____________

Commission file number 1-06446


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 29, 2004 was 123,879,969 shares.

KINDER MORGAN, INC. AND SUBSIDIARIES
FORM 10-Q
QUARTER ENDED SEPTEMBER 30, 2004


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.

4

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 an energy transportation, storage and related services provider that has operations in the Rocky Mountain and mid-continent regions of the United States, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Louisiana, Missouri, Nebraska, New Mexico, Oklahoma, Texas and Wyoming. Our business activities include: (i) storing, transporting and selling natural gas, (ii) providing retail natural gas distribution services and (iii) operating and, in previous periods, constructing electric generation facilities. We have both regulated and nonregulated operations. 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, 2003 ("2003 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 2003 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 would not be recognized for stock options unless the options were granted at an exercise price lower than the market price on the grant date, which we have not done. 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, among other factors, 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 $218,000 and $206,000 for the three months ended September 30, 2004 and 2003, respectively and $726,000 and $706,000 for the nine months ended September 30, 2004 and 2003, 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 11. 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 0.3 million and 1.2 million for the three months ended September 30, 2004 and 2003, respectively, and 0.2 million and 2.6 million for the nine months ended September 30, 2004 and 2003, 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, 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 $0.3 million and $0.1 million for the three months ended September 30, 2004 and 2003, respectively, and $0.7 million and $0.5 million for the nine months ended September 30, 2004 and 2003, 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.

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5.   Comprehensive Income

Our comprehensive income is as follows:

The Accumulated Other Comprehensive Loss of $72.7 million at September 30, 2004 consisted of (i) $62.4 million representing our pro rata share of the accumulated other comprehensive loss of Kinder Morgan Energy Partners and (ii) $10.3 million representing unrecognized net losses on hedging activities.

6.   Kinder Morgan Management, LLC

On August 13, 2004, Kinder Morgan Management made a distribution of 0.018039 of its shares per outstanding share (920,140 total shares) to shareholders of record as of July 30, 2004, based on the $0.71 per common unit distribution declared by Kinder Morgan Energy Partners for the second quarter of 2004. On November 12, 2004, Kinder Morgan Management will make a distribution of 0.017892 of its shares per outstanding share (929,105 total shares) to shareholders of record as of October 29, 2004, based on the $0.73 per common unit distribution declared by Kinder Morgan Energy Partners for the third quarter of 2004. These distributions are paid in the form of additional Kinder Morgan Management shares or fractions thereof calculated by dividing 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.

7.   Investments and Sales

In July 2004, we sold our remaining surplus LM6000 gas-fired turbine for consideration of $8.3 million (net of marketing fees), which consideration consisted of $2.0 million in cash, a note receivable of $6.5 million and a payable for marketing fees of $0.2 million. The $5.0 million current portion of this note receivable is recorded in the caption "Note Receivable" in our Consolidated Balance Sheet as of September 30, 2004.

In April 2004, we sold two surplus LM6000 gas-fired turbines for consideration of $16.5 million (net of marketing fees), which consideration consisted of $2.4 million in cash, a note receivable of $14.5 million and a payable for marketing fees of $0.4 million. During September 2004, the remaining balance of this receivable was collected. In June 2004, we sold two surplus LM6000 turbines and two boilers to Kinder Morgan Production Company, L.P., a subsidiary of Kinder Morgan Energy Partners, for their

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estimated fair market value of $21.1 million, which we received in cash. This equipment was a portion of the equipment that became surplus as a result of our decision to exit the power development business. The book value of the remaining surplus power generation equipment available for sale at September 30, 2004 was $26.9 million.

In February 2004, Kinder Morgan Energy Partners issued 5.3 million common units in a public offering at a price of $46.80 per common unit, receiving total net proceeds (after underwriting discount) of $237.8 million. We did not acquire any of these common units. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transaction) from approximately 19.0% to approximately 18.5% and had the associated effects of increasing (i) our investment in the net assets of Kinder Morgan Energy Partners by $23.2 million, (ii) associated accumulated deferred income taxes by $24,000 and (iii) paid-in capital by $40,000 and, in addition, reduced our equity method goodwill in Kinder Morgan Energy Partners by $23.1 million. In addition, in February 2004, in order to maintain our one percent general partner interest in Kinder Morgan Energy Partners' operating partnerships, we made a contribution of approximately $2.6 million.

On March 25, 2004, Kinder Morgan Management closed the issuance and sale of 360,664 listed shares in a limited registered offering. None of the shares in the offering were purchased by Kinder Morgan, Inc. Kinder Morgan Management used the net proceeds of approximately $14.9 million from the offering to buy additional i-units from Kinder Morgan Energy Partners.

8.   Summarized Income Statement Information for Kinder Morgan Energy Partners

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 to limited partner interests in the form of Kinder Morgan Energy Partners common units, i-units 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 2003 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, 2004 and in its Annual Report on Form 10-K for the year ended December 31, 2003.

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 7 of Notes

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to Consolidated Financial Statements included in our 2003 Form 10-K contains additional information on these matters.

10.  Financing

At September 30, 2004, we had available an $800 million five-year senior unsecured revolving credit facility dated August 18, 2004. This credit facility replaced a $445 million 364-day credit facility dated October 14, 2003 and a $355 million three-year revolving credit agreement dated October 15, 2002, and includes covenants and requires payment of facility fees that are similar in nature to the covenants and facility fees required by the revolving bank facilities it replaces, which are discussed in our 2003 Form 10-K. This credit facility can be used for general corporate purposes, including serving as support for our commercial paper program. Under this bank facility, 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 facility at September 30, 2004.

The commercial paper we issue, which is supported by the credit facility 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, 2004 was $37.6 million, representing a reduction of $90.3 million from the $127.9 million outstanding at December 31, 2003. Our weighted-average interest rate on short-term borrowings outstanding at September 30, 2004 was 1.85 percent. Average short-term borrowings outstanding during the third quarter of 2004 were $87.5 million and the weighted-average interest rate was 1.53 percent. Average short-term borrowings outstanding during the first nine months of 2004 were $115.1 million and the weighted-average interest rate was 1.23 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 on hand and incremental short-term borrowing. Our current maturities of long-term debt of $580 million at September 30, 2004 consisted of (i) $5 million of current maturities of our 6.50% Series Debentures due September 1, 2013, (ii) $500 million of 6.65% Series Senior Notes due March 1, 2005 and (iii) $75 million of 8.75% Series Debentures due October 15, 2024, which we redeemed on October 21, 2004. Our $150 million of 6.67% Series Debentures due November 1, 2027, which had been redeemable at par through a one-time option by the holders on November 1, 2004, are reflected in "Long-term Debt" on the accompanying Consolidated Balance Sheet as of September 30, 2004 since the holders did not elect to require us to redeem the debentures.

On August 13, 2004, we paid a cash dividend on our common stock of $0.5625 per share to shareholders of record as of July 30, 2004. On October 20, 2004, our Board of Directors approved a cash dividend of $0.5625 per common share payable on November 12, 2004 to shareholders of record as of October 29, 2004.

11.  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, $450 million, $500 million and $550 million in February 2002, July 2002, November 2003 and April 2004, respectively. As of September 30, 2004, we had repurchased a total of approximately $507.8 million (9,963,900 shares) of our outstanding common stock under the program, of which $15.8 million (264,900 shares) and $55.1 million (931,100 shares) were repurchased in the three months and nine months ended September 30, 2004, respectively. We repurchased $25.6 million (484,200 shares) and $28.0 million (537,800 shares) of our common stock in the three months and nine months ended September 30, 2003, respectively. (See the table included under Part II, Item 2 elsewhere in this report.)

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12.  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, 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 sale 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 applied to our consolidated operations and described in Note 1 of Notes to Consolidated Financial Statements included in our 2003 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.

13.  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, 2004 and 2003, our derivative activities relating to the mitigation of

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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 $10.3 million, representing unrecognized net losses on derivative activities at September 30, 2004. During the three and nine months ended September 30, 2004 and 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. In conjunction with these activities, we are required to place funds in margin accounts (included with "Restricted Deposits" in the accompanying interim Consolidated Balance Sheets) when the market value of these derivatives with specific counterparties exceeds established limits, or in conjunction with the purchase of exchange-traded derivatives.

We had outstanding fixed-to-floating interest rate swap agreements with a notional principal amount of $1.5 billion at September 30, 2004. 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 fair value of the outstanding swaps of $79.8 million at September 30, 2004 is included in the 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 in cash. We are amortizing this amount (reducing interest expense) over the remaining period the 6.65% Senior Notes are outstanding. The unamortized balance of $5.9 million at September 30, 2004 is included in the caption "Value of Interest Rate Swaps" under the heading "Long-term Debt" in the accompanying interim Consolidated Balance Sheet.

14.  Employee Benefits

(A)    Retirement Plans

The components of net periodic pension cost for our retirement plans are as follows:

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During the third quarter of 2004, we contributed $1.8 million to our retirement plans. We do not expect to make a contribution to our retirement plans during the fourth quarter of 2004.

(B)    Other Postretirement Employee Benefits

The components of net periodic benefit cost for our postretirement benefit plan are as follows:

We previously disclosed in our 2003 Form 10-K that we did not expect to make any significant contributions to our postretirement benefit plan during 2004 and, as of September 30, 2004, we continue to expect that total contributions to our postretirement benefit plan during 2004 will not be significant.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 ("the Act") was signed into law. In January 2004, the FASB issued Staff Position FAS 106-1 to provide guidance on accounting and disclosure for the Act as it pertains to postretirement benefit plans, and in May 2004, the FASB issued Staff Position FAS 106-2, effective July 1, 2004, which provides specific authoritative guidance on the accounting for the federal subsidy included in the Act. In the third quarter of 2004, our board approved a resolution to amend our postretirement benefit plan to eliminate prescription drug benefits for Medicare eligible retirees effective January 1, 2006, which eliminates any potential effects on our periodic postretirement benefit costs due to the federal subsidy included in the Act.

15.  Regulatory Matters

On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate natural gas pipeline was required to file a compliance plan by that date and was required to 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 (in general, a Hinshaw pipeline is a pipeline that receives gas at or within a state boundary, is regulated by an agency of that state, and all the gas it transports is consumed within that state), 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 ("LDCs") are excluded, however, if they do not make any off-system sales. The Standards of Conduct require, inter alia, separate staffing of interstate pipelines and their Energy Affiliates (but certain support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an Energy Affiliate. Natural Gas Pipeline Company of America and Kinder Morgan Interstate Gas Transmission LLC, a subsidiary of Kinder Morgan Energy Partners, filed for clarification and rehearing of Order No. 2004 on December 29, 2003, and numerous other rehearing requests have been submitted. In the request for rehearing, Natural Gas Pipeline Company of America and Kinder Morgan Interstate Gas

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Transmission LLC asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of Energy Affiliates. On February 9, 2004, Natural Gas Pipeline Company of America, TransColorado Gas Transmission Company, Canyon Creek Compression Company and Horizon Pipeline Company filed their compliance plans under Order No. 2004. In addition, on February 19, 2004, all of these interstate pipelines filed a joint request with the interstate pipelines owned by Kinder Morgan Energy Partners asking that their interaction with intrastate/Hinshaw pipeline affiliates be exempted from the Standards of Conduct. Separation from these entities would be the most burdensome requirement of the new rules for us.

On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the effective date of the new Standards of Conduct from June 1, 2004, to September 1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but provided further clarification or adjustment in several areas. The FERC continued the exemption for LDCs that do not make off-system sales and clarified that the LDC exemption applies if the LDC is also a Hinshaw pipeline. The FERC also clarified that an LDC can engage in certain sales and other Energy Affiliate activities to the limited extent necessary to support sales to customers located on its distribution system, and sales necessary to remain in balance under pipeline tariffs, without becoming an Energy Affiliate. The FERC declined to exempt natural gas producers from the definition of Energy Affiliate. The FERC also declined to exempt natural gas intrastate and Hinshaw pipelines, processors and gatherers from the definition of Energy Affiliate, but did clarify that such entities will not be Energy Affiliates if they do not participate in gas or electric commodity markets or interstate capacity markets (as capacity holder, agent or manager) or in financial transactions related to such markets. The FERC also clarified further the personnel and functions that can be shared by interstate natural gas pipelines and their Energy Affiliates, including senior officers and risk management personnel and the permissible role of holding or parent companies and service companies. The FERC also clarified that day-to-day operating information can be shared by interconnecting entities. Finally, the FERC clarified that an interstate natural gas pipeline and its Energy Affiliate can discuss potential new interconnects to serve the Energy Affiliate, but subject to very onerous posting and record-keeping requirements. The Kinder Morgan interstate natural gas pipelines have sought rehearing to clarify the applicability of the LDC and Parent Company exemptions to them.

On July 21, 2004, Natural Gas Pipeline Company of America, TransColorado Gas Transmission Company, Canyon Creek Compression Company and Horizon Pipeline Company filed additional joint requests with Trailblazer Pipeline Company and Kinder Morgan Interstate Gas Transmission LLC, subsidiaries of Kinder Morgan Energy Partners, asking for limited exemptions from certain requirements of FERC Order 2004 and asking for an extension of the deadline for full compliance with Order 2004 until 90 days after the FERC has completed action on the pipelines' various rehearing and exemption requests. The pipelines also requested that Rocky Mountain Natural Gas Company, one of our wholly owned subsidiaries, be classified as an exempt LDC for purposes of Order 2004. These exemptions request relief from the independent functioning and information disclosure requirements of Order 2004. The exemption requests propose to treat as Energy Affiliates within the meaning of Order 2004 two groups of employees, (i) individuals in the Choice Gas Commodity Group within our Retail operations and (ii) commodity sales and purchase personnel within Kinder Morgan Energy Partners' Texas Intrastate operations. Order 2004 regulations governing relationships between interstate pipelines and their Energy Affiliates would apply to relationships with these two groups. Under these proposals, certain critical operating functions could continue to be shared.

On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC extended the effective date of the new Standards of Conduct from September 1, 2004 to September 22, 2004. Also in this order, among other actions, the FERC denied the request for rehearing made by the Kinder Morgan

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interstate natural gas pipelines to clarify the applicability of the LDC and Parent Company exemptions to them.

On September 20, 2004, the FERC issued an order that conditionally granted the July 21, 2004 joint requests for limited exemptions from the requirements of the Standards of Conduct described above. In that order, the FERC directed Natural Gas Pipeline Company of America, TransColorado Gas Transmission Company, Canyon Creek Compression Company, Horizon Pipeline Company and the affiliated interstate natural gas pipelines owned by Kinder Morgan Energy Partners to submit compliance plans regarding these exemptions within 30 days. These compliance plans were filed on October 19, 2004 and set out certain steps taken by our interstate pipelines to assure that employees in the Choice Gas Commodity Group within our Retail operations and the commodity sales and purchasing personnel of Kinder Morgan Energy Partners' Texas intrastate operations do not have access to restricted interstate pipeline information or receive preferential treatment as to interstate pipeline services. The FERC will not enforce compliance with the independent functioning requirement of the Standards of Conduct as to these employees until 30 days after it acts on these compliance filings. In all other respects, our interstate natural gas pipelines were required to comply with the Standards of Conduct as of September 22, 2004.

Our interstate natural gas pipelines have implemented compliance with the Standards of Conduct as of September 22, 2004, subject to the exemptions described in the prior paragraph. Compliance includes, inter alia, the posting of compliance procedures and organizational information for each interstate pipeline on its internet website, the posting of discount and tariff discretion information and the implementation of independent functioning for Energy Affiliates not covered by the prior paragraph (electric and gas gathering, processing or production affiliates).

On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC-regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, we will no longer be permitted to use commodity price indices to structure transactions on our FERC-regulated natural gas pipelines. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. Price indexed contracts currently constitute an insignificant portion of the contracts on our FERC-regulated natural gas pipelines. Moreover, in subsequent orders in individual pipeline cases, the FERC has allowed negotiated rate transactions using pricing indices so long as revenue is capped by the applicable maximum rate(s). Rehearing on this aspect of the Modification to Policy Statement has been sought by Natural Gas Pipeline Company of America and others, but the FERC has not yet acted on rehearing.

On February 20, 2004, the D.C. Circuit Court of Appeals for the District of Columbia remanded back to the FERC a Williston Basin Interstate Pipeline proceeding in which the Court ruled that the FERC did not explain how the selective discounting policy adopted by the FERC in the Colorado Interstate Gas Co. and Granite State Gas Transmission cases would not compromise the pipelines' ability to target discounts at particular receipt/delivery points, subsystems or other defined geographic areas. On June 1, 2004, the FERC issued a Notice of Request for Comments, in the Williston Basin Interstate Pipeline proceeding, on issues pertaining to discounting policy adopted in the Colorado Interstate Gas Co. and Granite State Gas Transmission cases. Comments were due on August 9, 2004. Numerous parties filed comments, including Natural Gas Pipeline Company of America as part of the Kinder Morgan Interstate Pipeline filing. The FERC's decision in this case will affect the extent to which interstate pipelines such as Natural Gas Pipeline Company of America and their customers can specify rates at secondary points, which are binding on both parties as part of the service contract.

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

See Note 8 of Notes to Consolidated Financial Statements included in our 2003 Form 10-K for additional information regarding regulatory matters.

16.  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 9(A) of Notes to Consolidated Financial Statements included in our 2003 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 complaint asks to recover all royalties the Government allegedly should have received had the volume and heating content of the natural gas been valued properly, along with treble damages and civil penalties as provided for in the False Claims Act. Mr. Grynberg, as relator, seeks his statutory share of any recovery, plus expenses and attorney fees and costs. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The MDL case is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases (referred to as valuation claims). Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The United States' motion to dismiss most of the plaintiff's valuation claims has been granted by the Court. Mr. Grynberg has appealed that dismissal to the 10^th Circuit, which has requested briefing regarding its jurisdiction over

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that appeal. Discovery to determine issues related to the Court's subject matter jurisdiction, arising out of the False Claims Act, is complete, and briefing is underway. 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.

Lamb v. Kinder Morgan, Inc., et al., Civil Action No. 00-M-516, (formerly Adams v. Kinder Morgan, Inc. et al.) filed in the United States District Court for the District of Colorado. The case was originally filed on March 8, 2000 and is a purported class action. As of this date no class has been certified. Plaintiffs seek compensatory damages against all defendants jointly and severally, together with interest, attorney fees and expenses. The plaintiffs brought claims alleging securities fraud under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 on behalf of all people who purchased the common stock of Kinder Morgan during the class period from October 30, 1997 to June 21, 1999. The class period occurred prior to the installation of our current management team in October 1999. The complaint centers on allegations of misleading statements concerning operations of the Bushton Processing Plant and certain contracts, as well as allegations of overstatement of income in violation of accounting principles generally accepted in the United States of America during the class period. On February 23, 2001, the federal district court dismissed several claims raised by the plaintiff, with prejudice, and dismissed the remaining claims, without prejudice. On April 27, 2001, the Adams plaintiffs filed their second amended complaint. On March 29, 2002, the federal district court dismissed the Adams plaintiffs' second amended complaint with prejudice. On May 2, 2002, the Adams plaintiffs appealed the dismissal to the 10^th Circuit Court of Appeals. In a published decision, on August 11, 2003, the 10^th Circuit Court of Appeals reversed the district court's dismissal, but upheld the dismissal of Mr. Kinder, our Chairman and Chief Executive Officer, from this action. The mandate from the 10^th Circuit Court of Appeals was issued on October 17, 2003. Briefing regarding class certification is complete and a decision is pending. Merits discovery commenced on June 7, 2004. The Court granted Mr. Adam's motion to withdraw as a lead plaintiff. As a result, the case is now styled as Lamb v. Kinder Morgan, Inc. et al. A settlement conference occurred on August 2, 2004. No settlement was reached. Discovery is proceeding.

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 100^th 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 methods and assumptions used at the plants to allocate liquids and gas proceeds among the producers and processors. The petition asserts claims for breach of contract and Natural Resources Code violations relating to the period from 1994 to the present. To date, the plaintiff has not made a specific monetary demand nor produced a specific calculation of alleged damages. The plaintiff has alleged generally in the petition that damages are "not to exceed $200 million" plus attorney's fees, costs and interest. The defendants have filed a counterclaim for overpayments made to producers.

Pioneer Natural Resources USA, Inc., formerly known as Parker & Parsley Gas Processing Company ("Parker & Parsley"), is a co-defendant. Parker & Parsley has claimed indemnity from American Processing based on its sale of assets to American Processing on October 4, 1995. We have accepted indemnity and defense subject to a reservation of rights pending resolution of the suit. The plaintiff has also named ONEOK as a defendant. We and ONEOK are defending the case pursuant to an agreement

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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 223^rd Judicial District Court of Gray County, Texas. Plaintiff filed suit in late 1999 and alleged that American Processing, L.P., a former wholly owned subsidiary of Kinder Morgan, Inc., and subsequently ONEOK, which purchased American Processing from us in 2000, misallocated proceeds from the sale of compression liquids at a gas processing plant in Pampa, Texas. On March 17, 2004, following a bench trial, the Court issued a letter ruling which stated that plaintiff Manna Petroleum Services is entitled to recover damages in the principal sum of $556,932. The letter ruling also stated that the plaintiff may seek attorney's fees and costs and instructed the plaintiff to file proposed findings of fact and rulings of law before final judgment is entered. On April 28, 2004, defendants filed a motion for reconsideration of the Court's letter ruling and this motion is pending. Plaintiffs filed an application to recover $534,172 in attorney's fees and defendants have opposed this application. Plaintiff has not filed proposed findings of facts and rulings of law, and the trial court's judgment shall not be entered until a ruling on defendants' motion for reconsideration.

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 72^nd 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 engaged in fact discovery and trial is expected to occur in 2005 upon a date to be determined. Based on discovery obtained to date, we believe that resolution of the plaintiff's claims will be for amounts substantially less than the amounts sought.

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

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

17.  Recent Accounting Pronouncements

In January 2004, the FASB issued FASB Staff Position ("FSP") FAS 106-1, Accounting and Disclosure

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Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act"). This FSP permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to postpone accounting for the effects of the Act. Regardless of whether a company elects that deferral, the FSP requires certain disclosures pending further consideration of the underlying accounting issues. In May 2004, the FASB issued FSP FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which supersedes FSP FAS 106-1 effective July 1, 2004. FSP FAS 106-2 provides transitional guidance for accounting for the effects of the Act on the accumulated projected benefit obligation and periodic postretirement health care benefit expense. In the third quarter of 2004, our board approved a resolution to amend our postretirement benefit plan to eliminate prescription drug benefits for Medicare eligible retirees effective January 1, 2006, which eliminates any potential effects on our periodic postretirement benefit costs due to the federal subsidy included in the Act.

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

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

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

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

The principal impact of this interpretation on us is that, effective December 31, 2003, we began consolidation of Triton Power Company LLC and its wholly-owned subsidiary Triton Power Michigan LLC, which is the lessee of the Jackson, Michigan power generation facility. We operate and have a preferred interest in this entity in which the common interest is owned by others. Triton Power Company LLC has no debt but, as a result of this consolidation, we are including the lease obligation on the Jackson plant in our consolidated financial statements. The difference between the earnings impact under consolidation and under the previously applied equity method is not material.

In addition, as a result of the implementation of this interpretation, effective December 31, 2003, we (i) no longer include the transactions and balances of our business trusts, K N Capital Trust I and K N

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Capital Trust III, in our consolidated financial statements and (ii) began including our Junior Subordinated Deferrable Interest Debentures issued to the Capital Trusts in a separate caption under the heading "Long-term Debt" in our Consolidated Balance Sheets.

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

The revised statement requires additional disclosures to those in the original SFAS No. 132 about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The revised statement also requires interim disclosures; see Note 14.

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

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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) our 2003 Form 10-K, including the Consolidated Financial Statements, related Notes and Management's Discussion and Analysis of Financial Condition and Results of Operations. 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." Additional information on Kinder Morgan Energy Partners is contained in its report on Form 10-K for the year ended December 31, 2003 and in its report on Form 10-Q for the quarter ended September 30, 2004.

Our discussion and analysis of financial condition and results of operations are based on our interim consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America as applicable to interim financial statements to be filed with the Securities and Exchange Commission 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 that 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. Information regarding our accounting policies and estimates that we consider to be "critical" can be found in our 2003 Form 10-K. There have not been any significant changes in these policies and estimates during the first nine months of 2004.

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Our net income increased from $95.6 million in the third quarter of 2003 to $111.9 million in the third quarter of 2004, an increase of 17 percent. This increase is comprised of an $8.4 million increase in operating income and an $18.8 million increase in "Other Income and (Expenses)," partially offset by a $10.9 million increase in income tax expense. Our net income increased from $300.9 million in the first nine months of 2003 to $343.4 million in the first nine months of 2004, an increase of 14 percent. This increase is comprised of an $11.8 million increase in operating income and a $59.4 million increase in "Other Income and (Expenses)," partially offset by a $28.7 million increase in income tax expense. Following is a discussion of items affecting operating income and other income and expenses. Refer to the headings "Other Income and (Expenses)" and "Income Taxes" included elsewhere herein for additional information regarding these items.

Our results for the third quarter of 2004, in comparison to 2003, reflect an increase of $2.7 million (1%) in operating revenues and an increase of $8.4 million (10%) in operating income. The increase in operating revenues was attributable to the inclusion of our Triton Power affiliates in our consolidated

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operating results during 2004 and increased 2004 revenues in our TransColorado and Kinder Morgan Retail business segments, partially offset by decreased revenues in our Natural Gas Pipeline Company of America business segment (see the individual business segment discussions following for additional information). Operating income was positively impacted in the third quarter of 2004, relative to 2003, by increased earnings from our Natural Gas Pipeline Company of America and TransColorado business segments and the inclusion of the results of operations of our Triton Power affiliates in our 2004 consolidated operating results due to our adoption of a recent accounting pronouncement. Triton's third quarter $7.7 million contribution to our consolidated operating income is entirely offset by minority interests. These positive impacts were partially offset by decreased earnings from our Kinder Morgan Retail and Power business segments.

Our results for the first nine months of 2004, in comparison to 2003, reflect increases of $21.4 million (3%) in operating revenues and $11.8 million (4%) in operating income. The increase in operating revenues was principally attributable to increased 2004 revenues in our Kinder Morgan Retail and Power business segments, partially offset by decreased 2004 revenues in our Natural Gas Pipeline Company of America business segment. Operating income was positively impacted in the first nine months of 2004, relative to 2003, by increased earnings from our Natural Gas Pipeline Company of America business segment and the consolidation of the results of operations of our Triton Power affiliates in our 2004 consolidated results. Triton's $9.7 million contribution to our consolidated operating income for the first nine months of 2004 is entirely offset by minority interests. These positive impacts were offset by (i) decreased earnings from our Power and Kinder Morgan Retail business segments and (ii) increased general and administrative expenses due principally to increased legal, accounting and employee benefit expenses. Please refer to the individual business segment discussions included elsewhere herein for additional information regarding business segment results.

"Other Income and (Expenses)" increased from $69.3 million in the third quarter of 2003 to $88.1 million in the third quarter of 2004, an increase of 27 percent. This increase reflected increased equity in earnings of Kinder Morgan Energy Partners in the third quarter of 2004, due principally to the improved performance from the assets held by Kinder Morgan Energy Partners, partially offset by the inclusion of the minority interests in Triton Power, as discussed previously, and by an increase of $3.4 million in minority interest expense attributable to the minority interests in Kinder Morgan Management, LLC.

For the nine months ended September 30, 2004 and 2003, "Other Income and (Expenses)" increased from $197.2 million in 2003 to $256.6 million in 2004, an increase of 30 percent. This increase reflected increased equity in earnings of Kinder Morgan Energy Partners in 2004, due principally to the improved performance from the assets held by Kinder Morgan Energy Partners, and decreased 2004 interest expense resulting from our lower weighted-average interest rates and our lower debt balances. These positive impacts were partially offset by the inclusion of the minority interests in Triton Power, as discussed previously, and by an increase of $5.8 million in minority interest expense attributable to the minority interests in Kinder Morgan Management, LLC.

Diluted earnings per common share increased from $0.77 in the third quarter of 2003 to $0.90 in the third quarter of 2004, an increase of 17 percent. This increase reflected, in addition to the increase attributable to financial and operating impacts discussed preceding, a partially offsetting decrease attributable to an increase of 0.3 million (0.3%) in average shares outstanding. The increase in average shares outstanding resulted from (i) newly-issued shares due to (1) the employee stock purchase plan, (2) the issuance of restricted stock and (3) exercise of stock options by employees and (ii) the increased dilutive effect of stock options resulting from the increase in the market price of our shares, partially offset by our share repurchases (see Notes 2 and 11 of the accompanying Notes to Consolidated Financial Statements).

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Diluted earnings per common share increased from $2.43 in the first nine months of 2003 to $2.75 in the first nine months of 2004, an increase of 13 percent. This increase reflected, in addition to the increase attributable to financial and operating impacts discussed preceding, a partially offsetting decrease attributable to an increase of 1.2 million (1%) in average shares outstanding. Average shares outstanding increased for the first nine months of 2004 for principally the same reasons as it increased in the third quarter as discussed previously.

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 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.

The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to our consolidated operations and described in Note 1 of Notes to Consolidated Financial Statements included in our 2003 Form 10-K, except that (i) certain items below the "Operating Income" line (such as interest expense) 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

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"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.

Natural Gas Pipeline Company of America's segment earnings increased by $2.6 million (3%) from the third quarter of 2003 to the third quarter of 2004. Segment earnings for the third quarter of 2004 were positively impacted, relative to 2003, by (i) increased transportation and storage service revenues in 2004 resulting, in part, from successful re-contracting of transportation capacity and the recent expansion of our storage system, (ii) increased margins from operational gas sales largely due to higher market prices, (iii) $1.4 million in pre-tax gains in 2004 from the sale of certain land parcels in Illinois, and (iv) reduced 2004 property tax expenses. These favorable impacts were partially offset by (i) the fact that 2003 results included increased margin associated with the favorable conclusion of a regulatory matter, (ii) increased operations and maintenance expenses in 2004 resulting from increased hydrostatic testing and electric compression costs and (iii) increased depreciation expense. The decrease in overall operating revenues in the third quarter of 2004, relative to 2003, was largely the result of (i) decreased operational gas sales volumes and (ii) 2003 revenue recorded in conjunction with the conclusion of a regulatory matter. These negative impacts on revenue were partially offset by the increase in transportation and storage service revenues, as discussed above.

Natural Gas Pipeline Company of America's segment earnings increased by $18.3 million (7%) from the first nine months of 2003 to the first nine months of 2004. Segment results for the first nine months of 2004 were impacted, relative to 2003, by principally the same factors affecting third quarter results, as discussed above, except that on a year-to-date basis property tax expenses increased in 2004. In addition, on a year-to-date basis, 2004 results were positively impacted by $4.0 million in contractual customer penalty charges. These charges were billed prior to December 1, 2003, the effective date for Natural Gas Pipeline Company of America's Order 637 provisions, but had been reserved pending the final outcome of its Order 637 filings (see Note 15 of the accompanying Notes to Consolidated Financial Statements). The decrease in operating revenues in the first nine months of 2004, relative to 2003, was also largely the result of decreased operational gas sales volumes, partially offset by an increase in transportation and storage and penalty revenues. The increases in systems throughput for both the third quarter and first nine months of 2004, relative to 2003, did not have a significant direct impact on

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revenues or segment earnings due to the fact that transportation revenues are derived primarily from "demand" contracts in which shippers pay a fee to reserve a set amount of system capacity for their use.

In October 2004, we announced that we will spend approximately $52 million on acquisitions and expansions to Natural Gas Pipeline Company of America's pipeline and storage systems. Included in this amount are (i) the acquisition of the Black Marlin Pipeline, completed on September 1, 2004, which will add 38,000 dekatherms per day ("dth/day") of incremental capacity to the Amarillo to Gulf Coast line, (ii) the addition of 51,000 dth/day of cross haul capacity to the Amarillo to Gulf Coast line and 20,000 dth/day of incremental capacity to the Oklahoma Extension (also known as Segment One) by adding additional compressor horsepower and modifying certain existing compressor facilities and (iii) a 10 Bcf expansion of the Sayre storage facilities in Beckham County, Oklahoma. During the second quarter of 2004, Natural Gas Pipeline Company of America completed construction of its previously announced 10.7 Bcf storage service expansion at its existing North Lansing storage facility in east Texas, all of which is fully subscribed under long-term contracts. Please refer to our 2003 Form 10-K for additional information regarding Natural Gas Pipeline Company of America.

TransColorado's segment earnings increased by $2.2 million (45%) from the third quarter of 2003 to the third quarter of 2004. Segment results for the third quarter of 2004, relative to 2003, were impacted primarily by increased natural gas transportation revenues. The increases in TransColorado's natural gas transportation revenues and systems throughput volumes reflect, primarily, the expansion of TransColorado's system that was completed and placed into service in August 2004 (see the discussion below).

TransColorado's segment earnings increased by $0.7 million (4%) from the first nine months of 2003 to the first nine months of 2004. Segment results for the first nine months of 2004 were impacted, relative to 2003, by increased natural gas transportation revenues in the third quarter of 2004, as discussed above, partially offset by decreased natural gas transportation revenues during the first two quarters of 2004 resulting principally from lower basis differentials in 2004, and the fact that in 2003 a larger proportion of natural gas transportation contracts were tied to the basis differential. "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. As a result of recent contracting activities, in which we entered into long-term, fixed price contracts for most of TransColorado's long haul capacity, and the expansion of TransColorado's system capacity, the volume of activity that is subject to changes in basis differentials has decreased to 8% of its long haul capacity as of September 30, 2004.

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On September 25, 2003, we announced that we had signed a 10-year, firm natural gas transportation contract with an undisclosed shipper that would allow us to construct facilities resulting in a 125,000 dth/day expansion of capacity on the TransColorado system. The facilities consist of three new compressor stations and modifications at two existing compressor stations, which increase compression by 20,000 horsepower. In March 2004, we received FERC approval to construct the facilities and place them into service. In August 2004, the facilities were completed and placed into service.

In October 2004, we announced plans to expand TransColorado's system to provide for an additional 300,000 dth/day of primarily backhaul capacity. This expansion project, which will cost less than $20 million, is supported by commitments from an undisclosed shipper for up to 280,000 dth/day of capacity through 2015, with an option for a five-year extension. To accommodate the increased volumes on the northern part of the system, TransColorado will be reversing the flow of natural gas on the 46-mile portion of the system between DeBeque, Colorado and the Greasewood Hub in Rio Blanco County, Colorado, modifying existing interconnect facilities and installing a new north-end compressor station. This project will enhance the flexibility of TransColorado's system by allowing gas on the northern end of the pipeline to flow both northward and southward. Following completion of the project, current and future shippers will still have the ability to schedule natural gas for delivery from the far north end of the TransColorado system southward to San Juan Basin delivery points. In addition, the expanded system features an interconnect with the Wyoming Interstate Company pipeline at the Greasewood Hub. Subject to regulatory approvals, the additional capacity is expected to be available in January 2006. Please refer to our 2003 Form 10-K for additional information regarding TransColorado.