8-K

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


FORM 8-K


CURRENT REPORT

Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  November 13, 2006

KINDER MORGAN, INC.
(Exact name of registrant as specified in its charter)

Kansas
(State or other jurisdiction
of incorporation)
1-06446
(Commission
File Number)
48-0290000
(I.R.S. Employer
Identification No.)

500 Dallas Street, Suite 1000
Houston, Texas 77002
(Address of principal executive offices, including zip code)


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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01.  Other Events.

As previously disclosed, on August 14, 2006, Kinder Morgan, Inc. announced it will sell its natural gas retail distribution and related operations in Colorado, Nebraska, Wyoming and Hermosillo, Mexico, to GE Energy Financial Services for $710 million plus working capital. The transaction is subject to certain closing conditions and regulatory approvals, including approvals from state utility commissions. Accordingly, in Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2006, these U.S.-based natural gas distribution operations, which we sometimes refer to as Kinder Morgan Retail, were reflected as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. We have revised the information set forth in Exhibit 99.1 hereto to reflect Kinder Morgan Retail as discontinued operations for all periods presented in that Exhibit. A copy of these revised financial statements as of December 31, 2004 and 2005, and for each of the three years in the period ended December 31, 2005, including selected financial data as of and for each of the five years in the period ended December 31, 2005, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures about Market Risk, is attached hereto as Exhibit 99.1 and incorporated herein by reference.

Item 9.01.  Financial Statements and Exhibits.

(c)

Exhibits.

12.1

Statement re: computation of ratio of earnings to fixed charges

23.1

Consent of PricewaterhouseCoopers LLP

99.1

Revised financial statements as of December 31, 2004 and 2005, and for each of the three years in the period ended December 31, 2005, including selected financial data as of and for each of the five years in the period ended December 31, 2005, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures about Market Risk.

S I G N A T U R E

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

KINDER MORGAN, INC.

Dated: November 13, 2006	By:	/s/ Joseph Listengart
		Joseph Listengart Vice President and General Counsel

EXHIBIT INDEX

Exhibit Number	Description
12.1	Statement re: computation of ratio of earnings to fixed charges
23.1	Consent of PricewaterhouseCoopers LLP
99.1	Revised financial statements as of December 31, 2004 and 2005, and for each of the three years in the period ended December 31, 2005, including selected financial data as of and for each of the five years in the period ended December 31, 2005, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures about Market Risk.

EX-12.1

Exhibit 12.1

KINDER MORGAN, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(In US$ millions, except ratio of earnings to fixed charges)

	Nine Months Ended September 30,				Year Ended December 31,
	2006		2005		2005		2004		2003		2002		2001
Earnings:
Income from continuing operations before income taxes, extraordinary gains or losses, equity income and minority interest1	$	875.5	$	176.7	$	304.2	$	194.4	$	161.8	$	58.0	$	136.3
Add:
Fixed charges		648.0		137.0		210.0		164.2		164.2		188.4		246.1
Distributed income of equity investees		60.9		395.0		538.9		445.0		374.7		314.2		238.8
Less:
TRUPS requirement2		-		-		-		-		11.0		21.9		21.9
Capitalized interest from continuing operations1		19.2		0.5		1.3		0.7		0.5		1.4		4.2
Capitalized interest from discontinued operations		0.9		0.1		0.2		0.3		0.1		0.4		0.6
Minority interest in pre-tax income of  subsidiary with no fixed charges		46.6		46.4		45.0		50.4		41.5		33.8		14.8
Earnings as adjusted	$	1,517.7	$	661.7	$	1,006.6	$	752.2	$	647.6	$	503.1	$	579.7
Fixed Charges:
Interest, amortization of debt discount, premium and issuance costs1	$	592.6	$	122.5	$	188.9	$	147.2	$	143.5	$	153.7	$	206.0
Add:
Capitalized interest from continuing operations1		19.2		0.5		1.3		0.7		0.5		1.4		4.2
Capitalized interest from discontinued operations		0.9		0.1		0.2		0.3		0.1		0.4		0.6
Interest expense from discontinued operations		7.0		8.1		11.3		7.9		7.1		8.2		10.2
Estimated interest portion of rental expenses		28.3		5.8		8.3		8.1		2.0		2.8		3.2
TRUPS requirement2		-		-		-		-		11.0		21.9		21.9
Fixed Charges	$	648.0	$	137.0	$	210.0	$	164.2	$	164.2	$	188.4	$	246.1
Ratio of Earnings to Fixed Charges		2.34		4.83		4.79		4.58		3.94		2.67		2.36

^1.

During 2006, we entered into a definitive agreement to sell our U.S.-based natural gas distribution operations. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been excluded and reclassified to discontinued operations for all periods presented. In addition, the results of operations of Terasen’s discontinued Water and Utility Services, which we acquired November 30, 2005, have been excluded and reclassified to discontinued operations for the nine months ended September 30, 2006 and the year ended December 31, 2005.

^2.

The expense associated with our capital trust securities was included in minority interest prior to the third quarter of 2003. Due to our adoption of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and our subsequent adoption of Financial Accounting Standards Board Interpretation No. 46 (revised December 2004), Consolidation of Variable Interest Entities, the expense associated with these securities was included in interest expense beginning with the third quarter of 2003.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on (i) Form S-16 (Nos. 2-51894, 2-55664, 2-63470 and 2-75654), (ii) Form S-8 (Nos. 2-77752, 33-10747, 33-24934, 33-33018, 33-54403, 33-54443, 33-54555, 333-08059, 333-08087, 333-60839, 333-42178, 333-53908, 333-74864, 33-46999, 333-122345, 333-104264, and 333-132462), (iii) Form S-3 (Nos. 2-84910, 33-26314, 33-23880, 33-42698, 33-44871, 33-45091, 33-54317, 33-69432, 333-04385, 333-40869, 333-44421, 333-55921, 333-68257, 333-54896, 333-55866, 333-91257, 333-91316-02, 333-102963, 333-102962-02, 333-122555-01 , 333-123408-01 and 333-129033-01 ), and (iv) Form S-4 (Nos. 333-102873 and 333-130582-01 ) of Kinder Morgan, Inc. of our report dated March 13, 2006, except as to Note 7, for which the date is November 9, 2006, relating to the financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the ef fectiveness of internal control over financial reporting, which appears in this Current Report on Form 8-K.

PricewaterhouseCoopers LLP

Houston, Texas

November 13, 2006

EX-99.1

Exhibit 99.1

Table of Contents

Item*	Description	Page
6.	Selected Financial Data	1-2
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	3-28
7A.	Quantitative and Qualitative Disclosures about Market Risk	29-32
8.	Financial Statements and Supplementary Data	33-97

______________

*Item number corresponds to the similar item number in the Company’s Form 10-K for the year ended December 31, 2005.

Item 6.

Selected Financial Data.

Five-Year Review

Kinder Morgan, Inc. and Subsidiaries(1)

	Year Ended December 31,
	2005(2)		2004		2003		2002		2001
	(In thousands except per share amounts)
Operating Revenues	$	1,254,527	$	877,737	$	848,778	$	755,506	$	748,398
Gas Purchases and Other Costs of Sales		458,785		194,244		232,057		164,698		152,121
Other Operating Expenses(3)		371,853		342,483		316,560		397,807		262,494
Operating Income		423,889		341,010		300,161		193,001		333,783
Other Income and (Expenses)		451,479		365,187		281,562		214,429		17,926
Income from Continuing Operations Before Income Taxes		875,368		706,197		581,723		407,430		351,709
Income Taxes		345,509		208,024		225,082		121,839		146,948
Income from Continuing Operations		529,859		498,173		356,641		285,591		204,761
Income from Discontinued Operations, Net of Tax(4)		24,760		23,907		25,063		17,134		20,309
Net Income	$	554,619	$	522,080	$	381,704	$	302,725	$	225,070
Basic Earnings Per Common Share:
Continuing Operations	$	4.29	$	4.03	$	2.91	$	2.34	$	1.78
Discontinued Operations		0.20		0.19		0.20		0.14		0.17
Total Basic Earnings Per Common Share	$	4.49	$	4.22	$	3.11	$	2.48	$	1.95
Number of Shares Used in Computing Basic Earnings Per Common Share		123,465		123,778		122,605		122,184		115,243
Diluted Earnings Per Common Share:
Continuing Operations	$	4.25	$	3.99	$	2.88	$	2.31	$	1.69
Discontinued Operations		0.20		0.19		0.20		0.14		0.17
Total Diluted Earnings Per Common Share	$	4.45	$	4.18	$	3.08	$	2.45	$	1.86
Number of Shares Used in Computing Diluted Earnings 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(5)	$	144,507	$	103,204	$	131,988	$	149,558	$	88,572

(1)

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.

(2)

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.

(3)

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.

(4)

See Note 7 of the accompanying Notes to Consolidated Financial Statements for information regarding discontinued operations.

(5)

Capital Expenditures shown are for continuing operations only.

1

Item 6.

Selected Financial Data. (continued)

Five-Year Review (Continued)

Kinder Morgan, Inc. and Subsidiaries

	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

___________

(1)

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.

(2)

Excluding Accumulated Other Comprehensive Income/Loss.

(3)

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.

(4)

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:

	Year Ended December 31,
	2005		2004		2003		2002		2001
	(In thousands, except per share amounts)
Reported Net Income	$	554,619	$	522,080	$	381,704	$	302,725	$	225,070
Add Back: Goodwill Amortization,
Net of Related Tax Benefit		-		-		-		-		16,198
Adjusted Net Income	$	554,619	$	522,080	$	381,704	$	302,725	$	241,268
Reported Earnings per Diluted Share	$	4.45	$	4.18	$	3.08	$	2.45	$	1.86
Earnings per Diluted Share, as Adjusted	$	4.45	$	4.18	$	3.08	$	2.45	$	1.99

2

Item 7.

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

General

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes. Specifically, as discussed in Notes 4, 5 and 7 of the accompanying Notes to Consolidated Financial Statements, we have engaged in acquisitions, including the 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, prior to the reclassification of certain of our retail natural gas distribution facilities to discontinued operations as discussed following, during 2006, were 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 and investments in natural gas-fired power generation facilities. Our U.S.-based natural gas distribution facilities have been reclassified to discontinued operations in all periods presented as a result of our definitive agreement, entered into during 2006, to dispose of these operations. See Note 7 of the accompanying Notes to Consolidated Financial Statements. In November 2005, we acquired Terasen (operations acquired with Terasen were budgeted to contribute approximately 26% of the total of our 2006 segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners prior to the reclassification of our U.S.-based retail natural gas operations, which 26% 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 reside ntial, commercial and industrial customers in British Columbia, Canada. Our investment in Kinder Morgan Energy Partners (which, during 2006, was budgeted to contribute approximately 39% of the total of our segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners prior to the reclassification of our U.S.-based retail natural gas distribution operations) 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” under Item 1 in our Annual Report on Form 10-K for the year ended December 31, 2005 (the “2005 10-K”), our strategy and focus continues to be on ownership of fee-based energy-related assets that 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” in our 2005 10-K.

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” in our 2005 10-K. 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 continuing businesses (apart from our investment in Kinder Morgan Energy Partners) constitute four 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.

3

Item 7.

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

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, and (iii) Power, our investment in, in some cases, operation of, and in previous periods construction of electric power generation facilities. 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. During 2006, we announced a definitive agreement to dispose of our U.S.-based natural gas distribution operations, see Note 7 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 four current business segments, we will report the following business segments: (1) Products Pipelines, (2) Natural Gas Pipelines, (3) CO₂ and (4) Terminals.

Critical Accounting Policies and Estimates

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 sig nificantly 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 (which, for our U.S.-based operations, has been reclassified to discontinued operations for all periods presented as discussed in Note 7 of the accompanying Notes to Consolidated Financial Statements), 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 var iations 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 asse ssing 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.

4

Item 7.

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

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 and without adjustment for the change in these amounts that would be attributable to the expected disposition of our U.S.-based natural gas distribution operations), 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, and without adjustment for the expected disposition of our U.S.-based natural gas distribution operations as discussed preceding, 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) related to regulated business activities where the risk is passed through to customers and accordingly th e 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.

5

Item 7.

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

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.

Consolidated Financial Results

	Year Ended December 31,
	2005			2004			2003
	(In thousands except per share amounts)
Operating Revenues4, 7	$	1,254,527		$	877,737		$	848,778
Gas Purchases and Other Costs of Sales		(458,785	)		(194,244	)		(232,057	)
General and Administrative Expenses7		(72,334	)		(67,673	)		(62,191	)
Other Operating Expenses4		(299,519	)		(274,810	)		(254,369	)
Operating Income		423,889			341,010			300,161
Other Income and (Expenses)1, 2, 3, 5, 6, 7, 9		451,479			365,187			281,562
Income Taxes10		(345,509	)		(208,024	)		(225,082	)
Income from Continuing Operations		529,859			498,173			356,641
Income from Discontinued Operations, Net of Tax8		24,760			23,907			25,063
Net Income	$	554,619		$	522,080		$	381,704
Diluted Earnings Per Common Share:
Income from Continuing Operations	$	4.25		$	3.99		$	2.88
Income from Discontinued Operations		0.20			0.19			0.20
Total Diluted Earnings Per Common Share	$	4.45		$	4.18		$	3.08
Number of Shares Used in Computing Diluted Earnings Per Common Share		124,642			124,938			123,824

¹

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.

²

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.

³

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.

⁴

Includes pre-tax charges of $6.5 million ($4.1 million after tax), $15.0 million ($9.4 million after tax) net of the recognition of deferred power development revenues and the impact of the resolution of certain litigation contingencies 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.

⁵

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

⁶

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

⁷

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.

6

Item 7.

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

⁸

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.

⁹

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.

¹⁰

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 $498.2 million in 2004 to $529.9 million in 2005, an increase of $31.7 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 $86.8 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) increased interest expense due to higher interest rates, interest e xpense on Terasen’s existing debt and interest expense on incremental debt issued to acquire Terasen, (iii) increased general and administrative expenses due principally to the general and administrative costs of Terasen and (iv) increased income taxes.

Operating revenues increased by $376.8 million (43%) from 2004 to 2005 due largely to (i) revenues from the Terasen assets and (ii) increased revenues in our NGPL business segment. 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 $356.6 million in 2003 to $498.2 million in 2004, an increase of $141.6 million (40%). 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 business segment 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 $29.0 million (3%) from 2003 to 2004 reflecting, in addition to the incr emental power development revenues discussed in the table above, 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 $3.99 in 2004 to $4.25 in 2005, an increase of $0.26 (6.5%). 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 ac companying 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 $2.88 in 2003 to $3.99 in 2004, an increase of $1.11 (38.5%). 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%).

7

Item 7.

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

Results of Operations

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) Power, the operation and, in previous periods, construction of natural gas-fired electric generation facilities and (v) prior to its sale as dis cussed 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 have now discontinued (see Note 7 of the accompanying Notes to Consolidated Financial Statements) and in December 2005, we discontinued the water and utility services businesses acquired with Terasen. In 2006, we entered into a definitive agreement to sell our U.S.-based natural gas distribution operations, which were historically reported as the Kinder Morgan Retail segment and are now included in discontinued operations (See Note 7 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 four 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 four 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.

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
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

In the fourth quarter of 2002, as further discussed under “Power” following, we decided to discontinue the development

8

Item 7.

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

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.

Natural Gas Pipeline Company of America

	Year Ended December 31,
	2005		2004		2003
	(In thousands except systems throughput)
Operating Revenues	$	947,349	$	778,877	$	784,732
Gas Purchases and Other Costs of Sales	$	299,154	$	188,757	$	226,599
Segment Earnings	$	435,154	$	392,806	$	372,017
Systems Throughput (Trillion Btus)		1,664.8		1,539.6		1,498.6

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 ef fective 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 utiliz ation 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)

9

Item 7.

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

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 t he 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 contracte d 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 informat ion 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

10

Item 7.

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

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.

Kinder Morgan Canada (Formerly Terasen Pipelines)

	Month Ended December 31, 2005
	(In thousands)
Operating Revenues		$	18,941
Segment Earnings		$	12,549

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 diamet er 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.

11

Item 7.

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

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 Envir onment 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.

Terasen Gas

	Month Ended December 31, 2005
	(In thousands)
Operating Revenues		$	223,322
Gas Purchases and Other Costs of Sales		$	156,157
Segment Earnings		$	45,187

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.

12

Item 7.

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

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.

Power

	Year Ended December 31,
	2005		2004		2003
	(In thousands)
Operating Revenues	$	54,166	$	70,064	$	31,849
Gas Purchases and Other Costs of Sales	$	3,474	$	4,710	$	4,850
Segment Earnings1	$	19,693	$	15,255	$	22,076

________

¹

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 Consolid ated 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.

In February 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading agreed to supply natural gas to and market capacity for 16 years for a 550-megawatt natural gas-fired Orion technology electric power plant in Jackson, Michigan. Effective July 1, 2002, construction of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC (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. 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

13

Item 7.

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

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 o f 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 interes t 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.

14

Item 7.

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

TransColorado

	Year Ended December 31,
	2004		2003
	(In thousands)
Operating Revenues	$	28,795	$	32,197
Gas Purchases and Other Costs of Sales	$	777	$	608
Segment Earnings	$	20,255	$	23,112

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.

Earnings from Our Investment in Kinder Morgan Energy Partners

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

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
General Partner Interest, Including Minority    Interest in the Operating Limited Partnerships	$	484,618		$	403,535		$	333,675
Limited Partner Units (Kinder Morgan    Energy Partners)		32,333			41,061			36,516
Limited Partner i-units (Kinder Morgan Management)		88,448			113,482			94,776
		605,399			558,078			464,967
Pre-tax Minority Interest in Kinder Morgan    Management		(70,572	)		(81,082	)		(66,642	)
Pre-tax Earnings from Investment in Kinder        Morgan Energy Partners1	$	534,827		$	476,996		$	398,325

________

¹

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.

15

Item 7.

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

Other Income and (Expenses)

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Interest Expense, Net1	$	(166,275	)	$	(125,303	)	$	(132,513	)
Interest Expense – Deferrable Interest Debentures2		(21,912	)		(21,912	)		-
Interest Expense – Capital Securities		(712	)		-			-
Interest Expense – Capital Trust Securities2		-			-			(10,956	)
Equity in Earnings of Kinder Morgan Energy Partners3		605,399			558,078			464,967
Equity in Earnings of Power Segment4		11,552			8,537			8,839
Equity in Earnings of Horizon Pipeline		1,715			1,615			1,501
Equity in Earnings of Express Pipeline		2,000			-			-
Other Equity in Earnings (Losses)5		975			-			(2,882	)
Minority Interests2, 3		(50,457	)		(56,420	)		(52,493	)
Net Gains (Losses) from Sales of Assets6, 1		79,053			1,972			(130	)
Contribution to Kinder Morgan Foundation7		(15,000	)		-			-
Loss on Early Extinguishment of Debt8		-			(3,894	)		-
Other, Net9, 10, 11, 1		5,141			2,514			5,229
	$	451,479		$	365,187		$	281,562

¹

Excludes amounts allocated to discontinued operations.

²

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.

³

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.

⁴

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

⁵

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

⁶

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.

⁷

$9.5 million after tax.

⁸

$2.4 million after tax.

⁹

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

¹⁰

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.

¹¹

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 $365.2 million in 2004 to income of $451.5 million in 2005, an increase of $86.3 million (24%). 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

16

Item 7.

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

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 $281.6 million in 2003 to income of $365.2 million in 2004, an increase of $83.6 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 $2.1 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.

Income Taxes – Continuing Operations

The income tax provision for continuing operations increased from $208.0 million in 2004 to $345.5 million in 2005, an increase of $137.5 million (66%) due principally to (i) the fact that the 2004 tax provision includes a reduction of $69.4 million due to the impact of applying a lower effective tax rate on previously recorded net deferred tax liabilities, (ii) an increase of $64.5 million due to an increase in pre-tax income from continuing operations of $169.2 million, (iii) a decrease of $2.1 million related to Kinder Morgan Management minority interest and (iv) an increase of $5.7 million attributable to other items.

The income tax provision for continuing operations decreased from $225.1 million in 2003 to $208.0 million in 2004, a decrease of $17.1 million (8%). The net decrease of $17.1 million results from (i) a reduction of $69.4 million due to the impact of a lower effective tax rate on previously recorded net deferred tax liabilities, (ii) an increase of $46.0 million attributable to $124.5 million additional pre-tax income from continuing operations, (iii) an increase of $1.5 million attributable to Kinder Morgan Management minority interest and (iv) an increase of $4.8 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.

Income Taxes – Realization of Deferred Tax Assets

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.

Discontinued Operations

In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S.-based natural gas distribution and related operations for $710 million plus working capital. Pending regulatory approvals, we expect this transaction to close by the end of the first quarter of 2007. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented. For the years ended December 31, 2005, 2004 and 2003, including allocations of general and administrative, interest and income tax expenses, we recorded income of $22.3 million (net of tax of $15.4 million), $30.3 million (net of tax of $18.7 million) and $25.1 million (net of tax of $19.5 million), respectively, from these operations.

17

Item 7.

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

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 pr eviously 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.

Liquidity and Capital Resources

Primary Cash Requirements

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, inclusive of amounts associated with our discontinued U.S.-based natural gas distribution operations. 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.

Invested Capital

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 M organ, 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.

18

Item 7.

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

	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 Securities		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%

 _____________

¹

See “Significant Financing Transactions” following.

²

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.

³

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.

19

Item 7.

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

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.

Short-term Liquidity

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. dolla rs 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.

Significant Financing Transactions

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” in our 2005 10-K). 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 duri ng 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

20

Item 7.

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

$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 revol ving 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

21

Item 7.

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

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.

Off-Balance Sheet Arrangements

	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

___________

¹

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

²

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

³

Debtors have recourse only to the assets of the entity, not to the owners.

⁴

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.

22

Item 7.

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

⁵

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.

Aggregate Contractual Obligations

			Amount of Commitment Expiration Per Period
	Total		Less than 1 year		2-3 years		4-5 years		After 5 years
	(In millions)
Contractual Obligations:
Long-term Debt, Including Current Maturities:
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	$	-	$	-	$	-

¹

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.

²

Includes obligations under Terasen Gas vehicle leases.

³

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.

⁴

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, which has been reclassified as discontinued as discussed under “Discontinued Operations” elsewhere herein, 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.

⁵

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.

⁶

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 u s 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.

23

Item 7.

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

⁷

The 2006 capital expenditure budget totals approximately $611.6 million, inclusive of amounts associated with our discontinued U.S.-based natural gas distribution operations. 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.

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

___________

¹

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.

Investment in Kinder Morgan Energy Partners

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.

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.

Cash Flows

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 from Operating Activities

“Net Cash Flows Provided by Operating Activities” decreased from $644.4 million in 2004 to $616.2 million in 2005, a

24

Item 7.

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

decrease of $28.2 million (4.4%). This negative variance is principally due to (i) a $40.3 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 $40.3 million increased source of cash from discontinued operations, of whi ch $26.7 million is attributable to our discontinued U.S.-based natural gas distribution operations and $10.0 million is attributable to Terasen’s discontinued Water and Utility Services (see Note 7 of the accompanying Notes to Consolidated Financial Statements) and (iii) a net increased source of cash of $28.9 million for gas in underground storage. 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 $9.0 million increase in cash attributable to our discontinued U.S.-based natural gas distribution operations (see Note 7 of the accompanying Notes to Consolidated Financial Statements), (iii) a $19.3 million reduction in cash paid for interest during 2004 and (iv) a $7.0 million decrease in cash paid for income taxes during 2004. These positive impacts were partially offset by, (i) a decrease of $53.5 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 from Investing Activities

“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 $41.3 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) an $18.9 million decreased use of cash for discontinued investing activities, primarily attributable to capital expenditures related to our discontinued U.S.-based natural gas distribution operations (see Note 7 of the accompanying Notes to Consolidated Financial Statements), (ii) $4 8.4 million net decreased 2005 investments in margin deposits associated with hedging activities utilizing energy derivative instruments, (iii) $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 (iv) 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, (iii) a $28.8 million reduction of capital expenditures during 2004 and (iv) 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) a $37.3 million increased use of cash

25

Item 7.

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

for discontinued investing activities, primarily attributable to capital expenditures related to our discontinued U.S.-based natural gas distribution operations (see Note 7 of the accompanying Notes to Consolidated Financial Statements) and (iii) an increase of $6.6 million in 2004 investments in margin deposits associated with hedging activities utilizing energy derivative instruments.

Net Cash Flows from Financing Activities

“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 o f 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” under Item 1 in our 2005 10-K, 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 ou r 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.

Litigation and Environmental Matters

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 s oil and ground water impacts from former releases to the environment at facilities we have acquired. Reserves for each project are generally

26

Item 7.

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

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 ex isting 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.

Regulation

See Note 8 of the accompanying Notes to Consolidated Financial Statements and “Business and Properties – Regulation” in Items 1 and 2 of our 2005 10-K for information regarding regulatory matters.

Recent Accounting Pronouncements

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

Information Regarding Forward-looking Statements

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 op erations 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;

27

Item 7.

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

·

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;

·

capital markets conditions;

·

the political and economic stability of the oil producing nations of the world;

·

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

·

our ability to achieve cost savings and revenue growth;

·

inflation;

·

interest rates;

·

the pace of deregulation of retail natural gas and electricity;

·

foreign exchange fluctuations;

·

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

·

the timing and success of business development efforts; and

·

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” in our 2005 Form 10-K 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. Other than as required by applicable law, 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 developme nts.

28

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

Risk Management

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.

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 Canada, (ii) as fuel in one of our Colorado power generation facilities, (iii) as fuel for compressors located on NGPL’s pipeline system and (iv) for operational sales of gas by NGPL. With respect to item (ii), our exposure is minimal and primarily consists of basis rather than commodity risk. With respect to item (iii), 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. We use derivatives to manage natural gas commodity price risk that is passed to customers. Item (iv) gives rise to natural gas commodity price risk which we h ave 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.

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 n et 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, including our discontinued U.S.-based natural gas distribution operations, but 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,

29

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk. (continued)

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, although it does include the impact of hedging associated with our discontinued U.S.-based natural gas distribution operations, see “Discontinued Operations” elsewhere herein. 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. Including our discontinued U.S.-based natural gas distribution operations, 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”, “Gas Purchases and Other Costs of Sales” and “Income from Discontinued Operations, Net of Tax” 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 transactions entered into on its behalf.

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

We have 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 $6 1.9 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

30

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk. (continued)

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 paym ents, 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.

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 in terest 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.

31

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk. (continued)

·

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 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 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.

32

Item 8.

Financial Statements and Supplementary Data.

INDEX

	Page
Report of Independent Registered Public Accounting Firm	34-35
Consolidated Statements of Operations	36
Consolidated Statements of Comprehensive Income	37
Consolidated Balance Sheets	38
Consolidated Statements of Stockholders’ Equity	39
Consolidated Statements of Cash Flows	40-41
Notes to Consolidated Financial Statements	42-94
Selected Quarterly Financial Data (Unaudited)	95-96
Supplementary Information on Oil and Gas Producing
Activities (Unaudited)	97

33

Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Kinder Morgan, Inc.:

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.

Consolidated financial statements

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 prese ntation. 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.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 (not appearing herein), 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 t he 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.

34

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 19% of the Company’s consolidated operating revenues (after reflecting the discontinued operation described in Note 7) for 2005 and 43% of the Company’s consolidated total assets at December 31, 2005.

PricewaterhouseCoopers LLP

Houston, Texas

March 13, 2006, except as to Note 7, for which the date is November 9, 2006

35

CONSOLIDATED STATEMENTS OF OPERATIONS
Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2005			2004			2003
	(In thousands except per share amounts)
Operating Revenues:
Transportation and Storage	$	766,524		$	670,927		$	629,127
Natural Gas Sales		404,463			130,128			180,703
Other		83,540			76,682			38,948
Total Operating Revenues		1,254,527			877,737			848,778
Operating Costs and Expenses:
Purchases and Other Costs of Sales		458,785			194,244			232,057
Operations and Maintenance		145,112			113,463			81,027
General and Administrative		72,334			67,673			62,191
Depreciation and Amortization		113,375			101,619			101,331
Taxes, Other Than Income Taxes		34,540			26,201			27,498
Impairment of Power Investments		6,492			33,527			44,513
Total Operating Costs and Expenses		830,638			536,727			548,617
Operating Income		423,889			341,010			300,161
Other Income and (Expenses):
Equity in Earnings of Kinder Morgan Energy Partners		605,399			558,078			464,967
Equity in Earnings of Other Equity Investments		16,242			10,152			7,458
Interest Expense, Net		(166,275	)		(125,303	)		(132,513	)
Interest Expense – Deferrable Interest Debentures		(21,912	)		(21,912	)		-
Interest Expense – Capital Securities		(712	)		-			-
Interest Expense – Capital Trust Securities		-			-			(10,956	)
Minority Interests		(50,457	)		(56,420	)		(52,493	)
Other, Net		69,194			592			5,099
Total Other Income and (Expenses)		451,479			365,187			281,562
Income from Continuing Operations Before Income Taxes		875,368			706,197			581,723
Income Taxes		345,509			208,024			225,082
Income from Continuing Operations		529,859			498,173			356,641
Income from Discontinued Operations, Net of Tax		24,760			23,907			25,063
Net Income	$	554,619		$	522,080		$	381,704
Basic Earnings Per Common Share:
Income from Continuing Operations	$	4.29		$	4.03		$	2.91
Income from Discontinued Operations		0.20			0.19			0.20
Total Basic Earnings Per Common Share	$	4.49		$	4.22		$	3.11
Number of Shares Used in Computing Basic Earnings Per Common Share		123,465			123,778			122,605
Diluted Earnings Per Common Share:
Income from Continuing Operations	$	4.25		$	3.99		$	2.88
Income from Discontinued Operations		0.20			0.19			0.20
Total Diluted Earnings Per Common Share	$	4.45		$	4.18		$	3.08
Number of Shares Used in Computing Diluted Earnings Per Common Share		124,642			124,938			123,824
Dividends Per Common Share	$	2.90		$	2.25		$	1.10

The accompanying notes are an integral part of these statements.

36

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

	Year Ended December 31,
	2005			2004				2003
	(In thousands)
Net Income	$	554,619			$	522,080			$	381,704
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes      (Net of Tax Benefit of $54,232, $4,647 and $16,251, respectively)		(91,962	)			(7,922	)			(26,515	)
Reclassification of Change in Fair Value of Derivatives to Net Income      (Net of Tax of $39,616, $9,010 and $24,680, respectively)		68,773				14,971				40,267
Adjustment to Recognize Minimum Pension Liability      (Net of Tax Benefit of $1,625 and Tax of $10,865, respectively)		(3,322	)			-				17,727
Equity in Other Comprehensive Loss of Equity Method      Investees (Net of Tax Benefit of $82,908, $41,604 and $15,897,         respectively)		(144,295	)			(71,950	)			(25,935	)
Minority Interest in Other Comprehensive Loss of Equity      Method Investees		95,094				35,842				13,492
Change in Foreign Currency Translation Adjustment		10,737				-				-
Change in Fair Value of Derivatives Utilized as a Hedge of      Investment in a Foreign Company (Net of Tax Benefit of $4,273)		(7,284	)			-				-
Total Other Comprehensive Income (Loss)		(72,259	)			(29,059	)			19,036
Comprehensive Income	$	482,360			$	493,021			$	400,740

The accompanying notes are an integral part of these statements.

37

CONSOLIDATED BALANCE SHEETS
Kinder Morgan, Inc. and Subsidiaries

	December 31,
	2005			2004
ASSETS:	(In thousands)
Current Assets:
Cash and Cash Equivalents	$	116,635		$	176,520
Restricted Deposits		10,563			38,049
Accounts Receivable, Net:
Trade		579,791			82,544
Related Parties		17,233			5,859
Note Receivable		-			4,594
Inventories		228,222			41,781
Gas Imbalances		16,931			5,625
Assets Held for Sale		126,649			-
Other		208,070			114,286
		1,304,094			469,258
Investments:
Kinder Morgan Energy Partners		2,202,946			2,305,212
Goodwill		2,781,041			918,076
Other		649,588			176,143
		5,633,575			3,399,431
Property, Plant and Equipment, Net		9,545,634			5,851,965
Deferred Charges and Other Assets		968,311			396,247
Total Assets	$	17,451,614		$	10,116,901
LIABILITIES AND STOCKHOLDERS’ EQUITY:
Current Liabilities:
Current Maturities of Long-term Debt	$	347,400		$	505,000
Notes Payable		610,555			-
Accounts Payable:
Trade		437,279			58,119
Related Parties		32			180
Accrued Interest		91,958			67,206
Accrued Taxes		100,054			32,547
Gas Imbalances		16,083			18,254
Rate Stabilization		115,182			-
Liabilities Held for Sale		21,911			-
Other		202,179			157,503
		1,942,633			838,809
Other Liabilities and Deferred Credits:
Deferred Income Taxes		3,156,393			2,530,065
Other		451,547			148,044
		3,607,940			2,678,109
Long-term Debt:
Outstanding Notes and Debentures		6,286,796			2,257,950
Deferrable Interest Debentures Issued to Subsidiary Trusts		283,600			283,600
Capital Securities		107,137			-
Value of Interest Rate Swaps		51,831			88,243
		6,729,364			2,629,793
Minority Interests in Equity of Subsidiaries		1,247,322			1,105,436
Commitments and Contingent Liabilities (Notes 9 and 17)
Stockholders’ Equity:
Preferred Stock (Note 13)		-			-
Common Stock-
Authorized – 300,000,000 Shares, Par Value $5 Per Share; Outstanding – 148,479,863 and 134,198,905     Shares, Respectively, Before Deducting 14,712,901 and 10,666,801 Shares Held in Treasury		742,399			670,995
Additional Paid-in Capital		3,056,286			1,863,145
Retained Earnings		1,175,340			975,912
Treasury Stock		(885,698	)		(558,844	)
Deferred Compensation		(36,971	)		(31,712	)
Accumulated Other Comprehensive Loss		(127,001	)		(54,742	)
Total Stockholders’ Equity		3,924,355			2,864,754
Total Liabilities and Stockholders’ Equity	$	17,451,614		$	10,116,901

The accompanying notes are an integral part of these statements.

38

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

	Year Ended December 31,
	2005					2004					2003
	Shares		Amount			Shares		Amount			Shares		Amount
	(Dollars in thousands)
Common Stock:
Beginning Balance	134,198,905		$	670,995		132,229,622		$	661,148		129,861,650		$	649,308
Acquisition of Terasen	12,476,974			62,385		-			-		-			-
Employee Benefit Plans	1,803,984			9,019		1,969,283			9,847		2,367,972			11,840
Ending Balance	148,479,863			742,399		134,198,905			670,995		132,229,622			661,148
Additional Paid-in Capital:
Beginning Balance				1,863,145					1,780,761					1,681,042
Acquisition of Terasen				1,084,374					-					-
Revaluation of Kinder Morgan Energy      Partners (KMP) Investment (Note 5)				7,823					(462	)				(4,070	)
Employee Benefit Plans				78,913					63,459					71,531
Tax Benefits from Employee      Benefit Plans				22,035					19,376					29,974
Other				(4	)				11					2,284
Ending Balance				3,056,286					1,863,145					1,780,761
Retained Earnings:
Beginning Balance				975,912					732,492					486,062
Net Income				554,619					522,080					381,704
Cash Dividends, Common Stock				(355,191	)				(278,660	)				(135,274	)
Ending Balance				1,175,340					975,912					732,492
Treasury Stock at Cost:
Beginning Balance	(10,666,801	)		(558,844	)	(8,912,660	)		(446,095	)	(8,168,241	)		(406,630	)
Treasury Stock Acquired	(3,865,800	)		(314,086	)	(1,695,900	)		(108,578	)	(724,600	)		(37,988	)
Employee Benefit Plans	(180,300	)		(12,768	)	(58,241	)		(4,171	)	(19,819	)		(1,477	)
Ending Balance	(14,712,901	)		(885,698	)	(10,666,801	)		(558,844	)	(8,912,660	)		(446,095	)
Deferred Compensation Plans:
Beginning Balance				(31,712	)				(36,506	)				(10,066	)
Current Year Activity [Note 1(S)]				(5,259	)				4,794					(26,440	)
Ending Balance				(36,971	)				(31,712	)				(36,506	)
Accumulated Other Comprehensive
Loss (Net of Tax):
Beginning Balance				(54,742	)				(25,683	)				(44,719	)
Unrealized Gain (Loss) on Derivatives      Utilized for Hedging Purposes				(23,189	)				7,049					13,752
Adjustment to Recognize Minimum      Pension Liability				(3,322	)				-					17,727
Equity in Other Comprehensive      Loss of Equity Method Investees				(144,295	)				(71,950	)				(25,935	)
Minority Interest in Other Comprehensive      Loss of Equity Method Investees				95,094					35,842					13,492
Currency Translation Adjustment				10,737					-					-
Change in Fair Value of Derivatives Utilized as a Hedge of Investment In a Foreign Company				(7,284	)				-					-
Ending Balance				(127,001	)				(54,742	)				(25,683	)
Total Stockholders’ Equity	133,766,962		$	3,924,355		123,532,104		$	2,864,754		123,316,962		$	2,666,117

The accompanying notes are an integral part of these statements.

39

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

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
Cash Flows from Operating Activities:
Net Income	$	554,619		$	522,080		$	381,704
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Income from Discontinued Operations, Net of Tax		(24,760	)		(23,907	)		(25,063	)
Loss from Impairment of Power Investments		6,492			33,527			44,513
Loss on Early Extinguishment of Debt		-			3,894			-
Depreciation and Amortization		113,375			101,619			101,331
Deferred Income Taxes		91,973			36,408			21,697
Equity in Earnings of Kinder Morgan Energy Partners		(605,399	)		(558,078	)		(464,967	)
Distributions from Kinder Morgan Energy Partners		530,810			435,309			369,022
Equity in Earnings of Other Equity Investments		(16,242	)		(10,152	)		(7,458	)
Distributions from Other Equity Investees		8,050			9,693			5,700
Minority Interests in Income of Consolidated Subsidiaries		50,457			56,420			41,537
Increase in Rate Stabilization Accounts		(4,624	)		-			-
Net (Gains) Losses on Sales of Assets		(76,385	)		(5,919	)		130
Foreign Currency Gain		(4,961	)		-			-
Gain from Settlement of Orcom Note		-			-			(2,917	)
Pension Contribution in Excess of Expense		(23,844	)		(4,638	)		(5,101	)
Changes in Gas in Underground Storage		28,049			(806	)		52,720
Changes in Working Capital Items [Note 1(R)]		(70,375	)		41,214			65,751
(Payment for) Proceeds from Termination of Interest Rate Swap		(3,543	)		-			28,147
Other, Net		(7,523	)		(22,010	)		(29,336	)
Net Cash Flows Provided by Continuing Operations		546,169			614,654			577,410
Net Cash Flows Provided by Discontinued Operations		70,051			29,775			24,096
Net Cash Flows Provided by Operating Activities		616,220			644,429			601,506
Cash Flows from Investing Activities:
Capital Expenditures		(144,507	)		(103,204	)		(131,988	)
Acquisition of Terasen, Net of Cash Acquired of $73,673		(2,065,500	)		-			-
Proceeds from Contribution of TransColorado to Kinder Morgan Energy Partners		-			210,824			-
Investment in Kinder Morgan Energy Partners (Note 2)		(4,504	)		(74,035	)		(1,784	)
Net (Investments in) Proceeds from Margin Deposits		27,486			(20,942	)		(14,375	)
Other Investments		(404	)		-			(11,329	)
Proceeds from Sales of Kinder Morgan Management, LLC Shares		254,802			-			-
Proceeds from Settlement of Orcom Note		-			-			2,727
Proceeds from Sales of Turbines and Boilers		-			42,096			8,547
Net (Cost of Removal) Proceeds from Sales of Assets		(4,042	)		(1,133	)		64
Net Cash Flows Provided by (Used in) Continuing Investing Activities		(1,936,669	)		53,606			(148,138	)
Net Cash Flows Used in Discontinued Investing Activities		(42,008	)		(60,908	)		(23,574	)
Net Cash Flows Used in Investing Activities		(1,978,677	)		(7,302	)		(171,712	)

40

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

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Cash Flows from Financing Activities:
Short-term Debt, Net		39,643			(127,900	)		127,900
Bridge Facility Issued		2,134,663			-			-
Bridge Facility Retired		(2,129,702	)		-			-
Long-term Debt Issued		2,400,000			-			-
Long-term Debt Retired		(505,000	)		(80,000	)		(511,083	)
Issuance of Shares by Kinder Morgan Management, LLC		-			67,603			-
Other Common Stock Issued		62,851			68,394			47,686
Premiums Paid on Early Extinguishment of Debt		-			(3,000	)		-
Short-term Advances (to) from Unconsolidated Affiliates		(11,668	)		(14,727	)		55,864
Purchase of Kinder Morgan Management Shares		-			-			(928	)
Treasury Stock Acquired		(317,147	)		(102,675	)		(37,988	)
Cash Dividends, Common Stock		(355,191	)		(278,660	)		(135,274	)
Minority Interests, Net		(2,416	)		(643	)		(548	)
Debt Issuance Costs		(14,284	)		-			-
Securities Issuance Costs		-			(75	)		-
Net Cash Flows Provided by (Used in) Continuing Financing Activities		1,301,749			(471,683	)		(454,371	)
Net Cash Flows Provided by Discontinued Financing Activities		565			-			-
Net Cash Flows Provided by (Used in) Financing Activities		1,302,314			(471,683	)		(454,371	)
Effect of Exchange Rate Changes on Cash		258			-			-
Net Increase (Decrease) in Cash and Cash Equivalents		(59,885	)		165,444			(24,577	)
Cash and Cash Equivalents at Beginning of Year		176,520			11,076			35,653
Cash and Cash Equivalents at End of Year	$	116,635		$	176,520		$	11,076

The accompanying notes are an integral part of these statements.

41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Nature of Operations and Summary of Significant Accounting Policies

(A) Nature of Operations

We are an energy infrastructure provider and have operations in the northwest and mid-continent regions of the United States and in western Canada, with principal operations in Arkansas, Illinois, Iowa, Kansas, Louisiana, Missouri, New Mexico, Oklahoma, Texas and Washington 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 Ki nder 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.

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. See Note 4.

During 2006, we entered into a definitive agreement to sell our U.S.-based natural gas distribution operations. These activities have been reclassified to “discontinued operations” in these Notes and in the accompanying Consolidated Financial Statements. See Note 7.

(B) Basis of Presentation

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.

(C) Accounting for Regulatory Activities

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, 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:

42

	December 31,
	2005		2004
	(In thousands)
Regulatory Assets:
Employee Benefit Costs	$	10,577	$	1,605
Deferred Income Taxes		19,671		13,866
Purchased Gas Costs		34,623		43,062
Plant Acquisition Adjustments		454		454
Rate Regulation and Application Costs		2,323		2,427
Debt Issuance Costs		11,532		689
Foreign Currency Rate Stabilization		98,410		-
Changes in Fair Value of Derivatives		90,763		-
Deferred Development Costs on Capital Projects		16,184		-
Commercial Commodity Unbundling Costs		4,153		-
Replacement Transportation Agreement		4,153		-
Other Regulatory Assets		17,393		-
Total Regulatory Assets		310,236		62,103
Regulatory Liabilities:
Deferred Income Taxes		40,987		17,773
Purchased Gas Costs		13,081		2,503
Rate Regulation and Application Costs		14,619		58
Foreign Currency Rate Stabilization		115,182		-
Changes in Fair Value of Derivatives		6,114		-
Other Regulatory Liabilities		11,458		-
Total Regulatory Liabilities		201,441		20,334
Net Regulatory Assets	$	108,795	$	41,769

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.  Certain of these regulatory assets and liabilities are associated with our discontinued U.S.-based natural gas distribution operations.  See Note 7.

(D) Revenue Recognition Policies

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. Our rate-regulated retail natural gas distribution business bills customers on a monthly cycle billing basis. Revenues are recorded on an accrual basis, including an estimate at the end of each accounting period for gas delivered and, if applicable, 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.

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(E) Earnings Per Share

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.

	2005	2004	2003
	(In thousands)
Weighted Average Common Shares Outstanding	123,465	123,778	122,605
Dilutive Common Stock Options	1,177	1,160	1,219
Shares Used to Compute Diluted Earnings Per Common Share	124,642	124,938	123,824

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.

(F) Restricted Deposits

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

(G) Accounts Receivable

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 balan ce in the allowance for doubtful accounts and activity for the years ended December 31, 2005, 2004 and 2003.

Allowance for Doubtful Accounts

	Year Ended December 31,
	2005			2004			2003
	(In millions)
Beginning Balance	$	3.1		$	5.2		$	4.9
Additions: Charged to Cost and Expenses1		4.9			1.4			1.9
Deductions: Write-off of Uncollectible Accounts		(2.2	)		(3.5	)		(1.6	)
Ending Balance	$	5.8		$	3.1		$	5.2

¹ Additions in 2005 include $3.1 million acquired with Terasen. See Note 4.

(H) Inventories

	December 31,
	2005		2004
	(In thousands)
Gas in Underground Storage (Current)	$	209,635	$	28,342
Materials and Supplies		18,587		13,439
	$	228,222	$	41,781

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.

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(I) Current Assets: Other

	December 31,
	2005		2004
	(In thousands)
Assets Held for Sale - Turbines and Boilers1	$	23,500	$	23,500
Current Deferred Tax Asset		10,905		30,198
Interest Receivable – Interest Rate Swaps		4,659		15,494
Derivatives		60,465		19,294
Prepaid Expenses		24,629		11,643
Income Tax Overpayments		10,853		6,681
Rate Stabilization		35,673		-
Hedge Deferral		21,872		2,660
Other		15,514		4,816
	$	208,070	$	114,286

¹ See Notes 5 and 6.

(J) Goodwill

	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.

(K) Other Investments

	December 31,
	2005		2004
	(In thousands)
Thermo Companies1	$	147,093	$	148,593
Horizon Pipeline Company		17,301		18,244
Subsidiary Trusts Holding Solely Debentures of Kinder Morgan		8,600		8,600
Express Pipeline		431,919		-
CustomerWorks LP		43,965		-
Other		710		706
	$	649,588	$	176,143

¹

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

45

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.

(L) Property, Plant and Equipment

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 t hat 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.

(M) Asset Retirement Obligations

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:

	Year Ended December 31,
	2005			2004
	(In thousands)
Balance at Beginning of Period	$	3,279		$	2,151
Liabilities Incurred		-			1,053
Liabilities Settled		(227	)		-
Accretion Expense		154			75
Balance at End of Period	$	3,206		$	3,279

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

46

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.

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.

Certain of the asset retirement obligations shown above are associated with our discontinued U.S.-based natural gas distribution operations, see Note 7.

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.

(N) Gas Imbalances and Gas Purchase Contracts

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. This take obligation is associated with our discontinued U.S.-based natural gas distribution operations, see Note 7.

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(O) Depreciation and Amortization

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:

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

(P) Interest Expense

“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. In addition, a portion of our interest expense has been allocated to discontinued operations.

	Year Ended December 31,
	2005			2004			2003
	(In millions)
Interest Expense	$	167.5		$	125.8		$	133.1
AFUDC — Interest		(1.2	)		(0.5	)		(0.6	)
Interest Expense, Net		166.3			125.3			132.5
Interest Expense – Deferrable Interest Debentures		21.9			21.9			-
Interest Expense – Capital Securities		0.7			-			-
Interest Expense – Capital Trust Securities		-			-			11.0
Total Interest Expense	$	188.9		$	147.2		$	143.5

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.

(Q) Other, Net

“Other, Net” as presented in the accompanying Consolidated Statements of Operations includes $79.1 million, $2.0 million and $(0.1) 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.

(R) Cash Flow Information

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.

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ADDITIONAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Accounts Receivable	$	(73,285	)	$	6,803		$	13,560
Materials and Supplies Inventory		581			489			(21	)
Other Current Assets		(50,634	)		(15,972	)		36,797
Accounts Payable		(2,863	)		(7,707	)		(12,754	)
Income Tax Benefits from Employee Benefit Plans		22,036			19,376			29,974
Other Current Liabilities		33,790			38,225			(1,805	)
	$	(70,375	)	$	41,214		$	65,751

Supplemental Disclosures of Cash Flow Information

	Year Ended December 31,
	2005		2004		2003
	(In thousands)
Cash Paid for:
Interest (Net of Amount Capitalized)	$	183,973	$	161,628	$	169,931
Distributions on Capital Trust Securities1	$	-	$	-	$	10,956
Income Taxes Paid (Net of Refunds)	$	203,962	$	144,146	$	151,104

¹

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.

(S) Stock-Based Compensation

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 p ercent 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.

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	Year Ended December 31,
	2005			2004			2003
	(In thousands except per share amounts)
Net Income As Reported	$	554,619		$	522,080		$	381,704
Add: Stock-based employee compensation expense     included in reported Net Income, net of related tax     effects		5,182			3,174			2,107
Deduct: Total stock-based employee compensation     expense determined under fair value based     method for all awards, net of related tax effects		(12,351	)		(15,772	)		(16,468	)
Pro Forma Net Income	$	547,450		$	509,482		$	367,343
Basic Earnings Per Common Share:
As Reported	$	4.49		$	4.22		$	3.11
Pro Forma	$	4.43		$	4.12		$	3.00
Diluted Earnings Per Common Share:
As Reported	$	4.45		$	4.18		$	3.08
Pro Forma	$	4.39		$	4.08		$	2.97

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:

	Year Ended December 31,
	2004	2003
Risk-free Interest Rate (%)	3.931	3.37-3.642
Expected Weighted-average Life	5.7 years1	6.3 years2
Volatility	0.391	0.38-0.452
Expected Dividend Yield (%)	3.701	1.33-2.972

___________

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.

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, relat ed 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.”

The amounts in this footnote do not reflect any changes which may result from the expected sale of our U.S.-based natural gas distribution operations as discussed in Note 7.

(T) Transactions with Related Parties

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 i nterest retained in the assets transferred.

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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 ne cessary 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.

Exclusive of related-party revenues involving our discontinued U.S.-based natural gas distribution operations, 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:

	Year Ended December 31,
	2005			2004			2003
	(In millions)
Natural Gas Transportation and Storage		$	3.7		$	3.8		$	4.4
Natural Gas Sales			9.4			5.6			5.4
Total Related-party Operating Revenues		$	13.1		$	9.4		$	9.8

The caption “Gas Purchases and Other Costs of Sales” in the accompanying Consolidated Statements of Operations includes related-party costs totaling $6.4 million, $6.2 million and $10.9 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. These amounts exclude related-party costs associated with our U.S.-based natural gas distribution operations. Certain transactions with related parties are included in Note 5.

(U) Accounting for Risk Management Activities

We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas and associated transportation. , We have utilized weather derivatives to reduce the variability in the earnings from our discontinued U.S.-based 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.

(V) Income Taxes

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.

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(W) Accounting for Legal Costs

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.

(X) Accounting for Minority Interests

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:

	December 31,
	2005		2004
	(In millions)
Kinder Morgan Management, LLC	$	1,221.7	$	1,083.0
Triton Power		21.8		18.8
Other		3.8		3.6
	$	1,247.3	$	1,105.4

(Y) Foreign Currency Translation

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.

2.   Investment in Kinder Morgan Energy Partners, L.P.

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 p roducts 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

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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.

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).

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.

	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

3.  Kinder Morgan Management, LLC

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

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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.

4.  Business Combinations

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 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

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

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positive cash flow generated by our investment in Kinder Morgan Energy Partners. The preliminary allocation of goodwill to reporting segments is as follows:

Preliminary Allocation of Goodwill:	(In thousands)
Terasen Gas	$	1,234,428
Kinder Morgan Canada		656,096
	$	1,890,524

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.

	Year Ended December 31,
	2005		2004
	(In thousands, except per share amounts)
Operating Revenues	$	2,922,480	$	2,610,887
Income from Continuing Operations	$	627,475	$	614,440
Net Income	$	628,156	$	608,016
Diluted Earnings Per Common Share	$	4.62	$	4.42
Common Shares Used in Computing Diluted Earnings Per Share		136,079		137,415

5.  Investments and Sales

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 approximate ly $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.

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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 resu lt 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

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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).

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 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.

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 N ote 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. As Igasamex USA Ltd. was part of our U.S.-based natural gas distribution business, this loss is included under the caption “Income from Discontinued Operations, Net of Tax” in the accompanying Consolidated Statement of Operations.

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.

6.  Impairment of Power Investments

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.

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7.  Discontinued Operations

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 and these Notes present these businesses as discontinued operations for all periods presented. Accordingly, the revenues, costs and expenses, 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 these statements under the captions “Income from Discontinued Operations, Net of Tax” and “Net Cash Flows Provided by Discontinued Operations” for all relevant periods.

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 associated with our sale of assets to ONEOK, Inc. (“ONEOK”). 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 associated with our sale of assets to ONEOK. 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.

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 these discontinued operations have been excluded from the respective captions in the accompanying Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows, and have been reported in the various statements under the captions “Current Assets: Assets Held for Sale”; “Current Liabilities: Liabilities Held for Sale”; “Net Cash Flows Provided by Discontinued Operations”; “Net Cash Flows Used in Discontinued Investing Activities” and “Net Cash Flows Provided by Discontinued Financing Activities” for all relevant periods.

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.

In addition, during 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S.-based natural gas distribution and related operations for $710 million plus working capital. Pending regulatory approvals, we expect this transaction to close by the end of the first quarter of 2007.

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the accompanying Consolidated Statements of Operations and Consolidated Statements of Cash Flows and these Notes have been revised to present these operations as discontinued operations. Therefore, the results of operations and cash flows of these discontinued operations have been excluded from the respective captions in the accompanying Consolidated Statements of Operations and Consolidated Statements of Cash Flows, and have been reported in the various statements under the captions “Income from Discontinued Operations, Net of Tax”; “Net Cash Flows Provided by Discontinued Operations” and “Net Cash Flows Used in Discontinued Investing Activities” for all relevant periods.

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Summarized financial data of discontinued operations are as follows:

	For the Year Ended December 31,
	2005		2004		2003
	(In thousands)
Income Statement Data
Operating Revenues	$	340,062	$	287,196	$	249,119
Income from Discontinued Operations, Net of Tax of $16,921, $14,936 and $19,518	$	24,760	$	23,907	$	25,063

We have not revised the accompanying Consolidated Balance Sheets to show the assets and liabilities of the U.S.-based natural gas distribution business as assets and liabilities held for sale. The table below shows (i) the amounts of the assets and liabilities of the U.S.-based natural gas distribution business that are included in the accompanying Consolidated Balance Sheet at December 31, 2005, and (ii) the assets and liabilities of Terasen Water and Utilities Services and its affiliates that are shown in the accompanying Consolidated Balance Sheet at December 31, 2005 as assets and liabilities held for sale.

	As of December 31, 2005
	U.S.-based Natural Gas Distribution		Terasen Water and Utility Services
Balance Sheet Data
Current Assets:
Cash	$	5,022	$	9
Accounts Receivable, Net		63,035		27,153
Inventories		17,787		15,483
Other Current Assets		17,021		667
		102,865		43,312
Non-current Assets:
Property, Plant and Equipment, Net		390,534		46,052
Other Investments		25		33,561
Deferred Charges and Other Assets		37,198		3,724
		427,757		83,337
Total Assets of Discontinued Operations	$	530,622	$	126,649
Current Liabilities:
Accounts Payable		37,428		18,852
Accrued Taxes		28,059		404
Other Current Liabilities		28,561		-
		94,048		19,256
Non-current Liabilities:
Long-term Debt		-		317
Deferred Income Taxes Payable		44,366		202
Other Deferred Credits		15,804		2,136
		60,170		2,655
Total Liabilities of Discontinued Operations	$	154,218	$	21,911

8.  Regulatory Matters

On February 28, 2006, Kinder Morgan Retail (which is subject to a definitive sale agreement, see Note 7) 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.

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.

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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 eq uity components of Terasen Gas Inc. and TGVI to 35% and 40%, respectively, and their allowed ROE’s to 8.80% and 9.5%, respectively.

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.

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 E nvironment 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 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 early 2007.

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

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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 r eaffirmed 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 we re 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

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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 file d 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 E nergy 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 person nel 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 unt il 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

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from Energy Affiliate.  Kinder Morgan’s U.S.-based natural gas distribution business became subject to a definitive sale agreement in 2006, see Note 7.

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 wi thout 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.

9.  Environmental and Legal Matters

(A) Environmental Matters

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 sign ificant costs.

(B) Litigation Matters

United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claims Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The complaint asks to recover all royalties the Government allegedly should have received had the volume and heating content of the natural gas been valued properly, along with treble damages and civil penalties as provided for in the False Claims Act. Mr. Grynberg, as relator, seeks his statutory share of any recovery, plus expenses and attorney fees and costs. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation (“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 h eld 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

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opposing leave to amend. Neither the Court nor the Special Master has 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.

Harrison County Texas Pipeline Rupture

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.

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10.  Property, Plant and Equipment

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

	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
Total		$	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
Total		$	6,484,702		$	632,737		$	5,851,965

11. Income Taxes

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

	Year Ended December 31,
	2005		2004		2003
	(In thousands)
United States	$	844,802	$	706,197	$	581,723
Foreign		30,566		-		-
Total	$	875,368	$	706,197	$	581,723

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

	Year Ended December 31,
	2005		2004			2003
	(Dollars in thousands)
Current Tax Provision:
U.S.
Federal	$	213,906	$	157,585		$	180,855
State		27,404		14,031			22,530
Foreign		12,226		-			-
		253,536		171,616			203,385
Deferred Tax Provision:
U.S.
Federal		86,232		84,485			22,667
State		5,510		(48,077	)		(970	)
Foreign		231		-			-
		91,973		36,408			21,697
Total Tax Provision	$	345,509	$	208,024		$	225,082
Effective Tax Rate		39.5%		29.5%			38.7%

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

	Year Ended December 31,
	2005	2004		2003
Federal Income Tax Rate	35.0%	35.0%		35.0%
Increase (Decrease) as a Result of:
State Income Tax, Net of Federal Benefit	2.3%	2.1%		2.2%
Kinder Morgan Management Minority Interest	1.9%	2.6%		3.0%
Deferred Tax Rate Change	-	(9.8%	)	-
Other	0.3%	(0.4%	)	(1.5%	)
Effective Tax Rate	39.5%	29.5%		38.7%

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

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Continuing Operations	$	345,509		$	208,024		$	225,082
Discontinued Operations		16,921			14,936			19,518
Equity Items		(121,200	)		(57,427	)		(38,468	)
Total	$	241,230		$	165,533		$	206,132

Deferred tax assets and liabilities result from the following:

	December 31,
	2005		2004
	(In thousands)
Deferred Tax Assets:
Postretirement Benefits	$	24,788	$	13,932
Gas Supply Realignment Deferred Receipts		250		2,210
Book Accruals		20,967		15,640
Derivatives		163,390		62,642
Capital Loss Carryforwards		935		20,804
Rate Matters		14,139		-
Other		-		6,021
Total Deferred Tax Assets		224,469		121,249
Deferred Tax Liabilities:
Property, Plant and Equipment		2,378,510		1,771,710
Investments		977,680		826,939
Prepaid Pension Costs		11,232		20,103
Rate Matters		-		2,364
Other		2,535		-
Total Deferred Tax Liabilities		3,369,957		2,621,116
Net Deferred Tax Liabilities	$	3,145,488	$	2,499,867
Current Deferred Tax Asset	$	10,905	$	30,198
Non-current Deferred Tax Liability		3,156,393		2,530,065
Net Deferred Tax Liabilities	$	3,145,488	$	2,499,867

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

66

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.

12. Financing

(A) Notes Payable

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 P artners 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:

·

Nonpayment of interest, principal or fees;

·

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

·

Adverse judgments in excess of $75,000,000; and

·

Voluntary or involuntary bankruptcy or liquidation.

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 c redit 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 Terasen Inc. credit facilities include the following financial covenants:

·

Total debt not to exceed 75% of total debt plus shareholder’s equity; and

·

Interest coverage ratio not less than 1.25:1.

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

·

Nonpayment of interest, principal or fees;

·

Unsatisfied awards; and

67

·

Voluntary or involuntary bankruptcy or liquidation.

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 Terasen Gas Inc. credit facilities do not include financial covenants.

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

·

Nonpayment of interest, principal or fees; and

·

Voluntary or involuntary bankruptcy or liquidation.

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.

This credit facility includes the following financial covenants:

·

Indebtedness to rate base ratio not to exceed 75%.

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

·

Nonpayment of interest, principal or fees;

·

Unsatisfied judgments in excess of C$15,000,000; and

·

Voluntary or involuntary bankruptcy or liquidation.

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

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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%.

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(B) Long-term Debt

	December 31,
	2005			2004
	(In thousands)
Kinder Morgan, Inc.
Debentures:
6.50% Series, Due 2013	$	40,000		$	45,000
7.35% Series, Due 2026		125,000			125,000
6.67% Series, Due 2027		150,000			150,000
7.25% Series, Due 2028		493,000			493,000
7.45% Series, Due 2098		150,000			150,000
Senior Notes:
6.65% Series, Due 2005		-			500,000
6.80% Series, Due 2008		300,000			300,000
6.50% Series, Due 2012		1,000,000			1,000,000
5.15% Series, Due 2015		250,000			-
Deferrable Interest Debentures Issued to Subsidiary Trusts1:
8.56% Junior Subordinated Deferrable Interest Debentures Due 2027		103,100			103,100
7.63% Junior Subordinated Deferrable Interest Debentures Due 2028		180,500			180,500
Carrying Value Adjustment for Interest Rate Swaps2		54,860			85,897
Unamortized Gain (Loss) on Termination of Interest Rate Swap		(3,161	)		2,346
Kinder Morgan Finance Company, ULC
5.35% Series, Due 2011		750,000			-
5.70% Series, Due 2016		850,000			-
6.40% Series, Due 2036		550,000			-
Terasen Inc.4
Medium Term Notes:
6.30% Series 1, Due 20083		181,930			-
4.85% Series 2, Due 20063		86,340			-
5.56% Series 3, Due 20143		113,139			-
8% Capital Securities, Due 2040		107,137			-
Carrying Value Adjustment for Interest Rate Swaps2		132			-
Terasen Gas Inc. 4
Purchase Money Mortgages:
11.80% Series A, Due 2015		64,449			-
10.30% Series B, Due 2016		171,969			-
Debentures and Medium Term Notes:
9.75% Series D, Due 2006		17,197			-
10.75% Series E, Due 2009		51,496			-
6.20% Series 9, Due 2008		161,651			-
6.95% Series 11, Due 2029		128,977			-
6.50% Series 13, Due 2007		85,985			-
6.15% Series 16, Due 2006		85,985			-
6.50% Series 18, Due 2034		128,977			-
5.90% Series 19, Due 2035		128,977			-
Floating Rate Series 20, interest rate of 3.36% Due 2007		128,977			-
Obligations under Capital Leases, at 6.07% (2004 – 6.23%)		7,537			-
Terasen Gas (Vancouver Island) Inc.4
Syndicated credit facility at short-term floating rates, weighted-average interest rate of 3.88% with maturities of $176.5 million in 2006 and $33.0 million in 2009		180,101			-
Terasen Pipelines (Corridor) Inc. 4
Debentures:
4.24% Series A, Due 2010		128,977			-
5.033% Series B, Due 2015		128,977			-
Unamortized Premium on Long-term Debt		2,921			3,359
Unamortized Debt Discount		(8,366	)		(3,409	)
Current Maturities of Long-term Debt		(347,400	)		(505,000	)
Total Long-term Debt	$	6,729,364		$	2,629,793

¹

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.

²

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

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³

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.

⁴

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.

Kinder Morgan, Inc.

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 pro spectus supplements, which redemption prices generally do not make early redemption an economically favorable alternative.

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 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.

Kinder Morgan Finance Company, ULC

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.

Terasen Inc.

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.

Terasen Gas Inc.

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

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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.

Terasen Gas (Vancouver Island) Inc.

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.

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.

(C) Capital Trust Securities

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 Securiti es 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.

(D) Capital 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.

(E) Common Stock

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

72

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.

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.

(F) Kinder Morgan Management, LLC

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 2004 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.

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.

13. Preferred 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.

14. Risk Management

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 d erivative’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

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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 have historically purchased, sold and/or consumed 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.  Our U.S.-based natural gas distribution business became subject to a definitive sale agreement in 2006, see Note 7.

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)  has given 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) have given 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 chose Kinder Morgan Retail as their Choice Gas supplier, we entered into agreements providing for sales of gas to these customers during a one-year period at fixed prices per unit, but variable volumes. We have mitigated 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 have mitigated a portion of the volumet ric risk through the purchase of over-the-counter natural gas options. The time period covered by this risk management strategy did not extend beyond one year and will no longer be necessary after the completion of the sale of our U.S.-based natural gas distribution operations as discussed preceding.

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 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.

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. Including our discontinued U.S.-based natural gas distribution operations, 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”, “Gas Purchases and Other Costs of Sales” and “Income from Discontinued Operations, Net of Tax” 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. Including amounts attributable to our discontinued U.S.-based natural gas distribution operations, 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.

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

74

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 comparabl e 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.

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 and entered into two new interest rate swap agreements with a notional value of C$195 million. See Note 21 for additional details on these transactions.

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.

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·

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, 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 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 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 but including our discontinued U.S.-based natural gas distribution operations, as of December 31, 2005:

	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		-				-			-

¹ 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.

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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.

	Commodity Contracts		Over the Counter Swaps and Options Contracts				Total
	(Dollars in thousands)
Deferred Net Gain (Loss)	$	-		$	84,651		$	84,651
Contract Amounts — Gross	$	-		$	455		$	455
Contract Amounts — Net	$	-		$	334		$	334
	(Number of contracts1)
Natural Gas
Notional Volumetric Positions: Long		-			58			58
Notional Volumetric Positions: Short		-			(8	)		(8	)
Net Notional Totals to Occur in 2006		-			32			32
Net Notional Totals to Occur in 2007 and Beyond		-			18			18

¹ 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.

15. Employee Benefits

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.

Kinder Morgan, Inc.

(A) Retirement 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 amounts in this footnote do not reflect any changes which may result from the expected sale of our U.S.-based natural gas distribution operations as discussed in Note 7.

Net periodic pension cost includes the following components:

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Service Cost	$	9,614		$	8,619		$	8,133
Interest Cost		12,133			11,566			11,118
Expected Return on Assets		(20,279	)		(16,338	)		(13,282	)
Net Amortization and Deferral		701			227			1,625
Net Periodic Pension Benefit Cost	$	2,169		$	4,074		$	7,594

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

	2005			2004
	(In thousands)
Benefit Obligation at Beginning of Year	$	204,881		$	180,862
Service Cost		9,614			8,619
Interest Cost		12,133			11,566
Actuarial Loss		8,497			13,865
Plan Amendments		3			-
Benefits Paid		(10,607	)		(10,031	)
Benefit Obligation at End of Year	$	224,521		$	204,881

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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:

	December 31,
	2005			2004
	(In thousands)
Fair Value of Plan Assets at Beginning of Year	$	206,610		$	185,610
Actual Return on Plan Assets During the Year		21,375			24,197
Contributions by Employer		25,034			6,834
Benefits Paid During the Year		(10,607	)		(10,031	)
Fair Value of Plan Assets at End of Year		242,412			206,610
Benefit Obligation at End of Year		(224,521	)		(204,881	)
Plan Assets in Excess of Projected Benefit Obligation		17,891			1,729
Unrecognized Net Loss		32,440			25,596
Prior Service Cost Not Yet Recognized in Net Periodic Pension Costs		1,666			1,840
Unrecognized Net Asset at Transition		-			(33	)
Prepaid Pension Cost	$	51,997		$	29,132

We do not expect to contribute to the Plan during 2006.

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:

Fiscal Year	Expected Net Benefit Payments
		(In thousands)
2006	$11,312
2007	$12,117
2008	$12,693
2009	$14,084
2010	$14,893
2011-2015	$93,819

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 vehic les 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

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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 o f 2006, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2005.

(B) Other Postretirement Employee Benefits

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 amounts in this footnote do not reflect any changes which may result from the expected sale of our U.S.-based natural gas distribution operations as discussed in Note 7.

Net periodic postretirement benefit cost includes the following components:

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Service Cost	$	382		$	373		$	406
Interest Cost		5,320			5,652			6,968
Expected Return on Assets		(5,710	)		(5,178	)		(5,450	)
Net Amortization and Deferral		3,309			3,199			3,333
Net Periodic Postretirement Benefit Cost	$	3,301		$	4,046		$	5,257

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

	2005			2004
	(In thousands)
Benefit Obligation at Beginning of Year	$	91,940		$	106,939
Service Cost		382			373
Interest Cost		5,320			5,652
Actuarial Loss		1,353			21,045
Benefits Paid		(13,055	)		(13,906	)
Retiree Contributions		3,875			3,796
Plan Amendments		-			(31,959	)
Benefit Obligation at End of Year	$	89,815		$	91,940

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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:

	December 31,
	2005			2004
	(In thousands)
Fair Value of Plan Assets at Beginning of Year	$	60,143		$	62,693
Actual Return on Plan Assets		2,003			9,888
Contributions by Employer		8,500			-
Retiree Contributions		3,876			3,728
Transfers In		218			-
Benefits Paid		(15,301	)		(16,166	)
Fair Value of Plan Assets at End of Year		59,439			60,143
Benefit Obligation at End of Year		(89,815	)		(91,940	)
Excess of Projected Benefit Obligation Over Plan Assets		(30,376	)		(31,797	)
Unrecognized Net Loss		70,201			68,084
Unrecognized Prior Service Cost		(17,945	)		(19,606	)
Prepaid Expense	$	21,880		$	16,681

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:

Fiscal Year	Expected Net Benefit Payments
	(In thousands)
2006	$ 7,535
2007	$ 7,339
2008	$ 7,152
2009	$ 7,007
2010	$ 6,843
2011-2015	$32,601

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.

(C) Actuarial Assumptions

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

	December 31,
	2005	2004	2003
Discount Rate	5.75%	6.00%	6.50%
Expected Long-term Return on Assets	9.00%	9.00%	9.00%
Rate of Compensation Increase (Pension Plan Only)	3.50%	3.50%	3.50%

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

	Year Ended December 31,
	2005	2004	2003
Discount Rate	6.00%	6.50%	7.00%
Expected Long-term Return on Assets	9.00%	9.00%	9.00%
Rate of Compensation Increase (Pension Plan Only)	3.50%	3.50%	3.50%

The assumed healthcare cost trend rates for the postretirement plan were:

	December 31,
	2005	2004	2003
Healthcare Cost Trend Rate Assumed for Next Year	3.0%	3.0%	3.0%
Rate to which the Cost Trend Rate is Assumed to     Decline (Ultimate Trend Rate)	3.0%	3.0%	3.0%
Year the Rate Reaches the Ultimate Trend Rate	2005	2004	2003

(D) Plan Investment Policies

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 investme nt 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 prot ection (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.

(E) Return on Plan 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.

Terasen

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:

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(A) Description of Plans

Defined Benefit Plans

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).

Defined Contribution Plan

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.

Supplemental Plans

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.

Other Postretirement Benefits

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).

(B) Actuarial Valuations

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.

Net periodic pension and postretirement costs include the following components:

	Month Ended December 31, 2005
	Pension Benefit Plans			Postretirement Benefit Plans
	(In thousands)
Service Cost	$	656			$	117
Interest Cost		1,248				298
Expected Return on Assets		(1,565	)			-
Expense Load		17				8
Net Periodic Pension Benefit Cost		356				423
Defined Contribution Cost		162				-
Total Benefit Expense	$	518			$	423

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

	Pension Benefit Plans			Postretirement Benefit Plans
	(In thousands)
Benefit Obligation at November 30, 2005	$	284,580			$	67,841
Service Cost		656				117
Interest Cost		1,248				298
Change in Discount Rate		6,808				2,312
Actuarial Loss		3,333				-
Contributions by Members		348				-
Benefits Paid		(850	)			(105	)
Benefit Obligation at End of Year	$	296,123			$	70,463

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:

	December 31, 2005
	Pension Benefit Plans			Postretirement Benefit Plans
	(In thousands)
Fair Value of Plan Assets at November 30, 2005	$	254,471			$	-
Actual Return on Plan Assets During the Period		2,201				-
Contributions by Employer		533				113
Contributions by Members		348				-
Expense Load		(14	)			(8	)
Benefits Paid During the Period		(850	)			(105	)
Fair Value of Plan Assets at End of Year		256,689				-
Benefit Obligation at End of Year		(296,123	)			(70,463	)
Projected Benefit Obligation in Excess of Plan Assets		(39,434	)			(70,463	)
Additional Minimum Benefit Liability		(1,850	)			-
Unrecognized Net Loss		9,503				2,312
Accrued Benefit Liability	$	(31,781	)		$	(68,151	)

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:

	Expected Net Benefit Payments
Fiscal Year	Pension Benefit Plans			Postretirement Benefit Plans
	(In thousands)
2006		$	11,877		$	1,333
2007		$	12,226		$	1,413
2008		$	12,552		$	1,492
2009		$	13,459		$	1,571
2010		$	13,239		$	1,652
2011-2015		$	74,232		$	9,629

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(C) Actuarial Assumptions

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

	Net Periodic Benefit Cost
	Month Ended		Benefit Obligations
	December 31, 2005		December 31, 2005
Discount Rate		5.25%		5.00%
Expected Long-term Return on Assets		7.50%		-%
Rate of Compensation Increase (Pension Plan Only)		3.50%		3.50%

The assumed healthcare cost trend rates for the postretirement plans were:

	December 31, 2005
Healthcare Cost Trend Rate Assumed for Next Year		7.0%
Rate to which the Cost Trend Rate is Assumed to     Decline (Ultimate Trend Rate)		5.0%
Year the Rate Reaches the Ultimate Trend Rate		2008

(D) Plan Investment Policies

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.

(E) Return on Plan Assets

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.

16. Common Stock Option and Purchase Plans

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 futu re 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

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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.

Plan Name	Shares Subject to the Plan	Option Shares Granted Through December 31, 2005	Vesting Period	Expiration Period
1992 Directors’ Plan	1,025,000	702,875	0 – 6 Months	10 Years
Long-term Incentive Plan	5,700,000	4,070,970	0 – 5 Years	5 – 10 Years
1999 Plan	10,500,000	8,058,468	3 – 4 Years	7 – 10 Years
Non-Employee Directors Plan	500,000	15,750	0 – 6 Months	10 Years

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:

	2005					2004					2003
	Shares		Wtd. Avg. Exercise Price			Shares		Wtd. Avg. Exercise Price			Shares		Wtd. Avg. Exercise Price
Outstanding at Beginning
of Year	5,026,436			$	44.18	6,499,507			$	35.45	7,480,915			$	35.94
Granted	-			$	-	354,525			$	60.91	1,019,700			$	50.42
Exercised	(1,505,399	)		$	41.48	(1,712,685	)		$	34.16	(1,653,991	)		$	26.25
Forfeited	(99,188	)		$	50.48	(114,911	)		$	49.11	(347,117	)		$	36.54
Outstanding at End of Year	3,421,849			$	45.21	5,026,436			$	44.18	6,499,507			$	35.45
Exercisable at End of Year	2,260,059			$	41.01	3,154,197			$	39.47	3,918,118			$	35.46
Weighted-Average Fair
Value of Options Granted				$	-				$	16.87				$	16.60

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:

Options Outstanding					Options Exercisable
Price Range	Number Outstanding	Wtd. Avg. Exercise Price		Wtd. Avg. Remaining Contractual Life	Number Exercisable	Wtd. Avg. Exercise Price
$00.00 - $23.81	519,442	$	23.73	3.64 years	519,442	$	23.73
$24.04 - $43.10	830,802	$	36.00	5.31 years	617,477	$	34.31
$49.00 - $53.20	828,341	$	50.95	5.16 years	828,341	$	50.95
$53.60 - $60.18	913,389	$	54.93	5.12 years	234,799	$	56.61
$60.79 - $61.40	329,875	$	60.90	6.01 years	60,000	$	61.40
	3,421,849	$	45.21	5.04 years	2,260,059	$	41.01

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.

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17. Commitments and Contingent Liabilities

(A) Leases and Guarantee

Expenses incurred under operating leases associated with continuing operations were $24.5 million in 2005, $24.0 million in 2004 and $5.9 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:

Year	Operating Leases		Purchase Obligations		Total
	(In millions)
2006	$	47.2	$	790.9	$	838.1
2007		46.0		98.5		144.5
2008		44.2		29.5		73.7
2009		41.9		27.1		69.0
2010		40.9		1.3		42.2
Thereafter		557.3		-		557.3
Total	$	777.5	$	947.3	$	1,724.8

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.

(B) Capital Expenditures Budget

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.

(C) Commitments for Incremental Investment

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.

(D) Government Grant

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 ca pital structure, as will the rate base used in determining rates. The amounts are not

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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.

(E) Standby Letters of Credit

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, Michiga n 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.

(F) Other Obligations

Other obligations are discussed in Note 7.

18. Fair Value

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.

	December 31,
	2005						2004
	Carrying Value			Fair Value			Carrying Value			Fair Value
	(In millions)
Financial Liabilities:
Long-term Debt:
Kinder Morgan, Inc.	$	2,846.4	1	$	3,043.5	1	$	3,132.5	1	$	3,420.6	1
Kinder Morgan Finance Company, ULC		2,150.0			2,167.6			-			-
Terasen Inc.		488.7	1		482.0	1		-			-
Terasen Gas Inc.		1,162.2			1,359.2			-			-
Terasen Gas (Vancouver Island) Inc.		180.1			180.1			-			-
Terasen Pipelines (Corridor) Inc.		258.0			259.8			-			-
	$	7,085.4		$	7,492.2		$	3,132.5		$	3,420.6
Energy Financial Instruments, Net	$	48.2		$	48.2		$	(0.2	)	$	(0.2	)
Outstanding Interest Rate Swaps:
Kinder Morgan, Inc.	$	(54.9	)	$	(54.9	)	$	(85.9	)	$	(85.9	)
Kinder Morgan Finance Company, ULC		14.2			14.2			-			-
Terasen Inc.		3.1			3.1			-			-
Terasen Gas Inc.		(1.4	)		(1.4	)		-			-
Terasen Gas (Vancouver Island) Inc.		(0.6	)		(0.6	)		-			-
Terasen Pipelines (Corridor) Inc.		0.3			0.3			-			-
	$	(39.3	)	$	(39.3	)	$	(85.9	)	$	(85.9	)

___________

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

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19. Business Segment Information

In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business segment performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system; (2) 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; (3) Kinder Morgan Canada (formerly Terasen Pipelines), principally consisting of the ownership and operation of three refined products and crude oil pipelines, (a) Trans Mountain Pipeline, (b) Corridor Pipeline and (c) a one-third interest in the Express and Platte pipeline systems; (4) Terasen Gas, the regulated sale and transportation of natural gas to resi dential, commercial and industrial customers in British Columbia, Canada; and (5) Power, the operation and, in previous periods, construction of natural gas-fired electric generation facilities. Our investment in TransColorado Gas Transmission Company was contributed to Kinder Morgan Energy Partners effective November 1, 2004 (see Note 5). In previous periods, we owned and operated other lines of business that we discontinued during 1999. In 2005, we discontinued the water and utility services businesses acquired with Terasen.  In 2006, we entered into a definitive agreement to sell our U.S.-based natural gas distribution operations, which were historically reported as the Kinder Morgan Retail segment and are now included in discontinued operations, see Note 7.

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 cur rently 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 pipelin es, 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”).

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

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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.

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Business Segment Information

	Year Ended December 31, 2005									December 31, 2005
	Segment Earnings			Revenues From External Customers1		Depreciation And Amortization		Capital Expenditures		Segment Assets
	(In thousands)
Natural Gas Pipeline Company of America	$	435,154		$	947,349	$	99,613	$	129,668	$	5,597,805
Kinder Morgan Canada		12,549			18,941		3,004		5,301		1,681,937
Terasen Gas		45,187			223,322		7,431		9,538		3,670,155
Power2		19,693			54,166		3,327		-		372,527
Segment Totals		512,583			1,243,778	$	113,375	$	144,507		11,322,424
Other Revenues3					10,749
Total Revenues				$	1,254,527
Earnings from Investment in Kinder   Morgan Energy Partners		605,399				Investment in Kinder Morgan
General and Administrative Expenses		(72,334	)			Energy Partners					2,202,946
Other Income and (Expenses)		(170,280	)			Goodwill					2,781,041
Income from Continuing Operations						Other4					1,145,203
Before Income Taxes	$	875,368				Consolidated				$	17,451,614

	Year Ended December 31, 2004									December 31, 2004
	Segment Earnings			Revenues From External Customers1		Depreciation And Amortization		Capital Expenditures		Segment Assets
	(In thousands)
Natural Gas Pipeline Company of America	$	392,806		$	778,878	$	94,462	$	88,202	$	5,546,509
TransColorado5		20,255			28,795		3,605		15,002		-
Power2		15,255			70,064		3,552		-		378,008
Segment Totals		428,316		$	877,737	$	101,619	$	103,204		5,924,517
Earnings from Investment in Kinder   Morgan Energy Partners		558,078				Investment in Kinder Morgan
General and Administrative Expenses		(67,673	)			Energy Partners					2,305,212
Other Income and (Expenses)		(212,524	)			Goodwill					918,076
Income from Continuing Operations						Other4					969,096
Before Income Taxes	$	706,197				Consolidated				$	10,116,901

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	Year Ended December 31, 2003									December 31, 2003
	Segment Earnings			Revenues From External Customers1		Depreciation And Amortization		Capital Expenditures		Segment Assets
	(In thousands)
Natural Gas Pipeline Company of America	$	372,017		$	784,732	$	92,193	$	114,504	$	5,551,595
TransColorado5		23,112			32,197		4,224		14,841		267,597
Power2		22,076			31,849		4,914		2,643		450,799
Segment Totals		417,205		$	848,778	$	101,331	$	131,988		6,269,991
Earnings from Investment in Kinder   Morgan Energy Partners		464,967				Investment in Kinder Morgan
General and Administrative Expenses		(62,191	)			Energy Partners					2,106,312
Other Income and (Expenses)		(238,258	)			Goodwill					972,380
Income from Continuing Operations						Other4					688,028
Before Income Taxes	$	581,723				Consolidated				$	10,036,711

______________

¹

There were no intersegment revenues during the periods presented.

²

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 (see Notes 5 and 6).

³

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.

⁴

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.

⁵

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.

Geographic Information

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.

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Revenues from External Customers

	Year Ended December 31, 2005
	United States		Canada		Total
	(In thousands)
Natural Gas Pipeline Company of America	$	947,349	$	-	$	947,349
Kinder Morgan Canada		946		17,995		18,941
Terasen Gas		-		223,322		223,322
Power		54,166		-		54,166
	$	1,002,461	$	241,317	$	1,243,778

Long-lived Assets

	At December 31, 2005
	United States		Canada		Total
	(In thousands)
Natural Gas Pipeline Company of America	$	5,470,841	$	-	$	5,470,841
Kinder Morgan Canada		313,304		1,342,430		1,655,734
Terasen Gas		-		3,000,815		3,000,815
Power		338,290		-		338,290
Investment in Kinder Morgan Energy Partners		2,202,946		-		2,202,946
Other		234,269		35,698		269,967
	$	8,559,650	$	4,378,943	$	12,938,593

20. Recent Accounting Pronouncements

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 o ur 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

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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 new 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:

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	Increase (Decrease)
	(In millions)
Current Assets		$	1,199
Investments:
Kinder Morgan Energy Partners			(2,203	)
Other			1,329
Other Non-current Assets			9,379
		$	9,704
Current Liabilities		$	1,792
Long-term Debt			5,319
Other Long-term Liabilities			1,140
Minority Interest in Equity of Subsidiaries			1,453
Stockholders’ Equity			-
		$	9,704

21. Subsequent Events

In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S.-based natural gas distribution and related operations for $710 million plus working capital, see Note 7.

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.

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 i n 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, 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.

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 c onditions 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.

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

	Three Months Ended
	March 31		June 30		September 30			December 31
	(In thousands except per share amounts) (Unaudited)
Operating Revenues	$	215,751	$	233,994	$	246,759		$	558,023
Gas Purchases and Other Costs of Sales		41,925		63,561		82,348			270,951
Other Operating Expenses		74,857		82,823		81,431			132,742	1
Operating Income		98,969		87,610		82,980			154,330
Other Income and (Expenses)		113,065		122,622		107,069			108,723
Income from Continuing Operations Before Income Taxes		212,034		210,232		190,049			263,053
Income Taxes		83,525		88,582		77,150			96,252
Income from Continuing Operations		128,509		121,650		112,899			166,801
Income (Loss) from Discontinued Operations, Net of Tax		14,770		346		(3,735	)		13,379
Net Income	$	143,279	$	121,996	$	109,164		$	180,180
Basic Earnings (Loss) Per Common Share:
Income from Continuing Operations	$	1.04	$	1.00	$	0.92		$	1.32
Income (Loss)from Discontinued Operations		0.12		-		(0.03	)		0.11
Total Basic Earnings Per Common Share	$	1.16	$	1.00	$	0.89		$	1.43
Number of Shares Used in Computing Basic Earnings Per Common Share		123,204		122,012		122,494			126,128
Diluted Earnings (Loss) Per Common Share:
Income from Continuing Operations	$	1.03	$	0.99	$	0.91		$	1.31
Income (Loss)from Discontinued Operations		0.12		-		(0.03	)		0.11
Total Diluted Earnings Per Common Share	$	1.15	$	0.99	$	0.88		$	1.42
Number of Shares Used in Computing
Diluted Earnings Per Common Share		124,413		123,103		123,684			127,249

¹Includes a charge of $6.5 million to record an impairment of certain of our Power assets; see Note 6.

 

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

	Three Months Ended
	March 31		June 30		September 30		December 31
	(In thousands except per share amounts) (Unaudited)
Operating Revenues	$	241,126	$	194,238	$	203,432	$	238,941
Gas Purchases and Other Costs of Sales		71,255		31,128		30,368		61,493
Other Operating Expenses		78,256		76,868		79,461		107,898	1
Operating Income		91,615		86,242		93,603		69,550
Other Income and (Expenses)		87,073		85,277		90,137		102,700
Income from Continuing Operations Before Income Taxes		178,688		171,519		183,740		172,250
Income Taxes		69,709		67,437		72,005		(1,127	)
Income from Continuing Operations		108,979		104,082		111,735		173,377
Income from Discontinued Operations, Net of Tax		18,063		308		195		5,341
Net Income	$	127,042	$	104,390	$	111,930	$	178,718
Basic Earnings (Loss) Per Common Share:
Income from Continuing Operations	$	0.88	$	0.84	$	0.91	$	1.40
Income from Discontinued Operations		0.15		-		-		0.04
Total Basic Earnings Per Common Share	$	1.03	$	0.84	$	0.91	$	1.44
Number of Shares Used in Computing Basic Earnings Per Common Share		123,715		123,882		123,673		123,844
Diluted Earnings (Loss) Per Common Share:
Income from Continuing Operations	$	0.87	$	0.84	$	0.90	$	1.39
Income from Discontinued Operations		0.15		-		-		0.04
Total Diluted Earnings Per Common Share	$	1.02	$	0.84	$	0.90	$	1.43
Number of Shares Used in Computing Diluted Earnings Per Common Share		124,938		124,955		124,683		125,021

¹Includes a charge of $33.5 million to record an impairment of certain of our Power assets; see Note 6.

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Supplemental Information on Oil and Gas Producing Activities (Unaudited)

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:

	December 31,
	2005		2004		2003
	(In thousands)
Net Capitalized Costs	$	169,448	$	176,566	$	145,224
Costs Incurred for the Year Ended		43,780		54,261		112,631	1
Results of Operations for the Year Ended		18,239		15,173		7,836	1

¹

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 additiona l 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.

	December 31,
	2005		2004		2003		20021
Proved Reserves:
Crude Oil (MBbls)		21,567		22,862		22,160		14,637
Natural Gas Liquids (MBbls)		2,884		3,741		3,091		3,114
Natural Gas (MMcf)2		327		294		626		3,568
Standardized Measure of Discounted Cash Flows     for the Year Ended	$	467,196	$	377,845	$	267,544

¹

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.

²

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

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