Kinder Morgan, Inc. 2005 Form 10-K

Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act: Yes þ No o

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act: Yes o No þ

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 þ No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer þ Accelerated filer o Non-accelerated filer o

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $7,944,425,382 at June 30, 2005.

The number of shares outstanding of the registrant’s common stock, $5 par value, as of February 28, 2006 was 133,591,141 shares.

Part III of this report incorporates by reference specific portions of the Registrant’s Proxy Statement relating to its 2006 Annual Meeting of Stockholders.

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

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. (a Kansas corporation, incorporated on May 18, 1927, formerly known as K N Energy, Inc.) and its consolidated subsidiaries. All dollars are United States dollars, except where stated otherwise. Canadian dollars are designated as C$. All volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute and at 60 degrees Fahrenheit and, in most instances, are rounded to the nearest major multiple. In this report, the term “MMcf” means million cubic feet, the term “Bcf” means billion cubic feet, the term “TJ” means terajoule (one thousand gigajoules), the term “PJ” means petajoule (one million gigajoules), the term “bpd” means barrels per day and the terms “Dth” (dekatherms) and “MMBtus” mean million British Thermal Units (“Btus”). Natural gas liquids consist of ethane, propane, butane, iso-butane and natural gasoline. For the purpose of making Imperial to Metric conversions, 1 mile equals 1.609 kilometers and 1MMBtu equals 1.055 gigajoules. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes.

We are one of the largest energy transportation and storage companies in North America, operating, either for ourselves or on behalf of Kinder Morgan Energy Partners, L.P. (“Kinder Morgan Energy Partners”), or owning an interest in approximately 43,000 miles of pipelines and approximately 150 terminals. We own and operate Natural Gas Pipeline Company of America, also referred to as NGPL, a major interstate natural gas pipeline system with approximately 9,800 miles of pipelines and associated storage facilities. We own and operate a refined petroleum products and crude oil pipeline business with three pipelines, (a) Trans Mountain Pipeline, (b) Corridor Pipeline and (c) a one-third interest in the Express and Platte pipeline systems. We own and operate retail natural gas distribution businesses serving approximately 892,000 customers in British Columbia and 245,000 customers in Colorado, Nebraska and Wyoming. We have constructed, and currently operate and own interests in certain natural gas-fired electric generation facilities. These businesses are discussed in detail in the next section of this report. Our common stock is traded on the New York Stock Exchange under the symbol “KMI.” Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.

On October 7, 1999, we completed the acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and the sole stockholder of the general partner of Kinder Morgan Energy Partners. To effect that acquisition, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan (Delaware). Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan (Delaware), was named our Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. As a result of that acquisition and certain subsequent transactions, we own the general partner of, and have a significant limited partner interest in, Kinder Morgan Energy Partners, one of the largest publicly traded pipeline limited partnerships in the United States in terms of market capitalization, and the owner and operator of the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Kinder Morgan Energy Partners owns an interest in and/or operates a diverse group of assets used in the transportation, storage and processing of energy products, including (i) refined petroleum products pipeline systems with more than 10,000 miles of products pipelines and over 60 associated terminals, (ii) approximately 15,000 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, (iii) approximately 85 liquid and bulk terminal facilities and more than 50 rail transloading and materials handling facilities located throughout the United States, handling over 80 million tons of coal, petroleum coke and other dry-bulk

materials annually and having a liquids storage capacity of almost 70 million barrels for refined petroleum products, chemicals and other liquid products and (iv) Kinder Morgan CO₂ Company, L.P., which transports, markets and produces carbon dioxide for use in enhanced oil recovery operations and owns interests in and/or operates seven oil fields in West Texas, all of which are using or have used carbon dioxide injection operations. Kinder Morgan CO₂ Company, L.P. also owns and operates the Wink Pipeline, a crude oil pipeline in West Texas. Additional information concerning our investment in Kinder Morgan Energy Partners and its various businesses is contained in Note 2 of the accompanying Notes to Consolidated Financial Statements and in Kinder Morgan Energy Partners’ 2005 Annual Report on Form 10-K. Beginning January 1, 2006, we will consolidate Kinder Morgan Energy Partners’ accounts and balances in our consolidated financial statements. See Note 20 of the accompanying Notes to Consolidated Financial Statements.

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

In the initial public offering, we purchased 10% of the Kinder Morgan Management shares, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which is consolidated in our financial statements) owned by the public is reflected as minority interest on our balance sheet. The earnings recorded by Kinder Morgan Management that are attributed to its shares held by the public are reported as “minority interest” in our Consolidated Statements of Operations. Subsequent to the initial public offering by Kinder Morgan Management of its shares, our ownership interest in Kinder Morgan Management has changed because (i) we recognize our share of Kinder Morgan Management’s earnings, (ii) we record the receipt of distributions attributable to the Kinder Morgan Management shares that we own, (iii) Kinder Morgan Management has made additional sales of its shares (both through public offerings and otherwise), (iv) pursuant to an option feature that was previously available to Kinder Morgan Management shareholders but no longer exists, we exchanged certain of the Kinder Morgan Energy Partners’ common units held by us for Kinder Morgan Management shares held by the public and (v) we sold some Kinder Morgan Management shares we owned in order to generate taxable gains to offset expiring tax loss carryforwards. At December 31, 2005, we owned 9.98 million Kinder Morgan Management shares representing 17.2% of Kinder Morgan Management’s total outstanding shares. Additional information concerning the business of, and our investment in and obligations to, Kinder Morgan Management is contained in Note 3 of the accompanying Notes to Consolidated Financial Statements and in Kinder Morgan Management’s 2005 Annual Report on Form 10-K.

On November 30, 2005, we completed the acquisition of all of the stock of Terasen Inc. (“Terasen”) pursuant to a Combination Agreement dated as of August 1, 2005, among us, one of our wholly owned subsidiaries, and Terasen (the “Combination Agreement”). Terasen shareholders were able to elect, for each Terasen share held, either (i) C$35.75 in cash, (ii) 0.3331 shares of our common stock, or (iii) C$23.25 in cash plus 0.1165 shares of our common stock. In the aggregate, we issued approximately 12.5 million shares of our common stock and paid approximately C$2.49 billion (or approximately US$2.13 billion) in cash to Terasen securityholders.

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

We intend to maintain a capital structure that provides flexibility and stability, while returning value to our shareholders through dividends and share repurchases. During 2005, we utilized cash generated from operations (including cash received from distributions attributable to our investment in Kinder Morgan Energy Partners) to pay common stock dividends, finance our capital expenditures program and repurchase our common shares. In the fourth quarter of 2005, we issued approximately 12.5 million shares of our common stock and $2.15 billion of long-term debt in connection with our acquisition of Terasen. In recent periods, we have increased our common stock dividends in response to changes in income tax laws that have made dividends a more efficient way to return cash to our shareholders. At December 31, 2005, our total debt to total capital ratio was 55.6%, with approximately 50% of our debt subject to floating interest rates.

We expect to benefit from accretive acquisitions (primarily by Kinder Morgan Energy Partners). Kinder Morgan Energy Partners has a multi-year history of making accretive acquisitions, which benefit us through our limited and general partner interests. This acquisition strategy is expected to continue, although we can provide no assurance that such acquisitions will occur in the future. In addition, we expect to benefit from expansion opportunities pursued both by Kinder Morgan Energy Partners and by us. Along with Sempra Pipelines & Storage, a unit of Sempra Energy (NYSE:SRE), Kinder Morgan Energy Partners is developing the Rockies Express Pipeline, a new natural gas pipeline that when completed will link producing areas in the Rocky Mountain region to the upper Midwest and Eastern United States. On February 28, 2006, the joint venture partners announced that they have received binding firm commitments for all of the capacity of the pipeline. The estimated over $4 billion project will be placed in service in segments and is expected to be completed by June 2009, subject to regulatory approvals. We expect to expand, within strict guidelines as to risk, rate of return and timing of cash flows, Kinder Morgan Canada’s (formerly Terasen Pipelines’) pipeline systems and NGPL’s pipeline system and acquire natural gas retail distribution properties that fit well with our current profile. In addition, we expect to fund the anticipated growth in our Terasen Gas and Kinder Morgan Retail service areas.

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

Terasen Acquisition
As discussed above, on November 30, 2005 we completed the Terasen acquisition. To finance the acquisition, we issued approximately 12.5 million shares of our common stock and our wholly owned Canadian subsidiary issued a total of $2.15 billion of U.S. dollar, fixed-rate notes with five, ten and thirty year maturities, which are fully and unconditionally guaranteed by us. The proceeds of the notes were used to repay in full a short-term bank loan incurred to initially finance the cash portion of the consideration paid to Terasen’s shareholders. Subsequently, through a wholly owned Canadian subsidiary, we swapped the debt into Canadian dollar fixed

Dividends
We increased our annual rate of cash dividends per share by $0.55 in the first quarter of 2005, $0.20 in the third quarter of 2005, and by $0.50 in the first quarter of 2006, reaching an annual rate of $3.50. These increases were principally in response to federal tax legislation enacted in 2003 and to increased cash flow.

Share Repurchase Program
We expanded the size of our common stock repurchase program by $50 million and $125 million in April and November 2005, respectively, to a total of $925 million. From the inception of the program in August 2001 through December 31, 2005, we have repurchased approximately $875 million of common stock, including approximately $314 million in 2005.

NGPL Re-Contracting Transportation and Storage Capacity
In 2005, NGPL extended long-term, firm transportation and storage contracts with some of its largest shippers. Combined, the contracts represent approximately 1.9 million Dth per day of peak-period firm transportation service. As of the end of 2005, firm long-haul transportation capacity was sold out through February 2007 (except for a portion of summer-only capacity available on the Gulf Coast Line), and storage is fully contracted until April 2007.

NGPL Storage Expansions
In August 2005, NGPL filed a certificate application with the Federal Energy Regulatory Commission (“FERC”) for an additional 10 Bcf expansion of its North Lansing storage facility in east Texas, which is expected to be completed in 2007 at a cost of approximately $64 million. NGPL completed an open season for this expansion and binding long-term precedent agreements have been executed on all of the additional capacity. The FERC order approving the project was issued January 23, 2006. In addition, NGPL began drilling storage injection/withdrawal wells during the third quarter of 2005 to expand its Sayre storage field in Oklahoma by 10 Bcf. The $35 million project is expected to begin service in the spring of 2006, and all of the expansion capacity has been contracted for under long-term agreements.

NGPL Amarillo-Gulf Coast Line Expansion
In June 2005, NGPL received a certificate from the FERC for its Amarillo-Gulf Coast cross-haul expansion, which is fully subscribed under long-term contracts. The $20.7 million project will add 51,000 Dth per day of capacity and is expected to be in service in April 2006. In addition, NGPL is adding a new compressor station to Segment 17 of its Amarillo-Gulf Coast line that will provide 140 MMcf per day of additional capacity. The $17 million project is expected to be in service by the fall of 2006, and all of the additional capacity is fully contracted.

New Credit Facility
In August 2005, we established a new five-year senior unsecured revolving credit facility with a capacity of $800 million. This five-year facility, which is the same size as the five-year facility it replaced, contains essentially the same credit covenants as the prior facility, except the definition of consolidated net worth, which is a component of total capitalization, was revised to exclude other comprehensive income/loss, and the definition of consolidated indebtedness was revised to exclude the debt of Kinder Morgan Energy Partners that is guaranteed by us. This facility was amended in October 2005 (i) to exclude the effects of consolidating Kinder Morgan Energy Partners as discussed in Note 20 of the accompanying Notes to Consolidated Financial Statements, (ii) to make administrative changes and (iii) to change definitions and covenants to reflect the inclusion of Terasen as a subsidiary of ours.

Sales of Kinder Morgan Management Shares
During 2005, we sold a total of 5.67 million Kinder Morgan Management shares that we owned for approximately $254.8 million. We recognized pre-tax gains totaling $78.5 million associated with these sales. These sales allow us to fully utilize a capital loss carryforward that was scheduled to expire in 2005.

Note 19 of the accompanying Notes to Consolidated Financial Statements contains financial information about our business segments.

We are an energy infrastructure provider. Our principal business segments are: (1) NGPL and certain affiliates, a major interstate natural gas pipeline and storage system, (2) Kinder Morgan Canada, a refined products and crude oil transportation pipeline business, (3) Terasen Gas, a natural gas distribution business involved in the transmission and distribution of natural gas and propane for residential, commercial and industrial customers in British Columbia, (4) Kinder Morgan Retail, a natural gas distribution business involved in the transmission and distribution of natural gas for residential, commercial, institutional and industrial customers, and the sale of natural gas to certain utility customers under our Choice Gas Program (a program that allows utility customers to choose their natural gas provider), in Colorado, Nebraska and Wyoming and (5) Power, a business that operates (and, in previous periods, constructed) natural gas-fired electric generation facilities. In November 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners for total consideration of $275 million, consisting of approximately $210 million in cash and 1.4 million Kinder Morgan Energy Partners common units. TransColorado’s segment earnings of $20.3 million in 2004 prior to its contribution represented approximately 2% of our total 2004 segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and approximately 2% of our 2004 income from continuing operations before interest and income taxes. As a result of our implementation of a new accounting pronouncement, beginning January 1, 2006, we will include the accounts and balances of Kinder Morgan Energy Partners in our consolidated financial statements. See Note 20 of the accompanying Notes to Consolidated Financial Statements. We expect that, in addition to our five current business segments, we will report the following business segments: (1) Products Pipelines, (2) Natural Gas Pipelines, (3) CO₂ and (4) Terminals.

Natural gas transportation, storage and retail sales accounted for approximately 93%, 92% and 95% of our consolidated revenues in 2005, 2004 and 2003, respectively. During 2005, 2004 and 2003, we did not have revenues from any single customer that exceeded 10% of our consolidated operating revenues. The operations of Kinder Morgan Energy Partners, a significant limited partnership equity-method investee in which we also hold the general partner interest, include (i) liquids and refined petroleum products pipelines, (ii) transportation and storage of natural gas, (iii) carbon dioxide transportation and production of carbon dioxide and oil and (iv) bulk and liquids terminals. Our equity in the earnings of Kinder Morgan Energy Partners (before reduction for the minority interest in Kinder Morgan Management) constituted approximately 54%, 61% and 60% of our income from continuing operations before interest and income taxes in 2005, 2004 and 2003, respectively. The following table gives our segment earnings, our earnings attributable to our investment in Kinder Morgan Energy Partners (net of pre-tax minority interest) and the percent of the combined total each represents, for each of the last two years. In 1999, we discontinued our wholesale natural gas marketing, non-energy retail marketing services and natural gas gathering and processing businesses. Notes 5 and 19 of the accompanying Notes to Consolidated Financial Statements contain additional information on asset sales and our business

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

During 2005, NGPL’s segment earnings of $435.2 million represented approximately 38% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and approximately 39% of our income from continuing operations before interest and income taxes. Through NGPL, we own and operate approximately 9,800 miles of interstate natural gas pipelines, storage fields, field system lines and related facilities, consisting primarily of two major interconnected natural gas transmission pipelines terminating in the Chicago, Illinois metropolitan area. The system is powered by 57 compressor stations in mainline and storage service having an aggregate of approximately 0.9 million horsepower. NGPL’s system has 605 points of interconnection with 30 interstate pipelines, 20 intrastate pipelines, a number of gathering systems, and 53 local distribution companies and other end users, thereby providing significant flexibility in the receipt and delivery of natural gas. NGPL’s Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 4,400 miles of mainline and various small-diameter pipelines. Its other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,200 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by NGPL’s approximately 800-mile Amarillo/Gulf Coast pipeline. In addition, NGPL owns a 50% equity interest in and operates Horizon Pipeline Company, L.L.C., a joint venture with Nicor-Horizon, a subsidiary of Nicor, Inc. This joint venture owns a natural gas pipeline in northern Illinois with a capacity of 380 MMcf per day.

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

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

NGPL’s principal delivery market area encompasses the states of Illinois, Indiana and Iowa and secondary markets in portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. NGPL is the largest transporter of natural gas to the Chicago market, and we believe that its transportation rates are very competitive in the region. In 2005, NGPL delivered an average of 1.88 trillion Btus per day of natural gas to this market. Given its strategic location at the center of the North American natural gas pipeline grid, we believe that Chicago is likely to continue to be a major natural gas trading hub for growing markets in the Midwest and Northeast.

Substantially all of NGPL’s pipeline capacity is committed under firm transportation contracts ranging from one to five years. Approximately 45% of the total transportation volumes committed under NGPL’s long-term firm transportation contracts as of February 1, 2006 had remaining terms of less than three years. NGPL continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts, and was very successful in doing so during 2005 as discussed under “Developments During 2005” elsewhere in this report. Nicor Gas Company, Peoples Gas Light and Coke Company, and Northern Indiana Public Service Company (NIPSCO) are NGPL’s three largest customers in terms of operating revenues from tariff services. During 2005, approximately 55% of NGPL’s operating revenues from tariff services were attributable to its eight largest customers. Contracts representing approximately 2.5% of NGPL’s total long-haul, contracted firm transport capacity as of January 31, 2006 are scheduled to expire during 2006.

NGPL is one of the nation’s largest natural gas storage operators with over 600 Bcf of total natural gas storage capacity, approximately 250 Bcf of working gas capacity and over 4.2 Bcf per day of peak deliverability from its storage facilities, which are located in major supply areas and near the markets it serves. NGPL owns and operates 13 underground storage reservoirs in eight field locations in four states. These storage assets complement its pipeline facilities and allow it to optimize pipeline deliveries and meet peak delivery requirements in its principal markets. NGPL provides firm and interruptible gas storage service pursuant to storage agreements and tariffs. Firm storage customers pay a monthly demand charge irrespective of actual volumes stored. Interruptible storage customers pay a monthly charge based upon actual volumes of gas stored.

In June 2005, NGPL received a certificate from the FERC for its Amarillo-Gulf Coast cross-haul expansion, which is fully subscribed under long-term contracts. The $20.7 million project will add 51,000 Dth per day of capacity and is expected to be in service in April 2006. In August 2005, NGPL filed a certificate application with the FERC for an additional 10 Bcf expansion of its North Lansing storage facility in East Texas, which is expected to be completed in 2007 at a cost of approximately $64 million. NGPL recently completed an open season for this expansion and binding long-term precedent agreements have been executed on all of the additional capacity. The FERC order approving the project was issued January 23, 2006. The FERC found that NGPL’s reworking of 16 existing injection/withdrawal wells as part of the project required certification, and the order granted that authority. In addition, NGPL began drilling storage injection/withdrawal wells during the third quarter of 2005 to expand its Sayre storage field in Oklahoma by 10 Bcf. The $35 million project is expected to begin service in the spring of 2006 and all of the expansion capacity has been contracted for under long-term agreements. In addition, NGPL is adding a new compressor station to Segment 17 of its Amarillo-Gulf Coast line that will provide 140 MMcf per day of additional capacity. The $17 million project is expected to be in service by the fall of 2006, and all of the additional capacity is fully contracted.

Competition: NGPL competes with other transporters of natural gas in virtually all of the markets it serves and, in particular, in the Chicago area, which is the northern terminus of NGPL’s two major pipeline segments and its largest market. These competitors include both interstate and intrastate natural

gas pipelines and, historically, most of the competition has been from such pipelines with supplies originating in the United States. More recently, NGPL has also faced competition from Alliance Pipeline, which began service during the 2000-2001 heating season carrying Canadian-produced natural gas into the Chicago market. At the same time, new pipelines, such as Vector Pipeline, were constructed for the specific purpose of transporting gas from the Chicago area to other markets, generally further north and further east. The overall impact of the increased pipeline capacity into the Chicago area, combined with additional take-away capacity and the increased demand in the area, has created a situation that remains dynamic with respect to the ultimate impact on individual transporters such as NGPL.

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

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

During 2005, Kinder Morgan Canada’s segment earnings of $12.5 million (representing our ownership of Kinder Morgan Canada for December 2005) represented 1% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and approximately 1% of our income from continuing operations before interest and income taxes.

Terasen Pipelines (Trans Mountain) Inc. (“Trans Mountain”) owns and operates a common carrier pipeline system originating at Edmonton, Alberta for the transportation of crude petroleum, refined petroleum and iso-octane to destinations in the interior and on the west coast of British Columbia. A connecting pipeline owned by a wholly owned subsidiary delivers petroleum to refineries in the State of Washington. Another wholly owned subsidiary owns and operates a six-inch diameter, 25 mile long pipeline for the transportation of jet fuel from Vancouver area refineries and marketing terminals and from Westridge Marine Terminal to Vancouver International Airport.

Trans Mountain’s pipeline is 715 miles in length and has a diameter of 24 inches for most of the line with the exception of two sections of 30-inch diameter pipeline, each having a length of approximately 51 miles. The capacity of the line out of Edmonton ranges from 225,000 bpd when heavy crude represents 20% of the total throughput to 285,000 bpd with no heavy crude. The pipeline system utilizes 11 pump stations controlled by a centralized computer system.

Trans Mountain also operates a 5.3 mile spur line from its Sumas Pump Station to the U.S. – Canada international border where it connects with a 63 mile pipeline system owned and operated by a wholly owned subsidiary. The pipeline system in Washington State has a sustainable throughput capacity of

approximately 135,000 bpd when heavy crude represents approximately 25% of throughput and connects to four refineries located in northwestern Washington State. The volumes of petroleum shipped to Washington State fluctuate in response to the price levels of Canadian crude oil in relation to petroleum produced in Alaska and other offshore sources.

The Trans Mountain pipelines are constructed on freehold lands and rights-of-way held by Trans Mountain. Crossings over or under highways, railways and bridges have been constructed pursuant to orders or permits from the appropriate authorities. Substantially all of Trans Mountain’s pipelines are constructed in rights-of-way granted by the Crown or the owners of privately-held lands, either in perpetuity for as long as they are used for a pipeline, or for fixed terms negotiated by Trans Mountain.

Under published tariffs for the Trans Mountain system, the tolls at December 31, including applicable terminalling and tankage charges, for transportation of light crude oil from Edmonton to principal delivery points are set forth below.

Tolls charged to nine shippers represented 93% of Trans Mountain’s consolidated 2005 revenues.

The petroleum transported through Trans Mountain’s pipeline system originates from fields in Alberta and British Columbia. The refined and partially refined petroleum transported to Kamloops and Vancouver originates from oil refineries located in Edmonton. Petroleum delivered through Trans Mountain’s pipeline system is used in markets in British Columbia and Washington State and elsewhere.

Overall Alberta crude oil supply has been increasing steadily over the past few years as a result of significant oilsands development with projects led by Shell Canada, Suncor Energy and Syncrude Canada. Further development is expected to continue into the future with expansions to existing oilsands production facilities as well as with new projects. In its moderate case, the Canadian Association of Petroleum Producers (“CAPP”) has recently forecasted Western Canadian production to increase by over 700,000 bpd between 2004 through 2010. This supply increase will likely result in constrained pipeline export capacity from Western Canada, which supports Trans Mountain’s view that both the demand for transportation services provided by Trans Mountain’s pipeline and the supply of petroleum will remain strong for the foreseeable future.

In 2005, deliveries on Trans Mountain averaged 220,886 bpd. This was a decrease of 6.4% from average 2004 deliveries of 236,115 bpd. A breakdown of total average deliveries for 2005 and 2004 is as follows:

Throughput in the U.S. pipeline system decreased by 18.6% from 2004 levels. The year over year decrease in Trans Mountain throughput reflects first quarter 2005 refinery turnarounds in Washington State and temporary production outages in the oilsands. Throughput levels in 2005 were also influenced

by refined product margins on the west coast and by crude oil price differentials for Canadian crude compared against competitive offshore supply sources.

Shipments of refined petroleum represent a significant portion of Trans Mountain’s throughput. In 2005, shipments of refined petroleum and iso-octane represented 37% of throughput, as compared with 39% in 2004.

In July 1998, Trans Mountain and Terasen Inc. entered into an agreement with Shell Canada Limited (Shell) and its partners for the construction and operation of the Corridor pipeline system (Corridor Pipeline). The Corridor Pipeline is owned by our subsidiary, Terasen Pipelines (Corridor) Inc. (“Corridor”) and is operated by Kinder Morgan Canada. Revenues and commercial operation commenced in May 2003, following the successful completion of construction.

The Corridor Pipeline provides for the pipeline transportation of diluted bitumen produced at the Muskeg River Mine, located approximately 43 miles north of Fort McMurray, Alberta, to a heavy oil upgrader that Shell and its partners have built adjacent to Shell’s existing Scotford Refinery near Edmonton, Alberta, a distance of approximately 281 miles. A smaller diameter parallel pipeline transports recovered diluent from the upgrader back to the mine. Corridor also consists of two additional pipelines, each 27 miles in length, to provide pipeline transportation between the Scotford Upgrader and the existing trunk pipeline facilities of Trans Mountain and Enbridge Pipelines Inc. in the Edmonton area.

We own a one-third interest in the Express System. The Express System is a batch-mode, common-carrier, crude pipeline system comprised of the Express Pipeline and the Platte Pipeline. The Express System transports a wide variety of crude types produced in Alberta to markets in Petroleum Administration Defense District IV, comprised of the states in the Rocky Mountain area of the United States (“PADD IV”) and Petroleum Administration Defense District II, comprised of the states in the central area of the United States (“PADD II”). The Express System also transports crude oil produced in PADD IV to downstream delivery points in PADD IV and to PADD II.

The Express Pipeline is a 780 mile, 24-inch diameter pipeline that begins at the crude pipeline hub at Hardisty, Alberta and terminates at the Casper, Wyoming facilities of the Platte Pipeline, and includes related metering and storage facilities including tanks and pump stations. At Hardisty, the Express Pipeline receives crude from certain other pipeline systems and terminals, which currently provide access to approximately 1.3 million bpd of crude moving through this delivery hub. The Express Pipeline is the major pipeline transporting Alberta crude into PADD IV.

The Express Pipeline has a design capacity of 280,000 bpd, after an expansion completed in April 2005. Receipts at Hardisty averaged 212,965 bpd during the year ended December 31, 2005, compared with 175,898 bpd during the year ended December 31, 2004.

The Platte Pipeline is a 926 mile, 20-inch diameter pipeline that runs from the crude pipeline hub at Casper, Wyoming to refineries and interconnecting pipelines in the Wood River, Illinois area, and includes related pumping and storage facilities (including tanks). The Platte Pipeline transports crude shipped on the Express Pipeline, crude produced in PADD IV and crude received in PADD II, to downstream delivery points. It is currently the only major crude pipeline transporting crude oil from PADD IV to PADD II. Various receipt and delivery points along the Platte Pipeline, with interconnections to other pipelines, enable crude to be moved to various markets in PADD IV and

PADD II. The Platte Pipeline has a capacity of 150,000 bpd when shipping heavy oil and averaged 137,164 bpd east of Casper during the year ended December 31, 2005, versus 102,500 bpd for the year ended December 31, 2004.

The current Express System rate structure is a combination of committed rates and uncommitted rates. The committed rates apply to those shippers who have signed long-term (10 or 15 year) contracts with the Express System to transport crude on a ship-or-pay basis. Uncommitted rates are the rates that apply to uncommitted services whereby shippers transport oil through the Express System without a long-term commitment between the shipper and the Express System.

Committed rates vary according to the destination of shipments and the length of the term of the transportation services agreement, with those shippers committing to longer-term agreements receiving lower rates.

Express Pipeline received 105,000 bpd of additional firm service commitments to the pipeline starting April 1, 2005, bringing the total firm commitment on Express to 235,000 bpd, or 84% of its total capacity. These contracts expire in 2007, 2012, 2014 and 2015 in amounts of 1%, 40%, 11% and 32% of total capacity, respectively. These contracts provide for committed tolls for transportation on the Express System, which can be increased each year by up to 2%. The remaining capacity is made available to shippers as uncommitted capacity.

Uncommitted rates were established on a cost of service basis and can be changed in accordance with applicable regulations discussed below. See “Regulation” elsewhere in this report. The table below provides a selection of tolls at December 31.

Competition: Trans Mountain’s pipeline to the west coast of North America and the Express System pipeline to the U.S. Rocky Mountains and Midwest are two of several pipeline alternatives for Western Canadian petroleum production, and throughput on these pipelines may decline if overall petroleum production in Alberta declines or if tolls become uncompetitive compared to alternatives. Our oil transportation business competes against other pipeline providers who could be in a position to establish and offer lower tolls, which may provide a competitive advantage in new pipeline development. Throughput on Trans Mountain may decline in situations where west coast petroleum prices, net of transportation costs, are relatively lower than alternative prices in the U.S. Midwest. Throughput on the Express System may also decline as a result of reduced petroleum product demand in the U.S. Rocky Mountains.

During 2005, Terasen Gas’ segment earnings of $45.2 million (representing our ownership of Terasen Gas for December 2005) represented 4% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and approximately 4% of our income from continuing operations before interest and income taxes.

Terasen Gas Inc. provides service to more than 100 communities with a service territory that has an estimated population of approximately four million. Terasen Gas Inc. is one of the largest natural gas

distribution companies in Canada. As of December 31, 2005, Terasen Gas Inc. and its subsidiaries transported and distributed natural gas to 804,743 residential, commercial and industrial customers, representing approximately 87% of the natural gas users in British Columbia. Terasen Gas Inc.’s service area extends from Vancouver to the Fraser Valley and the interior of British Columbia. The transmission and distribution business is carried on under statutes and franchises or operating agreements granting the right to operate in the municipalities or areas served. Terasen Gas Inc. is regulated by the British Columbia Utilities Commission (“BCUC”).

Terasen Gas Inc. provides natural gas distribution services to residential, small commercial and industrial heating customers predominantly on a non-contractual basis, whereby the customers are charged based on general services provided. Larger commercial and industrial customers are normally provided with services on a contractual basis.

Terasen Gas Inc. has approximately 2,200 commercial and industrial customers that arrange for some or all of their own gas supply and use Terasen Gas Inc.’s transportation services for delivery. Notwithstanding shifts over time between utility supply and direct purchases, Terasen Gas Inc.’s earnings remain unaffected since Terasen Gas Inc.’s margins remain substantially the same whether or not customers choose to buy natural gas from Terasen Gas Inc. or arrange their own supply. Customers arranging for their own supply in fact reduce the credit risk to Terasen Gas Inc.

Of Terasen Gas Inc.’s industrial customers, 158 are on interruptible service. The majority of these customers are capable of switching to alternative fuels. Forecast variances in industrial consumption can have an impact on Terasen Gas Inc.’s earnings. However, forecasts are updated annually based largely on the results of an annual survey of industrial customers.

Of the various industries that comprise Terasen Gas Inc.’s industrial market, the pulp and paper and wood products industries combined comprise approximately 47% of total consumption. All other industries individually represent less than 10% of total consumption.

In order to acquire supply resources that ensure reliable natural gas deliveries to its customers, Terasen Gas Inc. purchases supply from a select list of producers, aggregators, and marketers by adhering to strict standards of counterparty creditworthiness, and contract execution/management procedures. Terasen Gas Inc. contracts for approximately 137 PJ of baseload and seasonal supply, of which, 120 PJ is delivered off the Duke Energy Gas Transmission system, and 17 PJ is comprised of Alberta-sourced supply transported into British Columbia via TransCanada Pipelines Limited (“TransCanada”) Alberta and British Columbia systems. The majority of supply contracts in the current portfolio is one year in length, with the exception of one long-term contract expiring in October 2009.

Terasen Gas Inc. serves Greater Vancouver and the Fraser Valley through a transmission and distribution system that connects to the Duke Energy Gas Transmission pipeline near Huntingdon, British Columbia. This transmission system also supplies gas to Terasen Gas (Vancouver Island) Inc. for delivery to the Sunshine Coast, Vancouver Island and to Terasen Gas (Squamish) Inc., a subsidiary of Terasen Gas Inc., for distribution in Squamish, British Columbia. In addition, Terasen Gas Inc. is connected at Huntingdon to Northwest Pipeline to facilitate gas movement both north and south.

In the interior of British Columbia, Terasen Gas Inc. serves municipalities with numerous connections to the Duke pipeline system. Communities in the East Kootenay region of British Columbia are served through connections with TransCanada’s British Columbia system. Terasen Gas Inc. is connected to TransCanada’s British Columbia system through Terasen Gas Inc.’s Southern Crossing Pipeline between Yahk and Oliver. Terasen Gas Inc. also operates a propane distribution system in Revelstoke, British Columbia.

The Duke and TransCanada transportation tolls are regulated by the National Energy Board (“NEB”). Terasen Gas Inc. pays both fixed and variable charges for use of the pipelines, which are recovered through rates paid by Terasen Gas Inc.’s customers.

Terasen Gas Inc. incorporates peak shaving¹ and gas storage facilities into its portfolio to:

Peak shaving facilities supply natural gas to supplement our baseload supply sources at times when the demand for natural gas is greatest.

Terasen Gas Inc.’s peak shaving and storage assets and contracts for 2006 include the following:

Liquefied natural gas (LNG) plant: The plant is located on Tilbury Island in Delta, British Columbia, and has a capacity of approximately 660 TJ with a maximum daily deliverability rate of 165 TJ.

Carbon Storage: Atco Midstream Ltd. owns and operates the Carbon storage facility in Alberta. The contract provides for 3.0 PJ of capacity with a maximum daily deliverability of 28 TJ.

Aitken Creek Storage: Terasen Gas Inc. has storage contracts with Unocal Canada Limited which provide 20 PJ of capacity at the Aitken Creek storage facility in British Columbia, with a daily deliverability rate of 135 TJ.

Jackson Prairie Storage: The Jackson Prairie storage facility is jointly owned by two U.S. Pacific Northwest gas utilities and Northwest Pipeline near Chehalis, Washington. Terasen Gas Inc. is a party to three storage lease agreements that provide the right to approximately 3 PJ of capacity, with a maximum daily deliverability rate of about 110 TJ.

Mist Storage: Terasen Gas Inc. has two contracts with Northwest Natural Gas Company for natural gas storage in Oregon. The contracts provide a total capacity of approximately 3 PJ with a maximum daily deliverability rate of 121 TJ.

Southern Crossing Pipeline Peaking: Terasen Gas Inc. has the ability to interrupt firm transportation customers on the Southern Crossing pipeline in the amount of 0.78 PJ per winter with a maximum of 52 TJ of daily deliverability.

Terasen Gas Inc. is eligible for incentives under the Gas Supply Mitigation Incentive Plan established with the BCUC relating to its off-system sales activities and capacity release of excess transportation and storage capacity. For the 2005 Gas Year which runs from November 2004 to October 2005, Terasen Gas Inc. marketed approximately 36.5 PJ of surplus gas and 41 PJ of excess pipeline and storage capacity, which resulted in margins eligible for incentives totaling C$25.6 million (pre-tax), of which C$1.1 million (pre-tax) accrued to Terasen Gas Inc.

As of December 31, 2005, Terasen Gas Inc. had 23,958 miles of pipelines for use in natural gas transmission and distribution, compared with 23,766 miles as of December 31, 2004. In addition to the pipelines, Terasen Gas Inc. owns properties and equipment utilized for service shops, warehouses, metering, and regulating stations, as well as its main operations center in Surrey, British Columbia.

Terasen Gas Inc.’s pipelines are constructed for the most part under highways and streets pursuant to permits or orders from the appropriate authorities, franchise or operating agreements entered into with municipalities and rights-of-way held directly or jointly with British Columbia Hydro & Power

Authority (“B.C. Hydro”). Compressor stations and major regulator stations are located on freehold land, rights-of-way owned by Terasen Gas Inc. or properties shared with B.C. Hydro.

Terasen Gas Inc. currently holds operating agreements with all of the incorporated municipalities in which it distributes gas in the Greater Vancouver and Fraser Valley service areas, other than Richmond, British Columbia. The operating agreements are in force so long as the distribution lines of Terasen Gas Inc. are operative and do not contain any provision entitling the municipality to purchase the distribution system. No fees are payable by Terasen Gas Inc. under these operating agreements.

Terasen Gas Inc. currently holds franchise or operating agreements with most of the incorporated municipalities in which it distributes gas in the interior of British Columbia. Historically, approximately one-quarter of these franchise agreements contained a provision to the effect that at the end of the term the municipality could purchase the distribution system within the municipality as a going concern and at a price equal to the fair value of the business undertaking. If the municipality did not exercise the right to purchase or grant a new franchise or operating agreement, the gas utility would be required under the Utilities Commission Act to continue to provide service in the municipality unless the BCUC ordered otherwise. While such franchise or operating agreements are in effect, the municipalities receive franchise fees of three per cent of the gross revenue from customers in the municipality. The term of the franchise agreements ranges from 10 to 21 years. Some have expired and Terasen Gas Inc. is currently negotiating renewals and extensions with the remaining municipalities, some of which have a right to purchase the distribution system within their boundaries. For those municipalities with the right to purchase those distribution systems, an arrangement has been developed to transfer the economic risks and rewards of ownership to the municipality, while allowing Terasen Gas Inc. to continue to operate within the municipality.

These arrangements have been entered into with five municipalities to date. In each of the transactions, Terasen Gas Inc. entered into an arrangement whereby the municipality leased Terasen Gas Inc.’s gas distribution assets within the municipality’s boundaries for a term of 35 years for an initial cash payment. Terasen Gas Inc. in turn entered into a 17 year operating lease with the municipality whereby Terasen Gas Inc. will operate the gas distribution assets. Terasen Gas Inc. has the option to terminate the lease of the assets to the municipality at the end of 17 years in exchange for a payment to the municipality equal to the depreciated value of the leased assets. As of December 31, 2005, Terasen Gas Inc. had entered into such arrangements involving a total value of C$153 million.

Terasen Gas (Vancouver Island) Inc. (“TGVI”) owns and operates the natural gas transmission pipeline from the Greater Vancouver area across the Georgia Strait to Vancouver Island and the distribution system on Vancouver Island and along the Sunshine Coast of British Columbia. The combined system consists of 382 miles of natural gas transmission pipelines and 3,194 miles of distribution pipelines, some of which are under water. The combined system has a designed throughput capacity of 144 MMcf per day (155 TJ per day). TGVI serves approximately 85,000 residential, commercial and industrial customers along the Sunshine Coast and in various communities on Vancouver Island including Victoria and surrounding areas, including seven pulp and paper mills on Vancouver Island and the Sunshine Coast and a natural gas-fired electricity generation facility on Vancouver Island. During 2005, TGVI delivered approximately 33.6 petajoules of gas through its system. The rate base of TGVI as of December 31, 2005 was approximately C$454.7 million.

TGVI provides gas transportation service to the seven pulp and paper mills under a long-term transportation service agreement that was amended in December 2004 to extend it beyond the original renewal period by two years to December 31, 2012. The maximum daily volume of firm transportation service under the agreement was 20 TJ per day for 2005. In 2006, the maximum daily volume changes

to 12.5 TJ per day for the remainder of the renewal period. TGVI also delivers gas on both a firm (45.0 TJ per day) and interruptible basis to the gas-fired cogeneration plant at Elk Falls on Vancouver Island.

In order to acquire effective supply resources that ensure reliable natural gas deliveries to its customers, TGVI purchases supply from a select list of producers, aggregators, and marketers by adhering to strict standards of counterparty credit worthiness, and contract execution/management procedures. As of November 1, 2005, TGVI contracted approximately 12.5 TJ per day of baseload supply delivered off the Duke Energy Gas Transmission pipeline. TGVI also purchased approximately 31.8 TJ per day of seasonal supply to meet the higher loads during the winter months of December 2005 to February 2006.

TGVI maintains storage contracts with Unocal Canada Limited at Aitken Creek Storage facility in northern British Columbia, and Northwest Natural Gas Company at Mist Storage facility in Oregon. TGVI’s Aitken Creek Storage contract consists of 2.1 PJ of capacity with 13.6 TJ of daily deliverability and its Mist storage agreement consists of 0.69 PJ of capacity with 26.4 TJ of daily deliverability. TGVI also has access to an estimated 21.1 TJ of daily peaking supply deliverability from various peaking supply arrangements.

Terasen Gas (Whistler) Inc. (“Whistler Gas”) distributes piped propane gas to approximately 2,365 residential and commercial customers in the Whistler area of British Columbia. Whistler Gas owns and operates two propane storage and vaporization plants and approximately 79 miles of distribution pipelines serving customers in the Whistler area. Whistler Gas is regulated by the BCUC. The rate base of Whistler Gas at December 31, 2005 was approximately C$16.9 million.

Competition: Natural gas has maintained a competitive advantage in terms of pricing when compared with alternative sources of energy in British Columbia, despite the significant increase in natural gas commodity prices since 1999. However, because electricity prices in British Columbia continue to be set based on the historical average cost of production, rather than based on market forces, they have remained artificially low compared to market-priced electricity and, as a result, only marginally higher than comparable, market-based natural gas costs. A further sustained increase in natural gas commodity prices could cause natural gas in British Columbia to be uncompetitive with electricity, thereby decreasing the use of natural gas by customers.

During 2005, Kinder Morgan Retail’s segment earnings of $58.2 million represented 5% of total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners and approximately 5% of our income from continuing operations before interest and income taxes. As of December 31, 2005, through Kinder Morgan Retail, our retail natural gas distribution business served approximately 245,000 customers in Colorado, Nebraska and Wyoming through approximately 11,400 miles of distribution and transmission pipelines, underground storage fields, field system lines and related facilities. Kinder Morgan Retail’s intrastate pipelines, distribution facilities and retail natural gas sales in Colorado, Nebraska and Wyoming are subject to the regulatory authority of each state’s utility commission. In addition, Kinder Morgan Retail owns and operates a small natural gas distribution system in Hermosillo, Mexico.

Kinder Morgan Retail’s operations in Nebraska, Wyoming and eastern Colorado serve areas that are primarily rural and agricultural where natural gas is used primarily for space heating, crop irrigation, grain drying and processing of agricultural products. In much of Nebraska, the winter heating load is balanced by irrigation requirements in the summer and grain drying requirements in the fall. Kinder Morgan Retail’s operations in western Colorado serve the fast-growing resort and associated service

areas, and rural communities. These areas are characterized primarily by natural gas use for space heating, with historical annual growth rates of 4-8%. Kinder Morgan Retail’s operations include the sale of natural gas under its Choice Gas programs and the sale of non-jurisdictional products and services, natural gas-related equipment, and installation and repair services.

To support Kinder Morgan Retail’s business, underground storage facilities are used to provide natural gas deliverability for load balancing and peak system demand. Storage services for Kinder Morgan Retail’s natural gas distribution services are provided by (i) three facilities in Wyoming owned by Kinder Morgan, Inc., (ii) one facility in Colorado owned by a wholly owned subsidiary of Kinder Morgan, Inc. and (iii) one facility located in Nebraska and owned by Kinder Morgan Energy Partners. The peak natural gas storage withdrawal capacity available for Kinder Morgan Retail’s business is approximately 102 MMcf per day.

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

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

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

Kinder Morgan Retail currently provides unbundled natural gas services in Nebraska and Wyoming under its Choice Gas programs. Under these Choice Gas programs, competing natural gas providers currently sell natural gas to approximately 68% of Kinder Morgan Retail’s total customers. In unbundled areas, Kinder Morgan Retail competes as one of four or five natural gas marketers to provide the customer with natural gas commodity offerings. Kinder Morgan Retail currently provides the natural gas commodity for 45% of the end-use customers in these unbundled areas.

Power’s 2005 earnings, before a non-cash charge to reduce the carrying value of one of its investments, represented less than 2% of each of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and our income from continuing operations before interest and income taxes. We currently have ownership interests in two natural gas-fired electricity generation facilities in Colorado and one natural gas-fired electricity generation facility in Michigan. We also have a net profits interest in a third natural gas-fired electricity generation facility in Colorado. One of the Colorado facilities is operated as an independent power producer, with both a long-term power sales agreement

and gas supply contract. The other Colorado facility and the Michigan facility are operated under tolling agreements. Under the tolling agreements, purchasers of the electrical output take the risks in the marketplace associated with the cost of fuel and the value of the electric power generated. Kinder Morgan Power’s customers include power marketers and utilities. During 2005, approximately 70% of Power’s operating revenues represented tolling revenues of the Michigan facility, 18% was derived from the Colorado facility operated as an independent power producer under a long-term contract with XCEL Energy’s Public Service Company of Colorado unit, and the remaining 12% were primarily for operating the Ft. Lupton, Colorado power facility and a new gas-fired power facility in Snyder, Texas that began operations during the second quarter of 2005 and provides electricity to Kinder Morgan Energy Partners’ SACROC operations. In recent periods, we have recorded impairment charges associated with our power business activities; see Note 6 of the accompanying Notes to Consolidated Financial Statements.

Kinder Morgan Power previously designed, developed and constructed power projects. In 2002, following an assessment of the electric power industry’s business environment and noting a marked deterioration in the financial condition of certain power generating and marketing participants, we decided to discontinue our power development activities.

In February 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading agreed to supply natural gas to and market capacity for 16 years for a 550 megawatt natural gas-fired Orion technology (discussed below) electric power plant in Jackson, Michigan. Effective July 1, 2002, construction of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC (now valued at approximately $119 million); and, (ii) Triton Power Company LLC, through its wholly owned subsidiary, Triton Power Michigan LLC, entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC. Williams Energy Marketing and Trading supplies all natural gas to and purchases all power from the power plant under a 16-year tolling agreement with Triton Power Michigan LLC.

In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant in Wrightsville, Arkansas, utilizing Kinder Morgan Power’s Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. Kinder Morgan Power made an investment in the project company that owns the power plant, comprised primarily of preferred stock. In October 2003, the project company was included in Mirant Corporation’s bankruptcy filing. In the fourth quarter of 2003, we wrote off our remaining investment in the Wrightsville power facility, as further discussed in Note 6 of the accompanying Notes to Consolidated Financial Statements. During the third quarter of 2005, and subsequent to a negotiated settlement agreement approved by the court, Mirant sold the Wrightsville power facility to Arkansas Electric Cooperative Corporation.

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

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

Under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy Act of 1978, the FERC regulates both the performance of interstate transportation and storage services by interstate natural gas pipeline companies, and the rates charged for such services. The rates, terms and conditions of such services are subject to tariffs approved by the FERC. Rates are designed to recover an interstate pipeline’s costs of providing service, including financing costs, and to provide an opportunity to earn a reasonable and fair return on common equity. The rates that are set do not guaranty that a fair and reasonable return will be earned, and actual returns may vary from year to year according to various factors, including the total amount of services under contract, new investment, and increases in the cost of providing service.

In establishing the rates that an interstate pipeline may charge its customers, the FERC will generally consider an interstate pipeline’s rate base investment, costs, and revenues for a given test period, with adjustments for known and measurable changes. It will also look at the interstate pipeline’s capital structure and the cost of capital to determine whether existing rates need to be adjusted to establish new rates which are just and reasonable and sufficient to provide an opportunity to earn a fair and reasonable return on rate base. Rate base is generally the net depreciated cost of property, plant and equipment that is used or useful in providing service. A fair and reasonable return is established by determining the cost of individual components of the capital structure, including debt costs and a return on common equity, and weighting such costs to determine an aggregate return on rate base.

Where Kinder Morgan Retail provides a regulated and bundled gas supply sales service, it has rate adjustment mechanisms in place to track, pass through and recover in rates its prudently incurred gas costs on a dollar-for-dollar basis.

With the adoption of FERC Order No. 636 in 1992, the FERC required interstate natural gas pipelines that perform open access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies, whether such natural gas is purchased from the pipeline or from other merchants such as marketers or producers. Each interstate natural gas pipeline must now separately state the applicable rates for each unbundled service.

In Order Nos. 637 and 637-A, the FERC directed all interstate pipelines to make tariff changes as necessary to comply with new regulatory requirements regarding scheduling procedures, capacity segmentation, imbalance management services and penalty credits. The Order No. 637 tariff provisions for NGPL became effective on December 1, 2003. No issues remain outstanding as to NGPL’s Order No. 637 compliance program.

NGPL also is subject to the requirements of FERC Order No. 2004, et seq., which set out revised Standards of Conduct that apply uniformly to interstate gas transmission pipelines and public utilities, governing their relationships with energy affiliates. These new Standards of Conduct were designed to

be more restrictive than the previous regulations that did not cover an interstate natural gas pipeline’s relationship with energy affiliates that are not marketers. In addition, unlike the prior regulations, these requirements apply even if the energy affiliate is not a customer of its affiliated interstate pipeline. The rule is designed to prevent interstate natural gas pipelines from giving undue preference, including preference in the access to information, to any of their energy affiliates and to ensure that natural gas transportation is provided on a nondiscriminatory basis. NGPL and the other Kinder Morgan interstate pipelines have implemented compliance with the Standards of Conduct as of September 22, 2004.

On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, directed the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and significantly increased the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.

The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of the date of enactment and must perform subsequent integrity tests on a seven year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained, and the United States Department of Transportation has approved our qualification program. We believe that we are in substantial compliance with this law’s requirements and have integrated appropriate aspects of this pipeline safety law into our Operator Qualification Program.

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

The operations of our intrastate pipeline business are also affected by FERC rules and regulations issued pursuant to the Natural Gas Act and the Natural Gas Policy Act of 1978. Of particular importance are regulations that result in an increased ability to provide interstate transportation services without the necessity of obtaining prior FERC authorization for each transaction. A key element of the program is nondiscriminatory access, under which a regulated pipeline must agree, under certain conditions, to transport natural gas for any party requesting such service.

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

Kinder Morgan Retail’s rates, terms and conditions of utility services are set forth in published tariffs in each state, and are subject to approval and regulation by the utility regulatory commission in each state. Rates are designed to recover the costs of providing service, including financing costs, and to provide an opportunity for Kinder Morgan Retail to earn a reasonable and fair return on common equity. The rates that are set do not guaranty that Kinder Morgan Retail will earn a fair and reasonable return, and actual returns may vary from year to year according to various factors, including customer usage, new investment, and increases in the cost of providing service.

In establishing the rates that Kinder Morgan retail may charge its customers, the state utility commissions will generally consider the rate base investment, costs, and revenues for a given test period, with adjustments for known and measurable changes. They will also look at Kinder Morgan Retail’s capital structure and cost of capital to determine whether existing rates need to be adjusted to establish new rates which are just and reasonable and sufficient to provide an opportunity to earn a fair and reasonable return on rate base. Rate base is generally the net depreciated cost of property, plant and equipment that is used or useful in providing service. A fair and reasonable return is established by determining the cost of individual components of the capital structure, including debt cost and a return on common equity, and weighting such costs to determine an overall return on rate base.

We are a leader in providing for customer choice in purchasing gas supply directly from suppliers under our Choice Gas programs in Wyoming and Nebraska. We introduced the Choice Gas program in 1996, under an order issued by the Wyoming Public Service Commission. The program is available to all 72,000 end-use customers we serve in the state. In 1997, we announced a similar plan to give residential and small commercial customers in Nebraska a choice of natural gas suppliers. This program, the Nebraska Choice Gas program, became effective June 1, 1998 and is now available to all 94,000 customers we serve in Nebraska. The programs have succeeded in providing a choice of suppliers, competitive prices, and new products, services and pricing options to our customers, while maintaining reliability and security of supply. Kinder Morgan Retail continues to provide all services other than the natural gas commodity in these programs, and competes with other suppliers in offering natural gas supplies to retail customers.

Gas utilities in British Columbia are subject to the regulatory jurisdiction of the BCUC which derives its powers from the Utilities Commission Act (British Columbia). In addition to approving the rate base and new financings of Terasen Gas Inc., the BCUC also approves the rates charged to customers. These rates

are designed to recover the utility’s costs of providing service and allow the opportunity to meet financial commitments and earn a reasonable and fair return on common equity. The BCUC has jurisdiction to regulate and approve the terms and conditions under which gas utilities provide service.

As part of the establishment of the rates that a gas utility charges its customers, the BCUC establishes a rate base, approves a capital structure with which to finance such rate base, and is responsible for setting a reasonable and fair return on the debt and equity in the approved capital structure. Rate base is the aggregate of the depreciated cost of property, plant and equipment that is used or useful in serving the public, certain deferral accounts and a reasonable allowance for working capital. The fair return is established by determining the cost of individual components of the capital structure, including return on common equity, and weighting such costs to determine an aggregate return on rate base. The rates that are established and the terms and conditions of service are contained in a schedule of published and public tariffs. Before any tariff can be put into effect, it must be filed with the BCUC. The BCUC has jurisdiction to approve or refuse any amendment submitted for filing and to determine the rates which should be charged by a utility for its services. The BCUC is required to have due regard, among other things, to fixing rates that are not unjust or unreasonable. In fixing rates the BCUC must determine that such rates reflect a fair and reasonable charge for service of the nature and quality furnished by Terasen Gas Inc. to its customers and that such rates are sufficient to yield Terasen Gas Inc. a fair and reasonable compensation for its services and a fair and reasonable return on its rate base.

The BCUC uses a future test year in the establishment of rates for a utility. Pursuant to this method, the BCUC forecasts the volume of gas that will be sold and transported, together with all of the costs of Terasen Gas Inc. (including the rate of return) that Terasen Gas Inc. will incur in the test year. Rates are fixed to permit Terasen Gas Inc. to collect all of its costs (including the rate of return) if the forecast sales and transportation volumes are achieved. The forecast sales volumes assume normal weather. Certain costs are fixed and will be incurred regardless of the actual volume of gas sold. Accordingly, if the actual volumes of gas sales are less than those forecast in the test year, Terasen Gas Inc. might not recover all of the fixed costs. Interest expense, taxes other than income taxes, depreciation and amortization, certain operations and maintenance costs, the portion of the cost of gas that is fixed such as demand charges or reservation fees, and the fixed portion of transportation costs have the effect of being virtually fixed costs.

Two mechanisms to ameliorate unanticipated changes in sales volumes, such as changes caused by weather, have been implemented specifically for Terasen Gas Inc. The first relates to the recovery of all gas costs through deferral accounts which capture all variances (overages and shortfalls) from forecasts. Balances are either refunded to or recovered from customers via an application with the BCUC. The deferral accounts are called the Commodity Cost Reconciliation Account and the Midstream Cost Reconciliation Account. The second mechanism seeks to stabilize delivery revenues from residential and commercial customers through a deferral account that captures variances in the forecast versus actual customer use throughout the year. This mechanism is called the Revenue Stabilization Adjustment Mechanism. In February 2001, the BCUC issued guidelines for quarterly calculations to be prepared to determine whether customer rate adjustments are needed to reflect prevailing market prices for natural gas and to ensure that rate stabilization account balances are recovered on a timely basis.

Terasen Gas Inc. also has in place short-term and long-term interest rate deferral accounts to absorb interest rate fluctuations. The interest rate deferral accounts which were in place during 2005 effectively fixed the interest expense on short-term funds attributable to Terasen Gas Inc.’s regulated assets at 4.00 percent during 2005. The effective fixed short-term interest rate for 2006 has been set at 4.00 percent.

In addition to application for approval of interim and annual rate changes, the gas utilities may apply from time to time to the BCUC for rate changes to give effect to the changes in costs beyond the control of the utilities.

Important regulatory information, pertaining to decisions made by the BCUC with respect to Terasen Gas Inc., is summarized in the following table.

Terasen Gas Inc.’s allowed rates of return on common equity (“ROE”) are determined annually based on a formula that applies a risk premium to a forecast of long-term Government of Canada bond yields. On June 30, 2005, Terasen Gas Inc. applied to the BCUC to increase the deemed equity components from 33% to 38%. The application also requested an increase in allowed ROEs from the levels that result from the then current formula, which would have yielded 8.29% for Terasen Gas Inc. in 2006. The BCUC rendered its decision on the application on March 2, 2006, to be effective as of January 1, 2006. The generic ROE formula for a benchmark utility in British Columbia was changed such that it will be reset annually from a forecast of 30-year Canada Bonds plus a 3.90% risk premium when the forecast yield on 30-year Canada Bonds is 5.25%. The risk premium is adjusted annually by 75% of the difference between 5.25% and the forecast yield on 30-year Canada Bonds. For 2006, the forecast 30-year Canada Bond yield is 4.79% resulting in a Benchmark ROE for Terasen Gas Inc. of 8.80%, an improvement of 51 basis points over the old formula. In addition, the BCUC increased the deemed equity component for Terasen Gas Inc. to 35% from 33%.

2004-2007 Performance-Based Rate Plan: In 2003, Terasen Gas Inc. received BCUC approval of a negotiated settlement of a 2004-2007 Performance-Based Rate Plan (“PBR Settlement”). The PBR Settlement, which took effect January 1, 2004, establishes a process for determining Terasen Gas Inc.’s delivery charges and incentive mechanisms for improved operating efficiencies. The four-year agreement includes incentives for Terasen Gas Inc. to operate more efficiently through sharing of the benefits of cost reductions between Terasen Gas Inc. and its customers. It includes 10 service quality indicators designed to ensure Terasen Gas Inc. provides appropriate service levels and sets out the requirements for an annual review process which will provide a forum for discussion between Terasen Gas Inc. and interested parties regarding its current performance and future activities.

Operation and maintenance costs and base capital expenditures are subject to an incentive formula reflecting increasing costs due to customer growth and inflation, less a productivity factor based on 50% of inflation during the first two years and 66% of inflation during the last two years. Base capital expenditure amounts are a function of customer numbers and projected customer additions. The PBR Settlement provides for a 50/50 customer/shareholder sharing mechanism of earnings above or below the allowed return on equity.

Unbundling: Over the past several years, Terasen Gas Inc., the BCUC and a number of interested parties have laid the groundwork for the introduction of natural gas commodity unbundling. On November 1, 2004, commercial customers of Terasen Gas Inc. became eligible to sign up to buy their natural gas commodity supply directly from third-party suppliers. Terasen Gas Inc. continues to provide delivery of the natural gas. Approximately 78,000 commercial customers are eligible to participate in commodity unbundling. By December 2005, 14,413 customers elected to participate in this program.

The Province of British Columbia and TGVI’s previous parent company entered into the Vancouver Island Natural Gas Pipeline Agreement (the “VINGPA”) to restructure the financial arrangements

relating to TGVI’s pipeline and connected distribution systems. Under the VINGPA, the Province agreed to make quarterly payments from 1996 through 2011 related to natural gas production royalties associated with deemed volumes of natural gas transported through the Vancouver Island pipeline. The royalty related payment recognized in 2005 was C$46.7 million. Under the VINGPA, TGVI’s parent company agreed to provide future financial support of up to C$120 million over the period from 1996 to 2011 and C$17.5 million for 1995 to finance the principal amount of the revenue deficiencies incurred by TGVI. Annual revenue deficiencies were calculated as the difference between the regulated allowed return on approved rate base and earnings actually derived from sales revenues and expenses. The accumulated revenue deficiency resulting from overall revenues being below the cost of service had been recorded in a Revenue Deficiency Deferral Account (“RDDA”).

When Terasen acquired TGVI, the amount of the RDDA was C$85 million, for which Terasen paid a price of C$61 million. The accumulated RDDA totaled C$35.2 million at December 31, 2005, corresponding to a balance for TGVI regulatory purposes of C$48.3 million, down C$10.4 million from December 31, 2004. Terasen is committed to fund any increases in revenue deficiencies by purchasing preferred shares or subordinated debt issued by TGVI. The BCUC was directed to set rates beginning in 2003 that amortize the RDDA balance over the shortest period reasonably possible, having regard for TGVI’s competitive position relative to alternative energy sources and the desirability of reasonable rates. As part of the acquisition of TGVI, Terasen assumed the rights and obligations of TGVI’s previous parent company under the VINGPA.

TGVI’s distribution rates are set by the BCUC in accordance with regulatory principles generally applied by the BCUC to natural gas utilities operating within British Columbia. On November 30, 2005, TGVI received BCUC approval for a new regulatory settlement, which took effect January 1, 2006. The 2006-2007 settlement provides for a continuation of operation and maintenance cost incentive arrangements previously in place. As noted above, on March 2, 2006, the BCUC issued its Decision on the ROE application. In the Decision, TGVI’s request for an increase in its deemed equity components from 35% to 40% was approved. The Decision also resulted in an improvement in its allowed ROE to 70 basis points over the Benchmark ROE to 9.50% to be effective January 1, 2006.

The Canadian portion of the crude oil and refined product pipeline system is under the regulatory jurisdiction of the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service.

In October 1999, Trans Mountain entered into negotiations with CAPP and principal shippers for renewal of the prior Incentive Toll Settlement that expired at the end of 2000. A revised settlement (the “Renewal ITS”) was subsequently reached with CAPP and the principal shippers and the NEB approved the Renewal ITS effective January 1, 2001.

The Renewal ITS was in effect for the five-year period commencing January 1, 2001 and ending December 31, 2005. The Renewal ITS provided for base tolls which would, other than recalculation or adjustment in certain specified circumstances, remain in effect for the five-year period. The base tolls were calculated on an agreed throughput level of 188,700 bpd for each of the five years. Trans Mountain accepted the risk and benefit of variations in throughput within a band having limits of 12,580 bpd greater and 9,435 bpd less than the base throughput level. Any revenue shortfalls arising from annual throughput levels below 179,265 bpd were recovered from the shippers. Incremental revenues arising from annual throughput above 201,280 bpd were shared equally between Trans Mountain and the

shippers. Other than these adjustments for throughput outside the defined band, no sharing or recovery mechanisms were in place.

In November 2004, Trans Mountain entered into negotiations with CAPP and principal shippers for a new Incentive Toll Settlement to be effective for the period starting January 1, 2006 and ending December 31, 2010 (the “2006 ITS”). In January 2006, Trans Mountain reached agreement in principle reduced to a memorandum of understanding for the 2006 ITS. The agreement will also govern the financial arrangements for planned expansions to Trans Mountain that will add 75,000 bpd of incremental capacity to the system by late 2008. Details of the method of determining tolls are still under final negotiation and full settlement remains subject to approval of the NEB. Pending completion of full settlement, specific terms have not been disclosed to the public.

The toll charged for the portion of Trans Mountain’s pipeline system located in the United States falls under the jurisdiction of the FERC. Regulation by the FERC is on a complaint basis. There have been no complaints.

As an intra-provincial pipeline system, Corridor is subject to the jurisdiction of the Alberta Energy and Utilities Board (“AEUB”). With respect to Corridor, matters such as rates of return, construction and operation of facilities and tolls are governed by contractual arrangements with shippers and are subject to regulation by the AEUB. The Firm Service Agreement (“FSA”), which was effective, from a tolling perspective, with the commencement of commercial operations on May 1, 2003, sets pipeline tolls based on cost of service mechanisms. Shell and its partners have made a 25-year take or pay commitment under the FSA to transport a total of 150,000 bpd of bitumen and 65,000 bpd of diluent in the Corridor Pipeline.

The Canadian segment of the Express Pipeline is regulated by the NEB as a Group 2 pipeline, which results in rates and terms of service being regulated on a complaint basis only. The U.S. segment of the Express Pipeline and the Platte Pipeline are regulated by the FERC, which regulates the rates and terms of service of a common carrier. The FERC has additionally established methods by which pipelines may increase their rates.

Express committed rates are subject to a 2% inflation adjustment April 1 of each year. Uncommitted or ceiling rates for both the U.S. segment of Express Pipeline and Platte Pipeline are subject to adjustment in accordance with the FERC’s annual indexing formula. Platte has historically been unable to charge its ceiling rates and has had to discount its rates because of market fundamentals in PADD II. With changes in market conditions over the past year, Platte has been able to successfully remove all of its discounts. Today, all rates on Platte are at the applicable ceiling level.

Additionally, movements on the Platte Pipeline within the State of Wyoming are regulated by the Wyoming Public Service Commission (“WPSC”), which regulates the tariffs and terms of service of public utilities that operate in the State of Wyoming. The WPSC standards applicable to rates are similar to those of the FERC and the NEB.

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

compliance program, and we believe that our operations are in substantial compliance with applicable environmental laws and regulations. This program focuses on compliance with federal, provincial, state and local laws and regulations relating to the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act and solid waste issues, the Canadian Fisheries Act, NEB Act and other related and applicable environmental laws and regulations. Numerous governmental departments issue rules and regulations to implement and enforce such laws, for which compliance is often costly and onerous. Failure to comply with applicable environmental laws may result in substantial administrative, civil, and criminal penalties or injunctions that would restrict operations or require future compliance, damage awards against us, or other mandatory or consensual measures or liabilities. These laws and regulations can also impose liability for remedial costs on the owner or operator of properties or the generators of materials, regardless of fault. Moreover, a trend in environmental law is toward stricter standards, stricter enforcement, and more restrictions on operations. Depending on changes to current laws or regulations and any additional requirements that may be imposed by regulatory authorities, we could be required to incur additional capital expenditures over the next several years. This trend and other developments in environmental law may result in significant cost and liabilities for us.

We had an environmental reserve of approximately $16.8 million at December 31, 2005, to address remediation issues associated with approximately 50 projects. These projects include several ground water and soil hydrocarbon remediation efforts under the jurisdiction and direction of various state, federal, and provincial agencies. Additionally, 12 of the projects relate to Kinder Morgan Canada assets. Many of these remediation efforts are the result of historical releases from currently non-operating sites. Additionally, we are addressing impacts at several locations from the historical use of mercury, MTBE and polychlorinated biphenyls. We believe that costs for environmental remediation and separately ongoing compliance with applicable environmental regulations will not have a material adverse effect on our cash flows, financial position or results of operations, or materially diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, the discovery of circumstances or conditions currently unforeseen by us, or that the development of new facts or conditions will not cause us to incur significant unanticipated costs and liabilities.

Our senior executives are committed to ensuring that we are an industry leader with respect to environmental protection and compliance with environmental policies. Health, safety and environmental issues and initiatives are reported regularly to our senior executives.

We are in substantial compliance with legislative standards and environmental protection requirements with respect to our operations. We could be exposed to significant operational disruptions and environmental liability in the event of a petroleum product spill or an accident involving natural gas or a compromise to water or sewer distribution systems operated and/or maintained by the Company. We have taken what we believe to be reasonable and prudent steps to minimize our exposure in the case of a catastrophic event or environmental upset. The focus of our safety and environmental practices is to ensure reliable, cost effective, quality service with full regard for the safety of employees and the public while operating in an environmentally responsible manner.

Terasen Gas Inc. and Kinder Morgan Canada are active participants in Canada’s Voluntary Climate Change Challenge and Registry (“VCR”). For the sixth consecutive year, Terasen Gas Inc. received gold level reporting status from VCR in recognition of its efforts to manage and reduce greenhouse gas emissions. Terasen Gas Inc. received the VCR Leadership award, becoming the only company in its sector to have received the honor twice, previously in 2001. The VCR ranking acknowledges Terasen Gas Inc.’s efforts to develop specific measures and voluntarily set reduction targets. Kinder Morgan

Canada has achieved a silver level with VCR for the past three years and has registered to participate in the American Petroleum Institute’s voluntary program in the United States.

We have detailed emergency preparedness plans in place to respond to natural disasters, accidents and emergencies, and regularly test these plans in simulations involving employees and other emergency response organizations. The Company is also committed to monitor and assess its safety and environmental performance regularly. We incorporate safety performance measures into our employee compensation system, set targets and objectives for environmental performance, and conduct safety and environmental audits.

Amounts we spent during 2005, 2004, and 2003 on research and development activities were not material. We employed 8,481 people at December 31, 2005, including employees of our indirect subsidiary KMGP Services Company, Inc., who are dedicated to the operations of Kinder Morgan Energy Partners.

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

Our named executive officers and other employees that provide management or services to both us and the Group are employed by us. Additionally, other of our employees assist Kinder Morgan Energy Partners in the operation of its Natural Gas Pipeline assets. These employees’ expenses are allocated without a profit component between us and the appropriate members of the Group.

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

Note 19 of the accompanying Notes to Consolidated Financial Statements contains financial information about the geographic areas in which we do business.

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

You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our substantially increased debt as a result of the Terasen acquisition could adversely affect our financial health and make us more vulnerable to adverse economic conditions. As a result of our acquisition of Terasen, we have significantly more debt outstanding and significantly higher debt service requirements than in the recent past. As of December 31, 2005, we had outstanding approximately $7.7 billion of consolidated debt, of which approximately $4.8 billion was debt of our subsidiaries. As of December 31, 2005, we had the ability to borrow up to approximately $1.0 billion under our revolving credit facilities.

limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth or other purposes;

limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt;

placing us at a competitive disadvantage compared to competitors with less debt; and

Each of these factors is to a large extent dependent on economic, financial, competitive and other factors beyond our control.

Our large amount of floating rate debt makes us vulnerable to increases in interest rates. As of December 31, 2005, we had outstanding approximately $7.7 billion of consolidated debt. Of this amount, excluding debt related to assets for which interest expense is passed through in our tariffs and rates, approximately 50% was subject to floating interest rates, either as short-term commercial paper or as long-term fixed-rate debt converted to floating rates through the use of interest rate swaps. Should interest rates increase significantly, our cash available to service our debt would be adversely affected.

We are dependent upon the earnings and distributions of Kinder Morgan Energy Partners. For the year ended December 31, 2005, approximately 50% of our total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners was attributable to our general and limited partner interests in Kinder Morgan Energy Partners. A significant decline in Kinder Morgan Energy Partners’ earnings and/or cash distributions would have a corresponding negative impact on us.

Kinder Morgan Energy Partners could be treated as a corporation for United States income tax purposes. Kinder Morgan Energy Partners' treatment as a corporation would substantially reduce the cash distributions on the common units that it distributes quarterly. The anticipated benefit of our investment in Kinder Morgan Energy Partners depends largely on its treatment as a partnership for federal income tax purposes. Kinder Morgan Energy Partners has not requested, and does not plan to request, a ruling from the Internal Revenue Service on this or any other matter affecting Kinder Morgan Energy Partners. Current law requires Kinder Morgan Energy Partners to derive at least 90% of its annual gross income from specific activities to continue to be treated as a partnership for federal income tax purposes. Kinder Morgan Energy Partners may not find it possible, regardless of its efforts, to meet this income requirement or may inadvertently fail to meet this income requirement. Current law may change so as to cause Kinder Morgan Energy Partners to be treated as a corporation for federal income tax purposes without regard to its sources of income or otherwise subject it to entity-level taxation.

If Kinder Morgan Energy Partners was to be treated as a corporation for federal income tax purposes, it would pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35% and would pay state income taxes at varying rates. Under current law, distributions to unitholders, including us, would generally be taxed as a corporate distribution. Because a tax would be imposed upon Kinder Morgan Energy Partners as a corporation, the cash available for distribution to its unitholders, including us, would be substantially reduced.

In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon Kinder Morgan Energy Partners as an entity, the cash available for distribution to its unitholders would be reduced.

Competition could ultimately lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation capacity at favorable rates. For the year ended December 31, 2005, NGPL’s segment earnings represented approximately 38% of our total segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners. NGPL is an interstate natural gas pipeline that is a major supplier to the Chicago, Illinois area. In the past, interstate pipeline competitors of NGPL have constructed or expanded pipeline capacity into the Chicago area. To the extent that an excess of supply into this market area is created and persists, NGPL’s ability to recontract for expiring transportation capacity at favorable rates could be impaired. Contracts representing approximately 2.5% of NGPL’s total

long-haul, contracted firm transport capacity as of January 31, 2006 have not been renewed and are scheduled to expire before the end of 2006.

Trans Mountain’s pipeline to the West Coast of North America and the Express System, in which we own an interest, to the U.S. Rocky Mountains and Midwest are two of several pipeline alternatives for Western Canadian petroleum production. Throughput on these pipelines may decline if tolls become uncompetitive compared to alternatives. Our oil transportation business competes against other pipeline companies who could be in a position to offer different tolling structures, which may provide them with a competitive advantage in new pipeline development.

Because electricity prices in British Columbia continue to be set based on the historical average cost of production, rather than based on market forces, they have remained artificially low compared to market-priced electricity and, as a result, only marginally higher than comparable, market-based natural gas costs. A sustained increase in natural gas commodity prices could cause natural gas in British Columbia to be uncompetitive with electricity, thereby decreasing the use of natural gas by Terasen Gas’ customers.

Trans Mountain’s tolling arrangement with shippers is expiring and must be extended or renewed. In November 2000, Trans Mountain and shipper representatives reached a negotiated Incentive Toll Settlement to determine Trans Mountain’s tolls for the period 2001-2005 for use of the Trans Mountain pipeline network. This agreement was approved by the Canadian National Energy Board on March 22, 2001 to take effect as of January 1, 2001. In January 2006, Trans Mountain and CAPP, representing shippers, entered into a memorandum of understanding for a new Incentive Toll Settlement effective January 1, 2006 through December 31, 2010. The new Incentive Toll Settlement is subject to NEB approval, and Kinder Morgan Canada and CAPP have agreed to work towards a final agreement by the end of June 2006. There is no certainty as to whether final negotiations will be successful, whether a final settlement will be approved by the NEB, or what the terms of a new toll settlement might be. Our earnings could be negatively impacted in 2006 depending on the final tolling arrangements with shippers.

The rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) we charge shippers on our pipeline systems and the rates our natural gas distribution operations can charge are subject to regulatory approval and oversight. While there are currently no material proceedings challenging the rates on any of our natural gas pipeline systems, regulators and shippers on these pipelines do have rights to challenge the rates they are charged under certain circumstances prescribed by applicable regulations. We can provide no assurance that we will not face challenges to the rates we receive on our pipeline systems in the future. Any successful challenge could materially adversely affect our future earnings and cash flows.

As part of the establishment of the rates which gas distribution operations can charge their customers, utility regulators, including the British Columbia Utilities Commission, or BCUC, generally establish a rate base and a reasonable and fair return for the utility upon that rate base. The allowed rates of return on our gas distribution operations are calculated differently and vary in amount in different jurisdictions. In British Columbia, the allowed rates of return on equity are determined annually by the BCUC based on a formula that applies a risk premium to a forecast of long-term Government of Canada bond yields. The allowed returns on equity for Terasen Gas Inc. and TGVI are determined by formulae that result in lower allowed returns on equity if long-term Government of Canada bond yields decline. Most rates in British Columbia are established using a future test year which has forecasts of the volume of gas that will be sold and transported and the costs, including the rate of return, that the utility will incur with cost and revenue tracking and sharing mechanisms that result in annual rate adjustments. Terasen Gas Inc. and

TGVI have performance-based rate agreements expiring in 2007. There can be no assurance that new rate agreements will be entered into or that the regulatory process in which rates are determined will always produce rates that will result in full recovery of our British Columbia gas distribution operation’s costs.

Sustained periods of weather inconsistent with normal in areas served by our natural gas distribution operations can create volatility in our earnings. Our operating results may fluctuate on a seasonal basis. Weather-related factors such as temperature and rainfall at certain times of the year affect our earnings, principally in our retail natural gas distribution business. Sustained periods of temperatures and rainfall that differ from normal can create volatility in our earnings. In many areas, natural gas consumption patterns peak in the winter, especially for our retail natural gas distribution operations. Those operations normally generate higher net earnings in the first and fourth quarters, which are offset to some extent by lower earnings or net losses in the second and third quarters.

Proposed rulemaking by the FERC, the BCUC, the NEB or other regulatory agencies having jurisdiction could adversely impact our income and operations. Generally speaking, new laws or regulations or different interpretations of existing laws or regulations applicable to our assets could have a negative impact on our business, financial condition and results of operations.

Environmental regulation and liabilities could result in increased operating and capital costs. Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the United States and Canada. For example, if an accidental leak or spill occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up the leak or spill, pay for government penalties, address natural resource damages, compensate for human exposure, install costly pollution control equipment, or a combination of these and other measures. The resulting costs and liabilities could negatively affect our level of earnings and cash flow. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities. The impact of environmental standards or future environmental measures could increase our costs significantly. Since the costs of environmental regulation are already significant, additional or stricter regulation or enforcement could negatively affect our business.

We own or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where such wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, use and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed thereon may be subject to laws in the United States such as the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination

caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

Current or future distressed financial condition of customers could have an adverse impact on our operations in the event these customers are unable to pay us for the products or services we provide. Some of our customers are experiencing severe financial problems, and other customers may experience severe financial problems in the future. The bankruptcy of one or more of them, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our operations and financial condition.

Increased regulatory requirements relating to the integrity of our pipelines will require us to spend additional money to comply with these requirements. Through its regulated pipeline subsidiaries, we are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines for the U.S. Department of Transportation and pipeline companies in the areas of testing, education, training and communication. We have increased and expect to significantly increase our capital expenditures to address these matters. Additional laws and regulations that may be enacted in the future could significantly increase the amount of these expenditures.

The failure to successfully integrate Terasen’s operations with those of ours could adversely impact our results of operations. This would also be true for any other significant acquisition. The integration of Terasen and other companies that have previously operated separately involves a number of risks, including:

the diversion of management’s attention from the management of daily operations, difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems,

We regularly consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.

Future business development of our products pipelines is dependent on the supply of, and demand for, crude oil and other liquid hydrocarbons, particularly from the Alberta oilsands. Our pipelines depend on production of natural gas, oil and other products in the areas serviced by its pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut down production at lower product prices or higher production costs, especially where the existing cost of production exceeds other extraction methodologies, such as at the Alberta oilsands. Producers in areas serviced by us may not be successful in exploring for and developing additional reserves, and the gas plants and the pipelines may not be able to maintain existing volumes of throughput.

Commodity prices may not remain at a level which encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.

Changes in the business environment, such as a decline in crude oil prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from the Alberta oilsands. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil. Each of these factors impact our customers shipping through our pipelines, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts.

Throughput on our products pipelines may also decline as a result of changes in business conditions. Over the long term, business will depend, in part, on the level of demand for oil and natural gas in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas and crude oil, increase our costs and may have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas and oil.

We are subject to U.S. dollar/Canadian dollar exchange rate fluctuations. As a result of our acquisition of Terasen, a significant portion of our assets, liabilities, revenues and expenses will be denominated in Canadian dollars. We are a U.S. dollar reporting company. Fluctuations in the exchange rate between United States and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our stockholders’ equity under applicable accounting rules.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and floating interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

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

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

Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2004 and served as President until May 2005. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development and Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc.

C. Park Shaper is Director and President of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and President of Kinder Morgan, Inc. Mr. Shaper was elected President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. He served as Executive Vice President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from July 2004 until May 2005. Mr. Shaper was elected Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its formation in February 2001, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. in January 2000, and served as their Treasurer until January 2004, and their Chief Financial Officer until May 2005. He received a Masters of Business Administration degree from

the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University.

Steven J. Kean is Executive Vice President and Chief Operating Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kean was elected Executive Vice President and Chief Operating Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in January 2006. He served as Executive Vice President, Operations of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from May 2005 to January 2006. He served as President, Texas Intrastate Pipeline Group from June 2002 until May 2005. He served as Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. Until December 2001, Mr. Kean was Executive Vice President and Chief of Staff of Enron Corp. Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State University in May 1982.

Kimberly A. Dang, formerly Kimberly J. Allen, is Vice President, Investor Relations and Chief Financial Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mrs. Dang was elected Chief Financial Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. She served as Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from January 2004 to May 2005. She was elected Vice President, Investor Relations of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2002. From November 2001 to July 2002, she served as Director, Investor Relations. From May 2001 until November 2001, Mrs. Dang was an independent financial consultant. From September 2000 until May 2001, she served as an associate and later a principal at Murphee Venture Partners, a venture capital firm. Mrs. Dang has received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University and a Bachelor of Business Administration degree in accounting from Texas A&M University.

Ian D. Anderson is President of Kinder Morgan Canada. Mr. Anderson was elected President, Kinder Morgan Canada in November 2005. He served as Vice President, Finance and Corporate Services, Terasen Pipelines Inc. from July 2004 to November 2005. Mr. Anderson was Vice President, Finance and Corporate Controller, Terasen Inc. from August 2002 to July 2004 and he was Vice President, Finance and Regulatory Affairs at Centra Gas British Columbia (which became Terasen Gas (Vancouver Island) Inc. in 2003) from December 1999 to August 2002. Mr. Anderson is a Certified Management Accountant, and is a 1997 graduate of the University of Michigan Executive Program.

R.L. (Randy) Jespersen is President of Terasen Gas Inc. (formerly BC Gas Utility Ltd.) and Terasen Gas (Vancouver Island) Inc. Mr. Jespersen was appointed President of Terasen Gas (Vancouver Island) Inc. in January 2004, and appointed President of Terasen Gas Inc. in January 2002. He served as Senior Vice President, Energy Delivery Services from April 1998 through December 2001, and Senior Vice President, Gas Supply from March 1996 to April 1998. Mr. Jespersen received his Masters in Business Administration from the University of Saskatchewan in 1976, his B.Sc. (Business) degree from Oregon State University in 1975, and has a Business Diploma from Lethbridge Community College.

David D. Kinder is Vice President, Corporate Development and Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder was elected Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. He was elected Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in October 2002. He served as manager of corporate development for Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. from January 2000 to October 2002. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas

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

Scott E. Parker is Vice President (President, Natural Gas Pipelines) of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. He was elected Vice President (President, Natural Gas Pipelines) of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. Mr. Parker served as Co-President of NGPL from March 2003 to May 2005. Mr. Parker served as Vice President, Business Development of NGPL from January 2001 to March 2003. He held various positions at NGPL from January 1984 to January 2001. Mr. Parker holds a Bachelor’s degree in accounting from Governors State University.

James E. Street is Vice President, Human Resources and Administration of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in August 1999. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.

Daniel E. Watson is Vice President (President, Retail) for Kinder Morgan, Inc. Mr. Watson was elected Vice President (President, Retail) in October 1999. Mr. Watson also holds the title of President of Rocky Mountain Natural Gas Company, a Kinder Morgan, Inc. subsidiary. He has served as President, Rocky Mountain Natural Gas Company since October 1999. Mr. Watson received a Bachelor of Science degree in Geological Engineering in December, 1979, and a Bachelor of Science degree in Mining Engineering in May 1980, from the South Dakota School of Mines and Technology.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer

Our common stock is listed for trading on the New York Stock Exchange under the symbol “KMI.” Dividends paid and the high and low sale prices per share, as reported on the New York Stock Exchange, of our common stock by quarter for the last two years are provided below. In January 2006, we increased our quarterly common dividend to $0.875 per share.

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

Includes significant impacts from dispositions of assets. See Notes 1(Q) and 5 of the accompanying Notes to Consolidated Financial Statements for information regarding dispositions during 2005, 2004 and 2003.

2005 results include the results of Terasen Inc. subsequent to its November 30, 2005 acquisition by us. See Note 4 of the accompanying Notes to Consolidated Financial Statements for information regarding this acquisition.

Includes charges of $6.5 million, $33.5 million, $44.5 million and $134.5 million in 2005, 2004, 2003 and 2002, respectively, to reduce the carrying value of certain power assets; see Note 6 of the accompanying Notes to Consolidated Financial Statements.

Reflects the acquisition of Terasen Inc. on November 30, 2005. See Note 4 of the accompanying Notes to Consolidated Financial Statements for information regarding this acquisition.

As a result of our adoption of FASB Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities, the subsidiary trusts associated with these securities are no longer consolidated, effective December 31, 2003.

Excluding the value of interest rate swaps. See Note 14 of the accompanying Notes to Consolidated Financial Statements.

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes. Specifically, as discussed in Notes 4, 5 and 7 of the accompanying Notes to Consolidated Financial Statements, we have engaged in acquisitions, including the November 2005 acquisition of Terasen Inc., referred to in this report as Terasen, and divestitures (including the discontinuance of certain lines of business and the transfer of certain assets to Kinder Morgan Energy Partners) that may affect comparisons of financial position and results of operations between periods.

We are an energy infrastructure provider through our direct ownership and operation of energy-related assets, and through our ownership interests in and operation of Kinder Morgan Energy Partners. Our energy-related assets owned and operated directly (which, during 2006, are budgeted to contribute approximately 61% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners) include natural gas pipelines, natural gas storage facilities, petroleum pipelines, retail natural gas distribution facilities and investments in natural gas-fired power generation facilities. In November 2005, we acquired Terasen (operations acquired with Terasen are budgeted to contribute approximately 26% of the total of our 2006 segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, which is included in the 61% discussed above for directly owned operations), a provider of energy and utility services based in Vancouver, British Columbia, Canada (see Note 4 of the accompanying Notes to Consolidated Financial Statements). Terasen’s two core business operations are (i) Kinder Morgan Canada (formerly Terasen Pipelines), principally consisting of the ownership and operation of three refined products and crude oil pipelines: (1) Trans Mountain Pipeline, (2) Corridor Pipeline and (3) a one-third interest in the Express System; and (ii) Terasen Gas, the regulated sale and transportation of natural gas to residential, commercial and industrial customers in British Columbia, Canada. Our investment in Kinder Morgan Energy Partners (which, during 2006, is budgeted to contribute approximately 39% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners) includes ownership of the general partner interest, as well as ownership of limited partner units and shares of Kinder Morgan Management, LLC, referred to in this report as Kinder Morgan Management.

As described under “Business Strategy” elsewhere in this report, our strategy and focus continues to be on ownership of fee-based energy-related assets which are core to the energy infrastructure of North America and serve growing markets. These assets tend to have relatively stable cash flows while presenting us with opportunities to expand our facilities to serve additional customers and nearby markets. We evaluate the performance of our investment in these assets using, among other measures, segment earnings. In addition, please see “Developments During 2005” under Items 1 and 2 “Business and Properties” elsewhere in this report.

The variability of our operating results is attributable to a number of factors including (i) variability within U.S. and Canadian national and local markets for energy and related services, including the effects of competition, (ii) the impact of regulatory proceedings, (iii) the effect of weather on customer energy and related services usage, as well as our operation and construction activities, (iv) increases or decreases in interest rates, (v) the degree of our success in controlling costs and identifying, carrying out profitable expansion projects and integrating new acquisitions into our operations and (vi) changes in taxation policy or regulated rates. Certain of these factors are beyond our direct control, but we operate a structured risk management program to mitigate certain of the risks associated with changes in the price of natural gas, interest rates, currency exchange rates and weather (relative to historical norms).

The remaining risks are primarily mitigated through our strategic and operational planning and monitoring processes. See Item 1A “Risk Factors” elsewhere in this report. Effective November 1, 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners (see Note 5 of the accompanying Notes to Consolidated Financial Statements). Our remaining businesses (apart from our investment in Kinder Morgan Energy Partners) constitute five business segments. Our largest business segment and our largest source of operating income is Natural Gas Pipeline Company of America, (“NGPL”), which owns and operates a major interstate natural gas pipeline system that runs from natural gas producing areas in West Texas and the Gulf of Mexico to its principal market area of Chicago, Illinois. In accordance with our strategy to increase operational focus on core assets, we have worked toward renewing existing agreements and entering into new agreements to fully utilize the transportation and storage capacity of NGPL’s system. As a result, NGPL sold virtually all of its capacity through the 2005-2006 winter season. Please refer to the individual business segment discussion following for additional information regarding NGPL.

Our other business segments consist of (i) Kinder Morgan Canada (formerly Terasen Pipelines), our petroleum pipeline business that transports crude and refined products through Alberta and British Columbia, Canada and into Washington state and the U.S. Rocky Mountain and Midwest regions (ii) Terasen Gas, our retail distribution of natural gas to approximately 892,000 customers in British Columbia, Canada, (iii) Kinder Morgan Retail, our retail distribution of natural gas to approximately 245,000 customers in Colorado, Wyoming and Nebraska, and (iv) Power, our investment in, in some cases, operation of, and in previous periods construction of electric power generation facilities. Our retail natural gas distribution operations are located, in part, in areas where significant population and economic growth is occurring and we expect to participate in that growth through increased natural gas demand. Our power segment owns interests in and, in some cases, operates power generation facilities, and continues to hold a preferred investment in one gas-fired power plant constructed by us and placed into operation in 2002. During the fourth quarter of 2002, we announced that we were discontinuing our power development activities and we revalued certain of our power assets. We also revalued certain of our power assets during the fourth quarters of 2005, 2004 and 2003. See “Power” following and Note 6 of the accompanying Notes to Consolidated Financial Statements. As a result of our implementation of a new accounting pronouncement, beginning January 1, 2006, we will include the accounts and balances of Kinder Morgan Energy Partners in our consolidated financial statements. See Note 20 of the accompanying Notes to Consolidated Financial Statements. We expect that, in addition to our five current business segments, we will report the following business segments: (1) Products Pipelines, (2) Natural Gas Pipelines, (3) CO₂ and (4) Terminals.

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

In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the effective income tax rate to apply to our pre-tax income, deferred income tax assets, deferred income tax liabilities, 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, cost and timing of environmental remediation efforts, potential exposure to adverse outcomes from judgments or litigation settlements, exposures under contractual indemnifications and various other recorded or disclosed amounts. Certain of these accounting estimates are of more significance in our financial statement preparation process than others.

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

Our regulated utility operations are accounted for in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation. As a result, we record assets and liabilities that result from the ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. The accounting for these items is based on an expectation of the future decisions or approvals of the regulator. The deferral of differences between amounts included in tolls or rates and actual experience for specified expenses is based on the expectation that the regulator will approve the refund to or recovery from customers of the deferred balance. If the regulators’ future actions are different from our expectations, the timing and amount of the recovery of assets or refund of liabilities could be substantially different from that reflected in the financial statements. When assessing whether our regulatory assets and liabilities are probable of future recovery or refund, we consider such factors as changes in the regulatory environment, recent rate orders to other regulated utilities, and the status of any pending deregulation legislation. While we believe the existing regulatory assets are probable of recovery, the current regulatory and political climate on which this assessment is based is subject to change in the future.

With respect to the amount of income or expense we recognize in association with our pension and retiree medical plans, we must make a number of assumptions with respect to both future financial conditions (for example, medical costs, returns on fund assets and market interest rates) as well as future actions by plan participants (for example, when they will retire and how long they will live after retirement). Most of these assumptions have relatively minor impacts on the overall accounting recognition given to these plans, but two assumptions in particular, the discount rate and the assumed long-term rate of return on fund assets, can have significant effects on the amount of expense recorded and liability recognized. The selection of these assumptions is discussed in Note 15 of the accompanying Notes to Consolidated Financial Statements. While we believe our choices for these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of pension and retiree medical funding (excluding the pension and retiree medical plans of Terasen), a change of 1% in the long-term return assumption would increase (decrease) our annual retiree medical expense by approximately $634,000 ($634,000) and would increase (decrease) our annual pension expense by $2.3 million ($2.3 million) in comparison to that recorded in 2005. Similarly, a 1% change in the discount rate would increase (decrease) our accumulated

postretirement benefit obligation by $8.4 million ($7.6 million) and would increase (decrease) our projected benefit pension obligation by $27.8 million ($24.6 million) compared to those balances as of December 31, 2005.

Terasen’s postretirement benefit programs are unfunded, and therefore there is no impact to expense from a change in the long-term return assumptions. Terasen’s defined benefit pension programs are funded, but due to the significance of the regulated operations, the impact on expense of variances in long-term return assumptions and discount rates is materially recovered through rate-setting mechanisms. Terasen’s supplemental pension plans are unfunded and are therefore not subject to variances in long-term return assumptions. A 1% change in the discount rate would increase (decrease) Terasen’s accumulated postretirement benefit obligation by $10.1 million ($8.8 million) and its projected pension benefit obligation by $24.7 million ($23.5 million) compared to those balances as of December 31, 2005.

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

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

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

As discussed under “Risk Management” in Item 7A of this report, we enter into derivative contracts (natural gas futures, swaps and options) solely for the purpose of mitigating risks that accompany our normal business activities, including fluctuations in foreign currency exchange, interest rates and the price of natural gas and associated transportation. We account for these derivative transactions as hedges in accordance with authoritative accounting guidelines, marking the derivatives to market at each reporting date. At December 31, 2005, the majority of our derivative financial instruments either (i) met specific hedge accounting criteria whereby the unrealized gains and losses are either recognized as part of comprehensive income or, in the case of interest rate swaps, as a valuation adjustment to the underlying debt, or (ii) relate to regulated business activities where the risk is passed through to customers and accordingly the unrealized gains and losses are deferred until recovered or refunded to customers through rates. Unrealized gains or losses of derivative financial instruments that do not meet specific hedge accounting criteria or do not have the risk passed through to customers are recognized in income currently. Any inefficiency in the performance of the hedge is recognized in income currently or as appropriate, deferred in regulatory accounts and, ultimately, the financial results of the hedge are

recognized concurrently with the financial results of the underlying hedged item. All but an insignificant amount of our natural gas related derivatives are for terms of 18 months or less, allowing us to utilize widely available, published forward pricing curves in determining all of our appropriate market values. Our interest rate swaps are similar in nature to many other such financial instruments and are valued for us by commercial banks with expertise in such valuations.

We engage in a hedging program to mitigate our exposure to fluctuations in currency exchange rates and commodity prices and to balance our exposure to fixed and floating interest rates, and we believe that these hedges are generally effective in realizing these objectives. However, the accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. Generally, the financial statement volatility arises from an accounting requirement to recognize changes in values of financial instruments while not concurrently recognizing the values of the underlying transactions being hedged.

In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations. Even when we cannot enter into a completely effective hedge, we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

Includes pre-tax gains from sales of Kinder Morgan Management shares of $73.9 million ($31.6 million after tax) in the second and fourth quarters of 2005.

Includes a reduction of $43.8 million in 2005 pre-tax earnings ($20.7 million after tax) from our investment in Kinder Morgan Energy Partners resulting principally from the effects of certain regulatory, environmental, litigation and inventory items on Kinder Morgan Energy Partners’ earnings.

Includes a pre-tax charge of $15.0 million ($9.5 million after tax) in 2005 for our charitable contribution to the Kinder Morgan Foundation.

Includes pre-tax charges of $6.5 million ($4.1 million after tax), $15.0 million net of the recognition of deferred power development revenues and the impact of the resolution of certain litigation contingencies ($9.4 million after tax) and $47.4 million ($29.4 million after tax) in 2005, 2004 and 2003, respectively, for the impairment of certain investments in our Power business segment.

Includes 2005 net pre-tax gains on currency transactions and swaps of $2.3 million ($1.4 million after tax).

Includes a 2004 pre-tax charge of $3.9 million ($2.4 million after tax) due to the early extinguishment of debt.

Includes miscellaneous other pre-tax charges totaling $1.7 million ($1.1 million after tax) in 2005 and $1.6 million ($1.0 million after tax) in 2004.

Includes a 2003 pre-tax loss of $4.3 million ($2.7 million after tax) resulting from the sale of our interest in Igasamex USA Ltd.

Includes a $2.9 million ($1.8 million after tax) increase in 2003 earnings resulting from the settlement of a note receivable in an amount in excess of its carrying value.

Includes a $65.5 million reduction in the provision for income taxes in 2004 due principally to the impact of a reduction of the effective tax rate on previously recorded net deferred tax liabilities.

Our income from continuing operations increased from $528.5 million in 2004 to $552.2 million in 2005, an increase of $23.7 million. The items outlined in the footnotes above had the effect of increasing 2004 results by $52.7 million and decreasing 2005 results by $2.4 million. The remaining $78.8 million

increase is due to the following items: (i) increased earnings from our investment in Kinder Morgan Energy Partners, exclusive of the items discussed in the table above, (ii) increased earnings from our NGPL business segment, (iii) one month of 2005 earnings attributable to our acquisition of Terasen and (iv) a $4.5 million gain on sale of Kinder Morgan Management shares in the first quarter of 2005. These favorable income impacts were partially offset by (i) the contribution of our TransColorado business segment to Kinder Morgan Energy Partners effective November 1, 2004, (ii) decreased earnings from our Kinder Morgan Retail segment, (iii) increased interest expense due to higher interest rates, interest expense on Terasen’s existing debt and interest expense on incremental debt issued to acquire Terasen, (iv) increased general and administrative expenses due principally to the general and administrative costs of Terasen and (v) increased income taxes.

Operating revenues increased by $420.8 million (36%) from 2004 to 2005 due largely to (i) revenues from the Terasen assets and (ii) increased revenues in our NGPL and Kinder Morgan Retail business segments. These revenue increases were partially offset by (i) a reduction in revenues resulting from our contribution of TransColorado to Kinder Morgan Energy Partners in 2004 and (ii) the fact that 2004 results included the recognition of deferred power development revenues as discussed in the table above. Please refer to the individual business segment discussions included elsewhere herein for additional information regarding business segment results. Refer to the headings “Earnings from Our Investment in Kinder Morgan Energy Partners,” “Other Income and (Expenses),” “Income Taxes – Continuing Operations” and “Discontinued Operations” included elsewhere herein for additional information.

Our income from continuing operations increased from $381.7 million in 2003 to $528.5 million in 2004, an increase of $146.8 million (38.5%). In addition to the items discussed in the table above, the increase in income from continuing operations from 2003 to 2004 reflected increased income due to (i) increased earnings from our investment in Kinder Morgan Energy Partners in 2004, (ii) increased earnings from our NGPL and Kinder Morgan Retail business segments and (iii) decreased 2004 interest expense. These favorable impacts were partially offset by (i) decreased earnings from our TransColorado business segment that was contributed to Kinder Morgan Energy Partners during 2004, (ii) decreased earnings from our Power business segment and (iii) increased 2004 general and administrative expenses due principally to increased legal, accounting and employee benefits expenses. Operating revenues increased by $67.0 million (6%) from 2003 to 2004 reflecting, in addition to the incremental power development revenues discussed in the table above, (i) increased revenues in our Kinder Morgan Retail business segment and (ii) increased revenues in our Power segment due to the inclusion of our Triton Power affiliates in 2004 consolidated operating results. These increased operating revenues were partially offset by decreased operating revenues from our NGPL and TransColorado business segments.

Diluted earnings per common share from continuing operations increased from $4.23 in 2004 to $4.43 in 2005, an increase of $0.20 (4.7%). This increase reflected, in addition to the financial and operating impacts discussed preceding, a decrease of 0.3 million (0.2%) in average shares outstanding. The decrease in average shares outstanding resulted from the net effects of (i) 12.5 million shares issued to acquire Terasen, which were outstanding for one month, (ii) decreases in shares outstanding due to our share repurchase program (see Note 12(D) of the accompanying Notes to Consolidated Financial Statements), (iii) increases in shares outstanding due to newly-issued shares for (1) the employee stock purchase plan, (2) the issuance of restricted stock and (3) exercises of stock options by employees and (iv) the increased dilutive effect of stock options resulting from the increase in the market price of our shares (see Notes 1(E) and 16 of the accompanying Notes to Consolidated Financial Statements). Total diluted earnings per common share increased from $4.18 in 2004 to $4.45 in 2005, an increase of $0.27 (6.5%).

Diluted earnings per common share from continuing operations increased from $3.08 in 2003 to $4.23 in 2004, an increase of $1.15 (37.3%). This increase reflected, in addition to the financial and operating impacts discussed preceding, an increase of 1.1 million (0.9%) 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) exercises 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 (see Notes 1(E) and 16 of the accompanying Notes to Consolidated Financial Statements). These increases in average shares outstanding were partially offset by our share repurchases (see Note 12(D) of the accompanying Notes to Consolidated Financial Statements). Total diluted earnings per common share increased from $3.08 in 2003 to $4.18 in 2004, an increase of $1.10 (35.7%).

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.

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: (i) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system; (ii) Kinder Morgan Canada (formerly Terasen Pipelines), principally consisting of the ownership and operation of three refined products and crude oil pipelines: (1) Trans Mountain Pipeline, (2) Corridor Pipeline and (3) a one-third interest in the Express System; (iii) Terasen Gas, the regulated sale and transportation of natural gas to residential, commercial and industrial customers in British Columbia, Canada; (iv) Kinder Morgan Retail, the regulated sale and transportation of natural gas to residential, commercial and industrial customers principally in Nebraska, Wyoming and Colorado, but also including a small distribution system in Hermosillo, Mexico, and the sales of natural gas to certain utility customers under the Choice Gas Program; (v) Power, the operation and, in previous periods, construction of natural gas-fired electric generation facilities and (vi) prior to its sale as discussed following, TransColorado Gas Transmission Company, referred to as TransColorado, an interstate natural gas pipeline located in western Colorado and northwest New Mexico. Our investment in TransColorado Gas Transmission Company was contributed to Kinder Morgan Energy Partners effective November 1, 2004 (see Note 5 of the accompanying Notes to Consolidated Financial Statements). Effective with the contribution, the results of operations of TransColorado Gas Transmission Company are no longer included in our consolidated results of operations or our TransColorado business segment results. In previous periods, we owned and operated other lines of business that we discontinued during 1999 and in December 2005, we discontinued the water and utility services businesses acquired with Terasen. As a result of our implementation of a new accounting pronouncement, beginning January 1, 2006, we will include the accounts and balances of Kinder Morgan Energy Partners in our consolidated financial statements. See Note 20 of the accompanying Notes to Consolidated Financial Statements. We expect that, in addition to our five current business segments, we will report the following business segments: (1) Products Pipelines, (2) Natural Gas Pipelines, (3) CO₂ and (4) Terminals.

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

In the fourth quarter of 2002, as further discussed under “Power” following, we decided to discontinue the development portion of our power generation business and decreased the carrying value of certain of our power assets. Additional reductions in the carrying value of certain power assets have been made subsequently.

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

segment earnings. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

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

NGPL’s segment earnings increased from $392.8 million in 2004 to $435.2 million in 2005, an increase of $42.4 million (11%). Segment earnings for 2005 were positively impacted, relative to 2004, by (i) increased transportation and storage service revenues in 2005 resulting, in part, from increased firm demand revenues, the recent expansion of our storage system and the acquisition of the Black Marlin Pipeline (see discussion below) and (ii) increased operational gas sales. These positive impacts were partially offset by (i) an increase of $5.2 million in depreciation expense, (ii) an increase of $4.8 million in operations and maintenance expenses, principally attributable to higher electric compression costs, (iii) a $4.4 million increase in taxes other than income taxes, principally attributable to increased property taxes, (iv) the fact that 2004 results included $4.0 million in contractual customer penalty charges in 2004 that were billed prior to December 1, 2003, the effective date for NGPL’s Order 637 provisions, but had been reserved pending the final outcome of its Order 637 filings, (v) a $2.1 million reduction in gains from incidental sales of assets and (vi) the negative impact of significant changes in the values of various natural gas price indices relative to the value of the Henry Hub index used by the NYMEX in the valuation of derivative instruments, caused by hurricane-related supply disruptions in the Gulf of Mexico area. The increase in overall operating revenues in 2005, relative to 2004, was largely the result of (i) increased transportation and storage service revenues, as discussed above and (ii) increased operational gas sales volumes and increased natural gas prices in 2005. NGPL’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and recovery of storage cushion gas volumes. The increase in systems throughput in 2005, relative to 2004, was due principally to higher utilization of the Amarillo and Louisiana lines. The increase in systems throughput in 2005, relative to 2004, did not have a significant direct impact on revenues or segment earnings due to the fact that transportation revenues are derived primarily from “demand” contracts in which shippers pay a fee to reserve a set amount of system capacity for their use.

NGPL’s segment earnings increased from $372.0 million in 2003 to $392.8 million in 2004, an increase of $20.8 million (6%). Segment earnings for 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 expansion of our North Lansing storage facility that was completed in the second quarter of 2004 (see discussion following), (ii) increased margins from operational gas sales largely due to higher market prices, (iii) $4.0 million in contractual customer penalty charges in 2004 that were billed prior to December 1, 2003, the effective date for NGPL’s Order

637 provisions, but had been reserved pending the final outcome of its Order 637 filings and (iv) $2.3 million in pre-tax gains in 2004 from the sale of certain assets, principally land parcels in Illinois. 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 principally from increased hydrostatic testing and electric compression costs and (iii) increased depreciation expense due, in part, to system expansions. NGPL’s segment results for 2003 do not include a reduction of $4.1 million in interest expense attributable to the final settlement of a regulatory matter, which amount is included in “Interest Expense, Net.” The decrease in overall operating revenues in 2004, relative to 2003, was largely the result of decreased operational gas sales volumes and 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 and contractual customer penalty charges, as discussed above.

In 2005, NGPL extended long-term, firm transportation and storage contracts with some of its largest shippers, including Northern Illinois Gas Company (“Nicor”), The Peoples Gas Light and Coke Co., Northern Indiana Public Service Co., North Shore Gas Company, MidAmerican Energy Co., Ameren Corp. and BP Canada Energy Marketing (“BP”). Combined, the contracts represent approximately 1.9 million Dth per day of peak-period firm transportation service. Under the terms of the transportation agreement with Nicor, which extends into the first quarter of 2009, NGPL will provide its largest shipper with up to 917,865 Dth per day of firm transportation service. The new agreement replaces a contract that was due to expire March 31, 2006. In addition, Nicor has extended firm storage contracts totaling 42 Bcf that were scheduled to expire March 31, 2006, and March 31, 2007. A total of 16.5 Bcf has been extended until March 31, 2009, with the remaining 25.5 Bcf extended until March 31, 2010.

In August 2005, NGPL filed a certificate application with the FERC for an additional 10 Bcf expansion of its North Lansing storage facility in east Texas, which is expected to be completed in 2007 at a cost of approximately $64 million. NGPL recently completed an open season for this expansion and binding long-term precedent agreements have been executed on all of the additional capacity. The FERC order approving the project was issued January 23, 2006. In June 2005, NGPL received a certificate from the FERC for its Amarillo-Gulf Coast cross-haul expansion. The $20.7 million project will add 51,000 Dth per day of capacity and is expected to be in service in the spring of 2006. During the third quarter of 2005, NGPL began drilling storage injection/withdrawal wells to expand its Sayre storage field in Oklahoma by 10 Bcf. The $35 million project is expected to begin service in the spring of 2006 and all of the expansion capacity has been contracted for under long-term agreements. In addition, NGPL is adding a new compressor station to Segment 17 of its Amarillo-Gulf Coast line that will provide 140 MMcf per day of additional capacity. The $17 million project is expected to be in service by the fall of 2006 and all of the additional capacity is fully contracted.

In the second quarter of 2004, NGPL completed construction of 10.7 Bcf of storage service expansion at its existing North Lansing storage facility in east Texas, all of which is fully subscribed under long-term contracts. Effective September 1, 2004, NGPL acquired the Black Marlin Pipeline, a 38-mile, 30-inch pipeline that runs from Bryan County, Oklahoma to Lamar County, Texas. The Black Marlin Pipeline ties into NGPL’s Amarillo/Gulf Coast line and increased this line’s capacity by 38,000 Dth per day. This incremental capacity was fully subscribed in an open season under long-term contracts.

Substantially all of NGPL’s pipeline capacity is committed under firm transportation contracts ranging from one to five years. Under these contracts, over 90% of the revenues are derived from a demand charge and, therefore, are collected regardless of the volume of gas actually transported. The principal impact of the actual level of gas transported is on fuel recoveries, which are received in-kind as volumes move on the system. Approximately 45% of the total transportation volumes committed under NGPL’s

long-term firm transportation contracts in effect on February 1, 2006 had remaining terms of less than three years. Contracts representing approximately 2.5% of NGPL’s total long-haul, contracted firm transport capacity as of January 31, 2006 are scheduled to expire during 2006. NGPL continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts. During 2005, NGPL successfully re-contracted firm transportation and storage capacity to the end that, as of the end of 2005, firm long-haul transportation capacity was sold out through February 2007 (except for a portion of summer-only capacity available on the Gulf Coast Line). Storage is fully contracted until April 2007.

In a letter filed on December 8, 2005, NGPL requested that the Office of the Chief Accountant of the FERC confirm that NGPL’s proposed accounting treatment to capitalize the costs incurred in a one-time pipeline rehabilitation project that will address stress corrosion cracking on portions of NGPL’s pipeline system is appropriate. The rehabilitation project will be conducted over a five-year period at an estimated cost of $30 million per year. The filing is still pending before the FERC.

For 2006, we currently expect that NGPL will experience 7% growth in segment earnings in comparison to 2005. This increase in earnings is expected to be derived primarily from an increase in storage and firm transport revenues resulting from (i) the Amarillo-Gulf Coast cross-haul expansion expected to be in service in April 2006, (ii) the expansion of our Sayre storage field expected to begin service in the spring of 2006, (iii) the Segment 17 expansion and (iv) successful re-contracting at marginally higher rates. These positive effects on earnings will be partially offset by an expected increase of approximately $13 million in operating expenses related to pipeline integrity management programs due to our implementation of a FERC order effective January 1, 2006, which will cause us to expense certain program costs that previously were capitalized. See Note 8 of the accompanying Notes to Consolidated Financial Statements for additional information regarding this FERC order. However, as discussed following, there are factors beyond our control that can affect our results, including developments in the regulatory arena and as yet unforeseen competitive developments. Accordingly, our actual future results may differ significantly from our projections.

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

The majority of NGPL’s system is subject to rate regulation under the jurisdiction of the Federal Energy Regulatory Commission. Currently, there are no material proceedings challenging the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights, under certain circumstances prescribed by applicable regulations, to challenge the rates we charge. There can be no assurance that we will not face future challenges to the rates we receive for services on our pipeline systems.

The results of operations of Kinder Morgan Canada (formerly Terasen Pipelines) are included in our results beginning with the November 30, 2005 acquisition of Terasen. Kinder Morgan Canada owns and operates the Trans Mountain pipeline, a common carrier pipeline system originating at Edmonton, Alberta for the transportation of crude petroleum, refined petroleum and iso-octane to destinations in the interior and on the west coast of British Columbia, with connecting pipelines that deliver petroleum to refineries in the State of Washington and that transport jet fuel from Vancouver area refineries and marketing terminals and Westridge Marine Terminal to Vancouver International Airport. Kinder Morgan Canada also owns and operates the Corridor Pipeline, which transports diluted bitumen produced at the Muskeg River Mine, located approximately 43 miles north of Fort McMurray, Alberta, to a heavy oil upgrader near Edmonton, Alberta, a distance of approximately 281 miles. A smaller diameter parallel pipeline transports recovered diluent from the upgrader back to the mine. Corridor also consists of two additional pipelines, each 27 miles in length, to provide pipeline transportation between the Scotford Upgrader and the existing trunk pipeline facilities of Trans Mountain and Enbridge Pipelines Inc. in the Edmonton area. Kinder Morgan Canada also (i) operates and (ii) owns a one-third interest in the Express System. The Express System is a batch-mode, common-carrier, crude pipeline system comprised of the Express Pipeline and the Platte Pipeline. The Express System transports a wide variety of crude types produced in Alberta to markets in the Rocky Mountain and Midwest regions of the United States. The National Energy Board (“NEB”) regulates the Canadian portion of Trans Mountain’s crude oil and refined products pipeline system. The NEB authorizes pipeline construction and establishes tolls and conditions of service.

In January 2006, Kinder Morgan Canada entered into a memorandum of understanding with the Canadian Association of Petroleum Producers (“CAPP”) for a new Incentive Toll Settlement (the “2006-2010 ITS”). The 2006-2010 ITS will determine the tolls to be charged on the Trans Mountain system over the five-year term of the agreement, to take effect as of January 1, 2006. The agreement will also govern the financial arrangements for the Pump Station Expansion and Anchor Loop projects. The 2006-2010 ITS is subject to NEB approval, and Kinder Morgan Canada and the CAPP will work toward a final agreement by the end of June 2006. In addition to tolling and expansion parameters, the formal agreement contains capacity allocation procedures for the Westridge Marine Terminal and enhanced service standards definitions.

On November 10, 2005, Kinder Morgan Canada received approval from the NEB to increase the capacity of the Trans Mountain pipeline system from 225,000 bpd to 260,000 bpd. The C$230 million expansion (the “Pump Station Expansion”) is designed to add 35,000 bpd of heavy crude oil capacity by building new and upgrading existing pump stations along the pipeline system between Edmonton, Alberta, and Burnaby, British Columbia. Construction is expected to begin in early 2006 so that the expansion can be in service in April 2007.

Kinder Morgan Canada filed a comprehensive environmental report with the Canadian Environmental Assessment Agency on November 15, 2005, and filed a complete NEB application for the Anchor Loop Project on February 17, 2006. The C$400 million project involves looping a 98-mile section of the existing Trans Mountain pipeline system between Hinton, Alberta, and Jackman, British Columbia, and

the addition of three new pump stations. With construction of the Anchor Loop, the Trans Mountain system’s capacity will increase from 260,000 bpd to 300,000 bpd by the end of 2008.

Based on management’s expectations for petroleum transportation demand to the West Coast of British Columbia and shipper feedback, Kinder Morgan Canada has decided not to seek long-term contracts with shippers for the Pump Station Expansion Project or the Anchor Loop Project. As a result, there is no certainty that shipments on the Trans Mountain system will be sufficient to adequately recover the entire capital costs of the Pump Station and Anchor Loop expansions. However, the provisions of the 2006-2010 ITS will mitigate Trans Mountain’s financial exposure to throughput shortfalls during that timeframe.

Beyond the Anchor Loop project, Kinder Morgan Canada is actively pursuing TMX 2, an approximately C$1 billion project that would loop the Trans Mountain pipeline between Valemont and Kamloops and back to Edmonton, increasing throughput by 100,000 bpd, and TMX 3, a C$900 million project that would loop the Trans Mountain pipeline between Kamloops and the Lower Mainland United States, increasing throughput by 300,000 bpd. Kinder Morgan Canada plans to conduct open seasons for both projects in 2006. Further into the future, Kinder Morgan Canada is considering building a new 400,000 bpd pipeline across northern British Columbia to a new deep-water port facility in Kitimat, British Columbia at a projected cost of C$2.0 billion.

We have initiated engineering, environmental and consultation activities on the proposed Corridor pipeline expansion project. The proposed C$1.0 billion expansion includes building a new 42-inch diluent/bitumen (“dilbit”) pipeline, a new 20-inch products pipeline, tankage and upgrading existing pump stations along the existing pipeline system from the Muskeg River Mine north of Fort McMurray to the Edmonton region. The Corridor pipeline expansion will add an initial 200,000 bpd of dilbit capacity to accommodate the new bitumen production from the Muskeg River Mine. The current dilbit capacity is approximately 258,000 bpd. It is expected to climb to 278,000 by April 2006 by upgrading existing pump station facilities. By 2009, the dilbit capacity of the Corridor system is expected to be approximately 500,000 bpd. An application for the Corridor Pipeline Expansion Project was filed with the Alberta Energy Utilities Board and Alberta Environment on December 22, 2005. Pending regulatory and definitive shipper approval, construction will begin in late 2006.

In late 2003 and 2004, Terasen conducted open seasons to obtain long-term commitments for a portion of the Express System’s uncommitted capacity and for expansion capacity. Express has 84% of its 280,000 bpd post-expansion total capacity contracted. These contracts expire in 2007, 2012, 2014 and 2015 in amounts of 1%, 40%, 11% and 32% of total capacity, respectively. These contracts provide for committed tolls for transportation on the Express System, which can be increased each year by up to 2%. The remaining capacity is made available to shippers as uncommitted capacity.

The results of operations of Terasen Gas are included in our results beginning with the November 30, 2005 acquisition of Terasen. Terasen’s natural gas distribution operations consist primarily of Terasen

Gas Inc., Terasen Gas (Vancouver Island) Inc. (“TGVI”) and Terasen Gas (Whistler) Inc., collectively referred to in this report as Terasen Gas. Terasen Gas is regulated by the British Columbia Utilities Commission (“BCUC”).

Terasen Gas Inc. is the largest distributor of natural gas in British Columbia, serving approximately 805,000 customers in more than 100 communities. Major areas served by Terasen Gas Inc. are Greater Vancouver, the Fraser Valley and the Thompson, Okanagan, Kootenay and North Central Interior regions of the province. TGVI serves approximately 85,000 customers on Vancouver Island and the Sunshine Coast area and Terasen Gas (Whistler) serves approximately 2,000 customers in the Whistler region. Terasen Gas Inc. and TGVI provide transmission and distribution services to their customers, and obtain natural gas supplies on behalf of residential and commercial customers. Gas supplies are sourced primarily from northeastern British Columbia and from Alberta.

Terasen Gas Inc.’s allowed return on equity (“ROE”) is determined annually based on a formula that applies a risk premium to a forecast of long-term (30-year) Government of Canada bond yields. For 2005, the application of the ROE formula set Terasen Gas Inc.’s allowed ROE at 9.03%, down from 9.15% in 2004. On March 2, 2006, a Decision was issued by the BCUC approving changes to Terasen Gas Inc.’s and TGVI’s deemed equity components from 33% to 35% and from 35% to 40%, respectively. The same Decision also modified the previously existing generic ROE reset formula resulting in an increase in allowed ROEs from the levels that would have resulted from the old formula. The changes increased the allowed ROE from 8.29% to 8.80% for Terasen Gas Inc. and from 8.79% to 9.50% for TGVI in 2006.

Kinder Morgan Retail’s segment earnings decreased 16 percent from $69.3 million in 2004 to $58.2 million in 2005. Segment results for 2005, relative to 2004, were principally impacted by (i) reduced space heating and agricultural demand in 2005, (ii) an increase of $2.8 million in operations and maintenance expense due, in part, to system expansions and (iii) an increase of $1.1 million in depreciation expense due to system expansions. These negative impacts were partially offset by continued customer growth in Colorado. The $44.0 million increase in operating revenues in 2005, relative to 2004, was principally due to increased natural gas commodity sales prices in 2005 (which is accompanied by a corresponding increase in gas purchase costs), partially offset by lower volumes. Agriculture-related volumes decreased as a result of more efficient farming practices and competition from alternative fuels. Residential and commercial space heating volumes declined as a result of the residential and commercial use of more energy efficient natural gas-burning appliances and conservation, accelerated by higher commodity prices.

Kinder Morgan Retail’s segment earnings increased by $3.8 million (6%) from 2003 to 2004. This increase was due principally to (i) increased space heating demand in the first and fourth quarters of 2004, (ii) increased grain drying demand in the fourth quarter of 2004 and (iii) continued customer

growth in Colorado. These positive impacts were partially offset by reduced irrigation demand in the second and third quarters of 2004 and increased operations and maintenance and depreciation expenses in 2004 due, in part, to system expansion. The increase in operating revenues in 2004, relative to 2003, which was largely offset by an increase in gas purchases and other costs of sales, was principally due to (i) higher natural gas prices in 2004 (which, in general, are passed through as a component of the overall sales rate), (ii) the fact that a higher percentage of our Wyoming customers chose us as their natural gas supplier in 2004, either through regulated rates that pass-through the cost of gas to the customer, or through our Choice Gas program (which allows competing commodity natural gas providers to sell natural gas to customers connected to our natural gas distribution system), which increased our revenues from natural gas sales (accompanied by a corresponding increase in gas purchase costs), (iii) increased revenues from non-regulated merchandise sales and (iv) continued customer growth in Colorado. These positive impacts to 2004 revenues were partially offset by reduced irrigation demand in the second and third quarters of 2004.

Kinder Morgan Retail utilizes a weather hedging program to reduce the volatility of its earnings pattern by reducing the impact of weather-related demand fluctuations. See Note 14 of the accompanying Notes to Consolidated Financial Statements for additional information regarding our hedging strategy. During 2005, Kinder Morgan Retail completed a $14 million automated meter reading system serving its entire three-state service territory, and a $14 million project to increase transmission capacity to serve its Western Colorado distribution customers. During the second quarter of 2004, Kinder Morgan Retail completed and placed into service its $20 million, 58-mile natural gas transmission pipeline from Montrose to Ouray, Colorado.

For 2006, we currently expect that Kinder Morgan Retail will experience approximately 1% growth in segment earnings due largely to the addition of new customers in certain high-growth areas in Colorado. However, as discussed following, there are factors beyond our control that can affect our results, including developments in the regulatory arena, currently unforeseen competitive developments and weather-related impacts outside our hedging program. For these and other reasons, our actual future results may differ significantly from our projections.

On February 28, 2006, Kinder Morgan Retail filed a general rate increase application with the Wyoming Public Service Commission seeking an additional $7.94 million of revenue per year from its Wyoming gas utility operations. A final commission decision on the application is expected within 10 months of the filing date.

A significant portion of Kinder Morgan Retail’s business is subject to rate regulation by each respective state’s utility commission in Colorado, Wyoming and Nebraska. With the exception of the general rate increase application for our Wyoming gas utility operations discussed preceding, there are currently no material proceedings to change the base rates on any of Kinder Morgan Retail’s intrastate pipeline or distribution systems. Nonetheless, there can be no assurance that we will not face future challenges to the rates we receive for these services. Furthermore, we may choose to make additional rate filings in the future, the outcome of which would be uncertain, and which could result in a challenge to our requested or existing rates. Kinder Morgan Retail is also subject to market variability in natural gas prices and basis differentials. Please refer to the discussion of basis differentials under the heading “Natural Gas Pipeline Company of America” in this Item.

Does not include (i) pre-tax charges of $6.5 million, $33.5 million and $44.5 million in 2005, 2004 and 2003, respectively, to record the impairment of certain assets, (ii) incremental earnings of $18.5 million in 2004 reflecting (1) the recognition of previously deferred revenues associated with construction of the Jackson, Michigan power generation facility, (2) gains from the sale of surplus power generation equipment and (3) the settlement of certain litigation. Results for 2003 exclude a pre-tax loss of $2.9 million resulting from the sale of natural gas reserves by an equity-method investee. These items are discussed below.

Due to the adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, the results of operations of our Triton Power affiliates are included in our consolidated operating results and in the results of our Power segment beginning in 2004. Although the results of Triton have an impact on the total operating revenues and expenses of the Power business segment, after taking into account the associated minority interests, the consolidation of Triton had no effect on Power’s segment earnings.

Power’s segment earnings, as reported above, increased from $15.3 million in 2004 to $19.7 million in 2005, an increase of $4.4 million (29%). Segment earnings for 2005 were positively impacted, relative to 2004, principally by a $3.0 million increase in equity earnings from Thermo Cogeneration Partnership due largely to (i) the favorable resolution of claims in the Enron bankruptcy proceeding, (ii) higher capacity revenues and (iii) reduced 2005 interest expense resulting from the repayment of long-term debt. In addition, Power was positively impacted by earnings from providing operating and maintenance management services, starting in June 2005, at a new 103-megawatt combined-cycle natural gas-fired power plant in Snyder, Texas, which is generating electricity for Kinder Morgan Energy Partners’ SACROC operations. Certain surplus power generation equipment was sold during 2004 and 2003 (see Note 5 of the accompanying Notes to Consolidated Financial Statements). We recorded $3.9 million of pre-tax gains from these sales in 2004, which are excluded from segment earnings as reported above. In addition, we recorded revenues of $13.3 million and $1.3 million in 2004 resulting from development fees associated with the Jackson, Michigan power plant and the favorable settlement of litigation matters, respectively, which are excluded from the tabular presentation of segment earnings as reported above.

Power’s segment earnings, as reported above, decreased by $6.8 million (31%) from 2003 to 2004. Segment earnings for 2004 were negatively impacted, relative to 2003, primarily because 2003 results included $6.8 million in development fees for the Jackson, Michigan power plant.

entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC. Williams Energy Marketing and Trading supplies all natural gas to and purchases all power from the power plant under a 16-year tolling agreement with Triton Power Michigan LLC. Our preferred equity interest has no management or voting rights, but does retain certain protective rights, and is entitled to a cumulative return, compounded monthly, of 9.0% per annum. No income was recorded in 2005 and no income is expected in 2006 from this preferred investment due to the fact that the dividend on this preferred is not currently being paid, and uncertainty concerning the date at which such distributions will be received.

In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant in Wrightsville, Arkansas, utilizing Kinder Morgan Power’s Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. During the third quarter of 2003, we announced that Mirant had placed the Wrightsville, Arkansas plant in bankruptcy, and we would assess the long-term prospects for this facility during the fourth quarter. In December 2003, we completed our analysis and determined that it was no longer appropriate to assign any carrying value to our investment in this facility and recorded a $44.5 million pre-tax charge, effectively writing off our remaining investment in the Wrightsville power facility. This charge is excluded from the tabular presentation of segment earnings as reported above. During the third quarter of 2005, and subsequent to a negotiated settlement agreement approved by the court, Mirant sold the Wrightsville power facility to Arkansas Electric Cooperative Corporation.

During 2002, we noted that a number of factors had negatively affected Power’s business environment and certain of its current operations. These factors, which are currently expected to continue in the near to intermediate term, include (i) volatile and generally declining prices for wholesale electric power in certain markets, (ii) cancellation and/or postponement of the construction of a number of new power generation facilities, (iii) difficulty in obtaining air permits with acceptable operating conditions and constraints and (iv) a marked deterioration in the financial condition of a number of participants in the power generating and marketing business, including participants in the power plants in Jackson, Michigan and Wrightsville, Arkansas. During the fourth quarter of 2002, after completing an analysis of these and other factors to determine their impact on the market value of these assets and the prospects for this business in the future, we (i) determined that we would no longer pursue power development activities and (ii) recorded a $134.5 million pre-tax charge to reduce the carrying value of our investments in (1) sites for future power plant development, (2) power plants and (3) turbines and associated equipment.

Since 1998, we have had an investment in a 76 megawatt gas-fired power generation facility located in Greeley, Colorado. We became concerned with the value of this investment as a result of several recent circumstances including the expiration of a gas purchase contract, the amendment of the associated power purchase agreement and uncertainties surrounding the management of this facility, which has changed ownership twice in the last one and one-half years. These ownership changes made it difficult for us to obtain information necessary to forecast the future of this asset. During the fourth quarter of 2004, we concluded that we had sufficient information to determine that our investment had been impaired and, accordingly, reduced our carrying value by $26.1 million. During the fourth quarter of 2005, we concluded that we had sufficient information to determine that our investment had been further impaired and, accordingly, reduced our carrying value by an additional $6.5 million. These charges are excluded from the tabular presentation of segment earnings as reported above.

During 2003 and 2004, we sold six of our surplus turbines and certain associated equipment, including certain equipment to Kinder Morgan Energy Partners (see Note 5 of the accompanying Notes to Consolidated Financial Statements). Recognizing the effects of changes in technology and the limited

improvement of the general economies of the electric generation industry, we determined that the carrying values of our remaining turbines and associated equipment should be reduced. In the fourth quarter of 2004, we reduced the carrying value of these assets by $7.4 million. This charge is excluded from segment earnings as reported above. We are continuing our efforts to sell the remaining inventory of surplus turbines and associated equipment, which had a carrying value of $23.5 million at December 31, 2005.

Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, in December 2003, we made an additional investment in our Colorado power businesses in the form of approximately 1.8 million Kinder Morgan Management shares that we owned. We delivered these shares to an entity controlled by the former Thermo owners, which entity is required to retain the shares until they vest (400,000 shares will vest each January 1 of 2004, 2005 and 2006, with the remainder vesting on January 1, 2007). We will continue to receive distributions made by Kinder Morgan Management attributable to the unvested shares. We recorded our increased investment based on the third-party-determined $56.1 million fair value of the shares as of the contribution date, with a corresponding liability representing our obligation to deliver vested shares in the future. The effect of this incremental investment will be to increase our ownership interest in the Thermo entities beginning in 2010.

We expect that 2006 segment earnings from Power will increase by approximately 6% due to (i) a full year of providing operating and maintenance management services at the Snyder, Texas plant, (ii) improved performance of our owned power facility at Greeley, Colorado and (iii) lower depreciation and amortization of investments due to prior years’ impairment. Actual future results may differ significantly from our projections.

Effective November 1, 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners (see Note 5 of the accompanying Notes to Consolidated Financial Statements). TransColorado’s results shown above reflect its earnings through October 31, 2004 and nothing thereafter, however, we will continue to participate in the results of operations of TransColorado through our equity investment in Kinder Morgan Energy Partners. We recognized a $0.6 million pre-tax loss from the contribution of TransColorado, which is included in segment earnings, as reported above. TransColorado’s segment earnings decreased from $23.1 million in 2003 to $20.3 million in 2004, principally due to the fact that 2004 results include only the ten months through October 2004 and also include the $0.6 million pre-tax loss from the contribution of TransColorado.

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

Pre-tax earnings from our investment in Kinder Morgan Energy Partners in 2005 was negatively impacted by approximately $32.6 million due principally to the effects of certain regulatory, environmental, litigation and inventory items on Kinder Morgan Energy Partners’ 2005 earnings.

We reflect our investment in Kinder Morgan Energy Partners under the equity method of accounting and, accordingly, report our share of Kinder Morgan Energy Partners’ earnings as “Equity in Earnings” in our Consolidated Statement of Operations in the period in which such earnings are reported by Kinder Morgan Energy Partners. Beginning January 1, 2006, we will consolidate Kinder Morgan Energy Partners’ accounts and balances in our consolidated financial statements. See Note 20 of the accompanying Notes to Consolidated Financial Statements.

In addition to the items discussed in the table above, our pre-tax earnings from Kinder Morgan Energy Partners were positively impacted in 2005, in part, by the positive impacts of internal growth and acquisitions on Kinder Morgan Energy Partners’ earnings and cash flows. For 2006, pre-tax earnings attributable to our investment in Kinder Morgan Energy Partners are expected to increase by approximately 15% due to, among other factors, improved performance from existing assets. However, there are factors beyond the control of Kinder Morgan Energy Partners that may affect its results, including developments in the regulatory arena and as yet unforeseen competitive developments or acquisitions. Additional information on Kinder Morgan Energy Partners is contained in its Annual Report on Form 10-K for the year ended December 31, 2005.

The expense associated with our capital trust securities was included in “Minority Interests” prior to the third quarter of 2003 ($10.9 million for the year ended December 31, 2003). Due to our adoption of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, the expense associated with these securities was included in “Interest Expense – Capital Trust Securities” beginning with the third quarter of 2003. Due to our adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, the subsidiary trusts associated with our capital trust securities are no longer consolidated, effective December 31, 2003. The associated expense is included in “Interest Expense – Deferrable Interest Debentures” for the years ended December 31, 2005 and 2004.

Excludes a loss of $2.9 million in 2003 resulting from the sale of natural gas reserves by an equity-method investee.

Includes a loss of $2.9 million in 2003 resulting from the sale of natural gas reserves by an equity-method investee.

Includes pre-tax gains from sales of Kinder Morgan Management shares of $73.9 million ($31.6 million after tax) in the second and fourth quarters of 2005.

Includes a reduction of $43.8 million in 2005 pre-tax earnings ($20.7 million after tax) from our investment in Kinder Morgan Energy Partners resulting principally from the effects of certain regulatory, environmental, litigation and product inventory items on Kinder Morgan Energy Partners’ earnings.

Includes 2005 net pre-tax gains on currency transactions and swaps of $2.3 million ($1.4 million after tax).

Includes miscellaneous other pre-tax charges totaling $1.7 million ($1.1 million after tax) in 2005 and $1.6 million ($1.0 million after tax) in 2004.

Includes a 2003 pre-tax loss of $4.3 million ($2.7 million after tax) resulting from the sale of our interest in Igasamex USA Ltd.

Includes a $2.9 million ($1.8 million after tax) increase in 2003 earnings resulting from the settlement of a note receivable in an amount in excess of its carrying value.

“Other Income and (Expenses)” increased from income of $357.3 million in 2004 to income of $440.8 million in 2005, an increase of $83.5 million (23%). In addition to the items discussed in the notes to the table above, “Other Income and (Expenses)” was positively impacted in 2005, relative to 2004, by (i) increased equity in the earnings of Kinder Morgan Energy Partners, net of the associated minority interest in Kinder Morgan Management, due in part to internal growth and acquisitions within Kinder

Morgan Energy Partners (refer to the heading “Earnings from Our Investment in Kinder Morgan Energy Partners” included elsewhere herein), and (ii) a $4.5 million gain on sale of Kinder Morgan Management shares in the first quarter of 2005. These positive impacts were partially offset by increased interest expense due largely to (i) higher effective interest rates, partially offset by lower outstanding balances on our pre-Terasen debt and (ii) approximately $22.3 million of interest due to interest on Terasen’s existing debt and on incremental debt issued to acquire Terasen (see Notes 4 and 12 of the accompanying Notes to Consolidated Financial Statements). The increase in effective interest rates on our debt in 2005 is attributable to having a significant portion of our overall debt balances subject to floating interest rates. Refer to the heading “Risk Management” in Item 7A. Quantitative and Qualitative Disclosures About Market Risk, included elsewhere herein, and Note 14 of the accompanying Notes to Consolidated Financial Statements for additional information regarding our outstanding fixed-to-floating interest rate swap agreements. Refer to the heading “Income Taxes – Realization of Deferred Tax Assets” included elsewhere herein and Notes 5 and 11 of the accompanying Notes to Consolidated Financial Statements for additional information regarding our sales of Kinder Morgan Management shares that we owned.

“Other Income and (Expenses)” increased from income of $270.2 million in 2003 to income of $357.3 million in 2004, an increase of $87.1 million. This increase was principally due to (i) increased equity in the earnings of Kinder Morgan Energy Partners due, in part, to acquisitions made and strong performance from the assets held by Kinder Morgan Energy Partners, (ii) decreased interest expense, reflecting reduced debt outstanding offset by a slight increase in interest rates and (iii) a $6.4 million increase in gains from sales of assets (see Note 5 of the accompanying Notes to Consolidated Financial Statements). These positive impacts were partially offset by a $3.9 million loss on early extinguishment of debt (see Note 12 of the accompanying Notes to Consolidated Financial Statements) and a $14.9 million increase in minority interest expense.

The income tax provision increased from $226.7 million in 2004 to $360.9 million in 2005, an increase of $134.2 million (59%) due principally to (i) the fact that the 2004 tax provision includes a reduction of $70.3 million due to the impact of applying a lower effective tax rate on previously recorded net deferred tax liabilities, (ii) an increase of $60.7 million due to an increase in pre-tax income from continuing operations of $157.8 million, (iii) a decrease of $1.8 million related to Kinder Morgan Management minority interest and (iv) an increase of $5.0 million attributable to other items.

The income tax provision decreased from $244.6 million in 2003 to $226.7 million in 2004, a decrease of $17.9 million (7%). The net decrease of $17.9 million results from (i) a reduction of $70.3 million due to the impact of a lower effective tax rate on previously recorded net deferred tax liabilities, (ii) an increase of $44.2 million attributable to $128.9 million additional income from continuing operations, (iii) an increase of $2.5 million attributable to Kinder Morgan Management minority interest and (iv) an increase of $5.7 million attributable to other items. The reduction in the effective tax rate from 2003 to 2004 was principally due to a decrease in the component of the overall estimated effective tax rate attributable to state income taxes resulting from, among other factors, changes in apportionment of consolidated taxable income among the various states.

See Note 11 of the accompanying Notes to Consolidated Financial Statements for additional information on income taxes.

A capital loss carryforward can be utilized to reduce capital gain during the five years succeeding the year in which a capital loss is incurred. At December 31, 2004, we had a capital loss carryforward of

approximately $56.1 million, of which $52.5 million was to expire in 2005. In addition, during the third quarter of 2005, the Wrightsville power facility (in which we owned an interest) was sold to Arkansas Electric Cooperative Corporation, generating an estimated capital loss for tax purposes of $64.6 million. We did not record a loss for book purposes due to the fact that we had previously written off the carrying value of our investment in the Wrightsville power facility.

During 2005, in order to offset our capital loss carrryforward expiring in 2005 and our capital loss from the Wrightsville power facility, we sold 5.67 million Kinder Morgan Management shares that we owned, generating a gain for tax purposes of $118.1 million. As a result of these and other transactions, we have remaining a $2.5 million capital loss carryforward that expires $1.7 million during 2008 and $0.8 million during 2009. No valuation allowance has been provided with respect to this deferred tax asset.

On November 30, 2005, we acquired Terasen (see Note 4 of the accompanying Notes to Consolidated Financial Statements). At that time, we adopted and implemented a plan to discontinue the water and utility services line of business operated by Terasen, which offers water, wastewater and utility services, primarily in western Canada. On January 17, 2006, we announced a definitive agreement to sell these operations to a consortium, including members of the water business’ management, for approximately C$125 million, subject to certain purchase price adjustments at closing. We do not expect to incur any gain or loss for book purposes from this transaction. We expect this transaction to close by the end of April 2006. Our consolidated results for 2005 include a $0.7 million loss from discontinued operations, net of tax, from these operations from November 30 to December 31, 2005.

During 1999, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing of natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids, (iii) international operations and (iv) the direct marketing of non-energy products and services. During 2000, we completed the disposition of these businesses, with the exception of international operations (principally consisting of a natural gas distribution system in Hermosillo, Mexico) which, in the fourth quarter of 2000, we decided to retain. During 2005, we recorded an incremental gain of $3.2 (net of tax of $1.9 million), to adjust previously recorded liabilities to reflect our latest estimates. During the fourth quarter of 2004, we recorded incremental losses of approximately $6.4 million (net of tax benefits of $3.8 million) to increase previously recorded liabilities to reflect updated estimates and reflect the impact of settled litigation. We had a remaining liability of approximately $0.4 million at December 31, 2005 associated with these discontinued operations, representing legal obligations associated with our sale of assets to ONEOK, Inc. We do not expect significant additional financial impacts associated with these matters. Note 7 of the accompanying Notes to Consolidated Financial Statements contains certain additional financial information with respect to these discontinued operations.

Our primary cash requirements, in addition to normal operating, general and administrative expenses, are for debt service, capital expenditures, common stock repurchases and quarterly cash dividends to our common shareholders. Our capital expenditures other than sustaining capital expenditures, our common stock repurchases and our quarterly cash dividends to our common shareholders are discretionary. Our capital expenditures for 2006 are currently expected to be approximately $611.6 million. We expect to fund these expenditures with existing cash and cash flows from operating activities. In addition to utilizing cash generated from operations, we could meet these cash requirements through borrowings

under our credit facilities, issuing short-term commercial paper, long-term notes or additional shares of common stock.

Our ratio of total debt to total capital increased significantly in the fourth quarter of 2005 as the result of the acquisition of Terasen as discussed under “Significant Financing Transactions” following. The decline in our ratio of total debt to total capital from 2003 to 2004 relates to a number of factors, including our increased cash flows from operations. In recent periods, we have significantly increased our dividends per common share and have announced our intention to consider further increases on a periodic basis. We expect our ratio of total debt to total capital to increase further with the implementation of EITF 04-5, which will result in including the accounts and balances of Kinder Morgan Energy Partners in our consolidated financial statements in 2006. Although the total debt on our consolidated balance sheet will increase as a result of consolidating Kinder Morgan Energy Partners’ debt balances with ours, Kinder Morgan, Inc. has not assumed any additional obligations. See Note 20 of the accompanying Notes to Consolidated Financial Statements for information regarding EITF 04-5.

In addition to the direct sources of debt and equity financing shown in the following table, we obtain financing indirectly through our ownership interests in unconsolidated entities as shown under “Significant Financing Transactions” following. Our largest such unconsolidated investment is in Kinder Morgan Energy Partners. See “Investment in Kinder Morgan Energy Partners” following. In addition to our results of operations, these balances are affected by our financing activities as discussed following.

Cash and cash equivalents netted against short-term debt were $116,635, $176,520 and $11,076 for December 31, 2005, 2004 and 2003, respectively.

Outstanding notes and debentures plus short-term debt, less cash and cash equivalents.

Except for our Terasen subsidiaries, we employ a centralized cash management program that essentially concentrates the cash assets of our subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. Our centralized cash management program provides that funds in excess of the daily needs of our subsidiaries be concentrated, consolidated, or otherwise made available for use by other entities within our consolidated group. We place no restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to parent companies.

In addition, NGPL is subject to FERC-enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.

Terasen, for certain of its subsidiaries, employs a centralized cash management program that essentially concentrates the cash assets of these subsidiaries for the purpose of providing financial flexibility and lowering the cost of borrowing. Terasen’s centralized cash management program provides that funds in excess of the daily needs of its subsidiaries be concentrated or consolidated for use by other entities within the Terasen group.

Terasen Gas Inc. and TGVI, as stand-alone regulated entities, each operate their own separate cash management programs, funding short-term capital requirements through either commercial paper issuance or drawing on available credit facilities, while investing funds in excess of daily needs on a short-term basis to lower the overall net cost of borrowing.

As part of the conditions attached to the approval of the Terasen acquisition by the BCUC, the Terasen-owned utilities regulated by the BCUC, including Terasen Gas Inc. and TGVI, are required to maintain a percentage of common equity to total capital that is at least as much as that determined by the BCUC from time to time for ratemaking purposes, and none may pay a dividend that would reasonably be expected to violate this restriction without prior BCUC approval.

Our principal sources of short-term liquidity are our revolving bank facilities, our commercial paper programs (which are supported by our revolving bank facilities) and cash provided by operations. As of December 31, 2005, we had available (i) an $800 million five-year senior unsecured revolving credit facility dated August 5, 2005, (ii) C$450 million of 364-day senior unsecured revolving credit facilities under Terasen Inc., (iii) C$500 million of 364-day senior unsecured revolving credit facilities under Terasen Gas Inc., and (iv) a C$225 million 364-day senior unsecured revolving credit facility under Terasen Pipelines (Corridor) Inc. These credit facilities can be used for general corporate purposes, including as backup for each company’s respective commercial paper programs. At December 31, 2005 and February 28, 2006, we had $610.6 million and $681.9 million, respectively, of commercial paper issued and outstanding and drawings under our facilities. After inclusion of applicable outstanding letters of credit that reduce our borrowing capacity under the credit facilities, the remaining available borrowing capacity under the bank facilities was $1,016.1 million and $1,288.7 million at December 31, 2005 and February 28, 2006, respectively. Additionally, at December 31, 2005 and February 28, 2005, we had a $20 million demand facility associated with Terasen Pipelines (Corridor) Inc.’s credit facility put in place for overdraft purposes and short-term cash management. These bank facilities include

financial covenants and events of default that are common in such arrangements. The terms of these credit facilities are discussed in Note 12 of the accompanying Notes to Consolidated Financial Statements.

Our current maturities of long-term debt of $347.4 million at December 31, 2005 consisted of (i) $5.0 million of current maturities of our 6.50% Series Debentures due September 1, 2013 (which are payable September 1, 2006), (ii) $1.5 million of current maturities under Terasen Gas Inc.’s capital lease obligations (which are payable throughout 2006), (iii) $151.7 million of current maturities under Terasen Gas (Vancouver Island) Inc.’s credit facility (which was completely refinanced in 2006 by a C$350 million unsecured committed revolving credit facility), (iv) $86.0 million of Terasen Inc.’s 4.85% Series 2 Notes due May 8, 2006, (v) $86.0 million of Terasen Gas Inc.’s 6.15% Series 16 Notes due July 31, 2006 and (vi) $17.2 million of Terasen Gas Inc.’s 9.75% Series D Notes due December 17, 2006. Current maturities of Terasen Inc. and its subsidiaries are denominated in Canadian dollars but are reported here in U.S. dollars converted at the December 31, 2005 spot rate of 0.8598. Apart from our notes payable and current maturities of long-term debt, our current assets exceeded our current liabilities by approximately $319.4 million at December 31, 2005. Given our expected cash flows from operations and our unused debt capacity as discussed preceding, including our credit facilities, and based on our projected cash needs in the near term, we do not expect any liquidity issues to arise.

During 2005, we sold a total of 5.67 million Kinder Morgan Management shares that we owned for approximately $254.8 million. We recognized pre-tax gains totaling $78.5 million associated with these sales. These sales will allow us to fully utilize a capital loss carryforward that was scheduled to expire in 2005.

As discussed in Note 4 of the accompanying Notes to Consolidated Financial Statements, on November 30, 2005, we completed the acquisition of Terasen. Terasen shareholders were able to elect, for each Terasen share held, either (i) C$35.75 in cash, (ii) 0.3331 shares of Kinder Morgan common stock, or (iii) C$23.25 in cash plus 0.1165 shares of Kinder Morgan common stock. In the aggregate, we issued approximately $1.1 billion (12.48 million shares) of Kinder Morgan common stock and paid approximately C$2.49 billion (US$2.13 billion) in cash to Terasen securityholders. In addition, our short-term and long-term debt balances increased by approximately $0.6 billion and $2.1 billion, respectively, as a result of including the debt of Terasen and its subsidiaries in our consolidated balances. See Note 12 of the accompanying Notes to Consolidated Financial Statements for additional information regarding the debt of Terasen.

On November 23, 2005, 1197774 Alberta ULC, a wholly owned subsidiary of Kinder Morgan, Inc., entered into a 364-day credit agreement, with Kinder Morgan, Inc. as guarantor, which provides for a committed credit facility in the Canadian dollar equivalent of US$2.25 billion. This credit facility was used to finance the cash portion of the acquisition of Terasen (see Items 1 and 2 “Business and Properties”). Under this bank facility, a facility fee was required to be paid based on the total commitment, whether used or unused, at a rate that varies based on Kinder Morgan, Inc.’s senior debt rating. On November 30, 2005, 1197774 Alberta ULC borrowed approximately $2.1 billion under this facility to finance the cash portion of the acquisition of Terasen. The facility was terminated when the loan was repaid on December 9, 2005 after permanent financing was obtained as discussed further in this section. Interest paid during 2005 under this credit facility was $1.9 million.

On December 9, 2005, Kinder Morgan Finance Company, ULC, a wholly owned subsidiary of Kinder Morgan, Inc., issued $750 million of 5.35% Senior Notes due 2011, $850 million of 5.70% Senior Notes due 2016 and $550 million of 6.40% Senior Notes due 2036. Each series of these notes is fully and unconditionally guaranteed by Kinder Morgan, Inc. on a senior unsecured basis as to principal, interest

and any additional amounts required to be paid as a result of any withholding or deduction for Canadian taxes. The proceeds of approximately $2.1 billion, net of underwriting discounts and commissions, were ultimately distributed to repay in full the bridge facility incurred to finance the cash portion of the consideration for Kinder Morgan, Inc.’s acquisition of Terasen. These notes were sold in a private placement pursuant to Rule 144A under the Securities Act of 1933. In February 2006, Kinder Morgan Finance Company, ULC exchanged these notes for substantially identical notes that have been registered under the Securities Act.

On August 5, 2005, we entered into an $800 million five-year senior unsecured revolving credit facility. This credit facility replaced an $800 million five-year senior unsecured revolving credit agreement dated August 18, 2004, effectively extending the maturity of our credit facility by one year, and includes covenants and requires payment of facility fees, which are discussed in Note 12 of the accompanying Notes to Consolidated Financial Statements, that are similar in nature to the covenants and facility fees required by the revolving bank facility it replaced. In this credit facility, the definition of consolidated net worth, which is a component of total capitalization, was revised to exclude other comprehensive income/loss, and the definition of consolidated indebtedness was revised to exclude the debt of Kinder Morgan Energy Partners that is guaranteed by us. On October 6, 2005, we amended our $800 million five-year senior unsecured revolving credit facility (i) to exclude the effect of consolidating Kinder Morgan Energy Partners relating to the requirements of EITF 04-5 discussed previously, (ii) to make administrative changes and (iii) subject to the closing of our acquisition of Terasen, to change definitions and covenants to reflect the inclusion of Terasen as a subsidiary of ours.

On March 15, 2005, we issued $250 million of our 5.15% Senior Notes due March 1, 2015. The proceeds of $248.5 million, net of underwriting discounts and commissions, were used to repay short-term commercial paper debt that was incurred to pay our 6.65% Senior Notes that matured on March 1, 2005.

On March 1, 2005, our $500 million of 6.65% Senior Notes matured, and we paid the holders of the notes, utilizing a combination of cash on hand and borrowings under our commercial paper program.

On October 21, 2004, we retired our $75 million 8.75% Debentures due October 15, 2024 at 104.0% of the face amount. We recorded a loss of $2.4 million (net of associated tax benefit of $1.5 million) in connection with this early extinguishment of debt, which is included under the caption “Other, Net” in the accompanying Consolidated Statement of Operations for 2004.

On March 3, 2003, our $500 million of 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.

On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million, $500 million, $550 million, $750 million, $800 million and $925 million in February 2002, July 2002, November 2003, April 2004, November 2004, April 2005 and November 2005, respectively. As of December 31, 2005, we had repurchased a total of approximately $875.3 million (14,594,500 shares) of our outstanding common stock under the program, of which $314.1 million (3,865,800 shares), $108.6 million (1,695,900 shares) and $38.0 million (724,600 shares) were repurchased in the years ended December 31, 2005, 2004 and 2003, respectively. As of February 28, 2006, we have repurchased a total of approximately $906.8 million (14,934,300 shares) of our outstanding common stock, of which $31.5 million (339,800 shares) were repurchased in 2006. It is our intention to cease additional share repurchases in 2006 in order to fund capital projects, primarily in Canada.

As further discussed under “Risk Management” in Item 7A of this report, we had outstanding at December 31, 2005 (i) three receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-

currency interest rate swap agreements with Merrill Lynch with a combined notional value of C$1,240 million that have been designated as a hedge of our net investment in Canadian operations in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“Statement 133”), (ii) three receive-fixed-rate, pay-variable-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with Merrill Lynch having a combined notional value of C$1,254 million that do not qualify as a hedge of our net investment in Canadian operations in accordance with Statement 133, (iii) three fixed-to-floating interest rate swap agreements, with a notional principal amount of approximately C$295 million, which effectively convert a majority of its 4.85%, 6.30% and 5.56% Medium Term Notes due May 2006, December 2008 and September 2014, respectively, from fixed rates to floating rates that qualify for hedge accounting under Statement 133 but do not qualify for the “shortcut” method and (iv) fixed-to-floating interest rate swap agreements entered into in August 2001, September 2002 and November 2003, which effectively convert the interest expense associated with our 7.25% Debentures due in 2028 and our 6.50% Senior Notes due in 2012 from fixed to floating rates based on the three-month London Interbank Offered Rate (“LIBOR”) plus a credit spread with a combined notional principal amount of $1.25 billion that qualify as fair value hedges under Statement 133. In 2006, we (i) effectively terminated the C$1,254 million in receive-fixed-rate, pay-variable-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements, (ii) entered into six receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with a combined notional value of C$1,254 million that qualify as fair value hedges under Statement 133, (iii) entered into three fixed-to-floating interest rate swap agreements which effectively convert 50% of the interest expense associated with our 5.35% Senior Notes due 2011, 5.70% Senior Notes due 2016 and 6.40% Senior Notes due 2036 from fixed to floating rates based on the three-month LIBOR plus a credit spread with a combined notional principal amount of $1,075 million that qualify as fair value hedges under Statement 133, (iv) terminated two of Terasen Inc.’s fixed-to-floating interest rate swap agreements with a notional value of C$195 million and (v) entered into two new interest rate swap agreements under Terasen Inc. that also have been designated as fair value hedges but additionally qualify for the “shortcut” method of accounting prescribed for qualifying hedges under Statement 133 with a notional value of $C195 million.

On March 10, 2005, we terminated $250 million of our interest rate swap agreements associated with our 6.50% Senior Notes due 2012 and paid $3.5 million in cash. We are amortizing this amount to interest expense over the period the 6.50% Senior Notes are outstanding. The unamortized balance of $3.2 million at December 31, 2005 is included in the caption “Value of Interest Rate Swaps” under the heading “Long-term Debt” in the accompanying interim Consolidated Balance Sheet.

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 amortized this amount to interest expense over the period that remained until the 6.65% Senior Notes matured this year.

On November 10, 2004, Kinder Morgan Management closed the issuance and sale of 1,300,000 listed shares in a privately negotiated transaction with a single purchaser. None of the shares in the offering were purchased by us. Kinder Morgan Management used the net proceeds of approximately $52.6 million from the offering to buy additional i-units from Kinder Morgan Energy Partners. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management’s 2005 Annual Report on Form 10-K.

On March 25, 2004, Kinder Morgan Management closed the issuance and sale of 360,664 listed shares in a privately negotiated transaction with a single purchaser. None of the shares in the offering were purchased by us. 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.

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

At recorded value, in each case consisting principally of property, plant and equipment.

Does not include any portion of the goodwill recognized in conjunction with the 1998 acquisition of the Thermo Companies.

When Kinder Morgan Energy Partners issues additional equity, we are required to contribute an amount to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships. See “Investment in Kinder Morgan Energy Partners” following.

We would only be obligated if Kinder Morgan Energy Partners and/or its assets cannot satisfy its obligations. In addition, Kinder Morgan G.P., Inc., our subsidiary that is the general partner of Kinder Morgan Energy Partners, is obligated to support the operations and debt service payments of Kinder Morgan Energy Partners. This obligation, however, does not arise until the assets of Kinder Morgan Energy Partners have been fully utilized in meeting its own obligations and, in any event, does not extend beyond the assets of Kinder Morgan G.P., Inc.

Interest payments have not been adjusted for any amounts receivable related to our interest rate swaps outstanding. See Item 7A Quantitative and Qualitative Disclosures About Market Risk.

Approximately $498.9 million, $20.3 million, $41.0 million, $41.2 million and $396.4 million in each respective column is attributable to the lease obligation associated with the Jackson, Michigan power generation facility. The project company that is the lessee of this facility is consolidated as of December 31, 2003, as a result of the adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities.

Terasen Gas and TGVI have entered into gas purchase contracts, which represent future purchase obligations. Gas purchase contract commitments are based on market prices that vary with gas commodity indices. The amounts shown reflect index prices that were in effect at December 31, 2005. Kinder Morgan Retail is obligated under certain gas purchase contracts, dating from 1973, to purchase natural gas at fixed and escalating prices from a certain field in Montana.

We currently do not expect to make significant contributions to these plans in the next few years, although we could elect or be required to make such contributions depending on, among other factors, the return generated by plan assets and changes in actuarial assumptions.

The $183.6 million in letters of credit outstanding at December 31, 2005 consisted of the following: (i) three letters of credit, totaling $43.5 million, supporting our hedging of commodity risk, (ii) two letters of credit, totaling $43.7 million securing accrued unfunded retirement obligations to certain current and retired executives and employees of Terasen, (iii) a $15.1 million letter of credit to fund the Debt Service Reserve Account required under the Express System’s trust indenture, (iv) four letters of credit, totaling $39.7 million to secure obligations for construction of new pump stations on the Trans Mountain system, (v) four letters of credit, totaling $19.0 million, required under provisions of our property and casualty, worker’s compensation and general liability insurance policies, (vi) a $10.6 million letter of credit supporting the subordination of operating fees payable to us for operation of the Jackson, Michigan power generation facility to payments due under the operating lease of the facilities, (vii) a $6.6 million letter of credit associated with the outstanding debt of Thermo Cogeneration Partnership, L.P., the entity responsible for the operation of our Colorado power generation assets, (viii) a $2.0 million letter of credit supporting Thermo Cogeneration Partnership, L.P.’s performance under its contract with Public Service Company of Colorado, the principal customer of our Colorado power generation assets and (ix) 32 letters of credit, totaling $3.4 million supporting various company functions.

The 2006 capital expenditure budget totals approximately $611.6 million. Approximately $100.0 million of this amount had been committed for the purchase of plant and equipment at December 31, 2005.

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

In conjunction with our sale of the Bushton gas processing facility to ONEOK, Inc., at December 31, 1999, ONEOK became primarily liable under the associated operating lease and we became secondarily liable. Should ONEOK, Inc. fail to make payments as required under the lease, we would be required to make such payments, with recourse only to ONEOK.

At December 31, 2005, we owned, directly, and indirectly in the form of i-units corresponding to our ownership of Kinder Morgan Management shares, approximately 29.65 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 14.36 million common units, 5.31 million Class B units and 9.98 million i-units, represent approximately 13.5% of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 15.2% of Kinder Morgan Energy Partners’ total equity interests at December 31, 2005. We receive quarterly distributions on the i-units owned by Kinder Morgan Management in additional i-units, and distributions on our other units in cash.

In addition to distributions received on our limited partner interests and our Kinder Morgan Management shares as discussed above, we also receive an incentive distribution from Kinder Morgan Energy Partners as a result of our ownership of the general partner interest in Kinder Morgan Energy Partners. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to unit holders exceed specified target levels as set forth in Kinder Morgan Energy Partners’ partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for quarterly distributions above $0.23375 per limited partner unit. Including both our general and limited partner interests in Kinder Morgan Energy Partners, at the 2005 distribution level, we received approximately 51% of all quarterly distributions made by Kinder Morgan Energy Partners, of which approximately 42% is attributable to our general partner interest and 9% is attributable to our limited partner interest. The actual level of distributions we will receive in the future will vary with the level of distributable cash determined in accordance with Kinder Morgan Energy Partners’ partnership agreement.

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

“Net Cash Flows Provided by Operating Activities” decreased from $644.4 million in 2004 to $616.2 million in 2005, a decrease of $28.2 million (4.4%). This negative variance is principally due to (i) a $40.8 million increased use of working capital cash for hedging activities, due to increases in NGPL hedge volumes and natural gas prices, (ii) a $25.0 million pension payment and an $8.5 million postretirement benefit plan payment, both made during 2005, (iii) a $59.8 million increase in cash paid for income taxes during 2005, (iv) a $22.3 million increase in cash paid for interest during 2005 and (v) $6.8 million of severance and other payments to employees resulting from the acquisition of Terasen. See Note 4 of the accompanying Notes to Consolidated Financial Statements. These negative impacts were partially offset by (i) a $95.5 million increase in cash distributions received in 2005 attributable to our interest in Kinder Morgan Energy Partners (see the discussion following), (ii) a net increased source of cash of $23.5 million for gas in underground storage and (iii) an increase of $17.1 million in 2005 cash attributable to the change in the balance of deferred purchased gas costs. Cash flows attributable to deferred purchased gas costs vary with the relationship between the amount actually paid for natural gas and the amount currently included in regulated rates. This difference is recovered or refunded through subsequent rate adjustments. Significant period-to-period variations in cash used or generated from gas in storage transactions are due to changes in injection and withdrawal volumes as well as fluctuations in natural gas prices.

“Net Cash Flows Provided by Operating Activities” increased from $601.5 million in 2003 to $644.4 million in 2004, an increase of $42.9 million (7.1%). This positive variance is principally due to (i) a $66.3 million increase in cash distributions received in 2004 attributable to our interest in Kinder Morgan Energy Partners, (ii) a $19.3 million reduction in cash paid for interest during 2004, (iii) a $7.0 million decrease in cash paid for income taxes during 2004 and (iv) an increase of $22.5 million in 2004 cash attributable to the change in the balance of deferred purchased gas costs. These positive impacts were partially offset by, (i) a decrease of $52.3 million in cash inflows for gas in underground storage during 2004 and (ii) the fact that 2003 included $28.1 million of cash proceeds received from termination of an interest rate swap (see “Significant Financing Transactions” for further information regarding this transaction).

In general, distributions from Kinder Morgan Energy Partners are declared in the month following the end of the quarter to which they apply and are paid in the month following the month of declaration to the general partner and unit holders of record as of the end of the month of declaration. Therefore, the accompanying Statements of Consolidated Cash Flows for 2005, 2004 and 2003 reflect the receipt of $530.8 million, $435.3 million and $369.0 million, respectively, of cash distributions from Kinder Morgan Energy Partners for (i) the fourth quarter of 2004 and the first nine months of 2005, (ii) the fourth quarter of 2003 and the first nine months of 2004 and (iii) the fourth quarter of 2002 and the first nine months of 2003, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2005 total $145.8 million and $552.2 million, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2004 total $124.4 million and $458.3 million, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2003 total $101.4 million and $383.5 million, respectively. The increases in distributions during 2005 and 2004 reflect, among other

factors, acquisitions made by Kinder Morgan Energy Partners and improvements in its results of operations. Summarized financial information for Kinder Morgan Energy Partners is contained in Note 2 of the accompanying Notes to Consolidated Financial Statements.

“Net Cash Flows Used in Investing Activities” increased from $7.3 million in 2004 to $1,978.7 million in 2005, an increase of $1,971.4 million. This increased use of cash is principally due to (i) $2,065.5 million of cash used to acquire Terasen Inc. (See Note 4 of the accompanying Notes to Consolidated Financial Statements), (ii) a $23.2 increase in capital expenditures during 2005, (iii) the fact that 2004 included $210.8 million of proceeds received from Kinder Morgan Energy Partners for the contribution of TransColorado, and (iv) the fact that 2004 included $42.1 million of proceeds from the sales of turbines. These factors were partially offset by (i) $48.4 million net decreased 2005 investments in margin deposits associated with hedging activities utilizing energy derivative instruments, (ii) $254.8 million of proceeds received in 2005 from the sale of Kinder Morgan Management shares, (see Note 5 of the accompanying Notes to Consolidated Financial Statements) and (iii) the fact that 2004 included an additional $69.5 million investment in Kinder Morgan Energy Partners, which primarily consisted of Kinder Morgan Management’s purchase of additional i-units from Kinder Morgan Energy Partners with the proceeds of an issuance of its shares as discussed under “Net Cash Flows from Financing Activities” following.

“Net Cash Flows Used in Investing Activities” decreased from $171.7 million in 2003 to $7.3 million in 2004, a decrease of $164.4 million (95.7%). This decreased use of cash is principally due to (i) $210.8 million of proceeds received from Kinder Morgan Energy Partners in 2004 for the contribution of TransColorado, (ii) $33.5 million of additional proceeds received for sales of surplus natural gas-fired turbines and boilers in 2004 and (iii) the fact that 2003 included $11.3 million of expenditures for other investments, partially offset by (i) an additional $72.3 million investment in Kinder Morgan Energy Partners during 2004, (ii) the fact that 2003 included an additional $6.4 million of net proceeds from sales of other assets, (iii) additional capital expenditures of $3.4 million during 2004 and (iv) an increase of $6.5 million in 2004 investments in margin deposits associated with hedging activities utilizing energy derivative instruments.

“Net Cash Flows Provided by (Used in) Financing Activities” increased from a use of $471.7 million in 2004 to a source of $1,302.3 million in 2005, an increase of $1,774.0 million. This increase is principally due to (i) $2,137.2 million of proceeds, net of issuance costs, received in 2005 from the issuance of our wholly owned subsidiary, Kinder Morgan Finance Company’s (a) $750 million of 5.35% Senior Notes due January 5, 2011, (b) $850 million of 5.70% Senior Notes due January 5, 2016 and (c) $550 million of 6.40% Senior Notes due January 5, 2036, (ii) $248.5 million of proceeds, net of issuance costs, received in 2005 from the issuance of our 5.15% Senior Notes due March 1, 2015 (See Note 12 of the accompanying Notes to Consolidated Financial Statements), (iii) $39.6 million of short-term borrowings in 2005 versus a $127.9 million reduction in short-term debt in 2004 and (iv) the fact that 2004 included $78 million of cash used for the early retirement of our $75 million 8.75% Debentures due October 15, 2024. Partially offsetting these factors were (i) $500 million of cash used in 2005 to retire our $500 million 6.65% Senior Notes, (ii) a $214.5 million increase in cash paid during 2005 to repurchase our common shares, (iii) a $76.5 million increase in cash paid for dividends in 2005, principally due to the increased dividends declared per share (see discussion following in this section) and (iv) the fact that 2004 included $67.5 million of proceeds, net of issuance costs, from the issuance of Kinder Morgan Management shares.

“Net Cash Flows Used in Financing Activities” increased from $454.4 million in 2003 to $471.7 million in 2004, an increase of $17.3 million (3.8%). This increase is principally due to (i) a $127.9 million reduction in short-term debt in 2004 as compared to incremental short-term borrowings of $127.9 million in 2003, (ii) $78 million of cash used in 2004 for the early retirement of our $75 million 8.75% Debentures due October 15, 2024 (see Note 12 of the accompanying Notes to Consolidated Financial Statements), (iii) a $143.4 million increase in cash paid for common stock dividends in 2004, principally due to the increased dividends declared per share, (iv) a $70.6 million decreased source of cash from short-term advances to unconsolidated affiliates during 2004 and (v) a $64.7 million increase in cash paid during 2004 to repurchase our common shares. Partially offsetting these factors were (i) the fact that 2003 included $500 million of cash used to retire our 6.45% Senior Notes, (ii) $67.5 million of proceeds, net of issuance costs, from the issuance of Kinder Morgan Management shares in 2004 and (iii) an increase of $20.7 million received in 2004 for issuance of our common stock, principally as a result of the exercise of employee stock options.

Total cash payments for dividends were $355.2 million, $278.7 million and $135.3 million in 2005, 2004 and 2003, respectively. The increases in these amounts are principally due to increases in the dividends declared per common share and, to a minor extent, to increased shares outstanding. In January 2006, we increased our quarterly common dividend to $0.875 per share ($3.50 annualized). On February 14, 2006, we paid a dividend at the increased rate of $0.875 per share to shareholders of record as of January 31, 2006.

As discussed under “Business Strategy” elsewhere in this report, our intention is to maintain a capital structure that provides stability and flexibility, while returning value to our shareholders through dividends and share repurchases. In recent periods, we have increased our common stock dividends in response to changes in income tax laws that have made dividends a more efficient way to return cash to our shareholders. Our Board of Directors generally considers our dividend policy annually in conjunction with its January meeting and has recently shown a pattern of increasing dividends. The Board considers a number of factors in reaching its decision with respect to dividend policy including our historical and projected cash flows, our expected allocation of funds to share repurchases, the opportunity to invest in attractive capital projects and, as discussed above, changes in laws that may affect the taxation of dividends to our shareholders. We currently expect that our cash flows will be adequate to maintain at least our current level of dividends for 2006, although changes in our economic circumstances, in the economic circumstances of our industry or of the economy in general could cause the Board to reconsider our dividend policy at any time.

Our anticipated environmental capital costs and expenses for 2006, including expected costs for remediation efforts, are approximately $7.5 million (inclusive of Terasen Gas and Kinder Morgan Canada), compared to approximately $2.9 million of such costs and expenses incurred in 2005 (not including any costs spent by Terasen). We had an environmental reserve of approximately $16.8 million at December 31, 2005, to address remediation issues associated with approximately 50 projects. This reserve has not been discounted or reduced for expected insurance recoveries. Our reserve estimates range in value from approximately $16.8 million to $23.2 million, and the lower end of the range has been accrued as no amount within the range is considered more likely than any other. In addition, we have recorded a receivable of $3.6 million for expected cost recoveries that have been deemed probable. Our reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and evaluate the impacts of any significant developments and review

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

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

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

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

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

price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, electricity, coal and other bulk materials and chemicals in North America;

economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

changes in our tariff rates or those of Kinder Morgan Energy Partners implemented by the FERC, the BCUC or another regulatory agency or, with respect to Kinder Morgan Energy Partners, the California Public Utilities Commission;

Kinder Morgan Energy Partners’ ability and our ability to acquire new businesses and assets and integrate those operations into existing operations, as well as the ability to expand our respective facilities;

difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from Kinder Morgan Energy Partners’ terminals or pipelines or our terminals or pipelines;

Kinder Morgan Energy Partners’ ability and our ability to successfully identify and close acquisitions and make cost-saving changes in operations;

shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use Kinder Morgan Energy Partners’ or our services or provide services or products to Kinder Morgan Energy Partners or us;

production from exploration and production areas that we serve, such as West Texas, the U.S. Rocky Mountains and the Alberta oilsands;

changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;

changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;

our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;

our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;

interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;

our ability to obtain insurance coverage without a significant level of self-retention of risk;

acts of nature, sabotage, terrorism or other acts causing damage greater than our insurance coverage limits;

national, international, regional and local economic, competitive and regulatory conditions and developments;

the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products;

unfavorable results of litigation involving Kinder Morgan Energy Partners and the fruition of contingencies referred to in Kinder Morgan Energy Partners’ Annual Report on Form 10-K for the year ended December 31, 2005. Our future results also could be adversely impacted by unfavorable results of litigation and the fruition of contingencies referred to in Note 9 “Environmental and Legal Matters” to the Consolidated Financial Statements included elsewhere in this report.

There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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

We enter into derivative contracts solely for the purpose of hedging exposures that accompany our normal business activities. In accordance with the provisions of Statement 133, we designated these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments in offsetting the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. We enter into these transactions only with counterparties whose debt securities are rated investment grade by the major rating agencies. While we will continue to enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.

and Canada, (ii) to serve certain of our retail natural gas distribution customers in areas where regulatory restructuring has provided for competition in natural gas supply, for customers who have selected the Company as their supplier of choice under our Choice Gas program, (iii) as fuel in one of our Colorado power generation facilities, (iv) as fuel for compressors located on NGPL’s pipeline system and (v) for operational sales of gas by NGPL. With respect to item (iii), our exposure is minimal and primarily consists of basis rather than commodity risk. With respect to item (iv), this fuel is supplied by in-kind fuel recoveries that are part of the transportation tariff. Item (i) gives rise to natural gas commodity price risk that is “passed-through” to our customers as the retail gas distribution regulatory structures provide for such. The gas distribution operations under Terasen use derivatives to manage natural gas commodity price risk that is passed to customers. Items (ii) and (v) give rise to natural gas commodity price risk which we have chosen to substantially mitigate through our risk management program. We provide this mitigation through the use of financial derivative products, and we do not utilize these derivatives for any purpose other than risk mitigation.

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

As to the retail gas distribution operations under Terasen Gas, the majority of natural gas supply contracts have floating, rather than fixed prices. Natural gas price swap contracts at AECO and Huntingdon are used to fix the effective purchase price. Any differences between the effective cost of natural gas purchased and the price of natural gas included in rates are recorded in deferral accounts, and subject to regulatory approval, are passed through in future rates to customers. Terasen Gas’ price risk management strategy covers a term of 36 months and aims to (i) improve the likelihood that natural gas prices remain competitive with electricity rates, (ii) dampen price volatility on customer rates and (iii) reduce the risk of regional price disconnects. The accompanying Consolidated Balance Sheet at December 31, 2005 includes a net deferral of $19.1 million reported under the caption “Current Liabilities: Other” representing net losses as a result of ineffectiveness of these hedges that are recoverable from customers through rates.

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

Our Value-at-Risk model, excluding Terasen as discussed following, is used to measure the risk of price changes in the crude oil, natural gas and natural gas liquids markets. Value-at-Risk is a statistical measure of how much the marked-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We use a closed form model to evaluate risk on a daily basis. Our Value-at-Risk computations use a confidence level of 97.7% for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk

amount presented. During 2005, Value-at-Risk reached a high of $27.0 million and a low of $6.7 million. Value-at-Risk at December 31, 2005, was $17.1 million and, based on quarter-end values, averaged $16.3 million for 2005.

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

We have not included Terasen natural gas commodity price risk in our Value-At-Risk model. We acquired Terasen effective November 30, 2005. Historically Terasen has not been required to provide this information in its disclosure and therefore does not currently have the ability to calculate it. In addition, the derivatives are not entered into for trading purposes, but to hedge underlying physical risk, as is the case with all of Kinder Morgan, Inc.’s derivative activity, and all commodity price risk is “passed through” to the customers. It is our intention to incorporate Terasen’s derivatives into the Company’s Value-at-Risk model in the future. For purposes of the current disclosure, we have run a sensitivity analysis assuming a $0.86 (C$1) increase and decrease in the forward price curve of natural gas as of December 31, 2005, or approximately a 10% change in price. The portfolio consists of a combination of approximately 66% swaps and approximately 44% options based on a total notional value of approximately $455 million (C$529 million) with an average strike price of approximately $8.37/GJ (C$9.73/GJ). The portfolio mark-to-market at December 31, 2005 was approximately $84.7 million (C$98.4 million). An $0.86/GJ (C$1/GJ) increase in the forward curve resulted in approximately a $141.2 million (C$164.2 million) mark-to-market or approximately a $56.5 million (C$65.8 million) increase. An $0.86/GJ (C$1/GJ) decrease in the forward curve resulted in approximately a $30.0 million (C$34.8 million) mark-to-market, or approximately a $54.7 million (C$63.6 million) decrease.

Apart from our derivatives for retail distribution gas supply contracts under Terasen Gas, during the three years ended December 31, 2005, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized a pre-tax loss of approximately $3,488,000 in 2005, a pre-tax loss of approximately $1,376,000 in 2004 and a pre-tax gain of approximately $56,000 in 2003 as a result of ineffectiveness of these hedges, which amounts are reported within the captions “Natural Gas Sales” and “Gas Purchases and Other Costs of Sales” in the accompanying Consolidated Statements of Operations. There was no component of these derivative instruments’ gain or loss excluded from the assessment of hedge effectiveness.

As the hedged sales and purchases take place and we record them into earnings, we also reclassify the gains and losses included in accumulated other comprehensive income into earnings. We expect to reclassify into earnings, during 2006, substantially all of the balance of approximately $23.3 million in accumulated other comprehensive income representing unrecognized net losses on derivative activities at December 31, 2005. During the three years ended December 31, 2005, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

We also provide certain administrative risk management services to Kinder Morgan Energy Partners, although Kinder Morgan Energy Partners retains the obligations and rights arising from all derivative

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

We have fixed-to-floating interest rate swap agreements, with a notional principal amount of $1.25 billion at December 31, 2005 entered into in August 2001, September 2002 and November 2003, which effectively convert the interest expense associated with our 7.25% Debentures due in 2028 and our 6.50% Senior Notes due in 2012 from fixed rates to floating rates based on the three-month London Interbank Offered Rate (“LIBOR”) plus a credit spread. These swaps have been designated as fair value hedges and we have accounted for them utilizing the “shortcut” method prescribed for qualifying fair value hedges under Statement 133. Accordingly, the carrying value of the swap is adjusted to its fair value as of the end of each reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. The fair value of the swaps of $54.9 million at December 31, 2005 reflects $61.9 million included in the caption “Deferred Charges and Other Assets” and $7.0 million included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying Consolidated Balance Sheet. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually.

In December 2005 we entered into three receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with Merrill Lynch. These derivative instruments have a combined notional value of C$1,240 million and have been designated as a hedge of our net investment in Canadian operations in accordance with Statement 133. We have chosen to measure the amount of ineffectiveness of this hedging relationship using a methodology based on changes in forward exchange rates. Ineffectiveness will result if (i) the notional amount of the derivative does not match the portion of the net investment designated as being hedged, (ii) the derivative’s underlying exchange rate is not the exchange rate between the functional currency of the hedged net investment and the investor’s functional currency, or (iii) the hedging derivative is a cross-currency interest rate swap in which neither leg is based on comparable interest rate curves. We have recognized no ineffectiveness through the income statement as a result of these hedging relationships during 2005. The effective portion of the changes in fair value of these swap transactions are reported as a Cumulative Translation Adjustment under the caption “Other Comprehensive Income” in the accompanying Consolidated Balance Sheet. The fair value of the swaps at December 31, 2005 is a payable of $14.2 million which reflects $1.5 million included in the caption “Deferred Charges and Other Assets” and $15.7 million included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying Consolidated Balance Sheet. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually.

In February 2006 we entered into transactions to effectively terminate our three receive-fixed-rate, pay-variable-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with a combined notional value of C$1,254 million and entered into six receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with a combined notional value

of C$1,254 million. The new derivative instruments have been designated as hedges of our net investment in Canadian operations in accordance with Statement 133. As a result, we currently have C$2,494 million in U.S. dollar fixed to Canadian dollar fixed swaps. As previously disclosed on March 10, 2006, we expect to recognize a one time non-cash, after-tax loss of approximately $14 million in the first quarter of 2006 from changes in the fair value of our three receive-fixed-rate, pay-variable rate U.S. dollar to Canadian dollar cross-currency interest rate swaps from January 1, 2006 to the termination of the agreements to reflect the strengthening of the Canadian dollar versus the U.S. dollar.

In February 2006 we entered into three fixed-to-floating interest rate swap agreements with notional principal amounts of $375 million, $425 million and $275 million, respectively. These swaps effectively convert 50% of the interest expense associated with our 5.35% Senior Notes due 2011, 5.70% Senior Notes due 2016 and 6.40% Senior Notes due 2036, respectively, from fixed rates to floating rates based on the three-month LIBOR plus a credit spread. These swaps have been designated as fair value hedges and will be accounted for utilizing the “shortcut” method prescribed for qualifying fair value hedges under Statement 133.

Terasen Inc. has three fixed-to-floating interest rate swap agreements, with a notional principal amount of approximately C$295 million, which effectively convert a majority of its 4.85%, 6.30% and 5.56% Medium Term Notes due May 2006, December 2008 and September 2014, respectively, from fixed rates to floating rates. These swaps have been designated as fair value hedges. Accordingly, the carrying value of the swap is adjusted to its fair value as of the end of each reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. The fair value of the swaps of $3.1 million at December 31, 2005 is included in the caption “Deferred Charges and Other Assets” in the accompanying Consolidated Balance Sheet. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually.

In February 2006, Terasen Inc. terminated their fixed-to-floating interest rate swap agreements associated with their 6.30% and 5.56% Medium Term Notes due 2008 and 2014, respectively, with a notional value of C$195 million. Additionally, Terasen Inc. entered into two new interest rate swap agreements with a notional value of C$195 million. These new swaps have also been designated as fair value hedges but additionally qualify for the “shortcut” method of accounting prescribed for qualifying hedges under Statement 133.

Following is a description of interest rate swap agreements of (i) Terasen Gas Inc., (ii) Terasen Gas (Vancouver Island) Inc. and (iii) Terasen Pipelines (Corridor) Inc., all subsidiaries of Terasen Inc. These swaps have not been designated as fair value hedges; however the interest costs or changes in fair values of the underlying swaps is ultimately recoverable or payable to customers. The net payable position of the swaps representing the net fair value of $1.7 million at December 31, 2005 is included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying Consolidated Balance Sheet.

Terasen Gas Inc. has three floating-to-fixed interest rate swap agreements, with a notional principal amount of approximately C$49 million, which effectively convert its floating rate commercial paper to fixed rates in order to stabilize certain interest costs in the cost of service model approved by the regulatory authorities. These interest rate swaps mature in November 2007.

Terasen Gas (Vancouver Island) Inc. has four floating-to-fixed interest rate swap agreements, with a notional principal amount of C$108 million, which effectively convert its floating rate long-term bank debt to fixed rates in order to stabilize interest costs in the cost of service model approved by the regulatory authorities. Two of the interest swaps have matured in January 2006, and the other two interest swaps mature in October and November of 2008.

Terasen Pipelines (Corridor) Inc. has two fixed-to-floating interest rate swap agreements, with a notional principal amount of C$300 million, which effectively convert interest expense associated with its 4.24% and 5.033% Debentures due February 2010 and February 2015, respectively from fixed to floating rates.

Based on the long-term debt effectively converted to floating rate debt as a result of the swaps discussed above where the risk is not passed to customers through rates, a 1% change in interest rates would result in a $28 million annual impact on pre-tax income.

On March 3, 2003, we terminated the interest rate swap agreements associated with our 6.65% Senior Notes due 2005 and received $28.1 million in cash. We amortized this amount to interest expense over the period that remained until the 6.65% Senior Notes matured in 2005.

We have completed integrated audits of Kinder Morgan, Inc.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan, Inc. and its subsidiaries (the “Company”) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 12(C) and Note 1(P) to the consolidated financial statements, the Company changed its method of accounting for its Capital Trust Securities effective December 31, 2003.

As discussed in Note 17(A) to the consolidated financial statements, the Company changed its method of accounting for its investment in Triton Power Company LLC effective December 31, 2003.

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting

includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management's Report on Internal Control Over Financial Reporting, management has excluded Terasen, Inc. and its consolidated subsidiaries from its assessment of internal control over financial reporting as of December 31, 2005 because these businesses were acquired by the Company in a purchase business combination during 2005. We have also excluded the Terasen, Inc. and its consolidated subsidiaries operations from our audit of internal control over financial reporting. This business, in the aggregate, constituted 15% of the Company’s consolidated operating revenues for 2005 and 43% of the Company’s consolidated total assets at December 31, 2005.

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

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

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

We are an energy infrastructure provider and have operations in the northwest, Rocky Mountain and mid-continent regions of the United States and in western Canada, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Louisiana, Missouri, Nebraska, New Mexico, Oklahoma, Texas, Washington and Wyoming in the United States and British Columbia and Alberta in Canada. Our business activities include: (i) storing, transporting and selling natural gas, (ii) transporting crude oil and refined petroleum products, (iii) providing retail natural gas distribution services, and (iv) operating and, in previous periods, constructing electric generation facilities. We have both regulated and nonregulated operations. Our common stock is traded on the New York Stock Exchange under the ticker symbol “KMI.” During 1999, we acquired Kinder Morgan Delaware as discussed in the following paragraph. As a result, we own, through Kinder Morgan Delaware, the general partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline limited partnership, referred to in these Notes as Kinder Morgan Energy Partners. We also own a significant limited partner interest in Kinder Morgan Energy Partners and receive a substantial portion of our earnings from returns on our investment in this entity.

In October 1999, K N Energy, Inc. (as we were then named), a Kansas corporation, acquired Kinder Morgan, Inc. (Delaware), a Delaware corporation, referred to in these Notes as Kinder Morgan Delaware. We then changed our name to Kinder Morgan, Inc. Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. (a Kansas corporation and formerly known as K N Energy, Inc.) and its consolidated subsidiaries.

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

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

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

The December 31, 2005 purchased gas costs balance of $34.6 million shown above as a regulatory asset includes $26.6 million in litigated gas costs. As of December 31, 2005, $306.0 million of our regulatory assets and $200.2 million of our regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from 1 to 20 years.

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. Our rate-regulated retail natural gas distribution businesses bill customers on a monthly cycle billing basis. Revenues are recorded on an accrual basis, including an estimate at the end of each accounting period for gas delivered and, if applicable, for which title has passed but bills have not yet been rendered.

We provide various types of natural gas storage and transportation services to customers, principally through NGPL’s and, prior to November 2004, TransColorado’s pipeline systems. The natural gas remains the property of these customers at all times. In many cases (generally described as “firm service”), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue ratably over the contract period. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn

from our storage facilities. In other cases (generally described as “interruptible service”), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements.

We provide crude oil transportation services and refined petroleum products transportation and storage services through Kinder Morgan Canada. Revenues are recorded when products are delivered and services have been provided and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities.

Basic earnings per common share is computed based on the weighted-average number of common shares outstanding during each period. Diluted earnings per common share is computed based on the weighted-average number of common shares outstanding during each period, increased by the assumed exercise or conversion of securities 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 1.7 million for 2003 were excluded from the diluted earnings per common share calculation because the effect of including them would have been antidilutive. No options were excluded from the diluted earnings per share calculation in 2005 and 2004 because none of the options would have been antidilutive. Note 16 contains more information regarding stock options.

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

The caption “Accounts Receivable, Net” in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts. Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. An allowance for doubtful accounts is charged to expense monthly, generally using a percentage of revenue or receivables, based on a historical analysis of uncollected amounts, adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. In support of credit extended to certain customers, we had received prepayments of $4.4 million and $3.8 million at December 31, 2005 and 2004, respectively, included with other current liabilities in the accompanying Consolidated Balance Sheets. The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2005, 2004 and 2003.

Inventories are carried at lower of cost or market and are accounted for using the following methods, with the percent of the total dollars at December 31, 2005 shown in parentheses: average cost (85.46%), last-in, first-out (14.09%) and first-in, first-out (0.45%). The excess of current cost over the reported last-in, first-out value of gas in underground storage valued under that method was $4.5 million at December 31, 2005. We also maintain gas in our underground storage facilities on behalf of certain third parties. We receive a fee from our storage service customers but do not reflect the value of their gas stored in our facilities in the accompanying Consolidated Balance Sheets.


	Kinder Morgan Energy Partners				Power Segment		Kinder Morgan Canada Segment			Terasen Gas Segment			Total
	(In thousands)
Balance as of December 31, 2003		$	947,548		$	24,832		$	-		$	-	$	972,380

Change in ownership percentage of Kinder Morgan Energy Partners related to Kinder Morgan Energy Partners common unit issuances			(54,304	)		-			-			-		(54,304	)

Balance as of December 31, 2004			893,244			24,832			-			-		918,076

Change in ownership percentage of Kinder Morgan Energy Partners related to Kinder Morgan Energy Partners common unit issuances			(33,867	)		-			-			-		(33,867	)

Acquisition of Terasen Inc.¹			-			-			656,096			1,234,428		1,890,524

Change in foreign currency rate			-			-			2,100			4,208		6,308

Balance as of December 31, 2005		$	859,377		$	24,832		$	658,196		$	1,238,636	$	2,781,041
___________ ¹ Preliminary allocation of goodwill. See Note 4.

Our investment in the Thermo Companies was reduced as a result of impairments recorded in 2005 and 2004, see Note 6.

Investments consist primarily of equity method investments in unconsolidated subsidiaries and joint ventures, and include ownership interests in net profits. We own 49.5% interests in Thermo Cogeneration Partnership, L.P. and Greenhouse Holdings, LLC, which are accounted for under the equity method. Our investment in Horizon Pipeline Company, in which we own a 50% interest, is also accounted for under the equity method.

On November 30, 2005, we acquired, in the Terasen transaction, a 33.33% interest in the Express Pipeline system and a 30% interest in CustomerWorks LP. We account for both of these investments under the equity method.

Property, plant and equipment is stated at historical cost, which for constructed plant includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction, administrative and general costs. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of depreciable utility property, plant and equipment, plus the cost of

removal less salvage, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-utility property, plant and equipment, and utility property, plant and equipment constituting an operating unit or system, when sold or abandoned.

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

In accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we review the carrying values of our long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. In the fourth quarters of 2005, 2004 and 2003, we recorded impairments of certain assets associated with our power business; see Note 6.

We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, (“SFAS No. 143”) 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. In March 2005, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143 (“FIN 47”). This Interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. The implementation of FIN 47 will not change the application of the guidance implemented under SFAS No. 143 in relation to our facts and circumstances. See Note 20 for further discussion of FIN 47. The impact of the adoption of SFAS No. 143 on us is discussed below by segment. A reconciliation of the changes in our accumulated asset retirement obligations for the years ended December 31, 2005 and 2004 is as follows:

In general, NGPL’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.

NGPL 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 December 31, 2005, 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 NGPL’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.

We acquired the assets of Kinder Morgan Canada effective November 30, 2005 as part of our acquisition of Terasen. The underground piping, compressor stations and associated facilities and equipment of Kinder Morgan Canada have been in service for many years. There are no plans to abandon or otherwise replace or remove any portion of these assets other than through the normal maintenance of the system. We have concluded that while the legal determination of obligation may exist to some extent, the corresponding asset retirement dates are indeterminable, and therefore sufficient information does not exist to estimate the fair value of any retirement obligation in relation to these assets and no asset retirement obligation has been recognized. A liability will be recognized for asset retirement obligations, if any, when the fair value of any such obligation is determinable.

We acquired the assets of Terasen Gas effective November 30, 2005 as part of our acquisition of Terasen. The assets of Terasen Gas have been in service for many years and there are no plans to abandon or otherwise replace or remove any portion of these assets other than through the normal maintenance of the system. We have concluded that while the legal determination of obligation may exist to some extent, the corresponding asset retirement dates are indeterminable, and therefore sufficient information does not exist to estimate the fair value of any retirement obligation in relation to these assets and no asset retirement obligation has been recognized. A liability will be recognized for asset retirement obligations related to these assets, if any, when the fair value of any such obligation is determinable.

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

In our Kinder Morgan Retail storage field operations we would, upon abandonment, be required to plug and abandon the wells and to remove our surface wellhead equipment and compressors. We currently have two small sites in Wyoming that are no longer being used as active storage facilities and estimate that, in 2013, we will incur approximately $200,000 in costs to fulfill these retirement obligations. We have no plans to cease using any of our other storage facilities as they are expected to, for the foreseeable future, provide critical deliverability to our customers in severe cold weather situations. With respect to our small natural gas production field in Colorado, we will be required, upon cessation of commercial operations, to plug and abandon the natural gas wells, remove surface equipment and remediate the well sites. We have estimated that this process will start in 2007 and continue through 2013 for a total cost of $240,000, with approximately half the total being spent in the final two years. Additionally, the Colbran Processing Plant in Colorado is scheduled for removal in 2007, and we have accrued approximately $89,000 (at present value) for removal costs related to this facility. The recognition of these obligations has resulted in a liability and associated asset of approximately $0.4 million as of December 31, 2005, 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 power plant, 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 (located on land that we also own), we have no asset retirement obligation with respect to those facilities, 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.

We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominations and actual gas receipts from and gas deliveries to our interconnecting pipelines under various operational balancing agreements. Natural gas imbalances are settled in cash or made up in-kind subject to the pipelines’ various terms. Terasen Gas and Terasen Gas (Vancouver Island) Inc. (“TGVI”) have entered into gas purchase contracts, which represent future purchase obligations. Gas purchase contract commitments are based on market prices that vary with gas commodity indices. Kinder Morgan Retail is obligated under certain gas purchase contracts, dating from 1973, to purchase natural gas at fixed and escalating prices from a certain field in Montana. This take obligation, which continues for the life of the field, is based on production from specific wells and, thus, varies from year to year. See Note 17 for gas purchase contract commitments.

Depreciation on our long-lived assets is computed principally based on the straight-line method over their estimated useful lives. Depreciation of certain non-regulated equipment is recorded using the declining balance method. The ranges of estimated useful lives used in depreciating assets are as follows:

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

The expense associated with our capital trust securities was included in “Minority Interests” prior to the third quarter of 2003 ($10.9 million for the year ended December 31, 2003). Due to our adoption of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, the expense associated with these securities was included in “Interest Expense – Capital Trust Securities” beginning with the third quarter of 2003. Due to our adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, the subsidiary trusts associated with our capital trust securities are no longer consolidated, effective December 31, 2003. The associated expense is included in “Interest Expense - Deferrable Interest Debentures” for the years ended December 31, 2005 and 2004, respectively.

“Other, Net” as presented in the accompanying Consolidated Statements of Operations includes $79.1 million, $2.0 million and $(4.4) million in 2005, 2004 and 2003, respectively, attributable to net gains/(losses) from sales of assets. These transactions are discussed in Note 5. Also included in “Other, Net” in 2005 is a $15 million charge for our charitable contribution to the Kinder Morgan Foundation.

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. “Other, Net,” presented as a component of “Net Cash Flows From Operating Activities” in the accompanying Consolidated Statements of Cash Flows includes, among other things, non-cash charges and credits to income including amortization of deferred revenue and amortization of gains and losses realized on the termination of interest rate swap agreements; see Note 14.

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

Beginning with the third quarter of 2003, these distributions are included in interest expense.

On November 30, 2005, we contributed 12.5 million shares of our common stock, representing approximately $1.1 billion of value, as partial consideration for the acquisition of Terasen Inc. The fair values of non-cash assets acquired and liabilities assumed were $7.4 billion and $4.2 billion, respectively. See Note 4.

A portion of the consideration received in the November 2004 contribution of TransColorado Gas Transmission Company was Kinder Morgan Energy Partners common units, see Note 5.

In December 2003, we made an incremental investment in our Colorado power businesses in the form of Kinder Morgan Management, LLC shares. See Note 5.

Distributions received by our Kinder Morgan Management, LLC 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, LLC to its shareholders are in the form of additional Kinder Morgan Management, LLC shares, see Note 3.

As discussed in Note 1(S) following, during 2005, 2004 and 2003, we made non-cash grants of restricted shares of common stock.

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 $1.0 million for each of the years 2004 and 2003 related to the 15 percent purchase discount offered under the employee stock purchase plan. Effective January 1, 2005, the purchase discount offered under the employee stock purchase plan was reduced to 5 percent. Amounts related to the 5 percent discount are not included in the pro forma amounts for 2005 because the employee stock purchase plan is no longer considered a compensatory plan under SFAS No. 123. Note 16 contains information regarding our common stock option and purchase plans. The FASB recently issued SFAS No. 123R (revised 2004), Share-Based Payment, which will change our accounting for stock options and similar awards, see Note 20.

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

During 2005, 2004 and 2003, we made restricted common stock grants of 239,690, 167,350 and 575,000 shares, respectively. These grants are valued at $21.4 million, $10.2 million and $34.0 million, respectively, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. Of the 239,690 restricted stock grants made in 2005, 15,750 shares vest during a six-month period, 26,500 shares vest during a three year period and 197,440 shares vest during a five year period. Of the 167,350 restricted stock grants made in 2004, 73,550 shares vest during a three year period and 93,800 shares vest during a five year period. The 2003 restricted stock grants vest during

a five year period. Expense related to restricted grants is recognized on a straight-line basis over the respective vesting periods. During 2005, 2004 and 2003, we amortized $8.2 million, $5.1 million and $3.4 million, respectively, related to restricted stock grants. The unamortized value of restricted stock grants is shown in the equity section of our Consolidated Balance Sheets under the caption, “Deferred Compensation.”

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

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

The “Accounts Receivable, Related Parties” balances shown in the accompanying Consolidated Balance Sheets primarily represent balances with Kinder Morgan Energy Partners for amounts arising from performing administrative functions for them, including cash management, hedging activities, centralized payroll and employee benefits services and expenses incurred in performing as general partner of Kinder Morgan Energy Partners. The net monthly balance payable or receivable from these activities is typically settled in cash in the following month.

Effective November 1, 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners. See Note 5.

From time to time in the ordinary course of business, we buy and sell pipeline and related services from Kinder Morgan Energy Partners and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with our policies governing such transactions.

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

The caption “Gas Purchases and Other Costs of Sales” in the accompanying Consolidated Statements of Operations includes related-party costs totaling $25.3 million, $29.1 million and $36.8 million for the years 2005, 2004 and 2003, respectively, primarily for natural gas transportation and storage services and natural gas provided by entities owned by Kinder Morgan Energy Partners. Certain transactions with related parties are included in Note 5.

We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas and associated transportation. In addition, we utilize weather derivatives to reduce the variability in the earnings from our natural gas distribution activities. Our accounting policy for these activities is in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and related pronouncements. This policy is described in detail in Note 14.

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. Note 11 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities.

In general, we expense legal costs as incurred. When we identify significant specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of probable costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available.

Due to our adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, the assets and liabilities of our Triton Power affiliates are included in our consolidated balance sheet, effective December 31, 2003. In addition, Triton’s operating results are included in our 2004 and 2005 consolidated operating results. Although the results of Triton have an impact on our total operating revenues and expenses, after taking into account the associated minority interests, the consolidation of Triton has no effect on our consolidated net income.

Also due to our adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, the subsidiary trusts associated with our capital trust securities are no longer consolidated, effective December 31, 2003. See Note 1(P) for a discussion regarding the expense associated with the capital trust securities.

The caption “Minority Interests in Equity of Subsidiaries” in our Consolidated Balance Sheets is comprised of the following balances:

We translate our Canadian dollar denominated Terasen financial statements into United States dollars using the current rate method of foreign currency translation. Under this method, assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, revenue and expense items are translated at average rates of exchange for the period, and the exchange gains and losses arising on the translation of the financial statements are reflected as a separate component of Accumulated Other Comprehensive Income in the accompanying Consolidated Balance Sheet.

Foreign currency transaction gains or losses, other than hedges of net investments in foreign companies, are included in results of operations. In 2005, we recorded net pre-tax gains of $2.3 million from foreign currency transactions and swaps. See Note 14 for information regarding our hedges of net investments in foreign companies.

We own the general partner of, and a significant limited partner interest in, Kinder Morgan Energy Partners. Kinder Morgan Energy Partners owns an interest in and/or operates a diverse group of assets used in the transportation, storage and processing of energy products, including (i) refined petroleum products pipeline systems with more than 10,000 miles of products pipelines and over 60 associated terminals, (ii) approximately 15,000 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, (iii) approximately 85 liquid and bulk terminal facilities and more than 50 rail transloading and materials handling facilities located throughout the United States, handling over 80 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 65 million barrels for refined petroleum products, chemicals and other liquid products and (iv) Kinder Morgan CO₂ Company, L.P., which transports, markets and produces carbon dioxide for use in enhanced oil recovery operations and owns interests in and/or operates seven oil fields in West Texas, all of which are using or have used carbon

dioxide injection operations. Kinder Morgan CO₂ Company, L.P. also owns and operates the Wink Pipeline, a crude oil pipeline in West Texas.

At December 31, 2005, we owned, directly, and indirectly in the form of i-units corresponding to our ownership of Kinder Morgan Management shares, approximately 29.65 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 14.36 million common units, 5.31 million Class B units and 9.98 million i-units, represent approximately 13.5% of the total limited partner interests of Kinder Morgan Energy Partners. See Note 3 for additional information regarding Kinder Morgan Management, LLC and Kinder Morgan Energy Partners’ i-units. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 15.2% of Kinder Morgan Energy Partners’ total equity interests at December 31, 2005. We receive quarterly distributions on the i-units owned by Kinder Morgan Management, LLC in additional i-units and distributions on our other units in cash.

In addition to distributions received on our limited partner interests and our Kinder Morgan Management, LLC shares as discussed above, we also receive an incentive distribution from Kinder Morgan Energy Partners as a result of our ownership of the general partner interest in Kinder Morgan Energy Partners. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to unit holders exceed specified target levels as set forth in Kinder Morgan Energy Partners’ partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for quarterly distributions above $0.23375 per limited partner unit. Including both our general and limited partner interests in Kinder Morgan Energy Partners, at the 2005 distribution level, we received approximately 51% of all quarterly distributions by Kinder Morgan Energy Partners, of which approximately 42% is attributable to our general partner interest and 9% is attributable to our limited partner interest. The actual level of distributions we will receive in the future will vary with the level of distributable cash determined in accordance with Kinder Morgan Energy Partners’ partnership agreement.

Following is summarized financial information for Kinder Morgan Energy Partners. Additional information regarding Kinder Morgan Energy Partners’ results of operations and financial position are contained in its 2005 Annual Report on Form 10-K.

Kinder Morgan Management, LLC, referred to in this report as Kinder Morgan Management, is a publicly traded Delaware limited liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., our indirect wholly owned subsidiary, owns all of Kinder Morgan Management’s voting shares. Kinder Morgan Management’s shares (other than the voting shares we hold) are traded on the New York Stock Exchange under the ticker symbol “KMR”. Kinder Morgan Management, pursuant to a delegation of control agreement, has been delegated, to the fullest extent permitted under Delaware law, all of Kinder Morgan G.P., Inc.’s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P., Inc.’s right to approve certain transactions.

On November 14, 2005, Kinder Morgan Management made a distribution of 0.016360 of its shares per outstanding share (932,292 total shares) to shareholders of record as of October 31, 2005, based on the $0.79 per common unit distribution declared by Kinder Morgan Energy Partners. On February 14, 2006, Kinder Morgan Management made a distribution of 0.017217 of its shares per outstanding share (997,180 total shares) to shareholders of record as of January 31, 2006, based on the $0.80 per common unit distribution declared by Kinder Morgan Energy Partners. These distributions are paid in the form of additional shares or fractions thereof calculated by dividing the Kinder Morgan Energy Partners’ cash distribution per common unit by the average market price of a Kinder Morgan Management share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Kinder Morgan Management has paid share distributions totaling 3,760,732, 3,500,512 and 3,342,417 shares in the years ended December 31, 2005, 2004 and 2003, respectively.

On November 10, 2004, Kinder Morgan Management closed the issuance and sale of 1,300,000 of its listed shares in a limited registered offering. None of the shares from the offering were purchased by Kinder Morgan, Inc. Kinder Morgan Management used the net proceeds of approximately $52.6 million from the offering to buy additional i-units from Kinder Morgan Energy Partners.

On March 25, 2004, Kinder Morgan Management closed the issuance and sale of 360,664 of its listed shares in a limited registered offering. None of the shares from 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.

At December 31, 2005, we owned 9.98 million Kinder Morgan Management shares representing 17.2% of Kinder Morgan Management’s outstanding shares.

On November 30, 2005, we completed the acquisition of Terasen Inc., referred to in this report as Terasen and, accordingly, Terasen’s results of operations are included in our consolidated results of operations beginning on that date. Terasen is an energy transportation and utility services provider based

in Vancouver, British Columbia, Canada. Terasen’s two core businesses are its natural gas distribution business and its petroleum pipeline business. Terasen Gas is the largest distributor of natural gas in British Columbia, serving approximately 892,000 customers. Terasen Pipelines, which we have renamed Kinder Morgan Canada, owns Trans Mountain Pipe Line, which extends from Edmonton to Vancouver and Washington State, and Corridor Pipeline, which extends from the Athabasca oilsands to Edmonton. Kinder Morgan Canada also operates and owns a one-third interest in the Express System, which extends from Alberta to the U.S. Rocky Mountain region and Midwest.

Pursuant to the Combination Agreement among us, one of our wholly owned subsidiaries, and Terasen, Terasen shareholders were able to elect, for each Terasen share held, either (i) C$35.75 in cash, (ii) 0.3331 shares of Kinder Morgan common stock, or (iii) C$23.25 in cash plus 0.1165 shares of Kinder Morgan common stock. In the aggregate, we issued approximately 12.48 million shares of Kinder Morgan common stock and paid approximately C$2.49 billion (US$2.13 billion) in cash to Terasen securityholders.

The acquisition was accounted for as a purchase and, accordingly, the assets acquired and liabilities assumed are recorded at their respective estimated fair market values as of the acquisition date. The calculation of the total purchase price and the preliminary allocation of that purchase price to the assets acquired and liabilities assumed based on their fair market values pursuant to an independent third-party preliminary valuation is shown following. The valuation is expected to be finalized no later than the fourth quarter of 2006.

The preliminary allocation of the purchase price resulted in the recording of $1.9 billion of total goodwill, which we do not expect to be deductible for income tax purposes. There are a number of factors contributing to the total purchase price that resulted in our recognition of goodwill from this transaction, including: a stable portfolio of natural gas distribution assets; potential future deregulation or unbundling of natural gas distribution services; expected increases in Canadian oilsands production and worldwide oil demand and the potential for expansion projects with attractive overall returns combined with our ability to capitalize on those projects due to (i) our expertise in developing and operating energy-related assets and (ii) our unique capital structure and significant positive cash flow generated by our investment in Kinder Morgan Energy Partners. The preliminary allocation of goodwill to reporting segments is as follows:

In connection with our acquisition of Terasen, we accrued estimates of costs for personnel reductions anticipated at the date of acquisition, in accordance with EITF No. 95-3, Recognition of Liabilities in Connection with a Purchase Business Combination. Adjustments to these estimates are made as plans are finalized, but in no event beyond one year from the acquisition date. We formulated an involuntary termination plan which covers 43 identified Terasen employees. We recorded a liability of $10.0 million as of November 30, 2005, to cover the costs of this involuntary termination plan. At December 31, 2005, the balance remaining for this liability was $5.2 million. The implementation of the termination plan began immediately after the acquisition date and will be completed within twelve months of the acquisition. To the extent these accruals are not utilized for the intended purpose, the excess is recorded as a reduction of the purchase price, typically by reducing recorded goodwill balances. Costs incurred in excess of the recorded accruals are expensed as incurred.

The following pro forma information gives effect to our acquisition of Terasen as if the business combination had occurred January 1 of each year presented. This unaudited pro forma information should be read in conjunction with the accompanying consolidated financial statements. This pro forma information does not necessarily indicate the financial results that would have occurred if this acquisition had taken place on the dates indicated, nor should it necessarily be viewed as an indicator of future financial results.

On December 27, 2005, we sold 1,670,000 Kinder Morgan Management shares that we owned for approximately $74.2 million. We recognized a pre-tax gain of $22.2 million associated with this sale.

On November 10, 2005, we sold 279,631 Kinder Morgan Management shares that we owned for approximately $13.0 million. We recognized a pre-tax gain of $4.2 million associated with this sale.

On November 8, 2005, Kinder Morgan Energy Partners issued 2.6 million common units in a public offering at a price of $51.75 per common unit, receiving total net proceeds (after underwriting discount) of $130.1 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 transactions) from approximately 16.2% to approximately 16.0% and had the associated effects of increasing our (i) investment in the net assets of Kinder Morgan Energy Partners by $10.8 million, (ii) associated accumulated deferred income taxes by $0.6 million and (iii) paid-in capital by $1.2 million and, in addition, reduced our equity method goodwill in Kinder Morgan Energy Partners by $9.0 million. In addition, in November 2005, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $1.3 million.

On October 31, 2005, we sold 1,586,965 Kinder Morgan Management shares that we owned for approximately $75.1 million. We recognized a pre-tax gain of $25.6 million associated with this sale.

In August and September 2005, Kinder Morgan Energy Partners issued 5.75 million common units in a public offering at a price of $51.25 per common unit, receiving total net proceeds (after underwriting discount) of $283.6 million. We did not acquire any of these common units. In August 2005, Kinder Morgan Energy Partners issued 64,412 common units as partial consideration for the acquisition of General Stevedores, L.P. These issuances, collectively, reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transactions) from approximately 17.3% to approximately 16.9% and had the associated effects of increasing our (i) investment in the net assets of Kinder Morgan Energy Partners by $30.1 million, (ii) associated accumulated deferred income taxes by $3.2 million and (iii) paid-in capital by $5.7 million and, in addition, reduced our equity method goodwill in Kinder Morgan Energy Partners by $21.2 million. In addition, in August 2005, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $2.6 million.

On June 1, 2005, we sold 1,717,033 Kinder Morgan Management shares that we owned for approximately $75.0 million. We recognized a pre-tax gain of $22.0 million associated with this sale.

In April 2005, Kinder Morgan Energy Partners issued 957,656 common units as partial consideration for the acquisition of seven bulk terminal operations. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transaction) from approximately 18.13% to approximately 18.06% and had the associated effects of increasing our (i) investment in the net assets of Kinder Morgan Energy Partners by $5.1 million, (ii) associated accumulated deferred income taxes by $0.5 million and (iii) paid-in capital by $0.9 million and, in addition, reduced our equity method goodwill in Kinder Morgan Energy Partners by $3.6 million. In addition, in April 2005, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $0.6 million.

On January 31, 2005, we sold 413,516 Kinder Morgan Management shares that we owned for approximately $17.5 million. We recognized a pre-tax gain of $4.5 million associated with this sale.

On November 10, 2004, Kinder Morgan Energy Partners issued 5.5 million common units in a public offering at a price of $46.00 per common unit, less commissions and underwriting expenses. On December 8, 2004, Kinder Morgan Energy Partners issued an additional 575,000 common units upon the exercise by the underwriters of an over-allotment option. After commissions and underwriting expenses, Kinder Morgan Energy Partners received net proceeds of $268.3 million. We did not acquire any of these common units. Kinder Morgan Energy Partners also issued 1.3 million i-units in conjunction with a Kinder Morgan Management limited registered offering of its shares in November 2004. We did not acquire any of the Kinder Morgan Management shares in this offering. These transactions reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transactions) from approximately 18.5% to approximately 17.9%. In accordance with our policy, we treat transactions such as these as “capital” transactions and, accordingly, no gain or loss was recorded. Instead, the impact of the difference between the sales proceeds and our underlying book basis had the effect of increasing our investment in the net assets of Kinder Morgan Energy Partners by $28.6 million and reducing our (i) equity method goodwill in Kinder Morgan Energy Partners by $29.6 million, (ii) paid-in capital by $0.4 million and (iii) associated accumulated deferred income taxes by $0.6 million. In addition, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $3.9 million; see Note 1(T).

Effective November 1, 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners for total consideration of $275.0 million (approximately $210.8 million in cash

and 1.4 million Kinder Morgan Energy Partners common units). In conjunction with this contribution, we recorded a pre-tax loss of $0.6 million.

Since 1998, we have had an investment in a 76 megawatt gas-fired power generation facility located in Greeley, Colorado. We recorded impairments of this investment during 2005 and 2004; See Note 6.

In July 2004, we sold our remaining surplus LM 6000 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. This note receivable has been collected as of December 31, 2005. In April 2004, we sold two LM6000 gas-fired turbines for $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 note 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 LM6000 turbines and two boilers to Kinder Morgan Production Company, L.P., a subsidiary of Kinder Morgan Energy Partners, for their 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. We recorded a pre-tax gain of $3.6 million in conjunction with these sales. Recognizing the effects of changes in technology and the limited improvement of the general economies of the electric generation industry, we determined that the carrying values of our remaining turbines and associated equipment should be reduced. In the fourth quarter of 2004, we reduced the carrying value of these assets by $7.4 million. The book value of the remaining surplus power generation equipment available for sale at December 31, 2005 was $23.5 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 from the offering were purchased by us. Kinder Morgan Management used the net proceeds of approximately $14.9 million from the offering to buy 360,664 additional i-units from Kinder Morgan Energy Partners. This issuance of i-units reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transaction) from approximately 18.54% to approximately 18.51% and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $1.2 million and reducing our (i) equity method goodwill in Kinder Morgan Energy Partners by $1.5 million, (ii) paid-in capital by $0.2 million and (iii) associated accumulated deferred income taxes by $0.1 million. In addition, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $0.2 million; see Note 1(T).

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 our (i) investment in the net assets of Kinder Morgan Energy Partners by $23.2 million, (ii) associated accumulated deferred income taxes by $0.1 million and (iii) paid-in capital by $0.2 million 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 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $2.4 million; see Note 1(T).

In December 2003, we received $8.5 million from the sale of one natural gas turbine. We ultimately recognized a pre-tax gain of $0.5 million on this transaction.

In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant in Wrightsville, Arkansas, utilizing Kinder Morgan Power’s Orion technology. Construction of this facility was completed and commercial operations commenced on July 1, 2002. Kinder Morgan Power made an investment in the project company that owns the power plant, comprised primarily of preferred stock. In October 2003, the project company was included in Mirant Corporation’s bankruptcy filing. In the fourth quarter of 2003, we wrote off our remaining investment in the Wrightsville power facility. During the third quarter of 2005, and subsequent to a negotiated settlement agreement approved by the court, Mirant sold the Wrightsville power facility to Arkansas Electric Cooperative Corporation.

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 (at the time of the transaction) from approximately 19.28% to approximately 18.86% and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $14.9 million and reducing our (i) equity method goodwill in Kinder Morgan Energy Partners by $21.4 million, (ii) associated accumulated deferred income taxes by $2.5 million and (iii) paid-in capital by $4.0 million. In addition, in June 2003, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $1.8 million; see Note 1(T).

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

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.

During the fourth quarter of 2003, we announced that, due principally to the fact that Mirant had placed the Wrightsville, Arkansas plant in bankruptcy during October, we would be assessing the long-term prospects for this facility during the fourth quarter and that a reduction in the plant’s carrying value was possible. During the fourth quarter of 2003 we completed our analysis and determined that it was no longer appropriate to assign any carrying value to our investment in this facility and recorded a $44.5 million pre-tax charge.

Since 1998, we have had an investment in a 76 megawatt gas-fired power generation facility located in Greeley, Colorado. We became concerned with the value of this investment as a result of several recent circumstances including the expiration of a gas purchase contract, the amendment of the associated power purchase agreement and uncertainties surrounding the management of this facility, which has changed ownership twice in the last one and one-half years. These ownership changes made it difficult for us to obtain information necessary to forecast the future of this asset. During the fourth quarter of 2004, we concluded that we had sufficient information to determine that our investment had been impaired and, accordingly, reduced our carrying value by $26.1 million. We wrote off the remaining carrying value of this investment ($6.5 million) in the fourth quarter of 2005 as it became clear that this

facility could no longer operate profitably in the high gas price environment resulting from hurricane damage to Gulf Coast production.

During 2003 and 2004, we sold six of our turbines and certain associated equipment (see Note 5). Recognizing the effects of technology and the limited improvement of the general economies of the electric generation industry, we determined that the carrying values of our remaining turbines and associated equipment should be reduced. In the fourth quarter of 2004, we reduced the asset values by $7.4 million. We are continuing our efforts to sell the remaining inventory of surplus turbines and associated equipment, which had a carrying value of $23.5 million at December 31, 2005.

Prior to mid-1999, we had major business operations in the upstream (gathering and processing), midstream (natural gas pipelines) and downstream (wholesale and retail marketing) portions of the natural gas industry and, in addition, had (i) non-energy retail marketing operations in the form of a joint venture called en●able and (ii) limited international operations. During 1999, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids, (iii) the direct marketing of non-energy products and services and (iv) international operations, which we subsequently decided to retain as discussed following.

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

With the exception of our international natural gas distribution operations, which we decided to retain, we completed the divestiture of our discontinued operations by December 31, 2000. During 2005, a gain of $3.2 million (net of taxes of $1.9 million) was recorded to reflect the settlement of previously recorded liabilities. In the fourth quarter of 2004, we recorded incremental losses of $6.4 million (net of tax benefits of $3.8 million tax) to increase previously recorded liabilities to reflect updated estimates and reflect the impact of litigation settlements. We had a remaining liability of approximately $0.4 million at December 31, 2005 associated with these discontinued operations, representing legal obligations associated with our sale of assets to ONEOK, Inc. (“ONEOK”).

On November 30, 2005, we acquired Terasen (see Note 4) and conducted a thorough review of assets associated with its water and utility service operations, which provides water, wastewater and utility services primarily in western Canada, and concluded that this business was outside of our core asset base of pipelines and terminals. In conjunction with the acquisition of Terasen we adopted and implemented plans to discontinue Terasen Water and Utility Services and its affiliates, excluding CustomerWorks LP, a 30 percent joint venture with Enbridge Inc.

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the results of operations, assets and liabilities and cash flows of the discontinued operation have been excluded from the respective captions in the accompanying Consolidated Statements of Income,

Consolidated Balance Sheets and Consolidated Statements of Cash Flows, and have been reported in the various statements under the captions “Discontinued Operations, Net of Tax”; “Gain (Loss) on Disposal of Discontinued Operations, Net of Tax”; “Current Assets: Assets Held for Sale”; “Current Liabilities: Liabilities Held for Sale”; “Net Cash Flows Provided by (Used in) Discontinued Operations”; “Net Cash Flows Used in Discontinued Investing Activities” and “Net Cash Flows Provided by Discontinued Financing Activities” for all relevant periods.

As discussed in Note 21, on January 17, 2006, we announced that Terasen entered into a definitive agreement to sell Terasen Water and Utility Services. In December of 2005, we recorded losses of $0.7 million (net of tax benefits of $0.3 million) to reflect the one month operating results of the water and utility business segment since its inclusion in our Consolidated Statement of Operations.

This business segment was included in the recent Terasen acquisition and, although no assurance can be given, it is estimated that this segment will sell at or close to its fair value. Any gain or loss on the disposal transaction plus any costs of disposal will be recognized as assets or liabilities assumed in the acquisition of Terasen and included in the allocation of the acquisition cost.

On February 17, 2006, Kinder Morgan Canada filed a complete National Energy Board (“NEB”) application for the Anchor Loop project. On November 15, 2005, Kinder Morgan Canada filed a comprehensive environmental report with the Canadian Environmental Assessment Agency regarding the project. The C$400 million project involves twinning a 98-mile section of the existing Trans Mountain pipeline system between Hinton, Alberta, and Jackman, British Columbia, and the addition of three new pump stations. With construction of the Anchor Loop, the Trans Mountain system’s capacity will increase from 260,000 barrels per day (“bpd”) to 300,000 bpd by the end of 2008.

Terasen Gas Inc.’s allowed return on equity (“ROE”) is determined annually based on a formula that applies a risk premium to a forecast of long-term Government of Canada bond yields. For 2005, the application of the ROE formula set Terasen Gas Inc.’s allowed ROE at 9.03%, down from 9.15% in 2004. On June 30, 2005, Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. (“TGVI”) applied to the British Columbia Utilities Commission (“BCUC”) to increase their deemed equity components from 33% to 38% and from 35% to 40%, respectively. The same application also requested an increase in allowed ROEs from the levels that would have resulted from the then applicable formula, which would have been 8.29% for Terasen Gas Inc. and 8.79% for TGVI in 2006. A decision from the BCUC was rendered on the application on March 2, 2006, to be effective as of January 1, 2006. The Decision resulted in increases in the deemed equity components of Terasen Gas Inc. and TGVI to 35% and 40%, respectively, and their allowed ROE’s to 8.80% and 9.5%, respectively.

We have initiated engineering, environmental and consultation activities on the proposed Corridor pipeline expansion project. The proposed C$1.0 billion expansion includes building a new 42-inch diluent/bitumen (“dilbit”) pipeline, a new 20-inch products pipeline, tankage and upgrading existing pump stations along the existing pipeline system from the Muskeg River Mine north of Fort McMurray to the Edmonton region. The Corridor pipeline expansion will add an initial 200,000 bpd of dilbit capacity to accommodate the new bitumen production from the Muskeg River Mine. The current dilbit capacity is approximately 258,000 bpd. It is expected to climb to 278,000 bpd by April 2006 by upgrading existing pump station facilities. By 2009, the dilbit capacity of the Corridor system is expected to be approximately 500,000 bpd. An application for the Corridor Pipeline Expansion Project was filed with the Alberta Energy Utilities Board and Alberta Environment on December 22, 2005. Pending regulatory and definitive shipper approval, construction will begin in late 2006.

On December 22, 2005 the FERC issued a Notice of Proposed Rulemaking (“NOPR”) to amend its regulations by establishing two new methods for obtaining market-based rates for underground natural gas storage services. First, the FERC is proposing to modify its market power analysis to better reflect

competitive alternatives to storage. Doing so would allow a storage applicant to include other storage services as well as non-storage products such as pipeline capacity, local production, or liquefied natural gas supply in its calculation of market concentration and its analysis of market share. Second, the FERC is proposing to modify its regulations to permit the FERC to allow market-based rates for new storage facilities even if the storage provider is unable to show that it lacks market power, provided the FERC finds that the market-based rates are in the public interest and necessary to encourage the construction of needed storage capacity and that customers are adequately protected from the abuse of market power. The Kinder Morgan interstate pipelines, including NGPL, as well as numerous other parties filed comments on the NOPR on February 27, 2006.

In a letter filed on December 8, 2005, NGPL requested that the Office of the Chief Accountant confirm that NGPL’s proposed accounting treatment to capitalize the costs incurred in a one-time pipeline rehabilitation project that will address stress corrosion cracking on portions of NGPL’s pipeline system is appropriate. The rehabilitation project will be conducted over a five-year period. The filing is still pending before the FERC.

On August 29, 2005, NGPL filed with the FERC a certificate application in Docket No. CP05-405-000 for authorization to construct and operate facilities at NGPL’s North Lansing storage facility in Harrison County, Texas to enable NGPL to provide an additional 10 billion cubic feet (“Bcf”) of cycled working gas and storage service under NGPL’s existing Rate Schedule NSS (i.e., firm storage service). Specifically, NGPL proposed to construct and operate: (i) twelve new injection/withdrawal wells, (ii) one 13,000 horsepower (“hp”) compressor unit at NGPL’s Compressor Station No. 388, (iii) 8.7 miles of 30-inch pipeline to loop a portion of the existing lateral between Compressor Station No. 388 and NGPL’s Gulf Coast mainline, along with a 30-inch tap that would be added to the mainline, (iv) looping on various field pipes and (v) new and upgraded metering facilities. In conjunction with its request to construct facilities, NGPL also requested authority to increase the peak day withdrawal level at North Lansing from 1,100 million cubic feet (“MMcf”) to 1,240 MMcf. The total estimated cost for the project is $64 million. The FERC order approving the project was issued January 23, 2006. The FERC found that NGPL’s reworking of 16 existing injection/withdrawal wells as part of the project required certification, and the order granted that authority.

On November 22, 2004, the FERC issued a Notice of Inquiry seeking comments on its policy of selective discounting. Specifically, the FERC asked parties to submit comments and respond to inquiries regarding the FERC’s practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons – when the discount is given to meet competition from another gas pipeline. After reviewing the comments, the FERC found that its current policy on selective discounting is an integral and essential part of the FERC’s policies furthering the goal of developing a competitive national natural gas transportation market. The FERC further found that the selective discounting policy provides for safeguards to protect captive customers. If there are circumstances on a particular pipeline that may warrant special consideration or additional protections for captive customers, those issues can be considered in individual cases. The FERC stated that this order is in the public interest because it promotes a competitive natural gas market and also protects the interests of captive customers. By an order issued May 31, 2005, the FERC reaffirmed its existing policy on selective discounting by interstate pipelines without change. Two entities filed for rehearing. By an order issued on November 17, 2005, the FERC denied all requests for rehearing. On January 9, 2006, a

petition for judicial review of the FERC’s May 31, 2005 and November 17, 2005 orders was filed by the Northern Municipal Distributor Group/Midwest Region Gas Task Force Association.

On November 5, 2004, the FERC issued a Notice of Proposed Accounting Release that would require FERC jurisdictional entities to recognize costs incurred in performing pipeline assessments that are a part of a pipeline integrity management program as maintenance expense in the period incurred. The proposed accounting ruling is in response to the FERC’s finding of diverse practices within the pipeline industry in accounting for pipeline assessment activities. The proposed ruling would standardize these practices. Specifically, the proposed ruling clarifies the distinction between costs for a “one-time rehabilitation project to extend the useful life of the system,” which could be capitalized, and costs for an “on-going inspection and testing or maintenance program,” which would be accounted for as maintenance and charged to expense in the period incurred.

On June 30, 2005, the FERC issued an order providing guidance to the industry on accounting for costs associated with pipeline integrity management requirements. The order is effective prospectively from January 1, 2006. Under the order, the costs to be expensed include those to: prepare a plan to implement the program; identify high consequence areas; develop and maintain a record keeping system; and inspect affected pipeline segments. The costs of modifying the pipeline to permit in-line inspections, such as installing pig launchers and receivers, are to be capitalized, as are certain costs associated with developing or enhancing computer software or to adding or replacing other items of plant. We expect an increase of $13 million in operating expenses in 2006 related to pipeline integrity management programs due to our implementation of this FERC order on January 1, 2006, which will cause us to expense certain program costs that previously were capitalized. The Interstate Natural Gas Association of America has sought rehearing of the FERC’s June 30 order. On September 19, 2005, the FERC denied the Interstate Natural Gas Association of America’s request for rehearing. On December 15, 2005, the Interstate Natural Gas Association of America filed a Petition for Review with the United States Court of Appeals for the District of Columbia Circuit (Court) in Docket No. 05-1426 asking the Court whether the FERC lawfully ordered that interstate pipelines must treat certain costs incurred in complying with the Pipeline Safety Improvement Act of 2002, along with related pipeline testing costs, as expenses rather than capital items for purposes of complying with the FERC’s regulatory accounting regulations.

In April 2004, NGPL was advised that, as part of an audit of the FERC Form No. 2s, the FERC would be conducting a compliance audit of NGPL’s Form No. 2s for the period January 1, 2000 through December 31, 2003. On May 4, 2005, the FERC issued their audit report recommending that NGPL (i) revise its procedures to ensure that fines and penalties are recorded in the proper accounts as required by the FERC’s Uniform System of Accounts, (ii) make a correcting entry in the amount of $215,000 to properly record a penalty that was paid in 2000 and (iii) implement procedures to ensure that inactive projects are cleared from construction work in progress on a timely basis. In addition, the FERC audit team identified approximately $20.6 million of costs associated with pipeline assessment that were capitalized by NGPL in accordance with its capitalization policies during the audit period. As described previously, the Chief Accountant of the FERC has issued a Notice of Proposed Accounting Release that is intended to provide industry guidance on accounting for pipeline assessment activities. The FERC audit report indicates that appropriate accounting for these costs will be further considered when this industry-wide proceeding is concluded and a final Accounting Release is approved by the FERC. The FERC final Accounting Release was issued June 30, 2005 and the new accounting guidelines will be effective January 1, 2006, as further described above. In a letter dated November 7, 2005, the FERC staff notified NGPL that NGPL’s Form No. 2 audit is now closed and that no further corrective action is required.

The FERC has commenced an audit of NGPL, as well as a number of other interstate pipelines, to test compliance with the FERC requirements related to the filing and posting of the Index of Customers. On February 14, 2006, the FERC issued its audit report. The audit report noted that there were instances where NGPL has excluded some shipper identification numbers, excluded the maximum storage quantity

for a bundled transportation and storage service and incorrectly identified a rate schedule. NGPL has made the appropriate corrections in its Index of Customers commencing with the January 1, 2006 Index. No further compliance action is required.

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. NGPL 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, NGPL and Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of Energy Affiliates. On February 9, 2004, the interstate pipelines owned by Kinder Morgan, Inc. and Kinder Morgan Energy Partners filed their compliance plans under Order No. 2004. In addition, on February 19, 2004, the Kinder Morgan interstate pipelines filed a joint request 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 the Kinder Morgan interstate pipelines.

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, but clarified that the LDC exemption still 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 producers from the definition of Energy Affiliate. The FERC also declined to exempt 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 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 pipeline and its Energy Affiliate can discuss potential new interconnects to serve the Energy Affiliate, but subject to posting and record-keeping requirements. The Kinder Morgan interstate pipelines sought rehearing to clarify the applicability of the LDC and Parent Company exemptions to them.

On July 21, 2004, the Kinder Morgan interstate pipelines filed additional joint requests asking for limited exemptions from certain requirements of FERC Order No. 2004 and asking for an extension of the deadline for full compliance with Order No. 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 Kinder Morgan, Inc.’s wholly owned subsidiaries, be classified as an exempt LDC for purposes of Order No. 2004. These exemptions requested relief from the independent functioning and information disclosure requirements of Order No. 2004. The exemption requests proposed to treat as Energy Affiliates within the meaning of Order No. 2004 two groups of employees, (i) individuals in the Choice Gas Commodity Group within Kinder Morgan, Inc.’s Retail operations and (ii) commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate operations. Order No. 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 interstate 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 the Kinder Morgan interstate pipelines to submit compliance plans regarding these filings within 30 days. These compliance plans were filed on October 19, 2004 and set out certain steps taken by the Kinder Morgan interstate pipelines to assure that employees in the Choice Gas Commodity Group within Kinder Morgan Inc.’s 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 of 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, the Kinder Morgan interstate pipelines were required to comply with Order No. 2004 by September 22, 2004.

The Kinder Morgan interstate 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 December 21, 2004, the FERC issued Order No. 2004-C, an order granting rehearing on certain issues and also clarifying certain provisions in the previous orders. The primary impact on the Kinder Morgan interstate pipelines from Order No. 2004-C is the granting of rehearing and allowing LDCs to participate in hedging activity related to on-system sales and still qualify for exemption from Energy Affiliate.

By an order issued on April 19, 2005, the FERC accepted the compliance plans filed by the Kinder Morgan interstate pipelines without modification, but subject to further amplification and clarification as to the intrastate group in three areas: (i) further description of the matters the shared transmission function personnel may discuss with the commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate operations; (ii) additional posting of organizational information about the commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate operations; and (iii) clarification that the President of Kinder Morgan Energy Partners’ intrastate pipeline group has received proper training and will not be a conduit for improperly sharing transmission or customer information with the commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate natural gas operations. The FERC also approved

treatment of Rocky Mountain Natural Gas Company as an exempt LDC. The Kinder Morgan interstate pipelines made a compliance filing on May 18, 2005.

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, interstate pipelines will no longer be permitted to use commodity price indices to structure transactions. 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. 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). In a FERC Order on Rehearing and Clarification issued January 19, 2006, the FERC modified its previous policy statement and now will again permit the use of gas commodity basis differentials in negotiated rate transactions without regard to rate or revenue caps.

Currently, there are no material proceedings challenging the base rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) on any of our natural gas 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.

We had an estimated total exposure of approximately $16.8 million to approximately $23.2 million and had recorded an environmental reserve of approximately $16.8 million at December 31, 2005 to address remediation issues associated with approximately 50 projects, recorded without discounting and without regard to expected insurance recoveries. In addition, we had recorded a receivable of $3.6 million for expected cost recoveries that have been deemed probable. 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.

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 (“MDL”), 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 Mr. 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 appealed that dismissal to the 10^th Circuit, which requested briefing regarding its jurisdiction over that appeal. Mr. Grynberg’s appeal was dismissed for lack of appellate jurisdiction. Discovery to determine issues related to the Court’s subject matter jurisdiction, arising out of the False Claims Act, is complete. Briefing has been completed and oral argument on jurisdictional issues was held before the Special Master on March 17 and 18, 2005. On May 7, 2003, Mr. 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. Neither the Court nor the Special Master have ruled on Mr. Grynberg’s motion to amend. On May 13, 2005, the Special Master issued his Report and Recommendations to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. The Special Master found that there was a prior public disclosure of the mismeasurement fraud Mr. Grynberg alleged, and that Mr. Grynberg was not an original source of the allegations. As a result, the Special Master recommended dismissal on jurisdictional grounds of the Kinder Morgan defendants. On June 27, 2005, Mr. Grynberg filed a motion to modify and partially reverse the Special Master’s recommendations, and the Defendants filed a motion to adopt the Special Master’s recommendations with modifications. An oral argument was held on December 9, 2005 on the motions concerning the Special Master’s recommendations. It is likely that Mr. Grynberg will appeal any dismissal to the 10^th Circuit Court of Appeals.

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. The plaintiff alleged generally in the petition that damages are “not to exceed $200 million” plus attorneys fees, costs and interest. The defendants 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 claimed indemnity from American Processing based on its sale of assets to American Processing on October 4, 1995. We accepted indemnity and defense subject to a reservation of rights pending resolution of the suit. The plaintiff 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.

On or about January 21, 2003, Benson-McCown & Company (“Benson-McCown”), another producer who sold gas to American Processing and ONEOK, filed a “Plea in Intervention” in which it essentially duplicated the plaintiff’s claims and also asserted the right to bring a class action and serve as one of the

class representatives. Defendants denied Benson-McCown’s claim and filed a counterclaim for overpayments made to Benson-McCown over the years.

On January 14, 2005, Defendants filed a motion to deny class certification. Subsequently, the plaintiffs agreed to dismiss and withdraw their class claims. An Agreed Order Dismissing all class claims, with prejudice, was entered by the Court on January 19, 2005. After the class claims were dismissed with prejudice, defendants settled the individual claims asserted by Darrell Sargent. The sole remaining claims are those asserted by Benson-McCown, individually, and defendants’ counterclaims with respect thereto.

On May 13, 2005, NGPL experienced a rupture on its 36-inch diameter Gulf Coast #3 natural gas pipeline in Harrison County, Texas. The pipeline rupture resulted in an explosion and fire that severely damaged an adjacent power plant co-owned by EWO Marketing, L.P. and others. In addition, local residents within an approximate one-mile radius were evacuated by local authorities until the site was secured. According to published reports, injuries were limited to one employee at the power plant who was treated for minor injuries and released. Although we are not aware of any litigation related to this matter which has been commenced as of the date hereof, NGPL has received claims for damages to nearby homes and buildings which allegedly resulted from the explosion. NGPL and its insurers are investigating such claims and processing them in due course.

Although no assurances can be given, we believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants. 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.

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

The components of income (loss) before income taxes from continuing operations are as follows:

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

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

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

During 2004, the effective tax rate applied in calculating deferred tax was reduced by approximately 1.1% due to a decrease in the state effective tax rate. As a result, net deferred tax liabilities were decreased by approximately $70.3 million.

During the third quarter of 2005, the Wrightsville power facility (in which we owned an interest) was sold to Arkansas Electric Cooperative Corporation, generating an estimated capital loss for tax purposes of $68.7 million. We did not record a loss for book purposes due to the fact that, for book purposes, we wrote off the carrying value of our investment in the Wrightsville power facility in 2003.

During 2005, in order to offset our capital loss carrryforward expiring in 2005 and our capital loss from the Wrightsville power facility, we sold 5.7 million Kinder Morgan Management shares that we owned, generating a gain for tax purposes of $118.1 million. As a result of these and other transactions, we have remaining a $2.5 million capital loss carryforward that expires $1.7 million during 2008 and $0.8 million during 2009. No valuation allowance has been provided with respect to this deferred tax asset.

We have not provided applicable U.S. deferred income taxes related to unremitted earnings of our investment in foreign subsidiaries. The company considers such earnings to be permanently reinvested outside of the United States. The effect of deferred income taxes associated with these unremitted earnings is not material.

At December 31, 2005, we had available an $800 million five-year senior unsecured revolving credit facility dated August 5, 2005. This credit facility replaced an $800 million five-year senior unsecured revolving credit agreement dated August 18, 2004, effectively extending the maturity of our credit

facility by one year, 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 facility it replaced and that are common in such arrangements. In this credit facility, the definition of consolidated net worth, which is a component of total capitalization, was revised to exclude other comprehensive income/loss, and the definition of consolidated indebtedness was revised to exclude the debt of Kinder Morgan Energy Partners that is guaranteed by us. This facility was amended on October 6, 2005 (i) to exclude the effect of consolidating Kinder Morgan Energy Partners relating to the requirements of EITF 04-5 discussed in Note 20, (ii) to make administrative changes and (iii) to change definitions and covenants to reflect the inclusion of Terasen as a subsidiary of ours. 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. This credit facility includes the financial covenant that consolidated indebtedness is not to exceed 65% of total capitalization.

The following constitute events of default under the credit facility, subject to certain cure periods:

Failure to make required payments under hedging agreements that exceed $100,000,000;

Based on our credit rating at December 31, 2005, our annual facility fee is 10 basis points on the total credit amount of $800 million. At December 31, 2005 and December 31, 2004, no amounts were outstanding under the bank facilities.

On November 23, 2005, 1197774 Alberta ULC, a wholly owned subsidiary of Kinder Morgan, Inc., entered into a 364-day credit agreement, with Kinder Morgan, Inc. as guarantor, which provides for a committed credit facility in the Canadian dollar equivalent of US$2.25 billion. This credit facility was used to finance the cash portion of the acquisition of Terasen (see Note 4), but could also be used for general corporate purposes. Under this bank facility, a facility fee is required to be paid based on the total commitment, whether used or unused, at a rate that varies based on Kinder Morgan, Inc.’s senior debt rating. On November 30, 2005, 1197774 Alberta ULC borrowed $2.1 billion under this facility to finance the cash portion of the acquisition of Terasen. The facility was terminated when the loan was repaid on December 9, 2005 after permanent financing was obtained as discussed further in this section. Interest paid during 2005 under this credit facility was $1.9 million.

At December 31, 2005, Terasen Inc. had available C$450 million in senior unsecured revolving credit facilities. The facilities have a term of 364 days, extendible annually for an additional 364 days at the option of the lenders, with a 1 year term-out provision if the banks do not extend. These credit facilities can be used for general corporate purposes and to support commercial paper issuance. Under these facilities, Terasen is required to pay a standby fee based on the total unused commitment, at a rate that varies based on Terasen’s senior debt rating.

The following constitute events of default under the credit facility, subject to certain cure periods:

Based on Terasen’s credit rating at December 31, 2005, the annual standby fee is 21.25 basis points on the unutilized commitment. At December 31, 2005, no amounts were outstanding under the bank facilities.

At December 31, 2005, Terasen Gas Inc. had available C$500 million in senior unsecured revolving credit facilities. The facilities have a term of 364 days, extendible annually for an additional 364 days at the option of the lenders. The credit facilities can be used for general corporate purposes and to support commercial paper issuance. Under these facilities, Terasen Gas Inc. is required to pay a standby fee based on the total unused commitment, at rates that vary based on Terasen Gas Inc.’s senior debt rating.

The following constitute events of default under the credit facility, subject to certain cure periods:

Based on Terasen’s credit rating at December 31, 2005, the annual standby fee ranges between 10 basis points and 15 basis points on the unutilized commitment. At December 31, 2005, no amounts were outstanding under the bank facilities.

At December 31, 2005, Terasen Pipelines (Corridor) Inc. had available a C$225 million senior unsecured revolving credit facility. The facility has a term of 364 days, extendible annually for an additional 364 days at the option of the lenders, with a 3 year term-out provision if the banks do not extend. This credit facility can be used for general corporate purposes and to support commercial paper issuance. The facility has associated, a $20 million demand facility put in place for overdraft purposes and short-term cash management. Under these facilities, Terasen Pipelines (Corridor) Inc. is required to pay a standby fee based on the total unused commitment, at a rate that varies based on Terasen Pipelines (Corridor) Inc.’s senior debt rating.

The following constitute events of default under the credit facility, subject to certain cure periods:

Based on Terasen’s credit rating at December 31, 2005, the annual standby fee is 10 basis points on the unutilized commitment. At December 31, 2005 no amounts were outstanding under the bank facility.

Commercial paper issued by us and supported by the $800 million bank facility are unsecured short-term notes with maturities not to exceed 270 days from the date of issue. During 2005, all commercial paper was redeemed within 36 days, with interest rates ranging from 2.55% to 4.43%. Commercial paper outstanding under the $800 million bank facility at December 31, 2005 was $25.0 million at a weighted-average interest rate of 4.41%. No commercial paper was outstanding under the $800 million bank facility at December 31, 2004. Average short-term borrowings outstanding during 2005 and 2004 were $198.1 million and $107.3 million, respectively. During 2005 and 2004, the weighted-average interest rates on short-term borrowings outstanding were 3.47% and 1.36%, respectively.

Commercial paper issued by Terasen Inc. are unsecured short-term notes with maturities not to exceed 364 days from the date of issue. Since the November 30, 2005 acquisition of Terasen, all of Terasen Inc.’s commercial paper was redeemed within 85 days, with interest rates ranging from 3.03% to 3.24%. Average short-term borrowings outstanding during the one month ended December 31, 2005 was $209 million. The weighted-average interest rates on short term borrowings outstanding for the one month ended December 31, 2005 was 3.10%. Commercial paper outstanding at December 31, 2005 was $197 million at a weighted-average interest rate of 3.12%. Terasen Gas Inc.’s floating rate commercial paper has associated floating-to-fixed interest rate swap agreements that effectively convert the related interest expense from floating to fixed rates. See Note 14 for additional information on these swap agreements.

Commercial paper issued by Terasen Gas Inc. are unsecured short-term notes with maturities not to exceed 364 days from the date of issue. Since the November 30, 2005 acquisition of Terasen, all commercial paper was redeemed within 91 days, with interest rates ranging from 2.82% to 3.28%. Average short-term borrowings outstanding during the one month ended December 31, 2005 was $266 million. The weighted-average interest rates on short term borrowings outstanding for the one month ended December 31, 2005 was 3.04%. Commercial paper outstanding at December 31, 2005 was $269 million at a weighted-average interest rate of 3.08%.

Commercial paper issued by Terasen Pipelines (Corridor) Inc. are unsecured short-term notes with maturities not to exceed 364 days from the date of issue. Since the November 30, 2005 acquisition of Terasen, all commercial paper was redeemed within 90 days, with interest rates ranging from 2.75% to 3.22%. Average short-term borrowings outstanding during the one month ended December 31, 2005 was $121 million. The weighted-average interest rates on short term borrowings outstanding for the one month ended December 31, 2005 was 3.03%. Commercial paper outstanding at December 31, 2005 was $120 million at a weighted-average interest rate of 3.16%.

As a result of our adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, effective December 31, 2003, the subsidiary trusts associated with these securities are no longer consolidated.

Adjustment of carrying value of long-term securities subject to outstanding interest rate swaps; see Note 14.

Includes purchase accounting adjustments, made to adjust the carrying values of the debt instruments and related interest rate swap agreements to their fair values at the date of acquisition. The adjustments are being amortized monthly over the term of the Notes.

Debt issued under Terasen Inc. and its subsidiaries is denominated in Canadian dollars but has been converted to U.S. dollars at the exchange rate at December 31, 2005 of 0.8598.

The 2013 Debentures are not redeemable prior to maturity. The 2028 and 2098 Debentures and the 2008 and 2012 Senior Notes are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. The 2028 Debentures and 2012 Senior Notes have associated fixed-to-floating interest rate swap agreements that effectively convert the related interest expense from fixed rates to floating rates based on the three-month London Interbank Offered Rate (“LIBOR”). See Note 14 for additional information on these swap agreements. The 2015 Senior Notes are redeemable in whole or in part at our option, but at redemption prices that generally do not make early redemption an economically favorable alternative. The 2026 and 2027 Debentures are redeemable in whole or in part, at our option after August 1, 2006, and November 1, 2004, respectively, at redemption prices defined in the associated prospectus supplements, which redemption prices generally do not make early redemption an economically favorable alternative.

On March 1, 2005, our $500 million of 6.65% Senior Notes matured, and we paid the holders of the notes, utilizing a combination of cash on hand and borrowings under our commercial paper program.

On October 21, 2004, we retired our $75 million 8.75% Debentures due October 15, 2024 at a premium of 104.0% of the face amount. We recorded a loss of $2.4 million (net of associated tax benefit of $1.5 million) in connection with this early extinguishment of debt, which is included under the caption “Other, Net” in the accompanying Consolidated Statement of Operations for 2004.

On March 3, 2003, our $500 million of 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.

On December 9, 2005, Kinder Morgan Finance Company, ULC issued $750 million of 5.35% Senior Notes due 2011, $850 million of 5.70% Senior Notes due 2016 and $550 million of 6.40% Senior Notes due 2036. The 2011, 2016 and 2036 Senior Notes issued by Kinder Morgan Finance Company, ULC are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. Each series of these notes is fully and unconditionally guaranteed by Kinder Morgan, Inc. on a senior unsecured basis as to principal, interest and any additional amounts required to be paid as a result of any withholding or deduction for Canadian taxes. The proceeds of $2.1 billion, net of underwriting discounts and commissions, were ultimately distributed to repay in full the bridge facility incurred to finance the cash portion of the consideration for Kinder Morgan, Inc.’s acquisition of Terasen on November 30, 2005 (see Note 4). These notes were sold in a private placement pursuant to a Purchase Agreement, dated December 6, 2005 among Kinder Morgan Finance Company, ULC, Kinder Morgan, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Citigroup Global Markets Inc., as representatives of the several initial purchasers named in the Purchase Agreement, and resold by the initial purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933. The notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements. In

February 2006, Kinder Morgan Finance Company, ULC exchanged these notes for substantially identical notes that have been registered under the Securities Act.

The Medium Term Notes are unsecured obligations but are subject to the restrictions of the Trust Indenture dated November 21, 2001. Terasen Inc.’s Series 2 Medium Term Notes are not redeemable prior to maturity. Terasen Inc.’s Series 1 and Series 3 Medium Term Notes are redeemable in whole or in part at the option of Terasen Inc. at prices defined in the associated Trust Indenture, which redemption prices generally do not make early redemption an economically favorable alternative. Terasen Inc.’s Medium Term Notes have associated fixed-to-floating interest rate swap agreements that effectively convert a majority of the related interest expense from fixed rates to floating rates. See Note 14 for additional information on these swap agreements.

The Series A and Series B Purchase Money Mortgages are collateralized equally and ratably by a first fixed and specific mortgage and charge on Terasen Gas’ Coastal Division assets, and are subject to the restrictions of the Trust Indenture dated December 3, 1990. The aggregate principal amount of Purchase Money Mortgages that may be issued under the Trust Indenture is limited to C$425 million. The Debentures are unsecured obligations but are subject to the restrictions of the Trust Indenture dated November 1, 1977, as amended and supplemented. The Series A Purchase Money Mortgage, Series D, Series 9 and Series 20 Debentures and Medium Term Notes are not redeemable prior to maturity. Terasen Gas Inc.’s Series B Purchase Money Mortgages, Series E Debentures and Series 11, Series 13, Series 16, Series 18 and Series 19 Debentures and Medium Term Notes are redeemable in whole or in part at the option of Terasen Gas Inc. at prices defined in the associated Trust Indenture, which redemption prices generally do not make early redemption an economically favorable alternative.

The obligations under capital leases represent fleet vehicles that Terasen Gas Inc. has leased from PHH Aral. The term of the leases are either 7 or 10 years, depending on the type of vehicle leased, and is fully collateralized by the vehicles themselves.

This credit facility from the syndicate of banks is collateralized by a first floating charge over all of the assets of TGVI, assignment of certain material contracts, and assignment of royalty revenue and interruptible incentive payments. The credit facility can be repaid at TGVI’s option without penalty. This credit facility was replaced by a revolving credit facility on January 13, 2006 as discussed in Note 21. TGVI’s credit facility has associated floating-to-fixed interest rate swap agreements that effectively convert the related interest expense from floating to fixed rates. See Note 14 for additional information on these swap agreements.

Terasen Pipelines (Corridor) Inc.’s Series A and Series B Debentures are redeemable in whole or in part at the option of Terasen Pipelines (Corridor) Inc. at prices defined in the associated Trust Indenture, which redemption prices generally do not make early redemption an economically favorable alternative. Terasen Pipelines (Corridor) Inc.’s Debentures have associated fixed-to-floating interest rate swap

agreements that effectively convert the related interest expense from fixed rates to floating rates. See Note 14 for additional information on these swap agreements.

Maturities of long-term debt (in thousands) for the five years ending December 31, 2010 are $347,400, $92,492 $769,104 $86,379 and $135,484, respectively.

At December 31, 2005 and 2004, the carrying amount of our long-term debt was $7.1 billion and $3.1 billion, respectively. The estimated fair values of our long-term debt at December 31, 2005 and 2004 are shown in Note 18.

Our business trusts, K N Capital Trust I and K N Capital Trust III, are obligated for $100 million of 8.56% Capital Trust Securities maturing on April 15, 2027 and $175 million of 7.63% Capital Trust Securities maturing on April 15, 2028, respectively, which are guaranteed by us. The 2028 Securities are redeemable in whole or in part, at our option at any time, at redemption prices as defined in the associated prospectus, but at redemption prices that generally do not make early redemption an economically favorable alternative. The 2027 Securities are redeemable in whole or in part (i) at our option after April 14, 2007 and (ii) at any time in certain limited circumstances upon the occurrence of certain events and at prices, all defined in the associated prospectus supplements. Upon redemption by us or at maturity of the Junior Subordinated Deferrable Interest Debentures, we must use the proceeds to make redemptions of the Capital Trust Securities on a pro rata basis. As a result of adopting FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, effective December 31, 2003, we (i) no longer include the transactions and balances of K N Capital Trust I and K N Capital Trust III in our consolidated financial statements and (ii) began including our Junior Subordinated Deferrable Interest Debentures issued to the Capital Trusts in a separate caption under the heading “Long-term Debt” in our Consolidated Balance Sheets. In addition, effective July 1, 2003 we (i) reclassified our trust preferred securities to the debt portion of our balance sheet and (ii) began classifying payments made by us in conjunction with the trust preferred securities as interest expense, rather than minority interest. For periods and dates prior to July 1, 2003, the Capital Trust Securities are treated as a minority interest, shown in our Consolidated Balance Sheets under the caption “Kinder Morgan-Obligated Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan,” and periodic payments made to the holders of these securities are classified under “Minority Interests” in our Consolidated Statements of Operations. See Note 18 for the fair value of these securities.

Terasen Inc. has C$125 million of 8% Capital Securities, which mature in 2040. Election options on these securities include: (i) to defer payments, (ii) to settle such deferred payments in either cash or common shares and (iii) to settle principal at maturity through the issuance of common shares. The securities are exchangeable at the option of the holder on or after April 19, 2010 for common shares of Terasen Inc. at 90% of the market price, subject to the right of Terasen Inc. to redeem the securities for cash.

As discussed in Note 4, on November 30, 2005, we completed the acquisition of Terasen. Terasen shareholders were able to elect, for each Terasen share held, either (i) C$35.75 in cash, (ii) 0.3331 shares of Kinder Morgan, Inc. common stock, or (iii) C$23.25 in cash plus 0.1165 shares of Kinder Morgan, Inc. common stock. In the aggregate, we issued approximately $1.1 billion (12.48 million shares) of Kinder Morgan Inc. common stock and paid approximately C$2.49 billion (US$2.13 billion) in cash to Terasen securityholders.

On February 14, 2006, we paid a cash dividend on our common stock of $0.875 per share to stockholders of record as of January 31, 2006.

2004, April 2005 and November 2005, respectively. As of December 31, 2005, we had repurchased a total of approximately $875.3 million (14,594,500 shares) of our outstanding common stock under the program, of which $314.1 million (3,865,800 shares), $108.6 million (1,695,900 shares) and $38.0 million (724,600 shares) were repurchased in the years ended December 31, 2005, 2004 and 2003, respectively.

In January 2003, our board of directors approved a plan to purchase shares of Kinder Morgan Management on the open market. During 2003 we purchased $0.9 million (29,000 shares) of Kinder Morgan Management stock.

We have authorized 200,000 shares of Class A and 2,000,000 shares of Class B preferred stock, all without par value. At December 31, 2005, 2004 and 2003, we did not have any outstanding shares of preferred stock.

On September 15, 2005, a rights agreement dated August 21, 1995 expired. In connection with this agreement, we had designated 150,000 shares of our Class B Preferred Stock as Class B Junior Participating Series Preferred Stock. No shares of the Class B Junior Participating Series Preferred Stock were outstanding or had been issued, and none will be issued. On October 20, 2005, after the approval of the Board of Directors, we filed a certificate with the State of Kansas eliminating from our restated articles of incorporation, as amended, all reference to our Class B Junior Participating Series Preferred Stock. The 150,000 shares previously designated as Class B Junior Participating Series Preferred Stock have been restored to the status of authorized and unissued shares of Class B Preferred Stock, undesignated as to series.

We utilize derivatives and other financial instruments to manage our exposure to changes in foreign currency exchange, interest rates and energy commodity prices. We account for these risk management activities according to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, “Statement 133.” Statement 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The accompanying Consolidated Balance Sheet as of December 31, 2005, includes, exclusive of amounts related to foreign currency exchange, interest rate swaps and Terasen Gas derivatives as discussed below, balances of approximately $81.6 million, $1.4 million,

$76.3 million and $821,000 in the captions “Current Assets: Other,” “Deferred Charges and Other Assets,” “Current Liabilities: Other,” and “Other Liabilities and Deferred Credits: Other” respectively, related to these derivative financial instruments. Statement 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, Statement 133 allows a derivative’s gains and losses to offset related results from the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.

We enter into derivative contracts solely for the purpose of hedging exposures that accompany our normal business activities. In accordance with the provisions of Statement 133, we designated these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. We enter into these transactions only with counterparties whose debt securities are rated investment grade by the major rating agencies. In general, the risk of default by these counterparties is low. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.

Our businesses require that we purchase, sell and consume natural gas. Specifically, we purchase, sell and/or consume natural gas (i) to serve our regulated natural gas distribution sales customers in the U.S. and Canada, (ii) to serve certain of our retail natural gas distribution customers in areas where regulatory restructuring has provided for competition in natural gas supply, for customers who have selected the Company as their supplier of choice under our Choice Gas program, (iii) as fuel in one of our Colorado power generation facilities, (iv) as fuel for compressors located on NGPL’s pipeline system and (v) for operational sales of gas by NGPL.

With respect to item (iii), our exposure is minimal and primarily consists of basis rather than commodity risk. With respect to item (iv), this fuel is supplied by in-kind fuel recoveries that are part of the transportation tariff. Item (i) gives rise to natural gas commodity price risk that is “passed-through” to our customers as the retail gas distribution regulatory structures provide for such. The gas distribution operations under Terasen use derivatives to manage natural gas commodity price risk that is passed to customers. Items (ii) and (v) give rise to natural gas commodity price risk which we have chosen to substantially mitigate through our risk management program. We provide this mitigation through the use of financial derivative products, and we do not utilize these derivatives for any purpose other than risk mitigation.

natural gas purchased and the price of natural gas included in rates are recorded in deferral accounts, and subject to regulatory approval, are passed through in future rates to customers. Terasen Gas’ price risk management strategy covers a term of 36 months and aims to (i) improve the likelihood that natural gas prices remain competitive with electricity rates, (ii) dampen price volatility on customer rates and (iii) reduce the risk of regional price disconnects. The accompanying Balance Sheet at December 31, 2005 includes a net deferral of $19.1 million reported under the caption “Current Liabilities: Other” representing net losses as a result of ineffectiveness of these hedges that are recoverable from customers through rates.

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 2006, substantially all of the accumulated other comprehensive income balance of approximately $23.3 million at December 31, 2005, representing unrecognized net losses on derivative activities. During the three years ended December 31, 2005, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

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

combined notional value of C$1,240 million and have been designated as a hedge of our net investment in Canadian operations in accordance with Statement 133. We have chosen to measure the amount of ineffectiveness of this hedging relationship using a methodology based on changes in forward exchange rates. Ineffectiveness will result if (i) the notional amount of the derivative does not match the portion of the net investment designated as being hedged, (ii) the derivative’s underlying exchange rate is not the exchange rate between the functional currency of the hedged net investment and the investor’s functional currency, or (iii) the hedging derivative is a cross-currency interest rate swap in which neither leg is based on comparable interest rate curves. We have recognized no ineffectiveness through the income statement as a result of these hedging relationships during 2005. The effective portion of the changes in fair value of these swap transactions are reported as a Cumulative Translation Adjustment under the caption “Other Comprehensive Income” in the accompanying Consolidated Balance Sheet. The fair value of the swaps at December 31, 2005 is a payable of $14.2 million which reflects $1.5 million included in the caption “Deferred Charges and Other Assets” and $15.7 million included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying Consolidated Balance Sheet. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually.

In December 2005 we entered into three receive-fixed-rate, pay-variable-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with Merrill Lynch. These derivative instruments have a combined notional value of C$1,254 million and do not qualify as a hedge of our net investment in Canadian operations in accordance with Statement 133. As a result, the gain or loss resulting from changes in the fair value of these swap transactions are recognized currently in earnings. During 2005, we recognized a pre-tax loss of $2.7 million as a result of recording these derivatives at fair value. During February 2006, we entered into transactions to terminate these and enter into new derivative instruments, with the same notional amount, that qualify as hedges and are prospectively designated as hedges of our net investment in Canadian operations in accordance with Statement 133. See Note 21 for additional details on these transactions.

In 2006, we swapped an additional $1.25 billion of U.S. dollar fixed-rate debt to floating rates. See Note 21 for additional details on this transaction.

Based on the long-term debt effectively converted to floating rate debt as a result of the swaps discussed above where the risk is not passed to customers through rates, the market risk related to a 1% change in interest rates would result in a $28 million annual impact on pre-tax income.

On March 3, 2003, we terminated the interest rate swap agreements associated with our 6.65% Senior Notes due in 2005 and received $28.1 million in cash. We amortized this amount to interest expense over the period that remained until the 6.65% Senior Notes matured this year.

Following is selected information concerning our natural gas risk management activities, excluding Terasen, as of December 31, 2005:

A term of reference describing a unit of commodity trading. One natural gas contract equals 10,000 MMBtus. One crude oil or natural gas liquids contract equals 1,000 barrels.

Our over-the-counter swaps and options are with a number of parties, each of which is an investment grade credit. At December 31, 2005, based on the fair values of open positions, if parties to the derivative instruments failed completely to perform, our maximum amount of credit risk was $6.7 million.

Following is selected information concerning natural gas risk management activities of Terasen Gas where the natural gas commodity price risk is passed to the customer through future rates.

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

Terasen Gas is exposed to credit risk in the event of non-performance by counterparties to derivative instruments. Terasen Gas deals with high credit quality institutions in accordance with established credit approval practices. At December 31, 2005, if parties to the derivative instruments failed to completely perform, our maximum amount of credit risk was $90.8 million.

On November 30, 2005, we completed the acquisition of Terasen, which included sponsorship of all of Terasen’s employee benefit plans. Following are separate discussions of the Kinder Morgan, Inc. and the Terasen employee benefit plans.

We have defined benefit pension plans covering eligible full-time employees. These plans provide pension benefits that are based on the employees’ compensation during the period of employment, age and years of service. These plans are tax-qualified subject to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended. Our funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds. Plan assets included our common stock valued at $32.0 million and $26.2 million as of December 31, 2005 and 2004, respectively. The measurement date for our retirement plans is December 31.

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

The accumulated benefit obligation through December 31, 2005 and 2004 was $212.7 million and $192.9 million, respectively.

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

Prepaid pension cost as of December 31, 2005 is recognized under the caption “Deferred Charges and Other Assets” in the accompanying Consolidated Balance Sheets.

The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Effective January 1, 2001, we added a cash balance plan to our retirement plan. Certain collectively bargained employees and “grandfathered” employees continue to accrue benefits through the defined pension benefit plan described above. All other employees accrue benefits through a personal retirement account in the cash balance plan. All employees converting to the cash balance plan were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. We make contributions on behalf of these employees equal to 3% of eligible compensation every pay period. In addition, we may make discretionary contributions to the plan based on our performance. No discretionary contributions were made for 2005 performance. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement.

In addition to our retirement plan described above, we have the Kinder Morgan, Inc. Savings Plan (the “Plan”), a defined contribution 401(k) plan. The plan permits all full-time employees to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, we may make discretionary contributions in years when specific performance objectives are met. Certain employees’ contributions are based on collective bargaining agreements. The mandatory contributions

are made each pay period on behalf of each eligible employee. Any discretionary contributions are generally made during the first quarter following the performance year. All employer contributions, including discretionary contributions, are in the form of Company stock, which is immediately convertible into other available investment vehicles at the employee’s discretion. Our Board of Directors has authorized a total of 6.7 million shares to be issued through the Plan. The total amount contributed for 2005, 2004 and 2003 was $14.6 million, $12.2 million and $11.5 million, respectively.

For employees hired on or prior to December 31, 2004, all contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Employer contributions for employees hired on or after January 1, 2005 will vest on the second anniversary of the date of hire. Effective October 1, 2005, for new employees of Kinder Morgan Energy Partners, L.P.’s Terminals segment, a tiered employer contribution schedule was implemented. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for services between two and five years, and 4% for service of five years or more. All employer contributions for Terminal employees hired after October 1, 2005 will vest on the fifth anniversary of the date of hire. Vesting and contributions for bargaining employees will follow the collective bargaining agreements.

At its July 2005 meeting, the compensation committee of our board of directors approved a special contribution of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2005 and continuing through the last pay period of July 2006. The additional 1% contribution is in the form of Company stock (the same as the current 4% contribution) and does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and the vesting schedule mirrors the company’s 4% contribution. Since this additional 1% company contribution is discretionary, compensation committee approval will be required annually for each additional contribution. During the first quarter of 2006, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2005.

We have a postretirement plan providing medical and life insurance benefits upon retirement for eligible employees and their eligible dependents. We fund a portion of the future expected postretirement benefit cost under the plan by making payments to Voluntary Employee Benefit Association trusts. Plan assets are invested in a mix of equity funds and fixed income instruments similar to the investments in our pension plans. The measurement date for our postretirement plan is December 31.

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

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets and the plan’s funded status. The prepaid expense is included in the caption “Deferred Charges and Other Assets” in our Consolidated Balance Sheets:

We expect to make contributions of approximately $8.7 million to the plan in 2006.

A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2005 net periodic postretirement benefit cost by approximately $5 (5) thousand and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2005 by approximately $85 (79) thousand.

The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

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 (“FSP”) FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, to provide guidance on accounting and disclosure for the Act as it pertains to postretirement benefit plans, and 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 superseded FSP FAS 106-1 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.

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

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

The investment policies and strategies for the assets of our pension and retiree life and medical plans are established by the plans’ Fiduciary Committee (the “Committee”). The stated philosophy of the Committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations will be met. The objectives of the investment management program are to (1) ultimately achieve and maintain a fully funded status based on relevant actuarial assumptions, (2) have the ability to pay all plan obligations when due, (3) as a minimum, meet or exceed actuarial return assumptions and (4) earn the highest possible rate of return consistent with established risk tolerances. In seeking to meet these objectives, the Committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee has adopted a strategy of using multiple asset classes. As of December 31, 2005, the following target asset allocation

ranges were in effect (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income – 20%/30%/40% and Equity – 60%/70%/80%. In order to achieve enhanced diversification, the equity category is further subdivided into sub-categories with respect to Kinder Morgan Stock, small cap vs. large cap, value vs. growth and international vs. domestic, each with its own target asset allocation (in the case of Kinder Morgan Stock, the allocation range was 5%/10%/15% at December 31, 2005).

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

For the year ending December 31, 2005, our defined benefit pension plan yielded a weighted-average rate of return of 9.36% above the expected rate of return on assets of 9.00%. Investment performance for a balanced fund comprised of a similar mix of assets yielded a weighted-average return of 5.46%, so our plans significantly outperformed the benchmark balanced fund index.

At December 31, 2005, our pension and retiree life and medical fund assets consisted of 72.5% equity, 26.2% debt and 1.3% cash and cash equivalents. Historically over long periods of time, widely traded large cap equity securities have provided a return of 10%, while fixed income securities have provided a return of 6%, indicating that a long term expected return predicated on the asset allocation as of December 31, 2005 would be approximately 8.8% if investments were made in the broad indexes. Therefore, we arrived at an overall expected return of 9% for purposes of making the required calculations.

We are a sponsor of pension plans for eligible employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements, which provide pension benefits in excess of statutory limits, and defined contributory plans. We also provide postretirement benefits other than pensions for retired employees. The following is a summary of each type of plan:

Retirement benefits under the defined benefit plans are based on employees’ years of credited service and remuneration. Company contributions to the plan are based upon independent actuarial valuations. The most recent actuarial valuations of the defined benefit pension plans for funding purposes were at December 31, 2004 and December 31, 2002 and the date of the next required valuations are December 31, 2007 and December 31, 2005. The December 31, 2005 valuation will not be completed until the

second quarter of 2006. The expected weighted average remaining service life of employees covered by the defined benefit pension plans is 11.8 years (2004 - 11.8 years).

Effective in 2000 for Terasen Gas and 2003 for petroleum transportation operations, all new non-union employees become members of defined contribution pension plans. Company contributions to the plan are based upon employee age and pensionable earnings for employees of the natural gas distribution operations and pensionable earnings for employees of the petroleum transportation operation.

Certain employees are eligible to receive supplemental benefits under both the defined benefit and defined contribution plans. The supplemental plans provide pension benefits in excess of statutory limits. The supplemental plans are unfunded and are secured by letters of credit. Beginning in 2006, we have capped eligible compensation for Canada-based employees at C$250,000 per year.

We provide retired employees with other postretirement benefits that include, depending on circumstances, supplemental health, dental and life insurance coverage. Postretirement benefits are unfunded and annual expense is recorded on an accrual basis based on independent actuarial determinations, considering among other factors, health care cost escalation. The most recent actuarial valuations were completed as of December 31, 2002 and the December 31, 2005 valuation will not be completed until second quarter 2006. The expected weighted average remaining service life of employees covered by these benefit plans is 9.9 years (2004 - 9.9 years).

We measure accrued benefit obligations and the fair value of plan assets for accounting purposes as of December 31 each year. The financial positions of the employee defined benefit pension plans and postretirement benefit plans are presented in aggregate in the tables below.

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

The accumulated pension and postretirement benefit obligation through December 31, 2005 was $248.9 million and $70.5 million, respectively.

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

For 2006, we expect to contribute approximately $7.3 million and $1.4 million to the pension and postretirement plans, respectively.

Accrued benefit liability as of December 31, 2005 is recognized under the caption, “Other Liabilities and Deferred Credits: Other” in the accompanying Consolidated Balance Sheets.

A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2005 net periodic postretirement benefit cost by approximately $1,273 ($1,016) and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2005 by approximately $13,313 ($11,084).

The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

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

The investment policy for benefit plan assets is to optimize the risk-return using a portfolio of various asset classes. Our primary investment objectives are to secure registered pension plans, and maximize investment returns in a cost-effective manner while not compromising the security of the respective plans. The pension plans utilize external investment managers to mange the investment policy. Assets in the plan are held in trust by independent third parties.

For the year ending December 31, 2005, our defined benefit pension plans yielded a weighted-average rate of return of 13.12%, well above management’s expected rate of return on assets of 7.25%. Investment performance for a median-indexed balanced fund comprised of a similar mix of assets yielded a weighted-average rate of return of 12.33%, so Terasen’s plans slightly outperformed the balanced fund index. Terasen asset mix at December 31, 2005 consisted of approximately 57% equity, 38% in fixed-income securities and 5% in real estate investments. Canadian equity returns for 2005 were very strong, partially offset by lower returns from bond performance. Management does not expect yields on the pension asset portfolios to continue to be as strong in 2006, and has lowered expected return on assets assumptions to 7.25% for 2006.

We have stock options issued under the following plans: The 1992 Non-Qualified Stock Option Plan for Non-Employee Directors (which plan has been terminated), the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which plan has been terminated), the Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan and the Non-Employee Directors Stock Awards Plan. The 1994 plan provided for and the 1999 plan and the Non-Employee Directors Stock Awards Plan provide for the issuance of restricted stock. We also have an employee stock purchase plan.

We account for these plans using the “intrinsic value” method contained in Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Had we applied the “fair value” method contained in SFAS No. 123, Accounting for Stock-Based Compensation, our earnings would have been affected; see Note 1(S). In December 2004, the FASB issued SFAS No. 123R (revised 2004), Share-Based Payment. This statement, which we will adopt in the first quarter of 2006, will affect the way we account for these plans; see Note 20.

On October 8, 1999, our Board of Directors approved the creation of our 1999 stock option plan, a broadly based non-qualified stock option plan. Under the plan, options may be granted to individuals who are regular full-time employees, including officers and directors who are employees. Prior to 2004, options under the plan vested in 25% increments on the anniversary of the grant over a four-year period from the date of grant and had a 10-year life. On July 20, 2004, approximately 289,000 shares were granted under the plan that will vest 100% after three years and have a seven-year life. On January 17, 2001, our Board of Directors approved an additional 5 million shares for future grants to participants in the 1999 Stock Option Plan, which brings the aggregate number of shares subject to the plan to 10.5 million. The Board also recommended, and our shareholders approved at our May 8, 2001 annual meeting, an additional 0.5 million shares for future grants to participants in the 1992 Directors’ Plan, which brings the aggregate number of shares subject to that plan to 1.03 million. On July 16, 2003, approximately 706,000 shares were granted to employees under the Long-term Incentive Plan. These shares will vest 100% after three years and have a 7-year life. Effective January 18, 2005, our Board of Directors established the Non-Employee Directors Stock Awards Plan. The plan was approved at our shareholders’ meeting on May 10, 2005. Under the plan, options and restricted stock may be granted to our non-employee directors. The aggregate number of shares of our common stock which may be issued under the plan with respect to options and restricted stock may not exceed 500,000.

Under all plans, except the Long-term Incentive Plan, options must be granted at not less than 100% of the market value of the stock at the date of grant. Under the Long-term Incentive Plan options may be granted at less than 100% of the market value of the stock at the date of grant although we do not expect to make any grants of options at less than 100% of the market value of the stock at the grant date. Compensation expense was recorded totaling $8.2 million, $5.1 million and $3.4 million for 2005, 2004 and 2003, respectively, relating to restricted stock grants awarded under the plans.

A summary of the status of our stock option plans at December 31, 2005, 2004 and 2003, and changes during the years then ended is presented in the table and narrative below:

The following table sets forth our common stock options outstanding at December 31, 2005, weighted-average exercise prices, weighted-average remaining contractual lives, common stock options exercisable and the exercisable weighted-average exercise price:

Under the employee stock purchase plan, we may sell up to 2,400,000 shares of common stock to eligible employees. Employees purchase shares through voluntary payroll deductions. Through 2004, shares were purchased quarterly at a 15% discount from the closing price of the common stock on the last trading day of each calendar quarter. Beginning with the March 31, 2005 quarterly purchase, the discount was reduced to 5%, thus making the employee stock purchase plan a non-compensatory plan under SFAS No. 123. Employees purchased 45,541 shares, 86,255 shares and 95,997 shares for plan years 2005, 2004 and 2003, respectively. Using the Black-Scholes model to assign value to the option inherent in the right to purchase stock under the provisions of the employee stock purchase plan, the weighted-average fair value per share of purchase rights granted in 2004 and 2003 was $11.28 and $9.67, respectively.

Expenses incurred under operating leases were $25.1 million in 2005, $24.3 million in 2004 and $6.4 million in 2003. The principal reason for the increased expense in 2005 and 2004 compared to 2003 is the lease associated with the Jackson, Michigan power generation facility as discussed below. Future minimum commitments under major operating leases and gas purchase contracts as of December 31, 2005 are as follows:

The significant increase from 2005 expenses incurred under operating leases to the expected lease obligations in 2006 is due to the inclusion of Terasen’s operating leases. We acquired Terasen effective November 30, 2005. See Note 4 for information regarding this acquisition.

Included in the future minimum commitments shown in the preceding table is the lease obligation associated with the Jackson, Michigan power generation facility. The project company that is the lessee of this facility is consolidated as of December 31, 2003, as a result of the adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. The facility is subject to a long-term tolling agreement, and the lease obligation is without recourse to the project investors.

Terasen Gas and TGVI have entered into gas purchase contracts, which represent future purchase obligations. Gas purchase contract commitments are based on market prices that vary with gas commodity indices. The amounts shown in the preceding table reflect index prices that were in effect at December 31, 2005. Kinder Morgan Retail is obligated under certain gas purchase contracts, dating from 1973, to purchase natural gas at fixed and escalating prices from a certain field in Montana. See Note 1(N).

Future minimum commitments under capital leases as of December 31, 2005 are $1.5 million for each of the years 2006 through 2010.

As a result of our December 1999 sale of assets to ONEOK, ONEOK became primarily obligated for the lease of the Bushton gas processing facility. We remain secondarily liable for the lease, which had a remaining minimum obligation of approximately $164.9 million at December 31, 2005, with payments that average approximately $23 million per year through 2012. In conjunction with our contributions of assets to Kinder Morgan Energy Partners at December 31, 1999, December 31, 2000 and November 1, 2004, we are a guarantor of approximately $733.5 million of Kinder Morgan Energy Partners’ debt. We would be obligated to perform under this guarantee only if Kinder Morgan Energy Partners and/or its assets were unable to satisfy its obligations.

Approximately $100.0 million of our consolidated capital expenditure budget for 2006 had been committed for the purchase of plant and equipment at December 31, 2005.

We could be obligated (i) based on operational performance of the equipment at the Jackson, Michigan power generation facility to invest up to an additional $3 to $8 million per year for the next 13 years and (ii) based on cash flows generated by the facility, to invest up to an additional $25 million beginning in 2018, in each case in the form of an incremental preferred interest.

In prior years, TGVI received non-interest bearing, repayable loans from the Canadian Federal and Provincial governments of C$50 million and C$25 million respectively, in connection with the construction and operation of the Vancouver Island natural gas pipeline. The government loans are repayable in any fiscal year after 2002 and prior to 2012 under certain circumstances and subject to the ability of TGVI to obtain non-government subordinated debt financing on reasonable commercial terms. As approved by the BCUC, these loans have been recorded as a government grant and have reduced the amounts reported for property, plant and equipment. We anticipate that all of the repayment criteria may be met in 2006 and, if met, will result in an estimated repayment of C$6.4 million of these loans in 2006. As the loans are repaid and replaced with non-governmental loans, plant and equipment and long-term debt will increase in accordance with the approved capital structure, as will the rate base used in determining rates. The amounts are not included in the obligations in the table above as the amounts and timing of repayments is dependent upon the approved Revenue Deficiency Deferral Account recovery each year and the ability to replace the loans with non-government subordinated debt financing on reasonable commercial terms.

Letters of credit totaling $183.6 million outstanding at December 31, 2005 consisted of the following: (i) three letters of credit, totaling $43.5 million, supporting our hedging of commodity risk, (ii) two letters of credit, totaling $43.7 million securing accrued unfunded retirement obligations to certain current and retired executives and employees of Terasen, (iii) a $15.1 million letter of credit to fund the Debt Service Reserve Account required under the Express System’s trust indenture, (iv) four letters of credit, totaling $39.7 million to secure obligations for construction of new pump stations on the Trans Mountain system, (v) four letters of credit, totaling $19.0 million, required under provisions of our property and casualty, worker’s compensation and general liability insurance policies, (vi) a $10.6 million letter of credit supporting the subordination of operating fees payable to us for operation of the Jackson, Michigan power generation facility to payments due under the operating lease of the facilities, (vii) a $6.6 million letter of credit associated with the outstanding debt of Thermo Cogeneration Partnership, L.P., the entity responsible for the operation of our Colorado power generation assets, (viii) a $2.0 million letter of credit supporting Thermo Cogeneration Partnership, L.P.’s performance under its contract with Public Service Company of Colorado, the principal customer of our Colorado power generation assets and (ix) 32 letters of credit, totaling $3.4 million supporting various company functions.

The following fair values of Long-term Debt and Capital Securities were estimated based on an evaluation made by an independent securities analyst. Fair values of “Energy Financial Instruments, Net” reflect the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. Market quotes are available for substantially all instruments we use.

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

during 1999 and, in 2005, we discontinued the water and utility services businesses acquired with Terasen.

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

NGPL’s principal delivery market area encompasses the states of Illinois, Indiana, Iowa and portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. NGPL is the largest transporter of natural gas to the Chicago, Illinois area, its largest market. During 2005, approximately 42% of NGPL’s transportation represented deliveries to this market. NGPL’s storage capacity is largely located near its transportation delivery markets, effectively serving the same customer base. NGPL has a number of individually significant customers, including local gas distribution companies in the greater Chicago area and major natural gas marketers and, during 2005, approximately 55% of its operating revenues from tariff services were attributable to its eight largest customers.

Kinder Morgan Canada owns and operates the Trans Mountain Pipe Line, a common carrier pipeline system originating at Edmonton, Alberta for the transportation of crude petroleum, refined petroleum and iso-octane to destinations in the interior and on the west coast of British Columbia, with connecting pipelines that deliver petroleum to refineries in the State of Washington and that transport jet fuel from Vancouver area refineries and marketing terminals and Westridge Marine Terminal to Vancouver International Airport. Kinder Morgan Canada also owns and operates the Corridor Pipeline, which transports diluted bitumen produced at the Muskeg River Mine located approximately 43 miles north of Fort McMurray, Alberta to a heavy oil upgrader near Edmonton, Alberta, a distance of approximately 281 miles. A smaller diameter parallel pipeline transports recovered diluent from the upgrader back to the mine. Corridor also consists of two additional pipelines, each 27 miles in length, to provide pipeline transportation between the Scotford Upgrader and the existing trunk pipeline facilities of Trans Mountain and Enbridge Pipelines Inc. in the Edmonton area. Kinder Morgan Canada also owns a one-third interest in the Express System. The Express System is a batch-mode, common-carrier, crude pipeline system comprised of the Express Pipeline and the Platte Pipeline. The Express System transports a wide variety of crude types produced in Alberta to markets in the Rocky Mountain and Midwest regions of the United States.

Terasen Gas provides natural gas service to over 100 communities with a service territory that has an estimated population of approximately four million. Terasen Gas is one of the largest natural gas distribution companies in Canada. As of December 31, 2005, Terasen Gas transported and distributed natural gas to approximately 892,000 residential, commercial and industrial customers in British Columbia. Terasen Gas’ service area extends from Vancouver to the Fraser Valley and the interior of British Columbia. The transmission and distribution business is carried on under statutes and franchises or operating agreements granting the right to operate in the municipalities or areas served. Terasen Gas is regulated by the British Columbia Utilities Commission (“BCUC”).

Kinder Morgan Retail’s markets are represented by residential, commercial and industrial customers located in Colorado, Nebraska and Wyoming. These markets represent varied types of customers in many industries, but a significant amount of Kinder Morgan Retail’s load is represented by the use of natural gas for space heating, grain drying and irrigation. The latter two groups of customers are concentrated in the agricultural industry, and all markets are affected by the weather.

Power’s current principal market is represented by the local electric utilities in Colorado, which purchase the power output from its generation facilities. Due to the adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, the results of operations of our Triton Power affiliates are included in our consolidated operating results and in the results of our Power segment beginning with the first quarter of 2004. Although the results of Triton have an impact on the total operating revenues and expenses of the Power business segment, after taking into account the associated minority interests, the consolidation of Triton had no effect on Power’s segment earnings. During 2005, approximately 70% of Power’s operating revenues were for operating the Jackson, Michigan Power facility, 18% were electric sales revenues from XCEL Energy’s Public Service Company of Colorado under a long-term contract, and the remaining 12% were primarily for operating the Ft. Lupton, Colorado power facility and a new gas-fired power facility in Snyder, Texas that began operations during the second quarter of 2005 and provides electricity to Kinder Morgan Energy Partners’ SACROC operations.

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

During 2005, 2004 and 2003, we did not have revenues from any single customer that exceeded 10% of our consolidated operating revenues.

Represents revenues from KM Insurance Ltd., our wholly owned subsidiary that was formed during the second quarter of 2005 for the purpose of providing insurance services to Kinder Morgan Energy Partners and us. KM Insurance Ltd. was formed as a Class 2 Bermuda insurance company, the sole business of which is to issue policies for Kinder Morgan Energy Partners and us to secure the deductible portion of our workers’ compensation, automobile liability and general liability policies placed in the commercial insurance market.

Includes, as applicable to each particular year, cash and cash equivalents, the market value of derivative instruments (including interest rate swaps), income tax receivables, assets of discontinued operations and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.

Effective November 1, 2004 we contributed our investment in TransColorado Gas Transmission Company to Kinder Morgan Energy Partners (see Note 5). TransColorado was a 50/50 joint venture with Questar Corp. until we bought Questar’s interest effective October 1, 2002, thus becoming the sole owner. As a result, TransColorado’s results shown above reflect our 50% equity interest in its earnings prior to October 1, 2002 and 100% of its results on a consolidated basis from October 1, 2002 through October 31, 2004.

Prior to 2005, all but an insignificant amount of our assets and operations were located in the continental United States. Upon our acquisition of Terasen on November 30, 2005, we obtained significant assets and operations in Canada. Following is geographic information regarding the revenues and long-lived assets of our business segments. Revenues from Kinder Morgan Canada and Terasen Gas, as presented below, include only the revenues subsequent to our November 30, 2005 acquisition of Terasen.

In December 2004, the FASB issued SFAS No. 123R (revised 2004), Share-Based Payment. This Statement amends SFAS No. 123, Accounting for Stock-Based Compensation, and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following:

share-based payment awards result in a cost that will be measured at fair value on the awards’ grant date, based on the estimated number of awards that are expected to vest. Compensation cost for awards that vest would not be reversed if the awards expire without being exercised;

when measuring fair value, companies can choose an option-pricing model that appropriately reflects their specific circumstances and the economics of their transactions;

companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects. Upon settlement of share-based payment awards, the tax effects will be recognized in the income statement or additional paid-in capital; and

public companies are allowed to select from three alternative transition methods – each having different reporting implications.

In April 2005, the Securities and Exchange Commission extended the effective date for public companies to implement SFAS No. 123R (revised 2004). The new Statement is now effective for non-small business entities starting with the first interim or annual period of the company’s first fiscal year beginning on or after June 15, 2005 (January 1, 2006, for us). Because we have used the fair-value method of accounting for stock-based compensation for pro forma disclosure under SFAS No. 123, we will apply SFAS No. 123R using a modified version of prospective application. Under this transition method, compensation cost is recognized on or after the required effective date for the portion of

outstanding awards for which the requisite service has not yet been rendered, based on the grant-date fair value of those awards calculated under SFAS No. 123 for pro forma disclosures. We estimate that the increased compensation cost resulting from expensing our employee stock options will result in a $0.02 and less than $0.01 decrease in earnings per diluted common share in 2006 and 2007, respectively. We have not issued employee stock options since 2004, and based on the current stock options outstanding, we expect the employee stock options will be completely expensed during 2007.

In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143. This Interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event.

Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred – generally upon acquisition, construction, or development and (or) through the normal operation of the asset. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for us). The implementation of this Interpretation had no impact on our financial position or results of operation.

In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. This Statement replaces Accounting Principles Board Opinion (“APB”) No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle.

SFAS No. 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. In contrast, APB No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle.

The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (January 1, 2006 for us). Earlier application is permitted for accounting changes and corrections of errors made occurring in fiscal years beginning after June 1, 2005. The Statement does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of this Statement. Adoption of this Statement will not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively.

In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. EITF 04-5 generally provides that a sole general partner is presumed to control a limited partnership and provides guidance

for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership.

For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). This issue will cause us to include the accounts and balances of Kinder Morgan Energy Partners and its majority-owned and controlled subsidiaries and its operating partnerships in our consolidated financial statements beginning with our Quarterly Report on Form 10-Q for the three months ended March 31, 2006.

We intend to prospectively apply EITF 04-5 using Transition Method A. The adoption of this pronouncement will have no impact on our consolidated stockholders’ equity. There will also be no impact on our debt covenants from the consolidation of Kinder Morgan Energy Partners because our $800 million credit facility was amended to exclude the effect of consolidating Kinder Morgan Energy Partners. See Note 12.

The adoption of this pronouncement will have the effect of increasing our consolidated operating revenues and expenses and consolidated interest expense beginning January 1, 2006. However, after recording the associated minority interests in Kinder Morgan Energy Partners, our net income and earnings per common share will not be affected. We estimate that the adoption of this pronouncement will impact our consolidated assets and liabilities as follows:

In February 2006 we entered into three fixed-to-floating interest rate swap agreements with notional principal amount of $375 million, $425 million and $275 million, respectively. These swaps effectively convert 50% of the interest expense associated with our 5.35% Senior Notes due 2011, 5.70% Senior Notes due 2016 and 6.40% Senior Notes due 2036, respectively, from fixed rates to floating rates based on the three-month LIBOR plus a credit spread. These swaps have been designated as fair value hedges

and will be accounted for utilizing the “shortcut” method prescribed for qualifying fair value hedges under Statement 133 and any unrealized gains or losses will be recognized in the balance sheet caption “Accumulated Other Comprehensive Loss” prospectively. As previously disclosed on March 10, 2006, we expect to recognize a one time non-cash, after-tax loss of approximately $14 million in the first quarter of 2006 from changes in the fair value of our three receive-fixed-rate, pay-variable rate U.S. dollar to Canadian dollar cross-currency interest rate swaps from January 1, 2006 to the termination of the agreements to reflect the strengthening of the Canadian dollar versus the U.S. dollar.

On January 13, 2006, Terasen Gas (Vancouver Island) Inc. entered into a five-year C$350 million unsecured committed revolving credit facility with a syndicate of banks. A portion of the facility was used to completely refinance Terasen Gas (Vancouver Island) Inc.’s existing term facility and intercompany advances from Terasen Inc. The facility will also be utilized to finance working capital requirements and for general corporate purposes. The terms and conditions are similar to those of the previous facility and common for such term credit facilities. Concurrently with executing this facility, Terasen Gas (Vancouver Island) Inc. entered into a C$20 million seven-year unsecured committed non-revolving credit facility with one bank. This facility will be utilized for purposes of refinancing any annual prepayments that Terasen Gas (Vancouver Island) Inc. may be required to make on non-interest bearing government contributions. The terms and conditions are primarily the same as the aforementioned Terasen Gas (Vancouver Island) Inc. facility except this facility ranks junior to repayment of Terasen Gas (Vancouver Island) Inc.’s Class B subordinated debt which is held by its parent company, Terasen Inc.

SELECTED QUARTERLY FINANCIAL DATA
KINDER MORGAN, INC. AND SUBSIDIARIES
Quarterly Operating Results for 2005

SELECTED QUARTERLY FINANCIAL DATA
KINDER MORGAN, INC. AND SUBSIDIARIES
Quarterly Operating Results for 2004

We do not directly have oil and gas producing activities, however, our equity method investee, Kinder Morgan Energy Partners, does have significant oil and gas producing activities. The Supplementary Information on Oil and Gas Producing Activities that follows is presented as required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities, and represents our proportionate interest in the oil and gas producing activities of Kinder Morgan Energy Partners. Our proportionate share of Kinder Morgan Energy Partners’ capitalized costs, costs incurred and results of operations from oil and gas producing activities consisted of the following:

Includes amounts relating to Kinder Morgan Energy Partners’ previous 15% ownership interest in MKM Partners, L.P., which Kinder Morgan Energy Partners accounted for under the equity method. MKM Partners, L.P. was dissolved on June 30, 2003.

Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations or declines based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.

The standardized measure of discounted cash flows is based on assumptions including year-end market pricing, future development and production costs and projections of future abandonment costs. A discount factor of 10% is applied annually to the future net cash flows.

The table below represents our proportionate share of Kinder Morgan Energy Partners’ (i) estimate of proved crude oil, natural gas liquids and natural gas reserves and (ii) standardized measure of discounted cash flows.

Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2005, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2005.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Terasen Inc. and its consolidated subsidiaries were excluded from the scope of our management’s assessment of internal control over financial reporting as of December 31, 2005 because these businesses were acquired by the Company in a purchase business combination during 2005. These businesses, in the aggregate, constituted 15% of our consolidated operating revenues for 2005 and 43% of our consolidated total assets at December 31, 2005.

There has been no change in our internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Certain information required by this item is contained in our Proxy Statement related to the 2006 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference. For information regarding our current executive officers, see “Executive Officers of the Registrant” in Part I.

Information required by this item is contained in our Proxy Statement related to the 2006 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference. Also see the discussion under “Other” within Items 1 and 2 (c) of this report and Note 5 of the accompanying Notes to Consolidated Financial Statements.

Reference is made to the index of financial statements and supplementary data under Item 8 in Part II.

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

The financial statements, including the notes thereto, of Kinder Morgan Energy Partners, an equity method investee of the Registrant, are incorporated herein by reference to pages 107 through 200 of Kinder Morgan Energy Partners’ Annual Report on Form 10-K for the year ended December 31, 2005.

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

Agreement and Plan of Merger, dated as of July 8, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-1 of K N Energy, Inc.’s Registration Statement on Form S-4 (File No. 333-85747))

First Amendment to Agreement and Plan of Merger, dated as of August 20, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-2 of K N Energy, Inc.’s Registration Statement on Form S-4 (File No. 333-85747))

Contribution Agreement, dated as of December 30, 1999, by and among Kinder Morgan, Inc., Natural Gas Pipeline Company of America, K N Gas Gathering, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. (Exhibit 99.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on January 14, 2000)

Combination Agreement, dated as of August 1, 2005, by and among Kinder Morgan, Inc., 0731297 B.C. Ltd. And Terasen Inc. (Exhibit 1.01 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on August 1, 2005)

Amended and Restated Articles of Incorporation of Kinder Morgan, Inc. and amendments thereto (Exhibit 3.1 to Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005)

Certificate of Designation of Kinder Morgan, Inc. Pursuant to Section 17-6401(g) of the Kansas General Corporation Code (Exhibit 3.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on October 25, 2005)

By-Laws of Kinder Morgan, Inc., as amended to January 18, 2006 (Exhibit 3.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on January 24, 2006)

Indenture dated as of September 1, 1988, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4(a) to Kinder Morgan, Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000)

First supplemental indenture dated as of January 15, 1992, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4.2 to the Registration Statement on Form S-3 (File No. 33-45091) of K N Energy, Inc. filed on January 17, 1992)

Second supplemental indenture dated as of December 15, 1992, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4(c) to Kinder Morgan, Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000)

Indenture dated as of November 20, 1993, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4.1 to the Registration Statement on Form S-3 (File No. 33-51115) of K N Energy, Inc. filed on November 19, 1993) Note — Copies of instruments relative to long-term debt in authorized amounts that do not exceed 10% of the consolidated total assets of Kinder Morgan, Inc. and its subsidiaries have not been furnished. Kinder Morgan, Inc. will furnish such instruments to the Commission upon request.

Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. dated May 18, 2001 (Exhibit 4.7 to Kinder Morgan, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002)

Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of August 21, 1995 (Exhibit 1 on Form 8-A dated August 21, 1995 (File No. 1-6446))

Amendment No. 1 to Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of September 8, 1998 (Exhibit 10(cc) to K N Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-6446))

Amendment No. 2 to Rights Agreement of Kinder Morgan, Inc. dated July 8, 1999, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as successor-in-interest to the Bank of New York, as Rights Agent (Exhibit 4.1 to Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999)

Form of Amendment No. 3 to Rights Agreement of Kinder Morgan, Inc. dated September 1, 2001, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as Rights Agent (Exhibit 4(m) to Kinder Morgan, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2001)

Form of Indenture dated as of August 27, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 (File No. 333-100338) filed on October 4, 2002)

Form of First Supplemental Indenture dated as of December 6, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 (File No. 333-102873) filed on January 31, 2003)

Form of 6.50% Note (contained in the Indenture incorporated by reference to Exhibit 4.12 hereto)

Form of Registration Rights Agreement dated as of December 6, 2002 among Kinder Morgan, Inc., Wachovia Securities, Inc., and Barclays Capital Inc. (filed as Exhibit 4.4 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 (File No. 333-102873) filed on January 31, 2003)

Form of certificate representing the common stock of Kinder Morgan, Inc. (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003)

Form of Senior Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan, Inc.’s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003)

Form of Senior Note of Kinder Morgan, Inc. (included in the Form of Senior Indenture incorporated by reference to Exhibit 4.16 hereto)

Form of Subordinated Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.4 to Kinder Morgan, Inc.’s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003)

Form of Subordinated Note of Kinder Morgan, Inc. (included in the Form of Subordinated Indenture incorporated by reference to Exhibit 4.18 hereto)

Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company, ULC, Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (Exhibit 4.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on December 15, 2005)

Certain instruments with respect to the long-term debt of Kinder Morgan, Inc. and its consolidated subsidiaries that relate to debt that does not exceed 10% of the total assets of Kinder Morgan, Inc. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan, Inc. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.

1994 Amended and Restated Kinder Morgan, Inc. Long-term Incentive Plan (Appendix A to Kinder Morgan, Inc.’s 2000 Proxy Statement on Schedule 14A)

Kinder Morgan, Inc. Amended and Restated 1999 Stock Plan (Appendix B to Kinder Morgan, Inc.’s 2004 Proxy Statement on Schedule 14A)

Kinder Morgan, Inc. Amended and Restated 1992 Stock Option Plan for Nonemployee Directors (Appendix A to Kinder Morgan, Inc.’s 2001 Proxy Statement on Schedule 14A)

2000 Annual Incentive Plan of Kinder Morgan, Inc. (Appendix D to Kinder Morgan, Inc.’s 2000 Proxy Statement on Schedule 14A)

Kinder Morgan, Inc. Employees Stock Purchase Plan (Appendix E to Kinder Morgan, Inc.’s 2000 Proxy Statement on Schedule 14A)

Form of Nonqualified Stock Option Agreement (Exhibit 10(f) to Kinder Morgan, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2000)

Form of Restricted Stock Agreement (Exhibit 10(g) to Kinder Morgan, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2000)

Directors and Executives Deferred Compensation Plan effective January 1, 1998 for executive officers and directors of K N Energy, Inc. (Exhibit 10(aa) to K N Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-6446))

Employment Agreement dated October 7, 1999, between the Company and Richard D. Kinder (Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November 16, 1999)

Form of Purchase Provisions between Kinder Morgan Management, LLC and Kinder Morgan, Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement of Kinder Morgan Management, LLC filed as Exhibit 4.2 to Kinder Morgan Management, LLC’s Registration Statement on Form 8-A/A filed on July 24, 2002)

Resignation and Non-Compete Agreement, dated as of July 21, 2004, between KMGP Services, Inc. and Michael C. Morgan (Exhibit 10.12 to Kinder Morgan, Inc.’s Form 10-Q for the quarter ended June 30, 2004)

Credit Agreement, dated as of August 5, 2005, by and among Kinder Morgan, Inc., the lenders party thereto, Citibank, N.A., as Administrative Agent and Swingline Lender, Wachovia Bank, National Association and JPMorgan Chase Bank, N.A., as Co-Syndication Agents and The Bank of Tokyo-Mitsubishi, Ltd. and Suntrust Bank, as Co-Documentation Agents (filed as Exhibit 10.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K, filed on August 11, 2005)

Amendment Number 1 to Credit Agreement, dated as of August 5, 2005, by and among Kinder Morgan, Inc., the lenders party thereto, Citibank, N.A., as Administrative Agent and Swingline Lender, Wachovia Bank, National Association and JPMorgan Chase Bank, N.A., as Co-Syndication Agents and The Bank of Tokyo-Mitsubishi, Ltd. and Suntrust Bank, as Co-Documentation Agents (Exhibit 10.2 to Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005)

Kinder Morgan, Inc. Non-Employee Directors Stock Awards Plan (Exhibit 10.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on May 13, 2005)

Form of Restricted Stock Agreement (Exhibit 10.2 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on May 13, 2005)

Form of Nonqualified Stock Option Agreement (Exhibit 10.3 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on May 13, 2005)

364-Day Credit Agreement dated as of November 23, 2005, by and among 1197774 Alberta ULC, as Borrower, Kinder Morgan, Inc., as Guarantor, the lenders party thereto, and Citibank, N.A., Canadian Branch, as Administrative Agent (Exhibit 10.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on November 30, 2005)

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries (incorporated by reference to pages 107 through 200 of the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2005)

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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


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


Title of each class		Name of each exchange on which registered
Common stock, par value $5 per share Purchase Obligation of Kinder Morgan Management, LLC shares		New York Stock Exchange New York Stock Exchange


	PART III
Item 10:	Directors and Executive Officers of the Registrant	167
Item 11:	Executive Compensation	167
Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	167
Item 13:	Certain Relationships and Related Transactions	167
Item 14:	Principal Accounting Fees and Services	167

	PART IV
Item 15:	Exhibits, Financial Statement Schedules	167-172

Signatures		173


	Year Ended December 31,
	2005				2004
	Amount		% of Total		Amount		% of Total
	(Dollars in thousands)
Investment in Kinder Morgan Energy Partners:
Equity in Earnings, Net of Kinder Morgan
Management Pre-tax Minority Interest	$	567,451	49.85	%	$	476,996		48.94	%
Segment Earnings:
NGPL		435,154	38.23	%		392,806		40.31	%
Kinder Morgan Canada		12,549	1.10	%		-		-	%
Terasen Gas		45,187	3.97	%		-		-	%
Kinder Morgan Retail		58,240	5.12	%		69,264		7.11	%
Power		19,693	1.73	%		15,255		1.56	%
TransColorado		-	-	%		20,255		2.08	%
Total	$	1,138,274	100.00	%	$	974,576		100.00	%


	Toll Per Barrel
	2005	2004
Edmonton to Burnaby	C$1.741	C$1.853
Edmonton to Sumas	C$1.560	C$1.667
US Mainline	US$0.30	US$0.30


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


			Page Number
	PART I
Items 1 and 2:	Business and Properties		5-31
		Business Strategy	7
		Developments During 2005	7
		Overview	9
		Natural Gas Pipeline Company of America	10
		Kinder Morgan Canada (Formerly Terasen Pipelines)	12
		Terasen Gas	15
		Kinder Morgan Retail	19
		Power	20
		Regulation	22
		Environmental Matters	28
		Safety and Environmental Protection	29
Item 1A:	Risk Factors		31
Item 1B:	Unresolved Staff Comments		36
Item 3:	Legal Proceedings		36
Item 4:	Submission of Matters to a Vote of Security Holders		36
Executive Officers of the Registrant			37-39

	PART II
Item 5:	Market for Registrant’s Common Equity, Related Stockholder
	Matters and Issuer Purchases of Equity Securities		40
Item 6:	Selected Financial Data		41-42
Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		43-79
		General	43
		Critical Accounting Policies and Estimates	44
		Consolidated Financial Results	48
		Results Of Operations	50
		Natural Gas Pipeline Company of America	52
		Kinder Morgan Canada (Formerly Terasen Pipelines)	55
		Terasen Gas	56
		Kinder Morgan Retail	57
		Power	59
		TransColorado	61
		Earnings from Our Investment in Kinder Morgan Energy Partners	62
		Other Income and (Expenses)	63
		Income Taxes – Continuing Operations	64
		Income Taxes – Realization of Deferred Tax Assets	64
		Discontinued Operations	65
		Liquidity and Capital Resources	65
		Investment in Kinder Morgan Energy Partners	73
		Cash Flows	74
		Litigation and Environmental Matters	76
		Regulation	77
		Recent Accounting Pronouncements	77
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk		79-84
Item 8:	Financial Statements and Supplementary Data		85-164
Item 9:	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		165
Item 9A:	Controls and Procedures		165
	Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures		165
	Management’s Report on Internal Control Over Financial Reporting		165
	Changes in Internal Control over Financial Reporting		166
Item 9B:	Other Information		166


	(bpd)
Delivery Point:	2005	2004
Vancouver (crude petroleum)	42,482	48,729
Vancouver (refined petroleum)	60,634	64,438
Kamloops (refined petroleum)	20,366	22,415
Westridge Marine Terminal	22,782	8,837
Washington State refineries	74,622	91,696
	220,886	236,115


	Toll Per Barrel (US$)
	2005		2004
Hardisty, Alberta to Casper, Wyoming	$	1.552	$	1.552
Hardisty, Alberta to Casper, Wyoming (committed)	$	1.287	$	1.263
Casper, Wyoming to Wood River, Illinois	$	1.410	$	1.170


	Year ended December 31,
	2006			2005			2004			2003
	(Canadian dollar amounts in millions)
Rate base	$	2,506		$	2,306		$	2,310		$	2,281
Deemed common equity component of total capital structure		35	%		33	%		33	%		33	%
Allowed rate of return on common equity		8.80	%		9.03	%		9.15	%		9.42	%


	Market Price Per Share
	2005		2004
	Low	High	Low	High
Quarter Ended:
March 31	$69.27	$81.57	$58.37	$64.62
June 30	$72.49	$83.97	$56.85	$64.25
September 30	$81.82	$99.97	$58.06	$62.99
December 31	$84.10	$96.28	$62.04	$73.82


	Dividends Paid Per Share
	2005	2004
Quarter Ended:
March 31	$0.7000	$0.5625
June 30	$0.7000	$0.5625
September 30	$0.7500	$0.5625
December 31	$0.7500	$0.5625

Stockholders as of February 10, 2006	126,000 (approximately)


Period	Total Number of Shares Purchased¹		Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs²		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to October 31, 2005		490,600		$	89.18		490,600		$	1,902,093
November 1 to November 30, 2005		688,700		$	89.68		688,700		$	65,125,113
December 1 to December 31, 2005		166,600		$	92.76		166,600		$	49,668,787

Total		1,345,900		$	89.88		1,345,900		$	49,668,787


	Year Ended December 31,
	2005(2)		2004			2003		2002			2001
	(In thousands except per share amounts)
Operating Revenues	$	1,585,772	$	1,164,933		$	1,097,897	$	1,015,255		$	1,054,907
Gas Purchases and Other Costs of Sales		662,962		349,564			354,261		311,224			339,301
Other Operating Expenses(3)		450,537		417,441			387,543		467,364			331,287
Operating Income		472,273		397,928			356,093		236,667			384,319
Other Income and (Expenses)		440,770		357,293			270,211		206,063			308
Income from Continuing Operations
Before Income Taxes		913,043		755,221			626,304		442,730			384,627
Income Taxes		360,873		226,717			244,600		135,019			159,557
Income from Continuing Operations		552,170		528,504			381,704		307,711			225,070
Gain (Loss) from Discontinued Operations,
Net of Tax		2,449		(6,424	)		-		(4,986	)		-
Net Income	$	554,619	$	522,080		$	381,704	$	302,725		$	225,070

Basic Earnings (Loss) Per Common Share:
Continuing Operations	$	4.47	$	4.27		$	3.11	$	2.52		$	1.95
Discontinued Operations		0.02		(0.05	)		-		(0.04	)		-
Total Basic Earnings Per Common Share	$	4.49	$	4.22		$	3.11	$	2.48		$	1.95

Number of Shares Used in Computing
Basic Earnings (Loss) Per Common Share		123,465		123,778			122,605		122,184			115,243

Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$	4.43	$	4.23		$	3.08	$	2.49		$	1.86
Discontinued Operations		0.02		(0.05	)		-		(0.04	)		-
Total Diluted Earnings Per Common Share	$	4.45	$	4.18		$	3.08	$	2.45		$	1.86

Number of Shares Used in Computing
Diluted Earnings (Loss) Per
Common Share		124,642		124,938			123,824		123,402			121,326

Dividends Per Common Share	$	2.90	$	2.25		$	1.10	$	0.30		$	0.20

Capital Expenditures(4)	$	187,404	$	164,242		$	160,804	$	174,953		$	124,171


	As of December 31,
	2005(1)				2004					2003					2002					2001
	(In thousands except per share amounts)
Total Assets	$	17,451,614				$	10,116,901				$	10,036,711				$	10,102,750				$	9,513,121

Capitalization:
Common Equity(2)	$	4,051,356	34	%		$	2,919,496	45	%		$	2,691,800	39	%		$	2,399,716	37	%		$	2,250,129	39	%
Deferrable Interest Debentures(3)		283,600	2	%			283,600	4	%			283,600	4	%			-	-				-	-
Capital Securities		107,137	1	%			-	-				-	-				-	-				-	-
Preferred Capital Trust Securities(3)		-	-				-	-				-	-				275,000	4	%			275,000	5	%
Minority Interests		1,247,322	10	%			1,105,436	17	%			1,010,140	15	%			967,802	15	%			817,513	14	%
Outstanding Notes and Debentures(4)		6,286,796	53	%			2,257,950	34	%			2,837,487	42	%			2,852,181	44	%			2,409,798	42	%
Total Capitalization	$	11,976,211	100	%		$	6,566,482	100	%		$	6,823,027	100	%		$	6,494,699	100	%		$	5,752,440	100	%

Book Value Per Common Share	$	29.34				$	23.19				$	21.62				$	19.35				$	18.24


Business Segment	Business Conducted	Referred to As:

Natural Gas Pipeline Company of America and certain affiliates	The ownership and operation of a major interstate natural gas pipeline and storage system	Natural Gas Pipeline Company of America, or NGPL
Petroleum Pipelines	The ownership and operation of crude and refined petroleum pipelines	Kinder Morgan Canada
Terasen Natural Gas Distribution	The regulated sale and transportation of natural gas to residential, commercial and industrial customers in British Columbia, Canada	Terasen Gas
Kinder Morgan Retail Natural Gas Distribution	The regulated sale and transportation of natural gas to residential, commercial and industrial customers in Nebraska, Wyoming and Colorado, the sales of natural gas to certain utility customers under the Choice Gas program and the operation of a small distribution system in Hermosillo, Mexico	Kinder Morgan Retail
Power Generation	The ownership and operation and, in previous periods, development and construction of natural gas-fired electric generation facilities	Power
TransColorado Gas Transmission Company	Prior to its disposition on November 1, 2004, the ownership and operation of an interstate natural gas pipeline system in Colorado and New Mexico	TransColorado


	Month Ended December 31, 2005
	(In thousands)
Operating Revenues		$	18,941

Segment Earnings		$	12,549


	December 31,
	2005			2004			2003
	(Dollars in thousands)
Long-term Debt:
Outstanding Notes and Debentures	$	6,286,796		$	2,257,950		$	2,837,487
Deferrable Interest Debentures Issued to Subsidiary Trusts		283,600			283,600			283,600
Capital Securities		107,137			-			-
Value of Interest Rate Swaps¹		51,831			88,243			88,242
		6,729,364			2,629,793			3,209,329
Minority Interests		1,247,322			1,105,436			1,010,140
Common Equity, Excluding Accumulated Other Comprehensive Loss		4,051,356			2,919,496			2,691,800
		12,028,042			6,654,725			6,911,269
Less Value of Interest Rate Swaps		(51,831	)		(88,243	)		(88,242	)
Capitalization		11,976,211			6,566,482			6,823,027
Short-term Debt, Less Cash and Cash Equivalents²		841,320			328,480			121,824
Invested Capital	$	12,817,531		$	6,894,962		$	6,944,851

Capitalization:
Outstanding Notes and Debentures		52.5%			34.4%			41.6%
Minority Interests		10.4%			16.8%			14.8%
Common Equity		33.8%			44.5%			39.4%
Deferrable Interest Debentures Issued to Subsidiary Trusts		2.4%			4.3%			4.2%
Capital Securites		0.9%			-%			-%

Invested Capital:
Total Debt³		55.6%			37.5%			42.6%
Common Equity, Excluding Accumulated Other Comprehensive Loss and Including Deferrable Interest Debentures Issued to Subsidiary Trusts, Capital Securities and Minority Interests		44.4%			62.5%			57.4%


	At December 31, 2005
Entity	Investment Amount			Investment Percent			Entity Assets¹		Entity Debt			Incremental Investment Obligation			Our Debt Responsibility
	(Millions of Dollars)
Ft. Lupton Power Plant	$	147.1	²		49.5	%	$	133.6	$	79.1	³		-			$	-

Express System		431.9			33.3	%		744.1		428.1			-				-

CustomerWorks LP		44.0			30.0	%		102.4		-			-				-

Horizon Pipeline Company		17.3			50.0	%		85.9		49.5	³		-				-

Kinder Morgan Energy Partners		3,062.3			15.2	%		11,923.5		5,319.4	⁵		-	⁴			733.5	⁵


			Amount of Commitment Expiration Per Period
	Total		Less than 1 year		2-3 years		4-5 years		After 5 years
	(In millions)
Contractual Obligations:
Long-term Debt, Including Current Maturities:
Principal Payments	$	7,004.3	$	347.4	$	861.6	$	221.9	$	5,573.4
Interest Payments¹		6,675.2		440.8		829.2		736.0		4,669.2
Capital Lease Obligations²		7.5		1.5		3.0		3.0		-
Operating Leases³		777.5		47.2		90.2		82.8		557.3
Gas Purchase Contracts⁴		947.3		790.9		128.0		28.4		-
Other Long-term Obligations		39.1		1.1		2.5		2.9		32.6
Pension and Postretirement Benefit Plans⁵
Total Contractual Cash Obligations	$	15,450.9	$	1,628.9	$	1,914.5	$	1,075.0	$	10,832.5

Other Commercial Commitments:
Standby Letters of Credit⁶	$	183.6		183.6	$	-	$	-	$	-
Capital Expenditures⁷	$	100.0		100.0	$	-	$	-	$	-


Contingent Liabilities:	Contingency	Amount of Contingent Liability at December 31, 2005
Guarantor of the Bushton Gas Processing Plant Lease¹	Default by ONEOK, Inc.	Total $164.9 million; Averages $23 million per year through 2012
Jackson, Michigan Power Plant Incremental Investment	Operational Performance	$3 to 8 million per year for 13 years
Jackson, Michigan Power Plant Incremental Investment	Cash Flow Performance	Up to a total of $25 million beginning in 2018


	Page

Report of Independent Registered Public Accounting Firm	86-87
Consolidated Statements of Operations	88
Consolidated Statements of Comprehensive Income	89
Consolidated Balance Sheets	90
Consolidated Statements of Stockholders’ Equity	91
Consolidated Statements of Cash Flows	92-93
Notes to Consolidated Financial Statements	94-161
Selected Quarterly Financial Data (Unaudited)	162-163
Supplementary Information on Oil and Gas Producing
Activities (Unaudited)	164


Item 8: Financial Statements and Supplementary Data (continued)	KMI Form 10-K


Property Type		Range of Estimated Useful Lives of Assets
		(In years)
Natural Gas Pipelines		24 to 68 (Transmission assets: average 55)
Petroleum Pipelines		17 to 45
Retail Natural Gas Distribution		5 to 66
Power Generation		4 to 30
General and Other		3 to 56


¹	For options granted under the 1992 Directors’ Plan in January 2004, the expected weighted-average life was 4.4 years and the volatility assumption was 0.33. For options granted under the 1992 Directors’ Plan in July 2004, the expected weighted-average life was 5.0 years and the volatility assumption was 0.32.
²	The assumptions used for employee options granted in 2003 varied based on date of grant. For options granted under the 1992 Directors’ Plan, the expected weighted-average life was 4.1 years and the volatility assumption was 0.45.


	Summarized Income Statement Information Year Ended December 31,
	2005		2004		2003
	(In thousands)
Operating Revenues	$	9,787,128	$	7,932,861	$	6,624,322
Operating Expenses		8,773,606		6,958,865		5,817,633
Operating Income	$	1,013,522	$	973,996	$	806,689

Income Before Cumulative Effect of a Change in Accounting Principle	$	812,227	$	831,578	$	693,872

Net Income	$	812,227	$	831,578	$	697,337


	Summarized Balance Sheet Information As of December 31,
	2005		2004
	(In thousands)
Current Assets	$	1,215,224	$	853,171
Noncurrent Assets	$	10,708,238	$	9,699,771
Current Liabilities	$	1,808,885	$	1,180,855
Noncurrent Liabilities	$	6,458,506	$	5,429,921
Minority Interest	$	42,331	$	45,646


The Total Purchase Price Consisted of the Following:	(In thousands)
Total Market Value of Kinder Morgan, Inc. Common Shares Issued	$	1,146,759
Cash Paid – U.S. Dollar Equivalent		2,134,291
Transaction Fees		14,500
Total Purchase Price	$	3,295,550


The Preliminary Allocation of the Purchase Price is as Follows:	(In thousands)
Current Assets	$	812,860
Goodwill		1,890,524
Investments		504,827
Property, Plant and Equipment		3,683,492
Deferred Charges and Other Assets		602,279
Current Liabilities		(1,502,841	)
Deferred Income Taxes		(680,531	)
Other Deferred Credits		(258,300	)
Long-term Debt		(1,756,760	)
	$	3,295,550


Preliminary Allocation of Goodwill:	(In thousands)
Terasen Gas	$	1,234,428
Kinder Morgan Canada		656,096
	$	1,890,524


	For the Year Ended December 31, 2005
Income Statement Data
Operating Revenues		$	8,817
Loss from Discontinued Operations, Net of Tax of $309		$	(711	)

	As of December 31, 2005
Balance Sheet Data
Current Assets:
Cash		$	9
Accounts Receivable, Net			27,153
Inventories			15,483
Other Current Assets			667
			43,312
Non-current Assets:
Property, Plant and Equipment, Net			25,624
Goodwill			20,428
Other Investments			33,561
Deferred Charges and Other Assets			3,724
			83,337

Total Assets of Discontinued Operations		$	126,649

Current Liabilities:
Accounts Payable			18,852
Accrued Taxes			404
			19,256
Non-current Liabilities:
Long-term Debt			317
Deferred Income Taxes Payable			202
Other Deferred Credits			2,136
			2,655

Total Liabilities of Discontinued Operations		$	21,911


	December 31, 2005
	Property, Plant and Equipment			Accumulated D&A			Net
	(In thousands)
Natural Gas Pipelines		$	6,833,529		$	481,583		$	6,351,946
Petroleum Pipelines			1,109,467			3,511			1,105,956
Retail Natural Gas Distribution			1,840,153			156,095			1,684,058
Electric Power Generation			39,220			9,786			29,434
General and Other			451,920			77,680			374,240
PP&E Related to Continuing Operations		$	10,274,289		$	728,655		$	9,545,634


	December 31, 2004
	Property, Plant and Equipment			Accumulated D&A			Net
	(In thousands)
Natural Gas Pipelines		$	5,880,944		$	401,537		$	5,479,407
Retail Natural Gas Distribution			376,364			143,574			232,790
Electric Power Generation			39,220			8,324			30,896
General and Other			188,174			79,302			108,872
PP&E Related to Continuing Operations		$	6,484,702		$	632,737		$	5,851,965


	Commodity Contracts			Over the Counter Swaps and Options Contracts				Total
	(Dollars in thousands)
Deferred Net Gain (Loss)	$	(48,063	)		$	11,657		$	(36,406	)
Contract Amounts — Gross	$	136,348			$	116,285		$	252,633
Contract Amounts — Net	$	(134,296	)		$	(10,955	)	$	(145,251	)

	(Number of contracts¹)
Natural Gas
Notional Volumetric Positions: Long		13				466			479
Notional Volumetric Positions: Short		(1,766	)			(614	)		(2,380	)
Net Notional Totals to Occur in 2006		(1,753	)			(83	)		(1,836	)
Net Notional Totals to Occur in 2007 and Beyond		-				(65	)		(65	)
Crude Oil
Notional Volumetric Positions: Long		-				-			-
Notional Volumetric Positions: Short		-				(19	)		(19	)
Net Notional Totals to Occur in 2006		-				(19	)		(19	)
Net Notional Totals to Occur in 2007 and Beyond		-				-			-
Natural Gas Liquids
Notional Volumetric Positions: Long		-				-			-
Notional Volumetric Positions: Short		-				-			-
Net Notional Totals to Occur in 2006		-				-			-
Net Notional Totals to Occur in 2007 and Beyond		-				-			-