KMI Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006
or
  

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________to_____________

Commission file number 1-06446
  

Kinder Morgan, Inc.

(Exact name of registrant as specified in its charter)
  

Kansas	48-0290000
(State or other jurisdiction of incorporation or organization)	(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)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ  No o

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

Large accelerated filer þ  Accelerated filer o  Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o  No þ

The number of shares outstanding of the registrant’s common stock, $5 par value, as of April 28, 2006 was 133,629,425 shares.

KMI Form 10-Q

KINDER MORGAN, INC. AND SUBSIDIARIES

FORM 10-Q

QUARTER ENDED MARCH 31, 2006

Contents

		Page Number
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements. (Unaudited)
	Consolidated Balance Sheets	3-4
	Consolidated Statements of Operations	5
	Consolidated Statements of Cash Flows	6-7
	Notes to Consolidated Financial Statements	8-53
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	54-72
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	72
Item 4.	Controls and Procedures.	72-73
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings.	73
Item 1A.	Risk Factors	73
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	73
Item 3.	Defaults Upon Senior Securities.	73
Item 4.	Submission of Matters to a Vote of Security Holders.	73
Item 5.	Other Information.	73
Item 6.	Exhibits.	73
SIGNATURE		74

2

KMI Form 10-Q

PART I. - FINANCIAL INFORMATION

Item 1.  Financial Statements.

CONSOLIDATED BALANCE SHEETS (Unaudited)

Kinder Morgan, Inc. and Subsidiaries

	March 31, 2006		December 31, 2005
	(In millions)
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	183.6	$	116.6
Restricted Deposits		49.4		10.6
Accounts, Notes and Interest Receivable, Net:
Trade		1,253.7		489.0
Related Parties		6.9		17.2
Inventories		249.3		228.2
Gas Imbalances		22.8		16.9
Assets Held for Sale		162.2		126.7
Rate Stabilization		62.0		35.7
Other		160.7		263.2
		2,150.6		1,304.1
Notes Receivable – Related Parties		92.0		-
Investments:
Kinder Morgan Energy Partners		-		2,202.9
Other		1,087.4		649.6
		1,087.4		2,852.5
Goodwill		3,572.0		2,781.0
Other Intangibles, Net		233.9		17.7
Property, Plant and Equipment, Net		18,740.5		9,545.6
Deferred Charges and Other Assets		1,128.3		950.7
Total Assets	$	27,004.7	$	17,451.6

The accompanying notes are an integral part of these statements.

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KMI Form 10-Q

CONSOLIDATED BALANCE SHEETS (Unaudited)

Kinder Morgan, Inc. and Subsidiaries

	March 31, 2006			December 31, 2005
	(In millions except shares)
LIABILITIES AND STOCKHOLDERS’ EQUITY:
Current Liabilities:
Current Maturities of Long-term Debt	$	209.7		$	347.4
Notes Payable		1,428.0			610.6
Cash Book Overdrafts		46.2			-
Accounts Payable – Trade		955.7			431.2
Accrued Interest		134.0			92.0
Accrued Taxes		168.9			100.1
Gas Imbalances		25.0			16.1
Rate Stabilization		50.4			115.1
Liabilities Held for Sale		77.3			21.9
Other		825.1			208.2
		3,920.3			1,942.6
Other Liabilities and Deferred Credits:
Deferred Income Taxes		3,229.4			3,156.4
Other		1,666.1			451.5
		4,895.5			3,607.9
Long-term Debt:
Outstanding Notes and Debentures		11,163.2			6,286.8
Deferrable Interest Debentures Issued to Subsidiary Trusts		283.6			283.6
Capital Securities		107.4			107.2
Value of Interest Rate Swaps		(22.7	)		51.8
		11,531.5			6,729.4
Minority Interests in Equity of Subsidiaries		2,688.1			1,247.3
Stockholders’ Equity:
Common Stock-
Authorized - 300,000,000 Shares, Par Value $5 Per Share
Outstanding – 148,659,412 and 148,479,863 Shares, Respectively, Before Deducting 15,055,151 and 14,712,901 Shares Held in Treasury		743.3			742.4
Additional Paid-in Capital		3,035.2			3,056.3
Retained Earnings		1,251.9			1,175.3
Treasury Stock		(917.3	)		(885.7	)
Deferred Compensation		-			(36.9	)
Accumulated Other Comprehensive Loss		(143.8	)		(127.0	)
Total Stockholders’ Equity		3,969.3			3,924.4
Total Liabilities and Stockholders’ Equity	$	27,004.7		$	17,451.6

The accompanying notes are an integral part of these statements.

4

KMI Form 10-Q

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

Kinder Morgan, Inc. and Subsidiaries

	Three Months Ended March 31,
	2006			2005
	(In millions except per share amounts)
Operating Revenues:
Natural Gas Sales	$	2,394.7		$	109.8
Transportation and Storage		819.7			207.4
Oil and Product Sales		174.4			1.6
Other		44.5			18.1
Total Operating Revenues		3,433.3			336.9
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales		2,257.6			112.6
Operations and Maintenance		301.9			40.1
General and Administrative		102.2			16.7
Depreciation, Depletion and Amortization		155.7			29.4
Taxes, Other Than Income Taxes		56.3			8.5
Total Operating Costs and Expenses		2,873.7			207.3
Operating Income		559.6			129.6
Other Income and (Expenses):
Equity in Earnings of Kinder Morgan Energy Partners		-			154.0
Equity in Earnings of Other Equity Investments		33.0			3.3
Interest Expense, Net		(181.4	)		(35.8	)
Interest Expense – Deferrable Interest Debentures		(5.5	)		(5.5	)
Interest Expense – Capital Securities		(2.1	)		-
Minority Interests		(90.1	)		(11.7	)
Other, Net		(17.7	)		6.1
Total Other Income and (Expenses)		(263.8	)		110.4
Income from Continuing Operations Before Income Taxes		295.8			240.0
Income Taxes		101.3			94.9
Income from Continuing Operations		194.5			145.1
Loss from Discontinued Operations, Net of Tax		(0.8	)		(1.8	)
Net Income	$	193.7		$	143.3
Basic Earnings (Loss) Per Common Share:
Income from Continuing Operations	$	1.46		$	1.18
Loss from Discontinued Operations		(0.01	)		(0.02	)
Total Basic Earnings Per Common Share	$	1.45		$	1.16
Number of Shares Used in Computing Basic Earnings Per Common Share		133.7			123.2
Diluted Earnings (Loss) Per Common Share:
Income from Continuing Operations	$	1.44		$	1.17
Loss from Discontinued Operations		(0.01	)		(0.02	)
Total Diluted Earnings Per Common Share	$	1.43		$	1.15
Number of Shares Used in Computing Diluted Earnings Per Common Share		135.0			124.4
Dividends Per Common Share	$	0.8750		$	0.7000

The accompanying notes are an integral part of these statements.

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KMI Form 10-Q

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

Kinder Morgan, Inc. and Subsidiaries

Increase (Decrease) in Cash and Cash Equivalents

	Three Months Ended March 31,
	2006			2005
	(In millions)
Cash Flows From Operating Activities:
Net Income	$	193.7		$	143.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Loss from Discontinued Operations, Net of Tax		0.8			1.8
Depreciation and Amortization		155.7			29.4
Deferred Income Taxes		32.8			37.0
Equity in Earnings of Kinder Morgan Energy Partners		-			(154.0	)
Distributions from Kinder Morgan Energy Partners		-			124.4
Equity in Earnings of Other Investments		(33.0	)		(3.3	)
Distributions from Other Equity Investees		24.3			2.9
Minority Interests in Income of Consolidated Subsidiaries		90.1			11.7
Changes in Rate Stabilization Accounts		(37.1	)		-
Deferred Purchased Gas Costs		4.1			9.8
Net Gains on Sales of Assets		(0.2	)		(5.1	)
Mark-to-Market Interest Rate Swap Loss		22.3			-
Pension Contribution in Excess of Expense		-			(24.7	)
Changes in Gas in Underground Storage		13.9			(21.8	)
Changes in Working Capital Items		7.3			(104.9	)
Payment to Terminate Interest Rate Swap		-			(3.5	)
Other, Net		(31.7	)		(10.2	)
Net Cash Flows Provided by Continuing Operations		443.0			32.8
Net Cash Flows Used in Discontinued Operations		(5.4	)		(0.5	)
Net Cash Flows Provided by Operating Activities		437.6			32.3
Cash Flows From Investing Activities:
Capital Expenditures		(259.6	)		(15.2	)
Acquisition of Entrega		(240.0	)		-
Acquisition of Terasen		(9.7	)		-
Net (Investments in) Proceeds from Margin Deposits		(38.9	)		17.2
Other Investments		(3.4	)		(0.3	)
Sale of Kinder Morgan Management Shares		-			17.5
Natural Gas Stored Underground and Natural Gas Liquids Line-fill		(9.8	)		-
Sales of Other Assets Net of Removal Costs		6.1			(0.7	)
Net Cash Flows (Used in) Provided by Continuing Investing Activities		(555.3	)		18.5
Net Cash Flows Used in Discontinued Investing Activities		(1.7	)		-
Net Cash Flows (Used in) Provided by Investing Activities		(557.0	)		18.5

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KMI Form 10-Q

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (continued)

Kinder Morgan, Inc. and Subsidiaries

Increase (Decrease) in Cash and Cash Equivalents

	Three Months Ended March 31,
	2006			2005
	(In millions)
Cash Flows From Financing Activities:
Short-term Debt, Net		251.3			221.0
Long-term Debt Issued		274.6			250.0
Long-term Debt Retired		(183.3	)		(500.0	)
Increase in Cash Book Overdrafts		4.5			11.0
Common Stock Issued		8.1			28.4
Excess Tax Benefits from Share-based Payment Arrangements		3.2			-
Short-term Advances (To) From Unconsolidated Affiliates		(4.2	)		13.9
Treasury Stock Acquired		(34.3	)		(153.5	)
Cash Dividends, Common Stock		(117.1	)		(86.4	)
Minority Interests, Contributions		90.7			-
Minority Interests, Distributions		(115.5	)		-
Debt Issuance Costs		(2.7	)		(1.5	)
Other, Net		(1.1	)		-
Net Cash Flows Provided by (Used in) Continuing Financing Activities		174.2			(217.1	)
Net Cash Flows Provided by Discontinued Financing Activities		0.5			-
Net Cash Flows Provided by (Used in) Financing Activities		174.7			(217.1	)
Effect of Exchange Rate Changes on Cash		(0.4	)		-
Effect of Accounting Change on Cash		12.1			-
Net Increase (Decrease) in Cash and Cash Equivalents		67.0			(166.3	)
Cash and Cash Equivalents at Beginning of Period		116.6			176.5
Cash and Cash Equivalents at End of Period	$	183.6		$	10.2

For supplemental cash flow information, see Note 1(K).

The accompanying notes are an integral part of these statements.

7

KMI Form 10-Q

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

We are one of the largest energy transportation and storage companies in North America, operating or owning an interest in approximately 43,000 miles of pipelines and approximately 150 terminals. We have both regulated and nonregulated operations. We also own the general partner interest and a significant limited partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline limited partnership. Due to our implementation of a recent accounting pronouncement (see Note 1(C)), we are including Kinder Morgan Energy Partners and its consolidated subsidiaries in our consolidated financial statements effective January 1, 2006. This means that for the first time the accounts, balances and results of operations of Kinder Morgan Energy Partners and its consolidated subsidiaries are presented on a consolidated basis with ours and those of our other consolidated subsidiaries for financial reporting purposes, instead of equity method accounting as previously reported. Our common stock is traded on the New York Stock Exchange under the ticker symbol “KMI.” Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000. Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Unless the context requires otherwise, references to “Kinder Morgan Energy Partners” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries.

We have prepared the accompanying unaudited interim consolidated financial statements under the rules and regulations of the Securities and Exchange Commission. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America. We believe, however, that our disclosures are adequate to make the information presented not misleading. The consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods presented. You should read these interim consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2005 (“2005 Form 10-K”) and the consolidated financial statements and related notes included in Kinder Morgan Energy Partners’ Annual Report on Form 10-K for the year ended December 31, 2005 (“Kinder Morgan Energy Partners’ 2005 Form 10-K”).

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 at December 31, 2005. 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 operates between the Athabasca oilsands and 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. Further information regarding this acquisition is available in our 2005 Form 10-K.

1.

Nature of Operations and Summary of Significant Accounting Policies

For a complete discussion of our significant accounting policies, see Note 1 of Notes to Consolidated Financial Statements included in our 2005 Form 10-K and Note 2 of Notes to Consolidated Financial Statements included in Kinder Morgan Energy Partners’ 2005 Form 10-K.

(A)

Stock-Based Compensation

Effective January 1, 2006, we implemented Statement of Financial Accounting Standards (“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. Because we have used the fair-value method of accounting for stock-based compensation for pro forma disclosure under SFAS No. 123, we are applying SFAS No. 123R using the modified prospective method. 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.

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KMI Form 10-Q

	Effect of Applying Statement No. 123(R) Three Months Ended March 31, 2006
	(In millions, except per share amounts)
Income from Continuing Operations Before Income Taxes		$	(1.9	)
Income from Continuing Operations		$	(1.2	)
Net Income		$	(1.2	)
Basic Earnings Per Common Share		$	(0.01	)
Diluted Earnings Per Common Share		$	(0.02	)
Net Cash Flows Provided by Operating Activities		$	(3.2	)
Net Cash Flows Provided by Financing Activities		$	3.2

For the three months ended March 31, 2005, had compensation cost for these plans been determined using the fair-value-based method, net income and diluted earnings per share would have been reduced to the pro forma amounts shown in the table below.

	Three Months Ended March 31, 2005
	(In millions, except per share amounts)
Net Income, As Reported		$	143.3
Add: Stock-based Employee Compensation Expense Included in Reported Net Income, Net of Related Tax Effects			1.2
Deduct: Total Stock-based Employee Compensation Expense Determined under the Fair Value Method for All Awards, Net of Related Tax Effects			(3.5	)
Net Income, Pro Forma		$	141.0
Basic Earnings Per Share:
As Reported		$	1.16
Pro Forma		$	1.14
Diluted Earnings Per Share:
As Reported		$	1.15
Pro Forma		$	1.13

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.

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. Effective January 18, 2006, the 1999 Stock Option Plan was amended to include Restricted Stock Units that may be granted to employees not residing in the United States. Each Restricted Stock Unit corresponds to one share of stock. The Board also recommended, and our shareholders approved at our May 8, 2001 annual meeting, an additional 0.5 million shares for future grants to participants in the 1992 Directors’ Plan, which brings the aggregate number of shares subject to that plan to 1.03 million. On July 16, 2003, approximately 706,000 shares were granted to employees under the Long-term Incentive Plan. These shares will vest 100% after three years and have a 7-year life. Effective January 18, 2005, our Board of Directors established the Non-Employee Directors Stock Awards Plan. The plan was approved at our shareholders’ meeting on May 10, 2005. Under

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KMI Form 10-Q

the plan, options and restricted stock may be granted to our non-employee directors. The aggregate number of shares of our common stock, which may be issued under the plan with respect to options and restricted stock may not exceed 500,000.

During the three months ended March 31, 2006, we recognized stock option compensation expense of $1.9 million. At March 31, 2006, unrecognized compensation cost was approximately $4.2 million, which will be recognized over the next two years.

During the three months ended March 31, 2006 and 2005, we made restricted common stock grants to our non-employee directors of 17,600 and 18,750 shares, respectively. These grants are valued at $1.7 million and $1.3 million, respectively, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. All of the restricted stock grants made in the three months ended March 31, 2006 and 2005 vest during a six-month period. Expense related to restricted grants is recognized on a straight-line basis over the respective vesting periods. During the three months ended March 31, 2006 and 2005, we amortized $3.4 million and $1.9 million, respectively, related to restricted stock grants.

During the three months ended March 31, 2006, we made restricted stock unit grants of 61,800 units. These grants are valued at $6.0 million, based on the closing market price of our common stock on either the date of grant or the measurement date, if different.  Of the 61,800 restricted stock unit grants, 27,950 units vest one-third per year over a three year period and the related expense is recognized on a graded basis over the vesting period and 33,850 units vest during a three year period and the related expense is recognized on a straight-line basis over the vesting period. Upon vesting the grants will be paid fifty percent in cash and fifty percent in our common shares. During the three months ended March 31, 2006, we amortized $0.4 million related to restricted stock unit grants.

As required by the provision of SFAS No. 123R, we have eliminated the deferred compensation balance previously shown on our Consolidated Balance Sheet against the caption “Additional Paid-in Capital.”

A summary of the status of our restricted stock and restricted stock unit plans at March 31, 2006, and changes during the three months then ended is presented in the table below:

	Three Months Ended March 31, 2006
	Shares		Weighted Average Grant Date Fair Value (In millions)
Outstanding at Beginning of Period	880,310			$	56.6
Granted	79,400				7.7
Exercised	(48,687	)			(2.8	)
Forfeited	(2,650	)			(0.2	)
Outstanding at End of Period	908,373			$	61.3
Intrinsic Value of Restricted Stock Exercised During the Period				$	4.7

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.

Plan Name	Shares Subject to the Plan	Option Shares Granted Through March 31, 2006	Vesting Period	Expiration Period
1992 Directors’ Plan	1,025,000	702,875	0 – 6 Months	10 Years
Long-term Incentive Plan	5,700,000	4,070,720	0 – 5 Years	5 – 10 Years
1999 Plan	10,500,000	8,048,968	3 – 4 Years	7 – 10 Years
Non-Employee Directors Plan	500,000	33,350	0 – 6 Months	10 Years

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KMI Form 10-Q

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.

A summary of the status of our stock option plans at March 31, 2006, and changes during the three months then ended is presented in the table and narrative below:

	Three Months Ended March 31, 2006
	Shares		Weighted Average Exercise Price
Outstanding at Beginning of Period	3,421,849			$	45.21
Granted	-			$	-
Exercised	(152,264	)		$	41.80
Forfeited	(13,800	)		$	53.73
Outstanding at End of Period	3,255,785			$	45.34
Exercisable at End of Period	2,261,694			$	41.76
Aggregate Intrinsic Value of Options Exercisable at End of Period (In millions)				$	113.6
Intrinsic Value of Options Exercised During the Period (In millions)				$	8.3
Cash Received from Exercise of Options During the Period (In millions)				$	6.4

The following table sets forth our common stock options outstanding at March 31, 2006, 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	498,722	$	23.73	3.39 years	498,722	$	23.73
$24.04 - $43.10	764,632	$	35.99	5.08 years	601,057	$	34.83
$49.00 - $53.20	778,942	$	50.95	4.91 years	778,942	$	50.95
$53.60 - $60.18	887,489	$	54.90	4.86 years	322,973	$	56.71
$60.79 - $61.40	326,000	$	60.90	5.77 years	60,000	$	61.40
	3,255,785	$	45.34	4.79 years	2,261,694	$	41.76

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. 123R. Employees purchased 11,314 shares and 12,507 shares for the three months ended March 31, 2006 and 2005, respectively.

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KMI Form 10-Q

(B) Nature of Operations

Our business activities include: (i) transporting, storing and selling natural gas, (ii) transporting crude oil and transporting, storing and processing refined petroleum products, (iii) providing retail natural gas distribution services, (iv) producing, transporting and selling carbon dioxide, commonly called CO₂, for use in, and selling crude oil produced from, enhanced oil recovery operations, (v) transloading, storing and delivering a wide variety of bulk, petroleum, petrochemical and other liquid products at terminal facilities located across the United States, and (vi) operating and, in previous periods, constructing electric generation facilities.

(C) Basis of Presentation

Our consolidated financial statements include the accounts of Kinder Morgan, Inc. and our majority-owned subsidiaries, as well as those of Kinder Morgan Energy Partners. Investments in 50% or less owned operations are accounted for under the equity method. These investments reported under the equity method include jointly owned operations in which we have the ability to exercise significant influence over their operating and financial policies, as was our investment in Kinder Morgan Energy Partners prior to January 1, 2006. All material intercompany transactions and balances have been eliminated. Certain prior period 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.

Due to our implementation of Emerging Issues Task Force (“EITF”) No. 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, we are including Kinder Morgan Energy Partners and its consolidated subsidiaries as consolidated subsidiaries in our consolidated financial statements effective January 1, 2006.

We have prospectively applied EITF No. 04-5 using Transition Method A. The adoption of this new pronouncement had no impact on our consolidated stockholders’ equity. There also was no impact on the financial covenants in our loan agreements from the implementation of EITF No. 04-5 because our $800 million credit facility was amended to exclude the effect of consolidating Kinder Morgan Energy Partners. See Note 12 of Notes to Consolidated Financial Statements included in our 2005 Form 10-K.

The adoption of this pronouncement had 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 were not affected.

(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 businesses bill customers on a monthly cycle billing basis. Revenues are recorded on an accrual basis, including an estimate at the end of each accounting period for gas delivered and, if applicable, for which title has passed but bills have not yet been rendered.

We provide various types of natural gas storage and transportation services to customers. 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 per the terms of the contract. 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 to customers. 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.

We recognize bulk terminal transfer service revenues based on volumes loaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received or volumes delivered depending on the customer contract. Liquids terminal minimum take-or-pay revenue is recognized at the

12

KMI Form 10-Q

end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product.

Revenues from the sale of oil and natural gas liquids production are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Revenues from the sale of natural gas production are recognized when the natural gas is sold. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer. As a result, we maintain a minimum amount of product inventory in storage and the differences between actual production and sales is not significant.

(E) Inventories

	March 31,			December 31,
	2006			2005
	(In millions)
Gas in Underground Storage (Current)		$	200.8		$	209.6
Materials and Supplies			33.1			18.6
Petroleum Products			15.4			-
		$	249.3		$	228.2

(F) Goodwill

Prior to the adoption of EITF No. 04-5 on January 1, 2006, we accounted for our investment in Kinder Morgan Energy Partners under the equity method. The difference between the cost of our investment and our underlying equity in the net assets of Kinder Morgan Energy Partners was recorded as equity method goodwill. Upon the adoption of EITF No. 04-5, we ceased accounting for our investment in Kinder Morgan Energy Partners under the equity method and beginning with the first quarter of 2006 we are including the accounts, balances and results of operations of Kinder Morgan Energy Partners in our consolidated financial statements. As a result, the character of the equity method goodwill was changed to goodwill arising from a business combination or acquisition, which must be allocated to one or more reporting units as of the original date of combination or acquisition.

We purchased our investment in Kinder Morgan Energy Partners in October 1999. The businesses of Kinder Morgan Energy Partners that existed at that time are presently located in the Products Pipelines, CO₂, and Terminals segments. The equity method goodwill recharacterized as goodwill arising from an acquisition was allocated to these reporting units effective January 1, 2006 based on the respective fair value of each reporting unit at the date of our 1999 investment in Kinder Morgan Energy Partners. In addition, treating Kinder Morgan Energy Partners as our consolidated subsidiary resulted in goodwill balances residing on its books to be included within our goodwill balance. Previously these amounts were included as part of our investment in Kinder Morgan Energy Partners pursuant to the equity method.

Changes in the carrying amount of our goodwill for the quarter ended March 31, 2006 are summarized as follows:

	Balance December 31, 2005		KMP Goodwill Consolidated into KMI		Reallocation of Equity Method Goodwill			Other1			Balance March 31, 2006
	(In millions)
Kinder Morgan Energy Partners	$	859.4	$	-	$	(859.4	)	$	-		$	-
Power Segment		24.8		-		-			-			24.8
Kinder Morgan Canada Segment2		658.2		-		-			(2.7	)		655.5
Terasen Gas Segment2		1,238.6		-		-			(5.3	)		1,233.3
Products Pipelines Segment		-		263.2		695.5			-			958.7
Natural Gas Pipelines Segment		-		288.4		-			-			288.4
CO2 Segment		-		46.1		26.9			-			73.0
Terminals Segment		-		201.3		137.0			-			338.3
Consolidated Total	$	2,781.0	$	799.0	$	-		$	(8.0	)	$	3,572.0

_________________

¹

Other adjustments include the translation of goodwill denominated in foreign currencies and purchase price adjustments.

13

KMI Form 10-Q

²

Goodwill assigned to the Kinder Morgan Canada and Terasen Gas business segments is based on the preliminary purchase price allocation for our November 30, 2005 acquisition of Terasen. See our 2005 Form 10-K for additional information regarding this acquisition.

We evaluate for the impairment of goodwill in accordance with the provisions of SFAS No. 142 Goodwill and Other Intangible Assets. Our annual impairment tests determined that the carrying value of goodwill was not impaired. For the investments we continue to account for under the equity method of accounting, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill and, according to the provisions of SFAS No. 142, equity method goodwill is not subject to amortization but rather to impairment testing in accordance with APB No. 18, The Equity Method of Accounting for Investments in Common Stock. As of March 31, 2006 we have reported $138.2 million of equity method goodwill within the caption “Investments: Other” in the accompanying Consolidated Balance Sheets.

(G) Other Intangibles, Net

Our intangible assets other than goodwill include lease value, contracts, customer relationships and agreements. These intangible assets have definite lives, are being amortized on a straight-line basis over their estimated useful lives, and are reported separately as “Other Intangibles, Net” in the accompanying Consolidated Balance Sheets. Following is information related to our intangible assets:

	March 31, 2006				December 31, 2005
	(In millions)
Lease Value:
Gross Carrying Amount		$	6.6			$	-
Accumulated Amortization			(1.2	)			-
Net Carrying Amount			5.4				-
Contracts and Other:
Gross Carrying Amount			253.6				29.4
Accumulated Amortization			(25.1	)			(11.7	)
Net Carrying Amount			228.5				17.7
Total Other Intangibles, Net		$	233.9			$	17.7

Amortization expense on our intangibles consisted of the following:

	Three Months Ended March 31,
	2006			2005
	(In millions)
Lease Value1		$	-		$	-
Contracts and Other			3.8			0.4
Total Amortizations		$	3.8		$	0.4

_______________

¹

2006 included expense of less than $0.1 million.

As of March 31, 2006, our weighted average amortization period for our intangible assets was approximately 18.8 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $14.8 million, $14.7 million, $13.5 million, $13.3 million and $13.2 million, respectively.

(H) Accounting for Minority Interests

Due to our implementation of EITF No. 04-5, we are including Kinder Morgan Energy Partners and its consolidated subsidiaries as consolidated subsidiaries in our consolidated financial statements effective January 1, 2006.

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KMI Form 10-Q

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

	March 31,		December 31,
	2006		2005
	(In millions)
Kinder Morgan Energy Partners	$	1,334.9	$	-
Kinder Morgan Management, LLC		1,234.7		1,221.7
Triton Power		19.2		21.8
Entrega Gas Pipeline LLC		90.0		-
Other		9.3		3.8
	$	2,688.1	$	1,247.3

On February 14, 2006, Kinder Morgan Energy Partners paid a quarterly distribution of $0.80 per common unit for the quarterly period ended December 31, 2005, of which $114.4 million was paid to the public holders (represented in minority interests) of Kinder Morgan Energy Partners’ common units. On April 19, 2006, Kinder Morgan Energy Partners declared a quarterly distribution of $0.81 per common unit for the quarterly period ended March 31, 2006. The distribution will be paid on May 15, 2006, to unitholders of record as of April 28, 2006.

(I) 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. Additional information regarding our asset retirement obligations is included in our 2005 Form 10-K and Kinder Morgan Energy Partners’ 2005 Form 10-K.

We have included $0.8 million of our total asset retirement obligations as of March 31, 2006 in the caption “Current Liabilities: Other” and the remaining $45.7 million in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying Consolidated Balance Sheet. A reconciliation of the changes in our accumulated asset retirement obligations for each of the three months ended March 31, 2006 and 2005 is as follows:

	Three Months Ended March 31,
	2006			2005
	(In millions)
Balance at Beginning of Period	$	3.2		$	3.3
KMP ARO Consolidated into KMI1		43.2			-
Liabilities Settled		(0.5	)		(0.2	)
Accretion Expense2		0.6			-
Balance at End of Period	$	46.5		$	3.1

¹

Represents asset retirement obligation balances of Kinder Morgan Energy Partners as of December 31, 2005. Due to our adoption of EITF No. 04-5, beginning with the first quarter of 2006, the accounts and balances of Kinder Morgan Energy Partners are included in our consolidated results as discussed in Note 1(C).

²

2005 included an amount of less than $0.1 million.

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KMI Form 10-Q

(J) Related Party Transactions

Plantation Pipe Line Company

Kinder Morgan Energy Partners owns a 51.17% equity interest in Plantation Pipe Line Company. An affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004, Plantation repaid a $10 million note outstanding and $175 million in outstanding commercial paper borrowings with funds of $190 million borrowed from its owners. Kinder Morgan Energy Partners loaned Plantation $97.2 million, which corresponds to its 51.17% ownership interest, in exchange for a seven-year note receivable bearing interest at the rate of 4.72% per annum. The note provides for semiannual payments of principal and interest on December 31 and June 30 each year beginning on December 31, 2004 based on a 25-year amortization schedule, with a final principal payment of $157.9 million due July 20, 2011. Kinder Morgan Energy Partners funded its loan of $97.2 million with borrowings under its commercial paper program. An affiliate of ExxonMobil owns the remaining 48.83% equity interest in Plantation and funded the remaining $92.8 million on similar terms.

As of March 31, 2006, the principal amount receivable from this note was $94.2 million. We included $2.2 million of this balance within “Accounts, Notes and Interest Receivable, Net – Related Parties” on our accompanying consolidated balance sheet, and we included the remaining $92.0 million balance within “Notes Receivable – Related Parties.”

Coyote Gas Treating, LLC

Kinder Morgan Energy Partners owns a 50% equity interest in Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise Field Services LLC owns the remaining 50% equity interest. Kinder Morgan Energy Partners is the managing partner of Coyote Gulch. In June 2001, Coyote Gulch repaid the $34.2 million in outstanding borrowings under its 364-day credit facility with funds borrowed from its owners. Kinder Morgan Energy Partners loaned Coyote Gulch $17.1 million, which corresponds to its 50% ownership interest, in exchange for a one-year note receivable bearing interest payable monthly at London Interbank Offered Rate (“LIBOR”) plus a margin of 0.875%. On June 30, 2002 and June 30, 2003, the note was extended for one year. On June 30, 2004, the term of the note was made month-to-month. In 2005, Kinder Morgan Energy Partners reduced its investment in the note by $0.1 million to account for its share of investee losses in excess of the carrying value of its equity investment in Coyote Gulch.

In March 2006, Enterprise and Kinder Morgan Energy Partners agreed to a resolution that would transfer Coyote Gulch’s notes payable to Enterprise and Kinder Morgan Energy Partners to members’ equity. According to the provisions of this resolution, Kinder Morgan Energy Partners then contributed the principal amount of $17.0 million related to its note receivable to its equity investment in Coyote Gulch. The $17.0 million amount is included within “Investments: Other” in our accompanying interim Consolidated Balance Sheet as of March 31, 2006.

(K) Cash Flow Information

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

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

	Three Months Ended March 31,
	2006			2005
	(In millions)
Accounts Receivable	$	273.7		$	(11.3	)
Materials and Supplies Inventory		1.0			0.2
Other Current Assets		118.4			(34.1	)
Accounts Payable		(364.8	)		(25.3	)
Excess Tax Benefits from Share-based Payment Arrangements		-			11.2
Other Current Liabilities		(21.0	)		(45.6	)
	$	7.3		$	(104.9	)

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KMI Form 10-Q

Supplemental Disclosures of Cash Flow Information:

Cash Paid During the Period for:
Interest, Net of Amount Capitalized	$	217.0	$	67.7
Income Taxes Paid	$	70.4	$	7.1

As discussed in Note 1(C), due to our adoption of EITF No. 04-5, beginning with the first quarter of 2006, the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our consolidated financial statements and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. Therefore, we have included Kinder Morgan Energy Partners’ cash and cash equivalents at December 31, 2005 of $12.1 million as an “Effect of Accounting Change on Cash” in the accompanying Consolidated Statement of Cash Flows.

In March 2006, Kinder Morgan Energy Partners made a $17.0 million contribution of net assets to its investment in Coyote Gulch.

(L) Interest Expense

“Interest Expense, Net” as presented in the accompanying interim Consolidated Statements of Operations is net of the debt component of the allowance for funds used during construction, which was $6.8 million for the three months ended March 31, 2006 and $0.2 million for the three months ended March 31, 2005.

(M) Income Taxes

The effective tax rate (calculated by dividing the amount in the caption “Income Taxes” by the amount in the caption “Income from Continuing Operations Before Income Taxes” as shown in the accompanying interim Consolidated Statements of Operations) was 34.2% for the three months ended March 31, 2006. This effective tax rate reflects, among other factors, differences from the federal statutory tax rate of 35% due to increases attributable to (i) state income taxes, (ii) the minority interest associated with Kinder Morgan Management and (iii) taxes on corporate equity and subsidiary earnings of Kinder Morgan Energy Partners and decreases attributable to (i) tax benefits resulting from our Terasen acquisition structure and (ii) taxes applicable to our Canadian operations. The effective tax rate was 39.5% for the three months ended March 31, 2005. This effective tax rate reflects, among other factors, differences from the federal statutory tax rate of 35% due to increases attributable to (i) state income taxes and (ii) the minority interest associated with Kinder Morgan Management.

2.

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 (stock options and restricted share units are currently the only such securities outstanding) convertible into common stock, for which the effect of conversion or exercise using the treasury stock method would be dilutive. No options were excluded from the diluted earnings per share calculation for the periods presented because none of the options would have been antidilutive. In recent periods, we have repurchased a significant number of our outstanding shares; see Note 10. In addition, in November 2005 we issued 12.5 million shares as partial consideration to acquire Terasen; see Note 5.

	Three Months Ended March 31,
	2006	2005
	(In millions)
Weighted-average Common Shares Outstanding	133.7	123.2
Dilutive Common Stock Options1	1.3	1.2
Shares Used to Compute Diluted Earnings Per Common Share	135.0	124.4

_____________

¹

2006 includes less than 0.1 million due to the dilutive effect of restricted share units.

17

KMI Form 10-Q

3.

Comprehensive Income

Our comprehensive income is as follows:

	Three Months Ended March 31,
	2006			2005
	(In millions)
Net Income:	$	193.7		$	143.3
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes		11.9			(29.2	)
Reclassification of Change in Fair Value of Derivatives to Net Income		14.1			(2.3	)
Equity in Other Comprehensive Loss of Equity Method Investees		-			(118.1	)
Minority Interest in Other Comprehensive Loss of Equity Method Investees		-			59.8
Change in Foreign Currency Translation Adjustment		(42.8	)		-
Other Comprehensive Loss		(16.8	)		(89.8	)
Comprehensive Income	$	176.9		$	53.5

The Accumulated Other Comprehensive Loss of $143.8 million at March 31, 2006 consisted of (i) $101.2 million representing unrecognized net losses on hedging activities, (ii) $39.3 million representing foreign currency translation adjustments and (iii) $3.3 million representing minimum pension liability.

4.

Kinder Morgan Management, LLC

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. On May 15, 2006, Kinder Morgan Management will make a distribution of 0.018566 of its shares per outstanding share (1,093,826 total shares) to shareholders of record as of April 28, 2006, based on the $0.81 per common unit distribution declared by Kinder Morgan Energy Partners. These distributions are paid in the form of additional shares or fractions thereof calculated by dividing the Kinder Morgan Energy Partners’ cash distribution per common unit by the average market price of a Kinder Morgan Management share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares.

5.

Business Combinations, Acquisitions and Joint Ventures

The following acquisitions were accounted for under the purchase method and the assets acquired were recorded at their estimated fair market values as of the acquisition date. The preliminary allocation of assets (and any liabilities assumed) may be adjusted to reflect the final determined amounts during a period of time following the acquisition. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.

Entrega Gas Pipeline LLC

Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline LLC from EnCana Corporation for $240.0 million in cash. Kinder Morgan Energy Partners contributed $160.0 million, which corresponded to its 66 2/3% ownership interest in Rockies Express Pipeline LLC. Sempra Energy holds the remaining 33 1/3% ownership interest and contributed $80.0 million. At the time of acquisition, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that will consist of two segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming, and (ii) a 191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado, where it will ultimately connect with Rockies Express Pipeline, an interstate natural gas pipeline that, at the time of acquisition, was being developed by Rockies Express Pipeline LLC.

In combination, the Entrega and Rockies Express pipelines have the potential to create a major new natural gas transmission pipeline that will provide seamless transportation of natural gas from Rocky Mountain production areas to Midwest and eastern Ohio markets. EnCana Corporation completed construction of the first segment of the Entrega Pipeline and interim service has begun. Under the terms of the purchase and sale agreement, Kinder Morgan Energy Partners and Sempra will construct the second segment of the Entrega Pipeline, and construction is scheduled to begin this summer. It is anticipated that the entire Entrega system will be placed into service by January 1, 2007.

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KMI Form 10-Q

In April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline LLC. Going forward, the entire pipeline system will be known as the Rockies Express Pipeline. Also in April 2006, Kinder Morgan Energy Partners paid EnCana approximately $4.6 million in cash as consideration for purchase price adjustments recognized in the second quarter of 2006.

As of March 31, 2006, our allocation of the purchase price to assets acquired and liabilities assumed was as follows:

	(In millions)
Purchase Price:
Cash Paid, Including Transaction Costs	$	240.0
Liabilities Assumed		-
Total Purchase Price	$	240.0
Allocation of Purchase Price:
Current Assets	$	-
Property, Plant and Equipment		240.0
Deferred Charges and Other Assets		-
	$	240.0

Terasen

On November 30, 2005, we completed the acquisition of 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 at December 31, 2005. 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. Further information regarding this acquisition is available in our 2005 Form 10-K.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the three months ended March 31, 2006 and 2005, assumes that all of the acquisitions we have made and joint ventures we have entered into between January 1, 2005 and March 31, 2006, including the ones listed above, had occurred as of the beginning of the period presented. We have prepared these unaudited pro forma financial results for comparative purposes only. These unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed these acquisitions and joint ventures as of January 1, 2005 or the results that will be attained in the future.

	Three Months Ended March 31,
	2006		2005
	(In millions, except per share amounts)
Operating Revenues	$	3,440.0	$	853.8
Income from Continuing Operations	$	194.1	$	185.8
Net Income	$	193.3	$	184.1
Diluted Earnings Per Common Share	$	1.43	$	1.34
Common Shares Used in Computing Diluted Earnings Per Share		135.0		136.9

Acquisitions Subsequent to March 31, 2006

On April 7, 2006, Kinder Morgan Production Company, L.P. purchased various oil and gas properties from Journey Acquisition – I, L.P. and Journey 2000, L.P. The acquisition was made effective March 1, 2006. The properties are primarily located in the Permian Basin area of West Texas, produce approximately 850 barrels of oil equivalent per day net, and include some fields with enhanced oil recovery development potential near our current carbon dioxide operations. The acquired operations are included as part of our CO₂ - KMP business segment. During the next several months, we will perform technical evaluations to confirm the carbon dioxide enhanced oil recovery potential and generate definitive plans to develop this potential if proven to be economic. The purchase price plus the anticipated investment to both further develop carbon dioxide enhanced oil recovery and construct a new carbon dioxide supply pipeline on all of the acquired properties is

19

KMI Form 10-Q

approximately $115 million. However, since we intend to divest in the near future those acquired properties that are not candidates for carbon dioxide enhanced oil recovery, our total investment is likely to be considerably less.

In April 2006, Kinder Morgan Energy Partners acquired terminal assets and operations from A&L Trucking, L.P. and U.S. Development Group in three separate transactions for an aggregate consideration of approximately $61.9 million, consisting of $61.6 million in cash and $0.3 million in assumed liabilities. The first transaction included the acquisition of equipment and infrastructure on the Houston Ship Channel that loads and stores steel products. The acquired assets complement Kinder Morgan Energy Partners’ nearby bulk terminal facility purchased from General Stevedores, L.P. in July 2005. The second acquisition included the purchase of a rail terminal at the Port of Houston that handles both bulk and liquids products. The rail terminal complements Kinder Morgan Energy Partners’ existing Texas petroleum coke terminal operations and maximizes the value of Kinder Morgan Energy Partners’ existing deepwater terminal by providing customers with both rail and vessel transportation options for bulk products. Thirdly, Kinder Morgan Energy Partners acquired the entire membership interest of Lomita Rail Terminal LLC, a limited liability company that owns a high-volume rail ethanol terminal in Carson, California. The terminal serves approximately 80% of the southern California demand for reformulated fuel blend ethanol with expandable offloading/distribution capacity, and the acquisition expanded Kinder Morgan Energy Partners’ existing rail transloading operations. All of the acquired assets are included in our Terminals - KMP business segment. We will allocate our total purchase price to assets acquired and liabilities assumed in the second quarter of 2006, and we expect to assign approximately $17.6 million of goodwill to our Terminals – KMP business segment.

6.

Sales of Assets

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.

During the first quarter 2006, we sold power generation equipment for $7.5 million (net of marketing fees.) This equipment was a portion of the equipment that became surplus as a result of our decision to exit the power development business. No gain or loss was recorded as a result of these sales. The book value of the remaining surplus power generation equipment available for sale at March 31, 2006 was $16.0 million.

7.

Summarized Income Statement Information for Kinder Morgan Energy Partners

Following is summarized income statement information for the three months ended March 31, 2005 for Kinder Morgan Energy Partners, a publicly traded master limited partnership in which we own the general partner interest, in addition to limited partner interests in the form of Kinder Morgan Energy Partners common units, i-units and Class B limited partner units. As discussed in Note 1(C), due to our adoption of EITF No. 04-5 on January 1, 2006, beginning with the first quarter of 2006 the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our consolidated results and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. This investment, which prior to January 1, 2006 was accounted for under the equity method, is described in more detail in our 2005 Form 10-K. Additional information on Kinder Morgan Energy Partners’ results of operations and financial position are contained in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 and in its Annual Report on Form
10-K for the year ended December 31, 2005.

	Three Months Ended March 31, 2005
	(In millions)
Operating Revenues		$	1,971.9
Operating Expenses			1,702.9
Operating Income		$	269.0
Net Income		$	223.6

8.

Discontinued Operations

In conjunction with the acquisition of Terasen on November 30, 2005 (see Note 5), 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., which offers water, wastewater and utility services, primarily in Western Canada. On January 17, 2006, we announced that Terasen entered into a definitive agreement to sell Terasen Water and Utility Services to a consortium, including members of the water business’ management, for approximately C$125 million, subject to certain price adjustments at closing. In the first quarter of 2006, we recorded incremental losses of $0.7 million (net of tax benefits of $0.4 million) to reflect the operating results of the water and utility business segment for the three months ended March 31, 2006.

20

KMI Form 10-Q

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 book value. Any gain or loss on the disposal transaction plus any costs of disposal will be recognized as assets acquired or liabilities assumed in the acquisition of Terasen and included in the allocation of the acquisition cost.

During 1999, we adopted and implemented a plan to discontinue a number of lines of business. During 2000, we essentially completed the disposition of these discontinued operations. In March 2006 and March 2005, we recorded incremental losses of approximately $103,000 (net of tax benefit of $60,000) and $1.8 million (net of tax benefit of $1.0 million), respectively, to increase previously recorded liabilities to reflect updated estimates.

The cash flows attributable to discontinued operations are included in the accompanying interim Consolidated Statements of Cash Flows under the captions “Net Cash Flows Used in Discontinued Operations,” “Net Cash Flows Used in Discontinued Investing Activities” and “Net Cash Flows Provided by Discontinued Financing Activities.” Note 7 of Notes to Consolidated Financial Statements included in our 2005 Form 10-K contains additional information on these matters.

9.

Financing

As discussed in Note 1(C), beginning January 1, 2006, we have prospectively applied EITF No. 04-5 which has resulted in the inclusion of the accounts and balances of Kinder Morgan Energy Partners in our consolidated financial statements. The adoption of this pronouncement had the effect, among other things, of increasing our consolidated debt beginning January 1, 2006, but had no impact on our consolidated stockholders’ equity. Information regarding the debt of Kinder Morgan Energy Partners can be found in its 2005 Form 10-K. Significant changes in our consolidated debt since December 31, 2005 are discussed following.

We and our consolidated subsidiaries had the following unsecured revolving credit facilities outstanding at March 31, 2006.

	March 31, 2006								Three Months Ended March 31, 2006
	Borrowings Outstanding Under Facility			Short-term Debt Outstanding		Weighted Average Interest Rate of Short-term Debt Outstanding			Average Short-term Debt Outstanding			Weighted Average Interest Rate of Short-term Debt Outstanding
	(U.S. Dollars in millions)
Kinder Morgan, Inc.
$800 million		$	-	$	-		-	%		$	3.7		4.66	%
Kinder Morgan Energy Partners
$1.6 billion and $250 million			-		1,051.3		4.90	%			817.6		4.66	%
Terasen
C$450 million1			-		94.2		4.62	%			104.0		3.83	%
Terasen Gas Inc.
C$500 million			-		160.1		3.62	%			208.9		3.43	%
Terasen Pipelines (Corridor) Inc.
C$225 million			-		122.4		3.39	%			123.2		3.40	%

¹

Short-term debt outstanding at March 31, 2006 consisted of bankers’ acceptances. Average short-term debt outstanding for the three months ended March 31, 2006 was a combination of commercial paper and bankers’ acceptances.

These facilities can be used by the respective borrowers for each entity’s general corporate purposes, including as backup for each entity’s commercial paper or bankers’ acceptance programs and include financial covenants and events of default that are common in such arrangements. The margin paid with respect to borrowings and the facility fees paid on the total commitment varies based the senior debt investment rating of the respective borrowers. Note 12 of Notes to Consolidated Financial Statements included in our 2005 Form 10-K and Note 9 of Notes to Consolidated Financial Statements in Kinder Morgan Energy Partners’ 2005 Form 10-K contain additional information on our credit facilities.

The commercial paper issued by the above-listed borrowers, which is supported by the credit facilities described above, is comprised of unsecured short-term notes with maturities not to exceed 364 days from the date of issue. Total commercial paper outstanding at December 31, 2005 was $610.6 million.

On February 22, 2006, Kinder Morgan Energy Partners entered into a nine-month $250 million credit facility due November 21, 2006 with a syndicate of financial institutions, and Wachovia Bank, National Association is the administrative agent. Borrowings under the credit facility can be used for general corporate purposes and as backup for Kinder Morgan Energy Partners’ commercial paper program and include financial covenants and events of default that are common in such arrangements.

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KMI Form 10-Q

On January 13, 2006, Terasen Gas (Vancouver Island) Inc. (“TGVI”) entered into a five-year C$350 million unsecured committed revolving credit facility with a syndicate of banks. TGVI issued banker’s acceptances under this facility to completely refinance TGVI’s former term facility and intercompany advances from Terasen. The banker’s acceptances have terms not to exceed 180 days at the end of which time they are replaced by new banker’s acceptances. The facility can 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, TGVI 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 TGVI may be required to make on non-interest bearing government contributions. The terms and conditions are primarily the same as the aforementioned TGVI facility except this facility ranks junior to repayment of TGVI’s Class B subordinated debt, which is held by its parent company, Terasen. At March 31, 2006, TGVI had issued bankers’ acceptances under the C$350 million credit facility with an average term of less than three months. While the bankers’ acceptances are short term, the underlying credit facility on which the bankers’ acceptances are committed is open through January 2011. Accordingly, borrowings outstanding at March 31, 2006 of $271.4 million under the $350 million credit facility have been classified as long-term debt in our accompanying interim Consolidated Balance Sheet at a weighted-average interest rate of 4.51%. For the three months ended March 31, 2006, average borrowings were $256.0 million at a weighted-average rate of 4.29%. No borrowings were made under the $20 million credit facility during the three months ended March 31, 2006.

Credit Agreements Entered into Subsequent to March 31, 2006

On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion five-year, unsecured revolving credit facility due April 28, 2011. This credit facility will support a planned $2.0 billion commercial paper program, and borrowings under the planned commercial paper program will reduce the borrowings allowed under the credit facility. As of April 28, 2006, there were no borrowings under the credit facility, and terms of the commercial paper program were being negotiated. Borrowings under the credit facility and commercial paper program will be primarily used to finance the construction of the Rockies Express interstate natural gas pipeline, and the borrowings will not reduce the borrowings allowed under Kinder Morgan Energy Partners’ credit facilities.

Rockies Express Pipeline LLC is a limited liability company owned 66 2/3% and controlled by Kinder Morgan Energy Partners. Sempra Energy holds the remaining 33 1/3% ownership interest. Both Kinder Morgan Energy Partners and Sempra have agreed to guarantee borrowings under the Rockies Express credit facility in the same proportion as their respective percentage ownership of the member interests in Rockies Express Pipeline LLC.

Common Stock

On February 14, 2006, we paid a cash dividend on our common stock of $0.875 per share to shareholders of record as of January 31, 2006. On April 19, 2006, our Board of Directors approved a cash dividend of $0.875 per common share payable on May 15, 2006 to shareholders of record as of April 28, 2006.

Kinder Morgan Energy Partners’ Common Units

On February 14, 2006, Kinder Morgan Energy Partners paid a quarterly distribution of $0.80 per common unit for the quarterly period ended December 31, 2005, of which $114.4 million was paid to the public holders of Kinder Morgan Energy Partners’ common units. The distributions were declared on January 18, 2006, payable to unitholders of record as of January 31, 2006. On April 19, 2006, Kinder Morgan Energy Partners declared a cash distribution of $0.81 per common unit for the quarterly period ended March 31, 2006. The distribution will be paid on May 15, 2006, to unitholders of record as of April 28, 2006. See Note 1(H) for additional information regarding our minority interests.

22

KMI Form 10-Q

10.

Common Stock Repurchase Plan

During the quarter ended March 31, 2006, we did not sell any equity securities that were not registered under the Securities Act of 1933, as amended.

Our Purchases of Our Common Stock

Period	Total Number of Shares Purchased1		Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs2		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 to   January  31, 2006		39,800		$	95.02		39,800		$	45,886,229
February 1 to   February 28, 2006		300,000		$	92.26		300,000		$	18,203,665
March 1 to   March 31, 2006		-		$	-		-		$	18,203,665
Total		339,800		$	92.58		339,800		$	18,203,665

¹

All purchases were made pursuant to our publicly announced repurchase plan.

²

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 March 31, 2006, we had repurchased a total of approximately $906.8 million (14,934,300 shares) of our outstanding common stock under the program, of which $31.5 million (339,800 shares) were repurchased in the three months ended March 31, 2006.

11.

Business Segments

In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business segment performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system; (2) Terasen Gas, the regulated sale and transportation of natural gas to residential, commercial and industrial customers in British Columbia, Canada; (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) Kinder Morgan Retail, the regulated sale and transportation of natural gas to residential, commercial and industrial customers principally in Nebraska, Wyoming and Colorado, but also including a small distribution system in Hermosillo, Mexico, and the sales of natural gas to certain utility customers under the Choice Gas Program; (5) Power, the ownership and operation of natural gas-fired electric generation facilities; (6) Products Pipelines – KMP, the ownership and operation of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; (7) Natural Gas Pipelines – KMP, the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (8) CO₂ – KMP, the production, transportation and marketing of carbon dioxide (“CO₂”) to oil fields that use CO₂ to increase production of oil plus ownership interests in and/or operation of oil fields in West Texas plus the ownership and operation of a crude oil pipeline system in West Texas and (9) Terminals – KMP, the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the United States. In previous periods, we owned and operated other lines of business that we discontinued during 1999 and, in 2005, we discontinued the water and utility services businesses acquired with Terasen.

The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to our consolidated operations and described in Note 1 of Notes to Consolidated Financial Statements included in our 2005 Form 10-K and Note 2 of Notes to Consolidated Financial Statements included in Kinder Morgan Energy Partners’ 2005 Form 10-K, except that (i) certain items below the “Operating Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance, (ii) equity in earnings of equity method investees (other than Kinder Morgan Energy Partners, the accounts, balances and results of operations of which are now consolidated with our own) are included in segment earnings (these equity method earnings are included in “Other Income and (Expenses)” in the accompanying interim Consolidated Statements of Operations), (iii)

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KMI Form 10-Q

certain items included in operating income (such as general and administrative expenses) are not considered by management in its evaluation of business segment performance, (iv) gains and losses from incidental sales of assets are included in segment earnings and (v) our business segments that are also segments of Kinder Morgan Energy Partners include certain other income and expenses and income taxes in their segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on segment earnings in relation to the level of capital employed. In addition, because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

BUSINESS SEGMENT INFORMATION

	Three Months Ended March 31, 2006											March 31, 2006
	Segment Earnings			Revenues From External Customers		Intersegment Revenues		Depreciation And Amortization		Capital Expenditures		Segment Assets1
	(In millions)
NGPL	$	127.0		$	257.6	$	0.5	$	25.8	$	28.6	$	5,602.9
Terasen Gas		115.7			591.8		-		22.8		24.6		4,711.5
Kinder Morgan Canada		28.2			48.8		-		8.9		7.9		2,295.4
Kinder Morgan Retail		28.0			139.9		0.7		5.0		4.8		491.2
Power		5.6			10.3		-		0.5		-		390.8
Products Pipelines – KMP		104.8			180.5		-		20.2		56.7		4,771.5
Natural Gas Pipelines – KMP		127.5			1,823.3		6.7		15.9		20.5		4,015.9
CO2 – KMP		81.9			174.7		-		39.3		74.2		1,784.2
Terminals – KMP		72.7			206.4		-		17.3		42.3		2,242.8
Segment Totals		691.4		$	3,433.3	$	7.9	$	155.7	$	259.6		26,306.2
General and Administrative Expenses		(102.2	)
Other Income and (Expenses) 2		(298.9	)					Other3					698.5
Income from Continuing Operations								Consolidated				$	27,004.7
Before Income Taxes4	$	290.3

	Three Months Ended March 31, 2005
	Segment Earnings			Revenues From External Customers5		Depreciation And Amortization		Capital Expenditures
	(In millions)
NGPL	$	114.2		$	206.5	$	24.1	$	12.0
Kinder Morgan Retail		33.1			121.1		4.5		3.2
Power		4.4			9.3		0.8		-
Segment Totals		151.7		$	336.9	$	29.4	$	15.2
Earnings from Investment in Kinder Morgan Energy Partners		154.0
General and Administrative Expenses		(16.7	)
Other Income and (Expenses)		(49.0	)
Income from Continuing Operations
Before Income Taxes	$	240.0

¹

Segment assets include goodwill allocated to the segments.

²

Includes (i) interest expense, (ii) minority interests, (iii) a $22.3 million ($14.1 million after tax) non-cash, non-recurring hedge loss associated with financing the Terasen Acquisition and (iv) other, net.

³

Includes cash, restricted deposits, market value of derivative instruments (including interest rate swaps) and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.

⁴

Includes $5.5 million of income tax expense that was allocated to business segments that are also business segments of Kinder Morgan Energy Partners.

⁵

There were no intersegment revenues during 2005.

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KMI Form 10-Q

GEOGRAPHIC INFORMATION

Prior to our acquisition of Terasen on November 30, 2005, all but an insignificant amount of our assets and operations were located in the continental United States. Upon our acquisition of Terasen, 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 External Customers

	Three Months Ended March 31, 2006
	United States		Canada		Mexico and Other1		Total
	(In millions)
NGPL	$	257.6	$	-	$	-	$	257.6
Terasen Gas		-		591.8		-		591.8
Kinder Morgan Canada		2.5		46.3		-		48.8
Kinder Morgan Retail		137.2		-		2.7		139.9
Power		10.3		-		-		10.3
Products Pipelines - KMP		176.8		3.7		-		180.5
Natural Gas Pipelines - KMP		1,819.8		-		3.5		1,823.3
CO2 - KMP		174.7		-		-		174.7
Terminals - KMP		205.0		-		1.4		206.4
	$	2,783.9	$	641.8	$	7.6	$	3,433.3

Long-lived Assets²

	At March 31, 2006
	United States		Canada		Mexico and Other1		Total
	(In millions)
NGPL	$	5,467.1	$	-	$	-	$	5,467.1
Terasen Gas		-		2,944.9		-		2,944.9
Kinder Morgan Canada		314.5		1,362.8		-		1,677.3
Kinder Morgan Retail		389.5		-		24.7		414.2
Power		340.2		-		-		340.2
Products Pipelines - KMP		3,661.7		49.1		-		3,710.8
Natural Gas Pipelines - KMP		2,944.0		-		85.3		3,029.3
CO2 - KMP		1,564.5		-		-		1,564.5
Terminals - KMP		1,569.5		-		8.4		1,577.9
Other		272.2		49.8		-		322.0
	$	16,523.2	$	4,406.6	$	118.4	$	21,048.2

________________

¹

Terminals – KMP includes revenues of $1.4 and long-lived assets of $8.4 attributable to operations in the Netherlands.

²

Long-lived assets exclude goodwill and other intangibles, net.

12.

Accounting for Derivative Instruments and Hedging Activities

We are exposed to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil as a result of the forecasted purchase or sale of these products. We have exposure to interest rate risk as a result of the issuance of variable and fixed rate debt and commercial paper and to foreign currency risk from our investments in businesses owned and operated outside the United States. Pursuant to our management’s risk management policy, we engage in derivative transactions for the purpose of mitigating these risks, which transactions are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and associated amendments (“SFAS No. 133”).

Commodity Price Risk Management

Our normal business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. Apart from our derivatives for retail distribution gas supply contracts under Terasen Gas, during the three months ended March 31, 2006 and 2005, our derivative activities relating to the mitigation of these risks were designated and qualified as cash flow hedges in accordance with SFAS No. 133. We recognized pre-tax losses of approximately $0.8 million (net of minority interest of $0.1 million) and $2.5 million in the three months ended March 31, 2006 and 2005, respectively as a result of ineffectiveness of these hedges, which amounts are reported within the captions

25

KMI Form 10-Q

“Natural Gas Sales” and “Gas Purchases and Other Costs of Sales” in the accompanying interim Consolidated Statements of Operations. There was no component of these derivatives 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. During the three months ended March 31, 2006 we reclassified $14.1 million (net of minority interest of $14.0 million) of accumulated other comprehensive loss into earnings as a result of hedged forecasted transactions occurring during the period. During the three months ended March 31, 2005 we reclassified $2.3 million of accumulated other comprehensive income into earnings as a result of hedged forecasted transactions occurring during the period. 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. Approximately $28.3 million (net of minority interest of $60 million) of our accumulated other comprehensive loss balance of $143.8 million as of March 31, 2006, is expected to be reclassified to earnings during the next twelve months. In conjunction with these activities, we are required to place funds in margin accounts (included with “Restricted Deposits” in the accompanying interim Consolidated Balance Sheet) or post letters of credit when the market value of these derivatives with specific counterparties exceeds established limits, or in conjunction with the purchase of exchange-traded derivatives. At March 31, 2006, our margin deposits associated with our commodity contract positions and over-the-counter swap partners totaled $38.8 million. As of December 31, 2005, we had no cash margin deposits associated with our commodity contract positions and over-the-counter swap partners. As of March 31, 2006 and December 31, 2005, we had six outstanding letters of credit totaling $423 million and three outstanding letters of credit totaling approximately $44 million, respectively, in support of our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.

As to our retail gas distribution under Terasen Gas, any differences between the effective cost of natural gas purchased and 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. As a result, any gains or losses resulting from these derivative instruments are included in the accompanying interim Consolidated Balance Sheet in the captions “Current Liabilities: Rate Stabilization” or “Current Assets: Rate Stabilization,” respectively.

Derivative instruments entered into for the purpose of mitigating commodity price risk include swaps, futures and options. The fair values of these derivative contracts are included in the accompanying interim Consolidated Balances Sheets within the captions “Current Assets: Other”, “Deferred Charges and Other Assets”, “Current Liabilities: Other”, and “Other Liabilities and Deferred Credits: Other”. The following table summarizes the fair values of our commodity derivative contracts as of March 31, 2006 and December 31, 2005:

	March 31, 2006		December 31, 2005
	(In millions)
Derivatives Asset (Liability)
Current Assets: Other	$	115.0		$	151.2
Deferred Charges and Other Assets		26.4			1.3
Current Liabilities: Other		596.6			78.9
Other Liabilities and Deferred Credits: Other		791.6			0.8

Our over-the-counter swaps and options are entered into with counterparties outside central trading facilities such as a futures, options or stock exchange. These contracts are with a number of parties all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

Interest Rate Risk Management

We have exposure to interest rate risk as a result of the issuance of variable and fixed rate debt and commercial paper. We enter into interest rate swap agreements to mitigate our exposure to changes in the fair value of our fixed rate debt agreements. These hedging relationships are accounted for under SFAS No. 133 using the “short-cut” method prescribed for qualifying 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 $81.0 million and $100.6 million at March 31, 2006 is included in the accompanying interim Consolidated Balance Sheet within the captions “Deferred Charges and Other Assets” and “Other Liabilities and Deferred Credits: Other,” respectively. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually.

On February 10, 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 Kinder Morgan Finance Company, ULC’s 5.35% Senior Notes due 2011, 5.70% Senior Notes due 2016 and

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KMI Form 10-Q

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 SFAS No. 133.

On February 24, 2006, Terasen 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 received proceeds of C$2.2 million. The cumulative loss recognized of C$2.3 million upon early termination of these fair value hedges is recorded under the caption “Value of Interest Rate Swaps” in the accompanying Consolidated Balance Sheet at March 31, 2006 and will be amortized to earnings over the original period of the swap transactions. Additionally, Terasen 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 and qualify for the “shortcut” method of accounting prescribed for qualifying hedges under SFAS No. 133.

As of March 31, 2006 we had outstanding the following interest rate swap agreements that qualify for fair value hedge accounting under SFAS No. 133:

(i)

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 Kinder Morgan Finance Company, ULC’s 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,

(ii)

fixed-to-floating interest rate swap agreements at Terasen, with a notional principal amount of C$195 million, which effectively convert a majority of its 6.30% and 5.56% Medium Term Notes due December 2008 and September 2014, respectively, from fixed rates to floating rates,

(iii)

fixed-to-floating interest rate swap agreements, 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 with a combined notional principal amount of $1.25 billion,

(iv)

fixed-to-floating interest rate swap agreements under Kinder Morgan Energy Partners having a combined notional principal amount of $2.1 billion which effectively convert the interest expense associated with the following series of its senior notes from fixed rates to floating rates:

·

$200 million principal amount of its 5.35% senior notes due August 15, 2007;

·

$250 million principal amount of its 6.30% senior notes due February 1, 2009;

·

$200 million principal amount of its 7.125% senior notes due March 15, 2012;

·

$250 million principal amount of its 5.0% senior notes due December 15, 2013;

·

$200 million principal amount of its 5.125% senior notes due November 15, 2014;

·

$300 million principal amount of its 7.40% senior notes due March 15, 2031;

·

$200 million principal amount of its 7.75% senior notes due March 15, 2032;

·

$400 million principal amount of its 7.30% senior notes due August 15, 2033; and

·

$100 million principal amount of its 5.80% senior notes due March 15, 2035.

As of March 31, 2006, we had outstanding the following interest rate swap agreements that are not 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 or shippers. As a result, gains or losses resulting from these derivative instruments are deferred in the accompanying interim Consolidated Balance Sheet in the captions “Deferred Charges and Other Assets” or “Other Liabilities and Deferred Credits: Other,” respectively. The fair value of these derivatives of $5.2 million at March 31, 2006 is included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying interim Consolidated Balance Sheet.

(i)

Terasen Gas Inc. has 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.

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KMI Form 10-Q

(ii)

TGVI has floating-to-fixed interest rate swap agreements, with a notional principal amount of C$65 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. The interest rate swaps mature in October and November of 2008.

(iii)

Terasen Pipelines (Corridor) Inc. has 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.

Net Investment Hedges

We are exposed to foreign currency risk from our investments in businesses owned and operated outside the United States. To hedge the value of our investment in Canadian operations, we have entered into various cross-currency interest rate swap transactions that have been designated as net investment hedges in accordance with SFAS No. 133. We have recognized no ineffectiveness through the income statement as a result of these hedging relationships during the three months ended March 31, 2006. The effective portion of the changes in fair value of these swap transactions are reported as a cumulative translation adjustment in the caption “Accumulated Other Comprehensive Loss” in the accompanying interim Consolidated Balance Sheet. The fair value of the swaps as of March 31, 2006 is a liability of $79.1 million which is included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying interim Consolidated Balance Sheet.

In February 2006 we entered into a series of transactions to effectively terminate our 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 a series of 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 SFAS No. 133. We recognized 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 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.

13.

Employee Benefits

Kinder Morgan, Inc.

(A)

Retirement Plans

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

	Three Months Ended March 31,
	2006			2005
	(In thousands)
Service Cost	$	2,829		$	2,493
Interest Cost		3,141			2,993
Expected Return on Assets		(5,329	)		(5,101	)
Amortization of:
Transition (Asset)/Obligation		-			(8	)
Prior Service Cost		44			44
(Gain)/Loss		380			179
Net Periodic Pension Cost	$	1,065		$	600

We previously disclosed in our 2005 Form 10-K that we expected to make no contributions to our retirement plans during 2006. As of March 31, 2006, no contributions have been made and we continue to expect to not make any additional contributions to the plans during 2006.

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KMI Form 10-Q

(B)

Other Postretirement Employee Benefits

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

	Three Months Ended March 31,
	2006			2005
	(In thousands)
Service Cost	$	97		$	110
Interest Cost		1,230			1,302
Expected Return on Assets		(1,400	)		(1,428	)
Amortization of:
Prior Service Cost		(393	)		(415	)
(Gain)/Loss		1,149			1,206
Net Periodic Postretirement Benefit Cost	$	683		$	775

We previously disclosed in our 2005 Form 10-K that we expect to make contributions of approximately $8.7 million to our postretirement benefit plan during 2006. As of March 31, 2006, contributions of approximately $8.7 million have been made. We expect that additional contributions, if any, to our postretirement benefit plan during 2006 will not be significant.

Terasen

(A)

Retirement Plans

The components of net periodic pension cost for Terasen’s retirement plans are as follows:

	Three Months Ended
	March 31, 2006
	(In thousands)
Service Cost		$	2,022
Interest Cost			3,733
Expected Return on Assets			(4,424	)
Plan Amendments			95
Other			44
Net Periodic Pension Cost			1,470
Defined Contribution Cost			568
Total Pension Costs		$	2,038

We previously disclosed in our 2005 Form 10-K that Terasen expects to make contributions of approximately $7.3 million to its retirement plans during 2006. As of March 31, 2006, contributions of approximately $1.8 million have been made. Terasen expects to make additional contributions of approximately $5.5 million to its retirement plans during 2006.

(B)

Other Postretirement Employee Benefits

The components of net periodic benefit cost for Terasen’s postretirement benefit plan are as follows:

	Three Months Ended
	March 31, 2006
	(In thousands)
Service Cost		$	421
Interest Cost			898
Other			(4	)
Net Periodic Postretirement Benefit Cost		$	1,315

We previously disclosed in our 2005 Form 10-K that Terasen expects to make contributions of approximately $1.4 million to its postretirement benefit plan during 2006. As of March 31, 2006, contributions of approximately $0.4 million have been made. Terasen expects to make additional contributions of approximately $1.0 million to its postretirement benefit plan during 2006.

Kinder Morgan Energy Partners

In connection with Kinder Morgan Energy Partners’ acquisition of SFPP, L.P., referred to in this report as SFPP, and Kinder Morgan Bulk Terminals, Inc. in 1998, Kinder Morgan Energy Partners acquired certain liabilities for pension and

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KMI Form 10-Q

postretirement benefits. Kinder Morgan Energy Partners provides medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. Kinder Morgan Energy Partners also provides the same benefits to former salaried employees of SFPP. Additionally, Kinder Morgan Energy Partners will continue to fund these costs for those employees currently in the plan during their retirement years. SFPP’s postretirement benefit plan is frozen, and no additional participants may join the plan.

The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement Plan. The benefits under this plan are based primarily upon years of service and final average pensionable earnings; however, benefit accruals were frozen as of December 31, 1998.

Net periodic benefit costs for the SFPP postretirement benefit plan includes the following components:

	Three Months Ended March 31, 2006
	(In thousands)
Service Cost		$	2
Interest Cost			67
Amortization of Prior Service Cost			(29	)
Actuarial (Gain)			(113	)
Net Periodic Benefit Cost		$	(73	)

As of March 31, 2006, we estimate our overall net periodic postretirement benefit cost for the year 2006 will be an annual credit of approximately $0.3 million.  This amount could change in the remaining months of 2006 if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities.

14.

Regulatory Matters

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

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. The NEB has set August 8, 2006, as the date when a public hearing of the application will commence. An NEB decision would then be expected before the end of 2006.

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 TGVI applied to the British Columbia Utilities Commission (“BCUC”) to increase their deemed equity components from 33% to 38% and from 35% to 40%, respectively. The same application also requested an increase in allowed ROEs from the levels that would have resulted from the then applicable formula, which would have been 8.29% for Terasen Gas Inc. and 8.79% for TGVI in 2006. A decision from the BCUC was rendered on the application on March 2, 2006, to be effective as of January 1, 2006. The decision resulted in increases in the deemed equity components of Terasen Gas Inc. and TGVI to 35% and 40%, respectively, and their allowed ROEs 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 proposed agreement, to take effect as of January 1, 2006. The proposed 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 are working 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 would add an initial 200,000 bpd of

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KMI Form 10-Q

dilbit capacity to accommodate the new bitumen production from the Muskeg River Mine. The current dilbit capacity is approximately 258,000 bpd. It is expected to climb to 278,000 bpd by April 2006 by upgrading existing pump station facilities. By 2009, the dilbit capacity of the Corridor system is expected to be approximately 500,000 bpd. An application for the Corridor pipeline expansion project was filed with the Alberta Energy Utilities Board and Alberta Environment on December 22, 2005. Pending regulatory and definitive shipper approval, construction will begin in late 2006.

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

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

On June 30, 2005, the FERC issued an order providing guidance to the industry on accounting for costs associated with pipeline integrity management requirements. The order is effective prospectively from January 1, 2006. Under the order, the costs to be expensed as incurred 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 adding or replacing other items of plant. We expect an increase of $13.8 million in operating expenses in 2006 related to pipeline integrity management programs due to our implementation of this FERC order on January 1, 2006, which will cause us to expense certain program costs that previously were capitalized. The Interstate Natural Gas Association of America has sought rehearing of the FERC’s June 30 order. On September 19, 2005, the FERC denied the Interstate Natural Gas Association of America’s request for rehearing. On December 15, 2005, the Interstate Natural Gas Association of America filed a Petition for Review with the United States Court of Appeals for the District of Columbia Circuit (Court) in Docket No. 05-1426 asking the Court whether the FERC lawfully ordered that interstate pipelines must treat certain costs incurred in complying with the Pipeline Safety Improvement Act of 2002, along with related pipeline testing costs, as expenses rather than capital items for purposes of complying with the FERC’s regulatory accounting regulations.

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KMI Form 10-Q

On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC-regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, interstate pipelines will no longer be permitted to use commodity price indices to structure transactions. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. In subsequent orders in individual pipeline cases, the FERC has allowed negotiated rate transactions using pricing indices so long as revenue is capped by the applicable maximum rate(s). In a FERC Order on Rehearing and Clarification issued January 19, 2006, the FERC modified its previous policy statement and now will again permit the use of gas commodity basis differentials in negotiated rate transactions without regard to rate or revenue caps. On March 23, 2006, the FERC dismissed rehearing requests and denied requests for clarification – all related to the January 19, 2006 order.

15.

Litigation, Environmental and Other Contingencies

Federal Energy Regulatory Commission Proceedings

SFPP, L.P.

SFPP is the subsidiary limited partnership that owns Kinder Morgan Energy Partners’ Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the FERC, including shippers’ complaints regarding interstate rates on the Pacific operations’ pipeline systems.

OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a consolidated proceeding that began in September 1992 and includes a number of shipper complaints against certain rates and practices on SFPP’s East Line (from El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California to Tucson, Arizona), as well as SFPP’s gathering enhancement fee at Watson Station in Carson, California. The complainants in the case are El Paso Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company, Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.), Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco Corporation (now part of ConocoPhillips Company). The FERC has ruled that the complainants have the burden of proof in this proceeding.

A FERC administrative law judge held hearings in 1996, and issued an initial decision in September 1997. The initial decision held that all but one of SFPP’s West Line rates were “grandfathered” under the Energy Policy Act of 1992 and therefore deemed to be just and reasonable; it further held that complainants had failed to prove “substantially changed circumstances” with respect to those rates and that the rates therefore could not be challenged in the Docket No. OR92-8 et al. proceedings, either for the past or prospectively. However, the initial decision also made rulings generally adverse to SFPP on certain cost of service issues relating to the evaluation of East Line rates, which are not “grandfathered” under the Energy Policy Act. Those issues included the capital structure to be used in computing SFPP’s “starting rate base,” the level of income tax allowance SFPP may include in rates and the recovery of civil and regulatory litigation expenses and certain pipeline reconditioning costs incurred by SFPP. The initial decision also held SFPP’s Watson Station gathering enhancement service was subject to FERC jurisdiction and ordered SFPP to file a tariff for that service.

The FERC subsequently reviewed the initial decision, and issued a series of orders in which it adopted certain rulings made by the administrative law judge, changed others and modified a number of its own rulings on rehearing. Those orders began in January 1999, with FERC Opinion No. 435, and continued through June 2003.

The FERC affirmed that all but one of SFPP’s West Line rates are “grandfathered” and that complainants had failed to satisfy the threshold burden of demonstrating “substantially changed circumstances” necessary to challenge those rates. The FERC further held that the one West Line rate that was not grandfathered did not need to be reduced. The FERC consequently dismissed all complaints against the West Line rates in Docket Nos. OR92-8 et al. without any requirement that SFPP reduce, or pay any reparations for, any West Line rate.

The FERC initially modified the initial decision’s ruling regarding the capital structure to be used in computing SFPP’s “starting rate base” to be more favorable to SFPP, but later reversed that ruling. The FERC also made certain modifications to the calculation of the income tax allowance and other cost of service components, generally to SFPP’s disadvantage.

On multiple occasions, the FERC required SFPP to file revised East Line rates based on rulings made in the FERC’s various orders. SFPP was also directed to submit compliance filings showing the calculation of the revised rates, the potential reparations for each complainant and in some cases potential refunds to shippers. SFPP filed such revised East Line rates and compliance filings in March 1999, July 2000, November 2001 (revised December 2001), October 2002 and February 2003 (revised March 2003). Most of those filings were protested by particular SFPP shippers. The FERC has held that certain of

32

KMI Form 10-Q

the rates SFPP filed at the FERC’s directive should be reduced retroactively and/or be subject to refund; SFPP has challenged the FERC’s authority to impose such requirements in this context.

While the FERC initially permitted SFPP to recover certain of its litigation, pipeline reconditioning and environmental costs, either through a surcharge on prospective rates or as an offset to potential reparations, it ultimately limited recovery in such a way that SFPP was not able to make any such surcharge or take any such offset. Similarly, the FERC initially ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that party’s complaint was filed, but ultimately held that each complainant could recover reparations for a period extending two years prior to the filing of its complaint (except for Navajo, which was limited to one month of pre-complaint reparations under a settlement agreement with SFPP’s predecessor). The FERC also ultimately held that SFPP was not required to pay reparations or refunds for Watson Station gathering enhancement fees charged prior to filing a FERC tariff for that service.

In April 2003, SFPP paid complainants and other shippers reparations and/or refunds as required by FERC’s orders. In August 2003, SFPP paid shippers an additional refund as required by FERC’s most recent order in the Docket No. OR92-8 et al. proceedings. SFPP made aggregate payments of $44.9 million in 2003 for reparations and refunds pursuant to a FERC order.

Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for review of FERC’s Docket OR92-8 et al. orders in the United States Court of Appeals for the District of Columbia Circuit. Certain of those petitions were dismissed by the Court of Appeals as premature, and the remaining petitions were held in abeyance pending completion of agency action. However, in December 2002, the Court of Appeals returned to its active docket all petitions to review the FERC’s orders in the case through November 2001 and severed petitions regarding later FERC orders. The severed orders were held in abeyance for later consideration.

Briefing in the Court of Appeals was completed in August 2003, and oral argument took place on November 12, 2003. On July 20, 2004, the Court of Appeals issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP. Among other things, the court’s opinion vacated the income tax allowance portion of the FERC opinion and the order allowing recovery in SFPP’s rates for income taxes and remanded to the FERC this and other matters for further proceedings consistent with the court’s opinion. In reviewing a series of FERC orders involving SFPP, the Court of Appeals held, among other things, that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. By its terms, the portion of the opinion addressing SFPP only pertained to SFPP and was based on the record in that case.

The Court of Appeals held that, in the context of the Docket No. OR92-8, et al. proceedings, all of SFPP’s West Line rates were grandfathered other than the charge for use of SFPP’s Watson Station gathering enhancement facility and the rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded that the FERC had a reasonable basis for concluding that the addition of a West Line origin point at East Hynes, California did not involve a new “rate” for purposes of the Energy Policy Act. It rejected arguments from West Line Shippers that certain protests and complaints had challenged West Line rates prior to the enactment of the Energy Policy Act.

The Court of Appeals also held that complainants had failed to satisfy their burden of demonstrating substantially changed circumstances, and therefore could not challenge grandfathered West Line rates in the Docket No. OR92-8 et al. proceedings. It specifically rejected arguments that other shippers could “piggyback” on the special Energy Policy Act exception permitting Navajo to challenge grandfathered West Line rates, which Navajo had withdrawn under a settlement with SFPP. The court remanded to the FERC the changed circumstances issue “for further consideration” in light of the court’s decision regarding SFPP’s tax allowance. While, the FERC had previously held in the OR96-2 proceeding (discussed following) that the tax allowance policy should not be used as a stand-alone factor in determining when there have been substantially changed circumstances, the FERC’s May 4, 2005 income tax allowance policy statement (discussed following) may affect how the FERC addresses the changed circumstances and other issues remanded by the court.

The Court of Appeals upheld the FERC’s rulings on most East Line rate issues; however, it found the FERC’s reasoning inadequate on some issues, including the tax allowance.

The Court of Appeals held the FERC had sufficient evidence to use SFPP’s December 1988 stand-alone capital structure to calculate its starting rate base as of June 1985; however, it rejected SFPP arguments that would have resulted in a higher starting rate base.

The Court of Appeals accepted the FERC’s treatment of regulatory litigation costs, including the limitation of recoverable costs and their offset against “unclaimed reparations” – that is, reparations that could have been awarded to parties that did not seek them. The court also accepted the FERC’s denial of any recovery for the costs of civil litigation by East Line

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KMI Form 10-Q

shippers against SFPP based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix. However, the court did not find adequate support for the FERC’s decision to allocate the limited litigation costs that SFPP was allowed to recover in its rates equally between the East Line and the West Line, and ordered the FERC to explain that decision further on remand.

The Court of Appeals held the FERC had failed to justify its decision to deny SFPP any recovery of funds spent to recondition pipe on the East Line, for which SFPP had spent nearly $6 million between 1995 and 1998. It concluded that the Commission’s reasoning was inconsistent and incomplete, and remanded for further explanation, noting that “SFPP’s shippers are presently enjoying the benefits of what appears to be an expensive pipeline reconditioning program without sharing in any of its costs.”

The Court of Appeals affirmed the FERC’s rulings on reparations in all respects. It held the Arizona Grocery doctrine did not apply to orders requiring SFPP to file “interim” rates, and that “FERC only established a final rate at the completion of the OR92-8 proceedings.” It held that the Energy Policy Act did not limit complainants’ ability to seek reparations for up to two years prior to the filing of complaints against rates that are not grandfathered. It rejected SFPP’s arguments that the FERC should not have used a “test period” to compute reparations that it should have offset years in which there were underrecoveries against those in which there were overrecoveries, and that it should have exercised its discretion against awarding any reparations in this case.

The Court of Appeals also rejected:

·

Navajo’s argument that its prior settlement with SFPP’s predecessor did not limit its right to seek reparations;

·

Valero’s argument that it should have been permitted to recover reparations in the Docket No. OR92-8 et al. proceedings rather than waiting to seek them, as appropriate, in the Docket No. OR96-2 et al. proceedings;

·

arguments that the former ARCO and Texaco had challenged East Line rates when they filed a complaint in January 1994 and should therefore be entitled to recover East Line reparations; and

·

Chevron’s argument that its reparations period should begin two years before its September 1992 protest regarding the six-inch line reversal rather than its August 1993 complaint against East Line rates.

On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips and ExxonMobil filed a petition for rehearing and rehearing en banc asking the Court of Appeals to reconsider its ruling that West Line rates were not subject to investigation at the time the Energy Policy Act was enacted. On September 3, 2004, SFPP filed a petition for rehearing asking the court to confirm that the FERC has the same discretion to address on remand the income tax allowance issue that administrative agencies normally have when their decisions are set aside by reviewing courts because they have failed to provide a reasoned basis for their conclusions. On October 4, 2004, the Court of Appeals denied both petitions without further comment.

On November 2, 2004, the Court of Appeals issued its mandate remanding the Docket No. OR92-8 proceedings to the FERC. SFPP and shipper parties subsequently filed various pleadings with the FERC regarding the proper nature and scope of the remand proceedings. On December 2, 2004, the FERC issued a Notice of Inquiry and opened a new proceeding (Docket No. PL05-5) to consider how broadly the court’s ruling on the tax allowance issue in BP West Coast Products, LLC v. FERC should affect the range of entities the FERC regulates. The FERC sought comments on whether the court’s ruling applies only to the specific facts of the SFPP proceeding, or also extends to other capital structures involving partnerships and other forms of ownership. Comments were filed by numerous parties, including the Kinder Morgan interstate natural gas pipelines, in the first quarter of 2005. On May 4, 2005, the FERC adopted a policy statement in Docket No. PL05-5, providing that all entities owning public utility assets - oil and gas pipelines and electric utilities - would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. Any tax pass-through entity seeking an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity’s public utility income. The FERC expressed the intent to implement its policy in individual cases as they arise.

On December 17, 2004, the Court of Appeals issued orders directing that the petitions for review relating to FERC orders issued after November 2001 in OR92-8, which had previously been severed from the main Court of Appeals docket, should continue to be held in abeyance pending completion of the remand proceedings before the FERC. Petitions for review of orders issued in other FERC dockets have since been returned to the court’s active docket (discussed further below in relation to the OR96-2 proceedings).

On January 3, 2005, SFPP filed a petition for a writ of certiorari asking the United States Supreme Court to review the Court of Appeals’ ruling that the Arizona Grocery doctrine does not apply to “interim” rates, and that “FERC only established a

34

KMI Form 10-Q

final rate at the completion of the OR92-8 proceedings.” BP West Coast Products and ExxonMobil also filed a petition for certiorari, on December 30, 2004, seeking review of the Court of Appeals’ ruling that there was no pending investigation of West Line rates at the time of enactment of the Energy Policy Act (and thus that those rates remained grandfathered). On April 6, 2005, the Solicitor General filed a brief in opposition to both petitions on behalf of the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and Western Refining filed an opposition to SFPP’s petition. SFPP filed a reply to those briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued orders denying the petitions for certiorari filed by SFPP and by BP West Coast Products and ExxonMobil.

On June 1, 2005, the FERC issued its Order on Remand and Rehearing, which addressed issues in both the OR92-8 and OR96-2 proceedings (discussed following).

With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on several issues that had been remanded by the Court of Appeals in BP West Coast Products. With respect to the income tax allowance, the FERC held that its May 4, 2005 policy statement would apply in the OR92-8 and OR96-2 proceedings and that SFPP “should be afforded an income tax allowance on all of its partnership interests to the extent that the owners of those interests had an actual or potential tax liability during the periods at issue.” It directed SFPP and opposing parties to file briefs regarding the state of the existing record on those questions and the need for further proceedings. Those filings are described below in the discussion of the OR96-2 proceedings. The FERC held that SFPP’s allowable regulatory litigation costs in the OR92-8 proceedings should be allocated between the East Line and the West Line based on the volumes carried by those lines during the relevant period. In doing so, it reversed its prior decision to allocate those costs between the two lines on a 50-50 basis. The FERC affirmed its prior decision to exclude SFPP’s pipeline reconditioning costs from the cost of service in the OR92-8 proceedings, but stated that SFPP will have an opportunity to justify much of those reconditioning expenses in the OR96-2 proceedings. The FERC deferred further proceedings on the non-grandfathered West Line turbine fuel rate until completion of its review of the initial decision in phase two of the OR96-2 proceedings. The FERC held that SFPP’s contract charge for use of the Watson Station gathering enhancement facilities was not grandfathered and required further proceedings before an administrative law judge to determine the reasonableness of that charge; those proceedings are currently in settlement negotiations before a FERC settlement judge.

Petitions for review of the June 1, 2005 order by the United States Court of Appeals for the District of Columbia Circuit have been filed by SFPP, Navajo, Western Refining, BP West Coast Products, ExxonMobil, Chevron, ConocoPhillips, Ultramar and Valero. SFPP has moved to intervene in the review proceedings brought by the other parties. A briefing schedule has been set by the Court, with initial briefs due May 30, 2006 and final briefs filed October 11, 2006.

On December 16, 2005, the FERC issued its Order on Initial Decision and on Certain Remanded Cost Issues, which provided further guidance regarding application of the FERC’s income tax allowance policy in this case, which is discussed below in connection with the OR96-2 proceedings. The December 16, 2005 order required SFPP to submit a revised East Line cost of service filing following FERC’s rulings regarding the income tax allowance and the ruling in its June 1, 2005 order regarding the allocation of litigation costs. SFPP is required to file interim East Line rates effective May 1, 2006 using the lower of the revised OR92-8 (1994 test year) or OR96-2 (1999 test year) rates, as adjusted for indexing through April 30, 2006. The December 16, 2005 order also required SFPP to calculate costs-of-service for West Line turbine fuel movements based on both a 1994 and 1999 test year and to file interim turbine fuel rates to be effective May 1, 2006, using the lower of the two test year rates as indexed through April 30, 2006. SFPP was further required to calculate estimated reparations for complaining shippers consistent with the order. As described further below, various parties filed requests for rehearing and petitions for review of the December 16, 2005 order.

Sepulveda proceedings. In December 1995, Texaco filed a complaint at the FERC (Docket No. OR96-2) alleging that movements on SFPP’s Sepulveda pipeline (Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject to the FERC’s jurisdiction under the Interstate Commerce Act, and claimed that the rate for that service was unlawful. Several other West Line shippers filed similar complaints and/or motions to intervene.

In an August 1997 order, the FERC held that the movements on the Sepulveda pipeline were subject to its jurisdiction. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda pipeline at five cents per barrel. Several shippers protested that rate.

In December 1997, SFPP filed an application for authority to charge a market-based rate for the Sepulveda service, which application was protested by several parties. On September 30, 1998, the FERC issued an order finding that SFPP lacks market power in the Watson Station destination market and set a hearing to determine whether SFPP possessed market power in the origin market.

In December 2000, an administrative law judge found that SFPP possessed market power over the Sepulveda origin market. On February 28, 2003, the FERC issued an order upholding that decision. SFPP filed a request for rehearing of that order on March 31, 2003. The FERC denied SFPP’s request for rehearing on July 9, 2003.

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As part of its February 28, 2003 order denying SFPP’s application for market-based ratemaking authority, the FERC remanded to the ongoing litigation in Docket No. OR96-2, et al. the question of whether SFPP’s current rate for service on the Sepulveda pipeline is just and reasonable. Hearings in this proceeding were held in February and March 2005. SFPP asserted various defenses against the shippers’ claims for reparations and refunds, including the existence of valid contracts with the shippers and grandfathering protection. In August 2005, the presiding administrative law judge issued an initial decision finding that for the period from 1993 to November 1997 (when the Sepulveda FERC tariff went into effect) the Sepulveda rate should have been lower. The administrative law judge recommended that SFPP pay reparations and refunds for alleged overcollections. SFPP filed in October 2005 a brief to the FERC taking exception to this and other portions of the initial decision.

OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond Shamrock Corporation filed a complaint at the FERC (Docket No. OR97-2) challenging SFPP’s West Line rates, claiming they were unjust and unreasonable and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of SFPP’s interstate rates, raising claims against SFPP’s East and West Line rates similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed above, but expanding them to include challenges to SFPP’s grandfathered interstate rates from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2). Tosco Corporation filed a similar complaint in April 1998. The shippers seek both reparations and prospective rate reductions for movements on all of SFPP’s lines. The FERC accepted the complaints and consolidated them into one proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC decision on review of the initial decision in Docket Nos. OR92-8, et al.

In a companion order to Opinion No. 435, the FERC gave the complainants an opportunity to amend their complaints in light of Opinion No. 435, which the complainants did in January 2000. In August 2000, Navajo and Western filed complaints against SFPP’s East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP’s interstate pipeline rates. These complaints were consolidated with the ongoing proceeding in Docket No. OR96-2, et al.

A hearing in this consolidated proceeding was held from October 2001 to March 2002. A FERC administrative law judge issued his initial decision in June 2003. The initial decision found that, for the years at issue, the complainants had shown substantially changed circumstances for rates on SFPP’s West, North and Oregon Lines and for SFPP’s fee for gathering enhancement service at Watson Station and thus found that those rates should not be “grandfathered” under the Energy Policy Act of 1992. The initial decision also found that most of SFPP’s rates at issue were unjust and unreasonable.

On March 26, 2004, the FERC issued an order on the phase one initial decision. The FERC’s phase one order reversed the initial decision by finding that SFPP’s rates for its North and Oregon Lines should remain “grandfathered” and amended the initial decision by finding that SFPP’s West Line rates (i) to Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no longer be “grandfathered” and are not just and reasonable. The FERC upheld these findings in its June 1, 2005 order, although it appears to have found substantially changed circumstances as to SFPP’s West Line rates on a somewhat different basis than in the phase one order. The FERC’s phase one order did not address prospective West Line rates and whether reparations were necessary. As discussed below, those issues have been addressed in the FERC’s December 16, 2005 order on phase two issues. The FERC’s phase one order also did not address the “grandfathered” status of the Watson Station fee, noting that it would address that issue once it was ruled on by the Court of Appeals in its review of the FERC’s Opinion No. 435 orders; as noted above, the FERC held in its June 1, 2005 order that the Watson Station fee is not grandfathered. Several of the participants in the proceeding requested rehearing of the FERC’s phase one order. The FERC denied those requests in its June 1, 2005 order. In addition, several participants, including SFPP, filed petitions with the United States Court of Appeals for the District of Columbia Circuit for review of the FERC’s phase one order. On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for review of the phase one order, which Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004, the Court of Appeals referred the FERC’s motion to the merits panel and directed the parties to address the issues in that motion on brief, thus effectively dismissing the FERC’s motion. In the same order, the Court of Appeals granted a motion to hold the petitions for review of the FERC’s phase one order in abeyance and directed the parties to file motions to govern future proceeding 30 days after FERC disposition of the pending rehearing requests. In August 2005, the FERC and SFPP jointly moved that the Court of Appeals hold the petitions for review of the March 26, 2004 and June 1, 2005 orders in abeyance due to the pendency of further action before the FERC on income tax allowance issues. In December 2005, the Court of Appeals denied this motion and placed the petitions seeking review of the two orders on the active docket.

The FERC’s phase one order also held that SFPP failed to seek authorization for the accounting entries necessary to reflect in SFPP’s books, and thus in its annual report to the FERC (“FERC Form 6”), the purchase price adjustment (“PPA”) arising from our 1998 acquisition of SFPP. The phase one order directed SFPP to file for permission to reflect the PPA in its FERC Form 6 for the calendar year 1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP noted that it had previously requested such permission and that the FERC’s regulations require an oil pipeline to include a PPA in its Form 6

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without first seeking FERC permission to do so. Several parties protested SFPP’s compliance filing. In its June 1, 2005 order, the FERC accepted SFPP’s compliance filing.

In the June 1, 2005 order, the FERC directed SFPP to file a brief addressing whether the records developed in the OR92-8 and OR96-2 cases were sufficient to determine SFPP’s entitlement to include an income tax allowance in its rates under the FERC’s new policy statement. On June 16, 2005, SFPP filed its brief reviewing the pertinent records in the pending cases and applicable law and demonstrating its entitlement to a full income tax allowance in its interstate rates. SFPP’s opponents in the two cases filed reply briefs contesting SFPP’s presentation. It is not possible to predict with certainty the ultimate resolution of this issue, particularly given the likelihood that the FERC’s policy statement and its decision in these cases will be appealed to the federal courts.

On September 9, 2004, the presiding administrative law judge in OR96-2 issued his initial decision in the phase two portion of this proceeding, recommending establishment of prospective rates and the calculation of reparations for complaining shippers with respect to the West Line and East Line, relying upon cost of service determinations generally unfavorable to SFPP.

On December 16, 2005, the FERC issued an order addressing issues remanded by the Court of Appeals in the Docket No. OR92-8 proceeding (discussed above) and the phase two cost of service issues, including income tax allowance issues arising from the briefing directed by the FERC’s June 1, 2005 order. The FERC directed SFPP to submit compliance filings and revised tariffs by February 28, 2006 (as extended to March 7, 2006) which were to address, in addition to the OR92-8 matters discussed above, the establishment of interim West Line rates based on a 1999 test year, indexed forward to a May 1, 2006 effective date and estimated reparations. The FERC also resolved favorably a number of methodological issues regarding the calculation of SFPP’s income tax allowance under the May 2005 policy statement and, in its compliance filings, directed SFPP to submit further information establishing the amount of its income tax allowance for the years at issue in the OR92-8 and OR96-2 proceedings.

SFPP and Navajo have filed requests for rehearing of the December 16, 2005 order. ExxonMobil, BP West Coast Products, Chevron, Ultramar, and ConocoPhillips have filed petitions for review of the December 16, 2005 order with the United States Court of Appeals for the District of Columbia Circuit. On February 13, 2006, the FERC issued an order addressing the pending rehearing requests, granting the majority of SFPP’s requested changes regarding reparations and methodological issues. SFPP, Navajo, and other parties have filed petitions for review of the December 16, 2005 and February 13, 2006 orders with the United States Court of Appeals for the District of Columbia Circuit.

On March 7, 2006, SFPP filed its compliance filings and revised tariffs. Various shippers filed protests of the tariffs. On April 21, 2006, various parties submitted comments challenging aspects of the costs of service and rates reflected in the compliance filings and tariffs. On April 28, 2006, the FERC issued an order accepting SFPP’s tariffs lowering its West Line and East Line rates in conformity with the FERC’s December 2005 and February 2006 orders. On May 1, 2006, these lower tariff rates became effective. The FERC indicated that a subsequent order would address the issues raised in the comments. On May 1, 2006, SFPP filed reply comments.

We are not able to predict with certainty the final outcome of the pending FERC proceedings involving SFPP, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. The final outcome will depend, in part, on the outcomes of the appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP, complaining shippers, and an intervenor.

Kinder Morgan Energy Partners estimated, as of December 31, 2003, that shippers’ claims for reparations totaled approximately $154 million and that prospective rate reductions would have an aggregate average annual impact of approximately $45 million, with the reparations amount and interest increasing as the timing for implementation of rate reductions and the payment of reparations has extended (estimated at a quarterly increase of approximately $9 million). Based on the December 16, 2005 order, rate reductions will be implemented on May 1, 2006. Kinder Morgan Energy Partners now assumes that reparations and accrued interest thereon will be paid no earlier than the first quarter of 2007; however, the timing, and nature, of any rate reductions and reparations that may be ordered will likely be affected by the final disposition of the application of the FERC’s new policy statement on income tax allowances to the Pacific operations in the FERC Docket Nos. OR92-8 and OR96-2 proceedings. In 2005, Kinder Morgan Energy Partners recorded an accrual of $105.0 million for an expense attributable to an increase in reserves related to SFPP’s rate case liability. Kinder Morgan Energy Partners had previously estimated the combined annual impact of the rate reductions and the payment of reparations sought by shippers on Kinder Morgan Energy Partners would be approximately 15 cents of distributable cash flow per unit. Based on our review of the FERC’s December 16, 2005 order and the FERC’s February 13, 2006 order on rehearing, and subject to the ultimate resolution of these issues in our compliance filings and subsequent judicial appeals, we now expect the total annual impact on Kinder Morgan Energy Partners will be less than 15 cents per unit. The actual, partial year impact on Kinder Morgan Energy Partners’ 2006 distributable cash flow per unit will likely be closer to 5 cents per unit and the partial year impact on our 2006 earnings per common share will be approximately $0.05 per share.

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Chevron complaint OR02-4 and OR03-5 proceedings. On February 11, 2002, Chevron, an intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the FERC dismissed Chevron’s complaint and motion to consolidate. Chevron filed a request for rehearing, which the FERC dismissed on September 25, 2002. In October 2002, Chevron filed a request for rehearing of the FERC’s September 25, 2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron filed a petition for review of this denial at the U.S. Court of Appeals for the District of Columbia Circuit.

On June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) - substantially similar to its previous complaint – and moved to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. Chevron requested that this new complaint be treated as if it were an amendment to its complaint in Docket No. OR02-4, which was previously dismissed by the FERC. By this request, Chevron sought to, in effect, back-date its complaint, and claim for reparations, to February 2002. SFPP answered Chevron’s complaint on July 22, 2003, opposing Chevron’s requests. On October 28, 2003 , the FERC accepted Chevron’s complaint, but held it in abeyance pending the outcome of the Docket No. OR96-2, et al. proceeding. The FERC denied Chevron’s request for consolidation and for back-dating. On November 21, 2003, Chevron filed a petition for review of the FERC’s October 28, 2003 order at the Court of Appeals for the District of Columbia Circuit.

On August 18, 2003, SFPP filed a motion to dismiss Chevron’s petition for review in OR02-4 on the basis that Chevron lacks standing to bring its appeal and that the case is not ripe for review. Chevron answered on September 10, 2003. SFPP’s motion was pending, when the Court of Appeals, on December 8, 2003, granted Chevron’s motion to hold the case in abeyance pending the outcome of the appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the Court of Appeals granted Chevron’s motion to have its appeal of the FERC’s decision in OR03-5 consolidated with Chevron’s appeal of the FERC’s decision in the OR02-4 proceeding. Following motions to dismiss by the FERC and SFPP, on December 10, 2004, the Court dismissed Chevron’s petition for review in Docket No. OR03-5 and set Chevron’s appeal of the FERC’s orders in OR02-4 for briefing. On January 4, 2005, the Court granted Chevron’s request to hold such briefing in abeyance until after final disposition of the OR96-2 proceeding. Chevron continues to participate in the Docket No. OR96-2 et al. proceeding as an intervenor.

Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines, Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental Airlines, Inc. (collectively, the “Airlines”) filed a complaint against SFPP at the FERC. The Airlines’ complaint alleges that the rates on SFPP’s West Line and SFPP’s charge for its gathering enhancement service at Watson Station are not just and reasonable. The Airlines seek rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company, L.P., and ChevronTexaco Products Company all filed timely motions to intervene in this proceeding. Valero Marketing and Supply Company filed a motion to intervene one day after the deadline. SFPP answered the Airlines’ complaint on October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP’s answer and on November 12, 2004, SFPP replied to the Airlines’ response. In March and June 2005, the Airlines filed motions seeking expedited action on their complaint, and in July 2005, the Airlines filed a motion seeking to sever issues related to the Watson Station gathering enhancement fee from the OR04-3 proceeding and consolidate them in the proceeding regarding the justness and reasonableness of that fee that the FERC docketed as part of the June 1, 2005 order. In August 2005, the FERC granted the Airlines’ motion to sever and consolidate the Watson Station fee issues.

OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC, which the FERC docketed as OR05-4. The complaint alleges that SFPP’s interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that “substantially changed circumstances” have occurred, removing such protection. The complainants seek rate reductions and reparations for two years prior to the filing of their complaint and ask that the complaint be consolidated with the Airlines’ complaint in the OR04-3 proceeding. ConocoPhillips Company, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 24, 2005.

On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the FERC, which the FERC docketed as OR05-5. The complaint alleges that SFPP’s interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that “substantially changed circumstances” have occurred, removing such protection. ConocoPhillips seeks rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 28, 2005.

On February 25, 2005, the FERC consolidated the complaints in Docket Nos. OR05-4 and OR05-5 and held them in abeyance until after the conclusion of the various pending SFPP proceedings, deferring any ruling on the validity of the complaints. On March 28, 2005, BP West Coast and ExxonMobil requested rehearing of one aspect of the February 25, 2005

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order; they argued that any tax allowance matters in these proceedings could not be decided in, or as a result of, the FERC’s inquiry into income tax allowance in Docket No. PL05-5. On June 8, 2005, the FERC denied the request for rehearing.

Consolidated Complaints. On February 13, 2006, the FERC consolidated the complaints in Docket Nos. OR03-5, OR04-3, OR05-4, and OR05-5 and set for hearing the portions of those complaints attacking SFPP’s North Line and Oregon Line rates, which rates remain grandfathered under the Energy Policy Act of 1992. A procedural schedule, leading to hearing in early 2007, has been established in that consolidated proceeding. Contemporaneously, settlement negotiations under the auspices of a FERC settlement judge are proceeding. The FERC also indicated in its order that it would address the remaining portions of these complaints in the context of its disposition of SFPP’s compliance filings in the OR92-8/OR96-2 proceedings.

North Line rate case, IS05-230 proceeding. In April 2005, SFPP filed to increase its North Line interstate rates to reflect increased costs, principally due to the installation of replacement pipe between Concord and Sacramento, California. Under FERC regulations, SFPP was required to demonstrate that there was a substantial divergence between the revenues generated by its existing North Line rates and its increased costs. SFPP’s rate increase was protested by various shippers and accepted subject to refund by the FERC. A hearing was held in January and February 2006, and the case has now been briefed to the administrative law judge.

Trailblazer Pipeline Company

On March 22, 2005, Marathon Oil Company filed a formal complaint with the FERC alleging that Trailblazer Pipeline Company violated the FERC’s Negotiated Rate Policy Statement and the Natural Gas Act by failing to offer a recourse rate option for its Expansion 2002 capacity and by charging negotiated rates higher than the applicable recourse rates. Marathon requested that the FERC require Trailblazer to refund all amounts paid by Marathon above Trailblazer’s Expansion 2002 recourse rate since the facilities went into service in May 2002, with interest. In addition, Marathon asked the FERC to require Trailblazer to bill Marathon the Expansion 2002 recourse rate for future billings. Marathon estimated that the amount of Trailblazer’s refund obligation at the time of the filing was over $15 million. Trailblazer filed its response to Marathon’s complaint on April 13, 2005. On May 20, 2005, the FERC issued an order denying the Marathon complaint and found that (i) Trailblazer did not violate FERC policy and regulations and (ii) there is insufficient justification to initiate further action under Section 5 of the Natural Gas Act to invalidate and change the negotiated rate.On June 17, 2005, Marathon filed its Request for Rehearing of the May 20, 2005 order. On January 19, 2006, the FERC issued an order which denied Marathon’s rehearing request.

California Public Utilities Commission Proceeding

ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission on April 7, 1997. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments. On October 1, 1997, the complainants filed testimony seeking prospective rate reductions aggregating approximately $15 million per year.

On August 6, 1998, the CPUC issued its decision dismissing the complainants’ challenge to SFPP’s intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of addressing the proper ratemaking treatment for partnership tax expenses, the calculation of environmental costs and the public utility status of SFPP’s Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, complainants sought prospective rate reductions aggregating approximately $10 million per year.

On March 16, 2000, SFPP filed an application with the CPUC seeking authority to justify its rates for intrastate transportation of refined petroleum products on competitive, market-based conditions rather than on traditional, cost-of-service analysis.

On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC asserting that SFPP’s California intrastate rates are not just and reasonable based on a 1998 test year and requesting the CPUC to reduce SFPP’s rates prospectively. The amount of the reduction in SFPP rates sought by the complainants is not discernible from the complaint.

The rehearing complaint was heard by the CPUC in October 2000 and the April 2000 complaint and SFPP’s market-based application were heard by the CPUC in February 2001. All three matters stand submitted as of April 13, 2001, and resolution of these submitted matters may occur within the second quarter of 2006.

The CPUC subsequently issued a resolution approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution approving the requested rate increase also required SFPP to submit cost data for 2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP’s overall rates for California intrastate transportation services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC’s analysis of cost data to be submitted by SFPP demonstrates that SFPP’s California jurisdictional rates are

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unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data required by the CPUC, which submittal was protested by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and Chevron Products Company. Issues raised by the protest, including the reasonableness of SFPP’s existing intrastate transportation rates, were the subject of evidentiary hearings conducted in December 2003 and may be resolved by the CPUC in the second quarter of 2006.

On November 22, 2004, SFPP filed an application with the CPUC requesting a $9 million increase in existing intrastate rates to reflect the in-service date of SFPP’s replacement and expansion of its Concord-to-Sacramento pipeline. The requested rate increase, which automatically became effective as of December 22, 2004 pursuant to California Public Utilities Code Section 455.3, is being collected subject to refund, pending resolution of protests to the application by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is not expected to resolve the matter before the third quarter of 2006.

We currently believe the complaints before the CPUC seek approximately $15 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $31 million. There is no way to quantify the potential extent to which the CPUC could determine that SFPP’s existing California rates are unreasonable. With regard to the amount of dollars potentially subject to refund as a consequence of the CPUC resolution requiring the provision by SFPP of cost-of-service data, referred to above, such refunds could total about $6 million per year from October 2002 to the anticipated date of a CPUC decision.

On January 26, 2006, SFPP filed a request for an annual rate increase of approximately $5.4 million with the CPUC, to be effective as of March 2, 2006. Protests to SFPP’s rate increase application have been filed by Tesoro Refining and Marketing Company, BP West Coast Products LLC, ExxonMobil Oil Corporation, Southwest Airlines Company, Valero Marketing and Supply Company, Ultramar Inc. and Chevron Products Company, asserting that the requested rate increase is unreasonable. Pending the outcome of protests to SFPP’s filing, the rate increase, which will be collected in the form of a surcharge to existing rates, will be collected subject to refund.

SFPP believes the submission of the required, representative cost data required by the CPUC indicates that SFPP’s existing rates for California intrastate services remain reasonable and that no refunds are justified.

We believe that the resolution of such matters will not have a material adverse effect on our business, financial position, results of operations or cash flows.

Other Regulatory Matters

In addition to the matters described above, we may face additional challenges to our rates in the future. Regulators and shippers on our pipelines have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future or that any successful challenge will not have a material adverse effect on our business, financial position, results of operations or cash flows. 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 a material adverse effect on our business, financial position, results of operations or cash flows.

Carbon Dioxide Litigation

Kinder Morgan CO₂ Company, L.P., Kinder Morgan G.P., Inc., and Cortez Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed March 29, 2001). These cases were originally filed as class actions on behalf of classes of overriding royalty interest owners (Shores) and royalty interest owners (Bank of Denton) for damages relating to alleged underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes were initially certified at the trial court level, appeals resulted in the decertification and/or abandonment of the class claims. On February 22, 2005, the trial judge dismissed both cases for lack of jurisdiction. Some of the individual plaintiffs in these cases re-filed their claims in new lawsuits (discussed below).

On May 13, 2004, William Armor, one of the former plaintiffs in the Shores matter whose claims were dismissed by the Court of Appeals for improper venue, filed a new case alleging the same claims for underpayment of royalties against the same defendants previously sued in the Shores case, including Kinder Morgan CO₂ Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas filed May 13, 2004). Defendants filed their answers and special exceptions on June 4, 2004. Trial is presently scheduled to occur on June 12, 2006, but will likely take place in late 2006 on account of an uncontested motion filed by the Plaintiffs to continue the trial date.

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On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state district court alleging the same claims for underpayment of royalties. Reddy and Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial District Court, Dallas County, Texas filed May 20, 2005). The defendants include Kinder Morgan CO₂ Company, L.P. and Kinder Morgan Energy Partners, L.P. On June 23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the court in the Armor lawsuit granted the motion to transfer and consolidate and ordered that the Reddy lawsuit be transferred and consolidated into the Armor lawsuit. The defendants filed their answer and special exceptions on August 10, 2005. The consolidated Armor/Reddy trial is presently scheduled to occur on June 12, 2006 but will likely take place in late 2006 on account of an uncontested motion filed by the Plaintiffs to continue the trial date.

Shell CO₂ Company, Ltd., predecessor in interest to Kinder Morgan CO₂ Company, L.P., is among the named counter-claim defendants in Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial District Court, Harris County, Texas filed June 17, 1998) (the “Bailey State Court Action”). The counter-claim plaintiffs are overriding royalty interest owners in the McElmo Dome Unit and have sued seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. In the Bailey State Court Action, the counter-claim plaintiffs asserted claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, negligence, negligence per se, unjust enrichment, violation of the Texas Securities Act, and open account. The trial court in the Bailey State Court Action granted a series of summary judgment motions filed by the counter-claim defendants on all of the counter-plaintiffs’ counter-claims except for the fraud-based claims. In 2004, one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege purported claims as a private relator under the False Claims Act and antitrust claims. The federal government elected to not intervene in the False Claims Act counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March 24, 2005) (the “Bailey Houston Federal Court Action”). Also on March 24, 2005, Bailey filed an instrument under seal in the Bailey Houston Federal Court Action that was later determined to be a motion to transfer venue of that case to the federal district court of Colorado, in which Bailey and two other plaintiffs have filed another suit against Kinder Morgan CO₂ Company, L.P. asserting claims under the False Claims Act. The Houston federal district judge ordered that Bailey take steps to have the False Claims Act case pending in Colorado transferred to the Bailey Houston Federal Court Action, and also suggested that the claims of other plaintiffs in other carbon dioxide litigation pending in Texas should be transferred to the Bailey Houston Federal Court Action. In response to the court's suggestion, the case of Gary Shores et al. v. ExxonMobil Corp. et al., No. 05-1825 (S.D. Tex., Houston Division) was consolidated with the Bailey Houston Federal Court Action on July 18, 2005. That case, in which the plaintiffs assert claims for McElmo Dome royalty underpayment, includes Kinder Morgan CO₂ Company, L.P., Kinder Morgan Energy Partners, L.P., and Cortez Pipeline Company as defendants. Bailey requested the Houston federal district court to transfer the Bailey Houston Federal Court Action to the federal district court of Colorado. Bailey also filed a petition for writ of mandamus in the Fifth Circuit Court of Appeals, asking that the Houston federal district court be required to transfer the case to the federal district court of Colorado. On June 3, 2005, the Fifth Circuit Court of Appeals denied Bailey's petition for writ of mandamus. On June 22, 2005, the Fifth Circuit denied Bailey’s petition for rehearing en banc. On September 14, 2005, Bailey filed a petition for writ of certiorari in the United States Supreme Court, which the U.S. Supreme Court denied on November 28, 2005. On November 21, 2005, the federal district court in Colorado transferred Bailey’s False Claims Act case pending in Colorado to the Houston federal district court. On November 30, 2005, Bailey filed a petition for mandamus seeking to vacate the transfer. The Tenth Circuit Court of Appeals denied the petition on December 19, 2005. The U.S. Supreme Court has denied Bailey’s petition for writ of certiorari. The Houston federal district court subsequently realigned the parties in the Bailey Houston Federal Court Action. Pursuant to the Houston federal district court’s order, Bailey and the other realigned plaintiffs have filed amended complaints in which they assert claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of contract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account. Bailey also asserted claims as a private relator under the False Claims Act and for violation of federal and Colorado antitrust laws. The realigned plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The Shell and Kinder Morgan defendants, along with Cortez Pipeline Company and ExxonMobil defendants, have filed motions for summary judgment on all claims. No current trial date is set.

On March 1, 2004, Bridwell Oil Company, one of the named defendants/realigned plaintiffs in the Bailey actions, filed a new matter in which it asserts claims which are virtually identical to the counter-claims it asserts against Shell CO₂ Company, Ltd. in the Bailey lawsuit. Bridwell Oil Co. v. Shell Oil Co. et al, No. 160,199-B (78^th Judicial District Court, Wichita County, Texas filed March 1, 2004). The defendants in this action include Kinder Morgan CO₂ Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, defendants filed answers, special exceptions, pleas in abatement, and motions to transfer venue back to the Harris County District Court. On January 31, 2005, the Wichita County judge abated the case pending resolution of the Bailey State Court Action. The case remains abated.

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On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Colorado federal action filed by Bailey under the False Claims Act (which was transferred to the Bailey Houston Federal Court Action as described above), filed suit against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District Court for the District of Colorado). Ptasynski, who holds an overriding royalty interest at McElmo Dome, asserts claims for civil conspiracy, violation of the Colorado Organized Crime Control Act, violation of Colorado antitrust laws, violation of the Colorado Unfair Practices Act, breach of fiduciary duty and confidential relationship, violation of the Colorado Payment of Proceeds Act, fraudulent concealment, breach of contract and implied duties to market and good faith and fair dealing, and civil theft and conversion. Ptasynski seeks actual damages, treble damages, forfeiture, disgorgement, and declaratory and injunctive relief. Kinder Morgan G.P., Inc. intends to seek dismissal of the case or, alternatively, transfer of the case to the Bailey Houston Federal Court Action. No trial date is currently set.

Kinder Morgan CO₂ Company, L.P. and Cortez Pipeline Company are among the named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case involves claims by overriding royalty interest owners in the McElmo Dome and Doe Canyon Units seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome and Doe Canyon. The plaintiffs also possess a small working interest at Doe Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties owed by the defendants and also allege other theories of liability including breach of covenants, civil theft, conversion, fraud/fraudulent concealment, violation of the Colorado Organized Crime Control Act, deceptive trade practices, and violation of the Colorado Antitrust Act. In addition to actual or compensatory damages, plaintiffs seek treble damages, punitive damages, and declaratory relief relating to the Cortez Pipeline tariff and the method of calculating and paying royalties on McElmo Dome carbon dioxide. The Court denied plaintiffs’ motion for summary judgment concerning alleged underpayment of McElmo Dome overriding royalties on March 2, 2005. The parties are continuing to engage in discovery. No trial date is currently set.

Cortez Pipeline Company and Kinder Morgan CO₂ Company, L.P., successor in interest to Shell CO₂ Company, Ltd., are among the named defendants in CO₂ Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The arbitration arises from a dispute over a class action settlement agreement which became final on July 7, 2003 and disposed of five lawsuits formerly pending in the U.S. District Court, District of Colorado. The plaintiffs in such lawsuits primarily included overriding royalty interest owners, royalty interest owners, and small share working interest owners who alleged underpayment of royalties and other payments on carbon dioxide produced from the McElmo Dome Unit in southwest Colorado. The settlement imposed certain future obligations on the defendants in the underlying litigation. The plaintiff in the current arbitration is an entity that was formed as part of the settlement for the purpose of monitoring compliance with the obligations imposed by the settlement agreement. The plaintiff alleges that, in calculating royalty and other payments, defendants used a transportation expense in excess of what is allowed by the settlement agreement, thereby causing alleged underpayments of approximately $10.3 million. The plaintiff also alleges that Cortez Pipeline Company should have used certain funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.2 million. Defendants deny that there was any breach of the settlement agreement. The arbitration panel has issued various preliminary evidentiary rulings. The arbitration is currently scheduled to commence on June 26, 2006.

J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO₂ Company, L.P., No. 04-26-CL (8^th Judicial District Court, Union County New Mexico)

This case involves a purported class action against Kinder Morgan CO₂ Company, L.P. alleging that it has failed to pay the full royalty and overriding royalty (“royalty interests”) on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit in the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit. The plaintiffs allege that they were members of a class previously certified as a class action by the United States District Court for the District of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-0012 (the “Feerer Class Action”). Plaintiffs allege that Kinder Morgan CO₂ Company’s method of paying royalty interests is contrary to the settlement of the Feerer Class Action. Kinder Morgan CO₂ Company has filed a motion to compel arbitration of this matter pursuant to the arbitration provisions contained in the Feerer Class Action settlement agreement, which motion was denied by the trial court. An appeal of that ruling has been filed and is pending before the New Mexico Court of Appeals. Oral arguments took place before the New Mexico Court of Appeals on March 23, 2006. No date for arbitration or trial is currently set.

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In addition to the matters listed above, various audits and administrative inquiries concerning Kinder Morgan CO₂ Company L.P.’s royalty and tax payments on carbon dioxide produced from the McElmo Dome Unit are currently ongoing. These audits and inquiries involve various federal agencies, the State of Colorado, the Colorado oil and gas commission, and Colorado county taxing authorities.

Commercial Litigation Matters

Union Pacific Railroad Company Easements

SFPP and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company and referred to in this report as UPRR) are engaged in two proceedings to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for each of the ten year periods beginning January 1, 1994 and January 1, 2004 (Southern Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the State of California for the County of San Francisco, filed August 31, 1994; and Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004).

With regard to the first proceeding, covering the ten year period beginning January 1, 1994, the trial court, on July 16, 2003, set the rent for years 1994 – 2003 at approximately $5.0 million per year as of January 1, 1994, subject to annual inflation increases throughout the ten year period. On February 23, 2005, the California Court of Appeals affirmed the trial court’s ruling, except that it reversed a small portion of the decision and remanded it back to the trial court for determination. On remand, the trial court held that there was no adjustment to the rent relating to the portion of the decision that was reversed, but awarded Southern Pacific Transportation Company interest on rental amounts owing as of May 7, 1997.

In April 2006, SFPP paid UPRR $15.3 million in satisfaction of its rental obligations through December 31, 2003. However, SFPP does not believe that the assessment of interest awarded Southern Pacific Transportation Company on rental amounts owing as of May 7, 1997 was proper, and SFPP is seeking appellate review of the interest award.

In addition, SFPP and UPRR are engaged in a second proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). SFPP was served with this lawsuit on August 17, 2004. SFPP expects that the trial in this matter will occur in late 2006.

SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right of way and the safety standards that govern relocations. SFPP believes that it must pay for relocation of the pipeline only when so required by the railroad’s common carrier operations, and in doing so, it need only comply with standards set forth in the federal Pipeline Safety Act in conducting relocations. UPRR contends that it has complete discretion to cause the pipeline to be relocated at SFPP’s expense at any time and for any reason, and that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards. Each party is seeking declaratory relief with respect to its positions regarding relocations.

It is difficult to quantify the effects of the outcome of these cases on SFPP because SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations. Even if SFPP is successful in advancing its position, significant relocations for which SFPP must nonetheless bear the expense (i.e. for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position and results of operations. These effects would be even more in the event SFPP is unsuccessful in one or more of these litigations.

RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial District).

On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the First Supplemental Petition filed by RSM Production Corporation on behalf of the County of Zapata, State of Texas and Zapata County Independent School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition alleges that these taxing units relied on the reported volume and analyzed heating content of natural gas produced from the wells located within the appropriate taxing jurisdiction in order to properly assess the value of mineral interests in place. The suit further alleges that the defendants undermeasured the volume and heating content of that natural gas produced from privately owned wells in Zapata County, Texas. The Petition further alleges that the County and School District were deprived of ad

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valorem tax revenues as a result of the alleged undermeasurement of the natural gas by the defendants. On December 15, 2001, the defendants filed motions to transfer venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery requests on certain defendants. On July 11, 2003, defendants moved to stay any responses to such discovery.

United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).

This action was filed on June 9, 1997 pursuant to the federal False Claims Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas acquisition and other Kinder Morgan subsidiaries are also defendants in this matter. An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases, referred to as valuation claims. Judge Downes denied the defendant’s motion to dismiss on May 18, 2001. The United States’ motion to dismiss most of plaintiff’s valuation claims has been granted by the court. Grynberg has appealed that dismissal to the 10^th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Subsequently, 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 arguments on jurisdiction were held before the Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to carbon dioxide production. Defendants have filed briefs opposing leave to amend. Neither the Court nor the Special Master has ruled on 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 Grynberg alleged, and that Grynberg was not an original source of the allegations. As a result, the Special Master recommended dismissal of the Kinder Morgan defendants on jurisdictional grounds. On June 27, 2005, 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 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.

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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.

Weldon Johnson and Guy Sparks, individually and as Representative of Others Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit Court, Miller County Arkansas).

On October 8, 2004, plaintiffs filed the above-captioned matter against numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC; and MidCon Corp. The complaint purports to bring a class action on behalf of those who purchased natural gas from CenterPoint and certain of its affiliates from October 1, 1994 to the date of class certification.

The complaint alleges that CenterPoint Energy, Inc., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-CenterPoint defendants, including the above-listed Kinder Morgan entities. The complaint further alleges that in exchange for CenterPoint’s purchase of such natural gas at above market prices, the non-CenterPoint defendants, including the above-listed Kinder Morgan entities, sell natural gas to CenterPoint’s non-regulated affiliates at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The complaint purports to assert claims for fraud, unlawful enrichment and civil conspiracy against all of the defendants, and seeks relief in the form of actual, exemplary and punitive damages, interest, and attorneys’ fees. The parties have recently concluded jurisdictional discovery and a hearing is scheduled for summer 2006 on various defendants' assertion that the Arkansas courts lack personal jurisdiction over them. Based on the information available to date and our preliminary investigation, the Kinder Morgan defendants believe that the claims against them are without merit and intend to defend against them vigorously.

Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder Morgan Operating L.P. “A,” and Kinder Morgan, Inc., No. 2000-45252 (189^th Judicial District Court, Harris County, Texas)

On September 1, 2000, plaintiff Exxon Mobil Corporation filed its original petition and application for declaratory relief against Kinder Morgan Operating L.P. “A,” Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder Morgan Operating L.P. “A,” Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P., Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron Helium Company. Plaintiff added Enron Corp. as party in interest for Enron Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a defendant. The claims against Enron Corp. were severed into a separate cause of action. Plaintiff’s claims are based on a gas processing agreement entered into on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company relating to gas produced in the Hugoton Field in Kansas and processed at the Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff also asserts claims relating to the helium extraction agreement entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated March 14, 1988. Plaintiff alleges that defendants failed to deliver propane and to allocate plant products to the plaintiff as required by the gas processing agreement and originally sought damages of approximately $5.9 million.

Plaintiff filed its third amended petition on February 25, 2003. In its third amended petition, the plaintiff alleges claims for breach of the gas processing agreement and the helium extraction agreement, requests a declaratory judgment and asserts claims for fraud by silence/bad faith, fraudulent inducement of the 1997 amendment to the gas processing agreement, civil conspiracy, fraud, breach of a duty of good faith and fair dealing, negligent misrepresentation and conversion. As of April 7, 2003, the plaintiff alleged economic damages for the period from November 1987 through March 1997 in the amount of $30.7 million. On May 2, 2003, the plaintiff added claims for the period from April 1997 through February 2003 in the amount of $12.9 million. On June 23, 2003, the plaintiff filed a fourth amended petition that reduced its total claim for economic damages to $30.0 million. On October 5, 2003, the plaintiff filed a fifth amended petition that purported to add a cause of action for embezzlement. On February 10, 2004, the plaintiff filed its eleventh supplemental responses to requests for disclosure that restated its alleged economic damages for the period of November 1987 through December 2003 as approximately $37.4 million. The matter went to trial on June 21, 2004. On June 30, 2004, the jury returned a unanimous verdict in favor of all defendants as to all counts. Final judgment was entered in favor of the defendants on August 19, 2004. Plaintiff has appealed the jury’s verdict to the 14^th Court of Appeals for the State of Texas. On February 21, 2006, the Court of Appeals unanimously affirmed the judgment in our favor entered by the trial court, and ordered ExxonMobil to pay all costs incurred in the appeal. ExxonMobil has not filed an appeal of this decision to the Texas Supreme Court, so the matter is now concluded.

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Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No. 2005-36174 (333^rd Judicial District, Harris County, Texas).

On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder Morgan Texas Pipeline, L.P., referred to in this summary as KMTP, and alleged breach of contract for the purchase of natural gas storage capacity and for failure to pay under a profit-sharing arrangement. KMTP counterclaimed that Cannon Interests failed to provide it with five billion cubic feet of winter storage capacity in breach of the contract. The plaintiff is claiming approximately $13 million in damages. The parties are in the discovery phase. A trial date has been set for September 18, 2006. KMTP will defend the case vigorously, and based upon the information available to date, it believes that the claims against it are without merit and will be more than offset by its claims against Cannon Interests.

Federal Investigation at Cora and Grand Rivers Coal Facilities

On June 22, 2005, Kinder Morgan Energy Partners announced that the Federal Bureau of Investigation is conducting an investigation related to coal terminal facilities of its subsidiaries located in Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves certain coal sales from their Cora, Illinois and Grand Rivers, Kentucky coal terminals that occurred from 1997 through 2001. During this time period, the subsidiaries sold excess coal from these two terminals for their own account, generating less than $15 million in total net sales. Excess coal is the weight gain that results from moisture absorption into existing coal during transit or storage and from scale inaccuracies, which are typical in the industry. During the years 1997 through 1999, the subsidiaries collected, and, from 1997 through 2001, the subsidiaries subsequently sold, excess coal for their own account, as they believed they were entitled to do under then-existing customer contracts.

Kinder Morgan Energy Partners has conducted an internal investigation of the allegations and discovered no evidence of wrongdoing or improper activities at these two terminals. Furthermore, it has contacted customers of these terminals during the applicable time period and has offered to share information with them regarding the excess coal sales. Over the five-year period from 1997 to 2001, the subsidiaries moved almost 75 million tons of coal through these terminals, of which less than 1.4 million tons were sold for their own account (including both excess coal and coal purchased on the open market). They have not added to their inventory of excess coal since 1999 and have not sold coal for their own account since 2001, except for minor amounts of scrap coal. Kinder Morgan Energy Partners is fully cooperating with federal law enforcement authorities in this investigation. In September 2005 and subsequent thereto, it responded to a subpoena in this matter by producing a large volume of documents, which, we understand, are being reviewed by the FBI and auditors from the Tennessee Valley Authority, which is a customer of the Cora and Grand Rivers terminals. We do not expect that the resolution of the investigation will have a material adverse impact on our business, financial position, results of operations or cash flows.

Queen City Railcar Litigation

On August 28, 2005, a railcar containing the chemical styrene began leaking styrene gas in Cincinnati, Ohio while en route to the Queen City Terminal. The railcar was sent by the Westlake Chemical Corporation from Louisiana, transported by Indiana & Ohio Railway, and consigned to Westlake at its dedicated storage tank at Queen City Terminals, Inc., a subsidiary of Kinder Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation of many residents and the alleged temporary closure of several businesses in the Cincinnati area. Within three weeks of the incident, seven separate class action complaints were filed in the Hamilton County Court of Common Pleas, including case numbers: A0507115, A0507120, A0507121, A0507149, A0507322, A0507332, and A0507913.

On September 28, 2005, the court consolidated the complaints under consolidated case number A0507913. Concurrently, thirteen designated class representatives filed a Master Class Action Complaint against Westlake Chemical Corporation, Indiana and Ohio Railway Corporation, Queen City Terminals, Inc., Kinder Morgan Liquids Terminals, LLC, Kinder Morgan GP, Inc. and Kinder Morgan Energy Partners, L.P., collectively the defendants, in the Hamilton County Court of Common Pleas, case number A0507105. The complaint alleges negligence, absolute nuisance, nuisance, trespass, negligence per se, and strict liability against all defendants stemming from the styrene leak. The complaint seeks compensatory damages in excess of $25,000, punitive damages, pre and post-judgment interest, and attorney fees. The claims against the Indiana and Ohio Railway and Westlake are based generally on an alleged failure to deliver the railcar in a timely manner, which allegedly caused the styrene to become unstable and leak from the railcar. The plaintiffs allege that the Kinder Morgan entities named as defendants in the case had a legal duty to monitor the movement of the railcar en route to the Queen City Terminal and guarantee its timely arrival in a safe and stable condition.

On October 28, 2005, an answer was filed denying the material allegations of the complaint. On December 1, 2005, the plaintiffs filed a motion for class certification. On December 12, 2005, the Kinder Morgan entities named as defendants in the case filed a motion for an extension of time to respond to plaintiffs’ motion for class certification in order to conduct discovery regarding class certification. On February 10, 2006, the court granted the defendants motion for additional time to conduct class discovery. The court has not established a scheduling order or trial date, and discovery is ongoing.

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On September 6, 2005 and before the procedural developments in the case discussed above, the city of Cincinnati filed a complaint on behalf of itself and in parens patriae against Westlake, Indiana and Ohio Railway, Kinder Morgan Liquids Terminals, LLC, Queen City Terminals, Inc. and Kinder Morgan GP, Inc., collectively the defendants, in the Court of Common Pleas, Hamilton County, Ohio, case number A0507323. Plaintiff’s complaint arose out of the same railcar incident discussed immediately above. The plaintiff’s complaint alleges public nuisance, negligence, strict liability, and trespass. The complaint seeks compensatory damages in excess of $25,000, punitive damages, pre and post-judgment interest, and attorney fees. On September 28, 2005, the Kinder Morgan defendants filed a motion to dismiss the parens patriae claim. On December 15, 2005, the Kinder Morgan defendants filed a motion for summary judgment. The plaintiff has not responded to either motion. A trial date has not been set.

Leukemia Cluster Litigation

Kinder Morgan Energy Partners is a party to several lawsuits in Nevada that allege that the plaintiffs have developed leukemia as a result of exposure to harmful substances. Based on the information available to date, Kinder Morgan Energy Partners’ own preliminary investigation, and the positive results of investigations conducted by State and Federal agencies, Kinder Morgan Energy Partners believes that the claims against it in these matters are without merit and intends to defend against them vigorously. The following is a summary of these cases.

Marie Snyder, et al v. City of Fallon, United States Department of the Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District Court, District of Nevada)(“Snyder”); Frankie Sue Galaz, et al v. United States of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No. cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)(“Galaz I”); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership “D”, Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court, State of Nevada, County of Washoe) (“Galaz II”); Frankie Sue Galaz, et al v. The United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership “D”, Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District Court, District of Nevada)(“Galaz III”)

On July 9, 2002, Kinder Morgan Energy Partners was served with a purported complaint for class action in the Snyder case, in which the plaintiffs, on behalf of themselves and others similarly situated, assert that a leukemia cluster has developed in the City of Fallon, Nevada. The complaint alleges that the plaintiffs have been exposed to unspecified “environmental carcinogens” at unspecified times in an unspecified manner and are therefore “suffering a significantly increased fear of serious disease.” The plaintiffs seek a certification of a class of all persons in Nevada who have lived for at least three months of their first ten years of life in the City of Fallon between the years 1992 and the present who have not been diagnosed with leukemia.

The complaint purports to assert causes of action for nuisance and “knowing concealment, suppression, or omission of material facts” against all defendants, and seeks relief in the form of “a court-supervised trust fund, paid for by defendants, jointly and severally, to finance a medical monitoring program to deliver services to members of the purported class that include, but are not limited to, testing, preventative screening and surveillance for conditions resulting from, or which can potentially result from exposure to environmental carcinogens,” incidental damages, and attorneys’ fees and costs.

The defendants responded to the complaint by filing motions to dismiss on the grounds that it fails to state a claim upon which relief can be granted. On November 7, 2002, the United States District Court granted the motion to dismiss filed by the United States, and further dismissed all claims against the remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs filed a motion for reconsideration and leave to amend, which was denied by the court on December 30, 2002. Plaintiffs filed a notice of appeal to the United States Court of Appeals for the 9^th Circuit. On March 15, 2004, the 9^th Circuit affirmed the dismissal of this case.

On December 3, 2002, plaintiffs filed an additional complaint for class action in the Galaz I matter asserting the same claims in the same court on behalf of the same purported class against virtually the same defendants, including us. On February 10, 2003, the defendants filed motions to dismiss the Galaz I Complaint on the grounds that it also fails to state a claim upon which relief can be granted. This motion to dismiss was granted as to all defendants on April 3, 2003. Plaintiffs filed a notice of appeal to the United States Court of Appeals for the 9^th Circuit. On November 17, 2003, the 9^th Circuit dismissed the appeal, upholding the District Court’s dismissal of the case.

On June 20, 2003, plaintiffs filed an additional complaint for class action (the “Galaz II” matter) asserting the same claims in Nevada State trial court on behalf of the same purported class against virtually the same defendants, including us (and excluding the United States Department of the Navy). On September 30, 2003, the Kinder Morgan defendants filed a motion

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to dismiss the Galaz II Complaint along with a motion for sanctions. On April 13, 2004, plaintiffs’ counsel voluntarily stipulated to a dismissal with prejudice of the entire case in State Court. The court has accepted the stipulation and the case was dismissed on April 27, 2004.

Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters (now dismissed) filed yet another complaint for class action in the United States District Court for the District of Nevada (the “Galaz III” matter) asserting the same claims in United States District Court for the District of Nevada on behalf of the same purported class against virtually the same defendants, including us. The Kinder Morgan defendants filed a motion to dismiss the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs filed a motion for withdrawal of class action, which voluntarily drops the class action allegations from the matter and seeks to have the case proceed on behalf of the Galaz family only. On December 5, 2003, the District Court granted the Kinder Morgan defendants’ motion to dismiss, but granted plaintiff leave to file a second amended complaint. Plaintiff filed a second amended complaint on December 13, 2003, and a third amended complaint on January 5, 2004. The Kinder Morgan defendants filed a motion to dismiss the third amended complaint on January 13, 2004. The motion to dismiss was granted with prejudice on April 30, 2004. On May 7, 2004, plaintiff filed a notice of appeal in the United States Court of Appeals for the 9^th Circuit. On March 31, 2006, the 9^th Circuit affirmed the District Court’s dismissal of the case. On April 27, 2006, plaintiff filed a motion for an en banc review of this decision by the full 9^th Circuit Court of Appeals.  The Kinder Morgan defendants intend to oppose this motion.

Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) (“Jernee”).

On May 30, 2003, a separate group of plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against Kinder Morgan Energy Partners and several Kinder Morgan related entities and individuals and additional unrelated defendants. Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing “harmful substances and emissions and gases” to damage “the environment and health of human beings.” Plaintiffs claim that “Adam Jernee’s death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins.” Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. The Jernee case has been consolidated for pretrial purposes with the Sands case (see below). Plaintiffs have filed a third amended complaint and all defendants have filed motions to dismiss all causes of action excluding plaintiffs’ cause of action for negligence. Defendants have also filed motions to strike portions of the complaint. These motions remain pending before the court. As is its practice, the court has not scheduled argument on any such motions.

In addition to the above, the parties have filed motions to implement case management orders, the Jernee matter having now been deemed “complex” by the court. Such orders are designed to stage discovery, motions and pretrial proceedings. The court initially entered the case management order proposed by the defendants. Following plaintiffs’ motion for reconsideration, however, the court reversed itself, vacated the original case management order, and entered a case management order submitted by the plaintiffs. Defendants plan to file a motion to vacate this second case management order and re-institute the original case management order.

Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second Judicial District Court, State of Nevada, County of Washoe) (“Sands”).

On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against Kinder Morgan Energy Partners and several Kinder Morgan related entities and individuals and additional unrelated defendants. The Kinder Morgan defendants were served with the complaint on January 10, 2004. Plaintiffs in the Sands matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing “harmful substances and emissions and gases” to damage “the environment and health of human beings.” Plaintiffs claim that Stephanie Suzanne Sands’ death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins. Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. The Sands case has been consolidated for pretrial purposes with the Jernee case (see above). Plaintiffs have filed a second amended complaint and all defendants have filed motions to dismiss all causes of action excluding plaintiffs’ cause of action for negligence. Defendants have also filed motions to strike portions of the complaint. These motions remain pending before the court. As is its practice, the court has not scheduled argument on any such motions.

In addition to the above, the parties have filed motions to implement case management orders, the Sands matter having now been deemed “complex” by the court. Such orders are designed to stage discovery, motions and pretrial proceedings. The

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court initially entered the case management order proposed by the defendants. Following plaintiffs’ motion for reconsideration, however, the court reversed itself, vacated the original case management order, and entered a case management order submitted by the plaintiffs. Defendants plan to file a motion to vacate this second case management order and re-institute the original case management order.

Pipeline Integrity and Releases

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.

Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona.

On January 28, 2005, Meritage Homes Corp. and its above-named affiliates filed a complaint in the above-entitled action against Kinder Morgan Energy Partners, L.P. and SFPP. The plaintiffs are homebuilders who constructed a subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30, 2003 pipeline rupture and accompanying release of petroleum products, soil and groundwater adjacent to, on and underlying portions of Silver Creek II became contaminated. Plaintiffs allege that they have incurred and continue to incur costs, damages and expenses associated with the delay of closings of home sales within Silver Creek II and damage to their reputation and goodwill as a result of the rupture and release. Plaintiffs’ complaint purports to assert claims for negligence, breach of contract, trespass, nuisance, strict liability, subrogation and indemnity, and negligence per se. Plaintiffs seek “no less than $1.5 million in compensatory damages and necessary response costs,” a declaratory judgment, interest, punitive damages and attorneys’ fees and costs. The parties have agreed to submit the claims to arbitration and are currently engaged in discovery. The defendants dispute the legal and factual bases for many of plaintiffs’ claimed compensatory damages, deny that punitive damages are appropriate under the facts, and intend to vigorously defend this action.

Walnut Creek, California Pipeline Rupture

On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a water main installation project hired by East Bay Municipal Utility District (“EBMUD”), struck and ruptured an underground petroleum pipeline owned and operated by SFPP in Walnut Creek, California. An explosion occurred immediately following the rupture that resulted in five fatalities and several injuries to employees or contractors of Mountain Cascade. The explosion and fire also caused other property damage.

On May 5, 2005, the California Division of Occupational Safety and Health (“CalOSHA”) issued two civil citations against Kinder Morgan Energy Partners relating to this incident assessing civil fines of $140,000 based upon its alleged failure to mark the location of the pipeline properly prior to the excavation of the site by the contractor. CalOSHA, with the assistance of the Contra Costa County District Attorney’s office, is continuing to investigate the facts and circumstances surrounding the incident for possible criminal violations. In addition, on June 27, 2005, the Office of the California State Fire Marshal, Pipeline Safety Division (“CSFM”) issued a Notice of Violation against Kinder Morgan Energy Partners, which also alleges that it did not properly mark the location of the pipeline in violation of state and federal regulations. The CSFM assessed a proposed civil penalty of $500,000. The location of the incident was not SFPP’s work site, nor did SFPP have any direct involvement in the water main replacement project. We believe that SFPP acted in accordance with applicable law and regulations, and further that according to California law, excavators, such as the contractor on the project, must take the necessary steps (including excavating with hand tools) to confirm the exact location of a pipeline before using any power operated or power driven excavation equipment. Accordingly, we disagree with certain of the findings of CalOSHA and the CSFM, and SFPP has appealed the civil penalties while, at the same time, continuing to work cooperatively with CalOSHA and the CSFM to resolve these matters.

As a result of the accident, fifteen separate lawsuits have been filed. Eleven are personal injury and wrongful death actions. These are: Knox, et al. v.. Mountain Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-00281); Farley v. Mountain cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-01573); Reyes, et al. v. East Bay Municipal Utility District, et al. (Alameda Sup. Ct. Case No. RG-05-207720); Arias, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No. RG-05-195567); Angeles, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No. RG-05-195680); Ramos, et al. v. East Bay

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Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-01840); Taylor, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-02306); Becerra v. Kinder Morgan Energy Partners, L.P., et al., (Contra Costa County Superior Court Case No. C05-02451); Im, et al. v. Kinder Morgan, Inc. et al. (Contra Costa County Superior Court Case No. C05-02077); Paasch, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-01844); and Fuentes et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C05-02286). These complaints all allege, among other things, that the Kinder Morgan defendants failed to properly field mark the area where the accident occurred. All of these plaintiffs seek compensatory and punitive damages. These complaints also allege that the general contractor who struck the pipeline, Mountain Cascade, Inc. (“MCI”), and EBMUD were at fault for negligently failing to locate the pipeline. Some of these complaints also name various engineers on the project for negligently failing to draw up adequate plans indicating the bend in the pipeline. A number of these actions also name Comforce Technical Services as a defendant. Comforce supplied SFPP with temporary employees/independent contractors who performed line marking and inspections of the pipeline on behalf of SFPP. Some of these complaints also named various governmental entities—such as the City of Walnut Creek, Contra Costa County, and the Contra Costa Flood Control and Water Conservation District—as defendants.

Two of the fifteen suits are related to alleged damage to a residence near the accident site. These are: USAA v. East Bay Municipal Utility District, et al., (Contra Costa County Superior Court Case No. C05-02128); and Chabot v. East Bay Municipal Utilities District, et al., (Contra Costa Superior Court Case No. C05-02312). The remaining two suits are by MCI and the welding subcontractor, Matamoros. These are: Matamoros v. Kinder Morgan Energy Partners, L.P., et al., (Contra Costa County Superior Court Case No. C05-02349); and Mountain Cascade, Inc. v. Kinder Morgan Energy Partners, L.P., et al, (Contra Costa County Superior Court Case No. C-05-02576). Like the personal injury and wrongful death suits, these lawsuits allege that the Kinder Morgan defendants failed to properly mark its pipeline, causing damage to these plaintiffs. The Chabot and USAA plaintiffs allege property damage, while MCI and Matamoros Welding allege damage to their business as a result of the Kinder Morgan defendants’ alleged failures, as well as indemnity and other common law and statutory tort theories of recovery.

Fourteen of these lawsuits are currently coordinated in Contra Costa County Superior Court; the fifteenth is expected to be coordinated with the other lawsuits in the near future. There are also several cross-complaints for indemnity between the co-defendants in the coordinated lawsuits.

Based upon Kinder Morgan Energy Partners’ investigation of the cause of the rupture of SFPP’s petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and fire, Kinder Morgan Energy Partners has denied liability for the resulting deaths, injuries and damages, is vigorously defending against such claims, and seeking contribution and indemnity from the responsible parties.

Cordelia, California

On April 28, 2004, SFPP discovered a spill of diesel fuel into a marsh near Cordelia, California from a section of SFPP’s 14-inch Concord to Sacramento, California pipeline. Estimates indicated that the size of the spill was approximately 2,450 barrels. Upon discovery of the spill and notification to regulatory agencies, a unified response was implemented with the United States Coast Guard, the California Department of Fish and Game, the Office of Spill Prevention and Response and SFPP. The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on May 2, 2004. SFPP has completed recovery of diesel from the marsh and has completed an enhanced biodegradation program for removal of the remaining constituents bound up in soils. The property has been turned back to the owners for its stated purpose. There will be ongoing monitoring under the oversight of the California Regional Water Quality Control Board until the site conditions demonstrate there are no further actions required.

SFPP is currently in negotiations with the United States Environmental Protection Agency (referred to in this report as the EPA), the United States Fish & Wildlife Service, the California Department of Fish & Game and the San Francisco Regional Water Quality Control Board regarding potential civil penalties and natural resource damages assessments. Since the April 2004 release in the Suisun Marsh area near Cordelia, California, SFPP has cooperated fully with federal and state agencies and has worked diligently to remediate the affected areas. As of December 31, 2005, the remediation was substantially complete.

Oakland, California

In February 2005, Kinder Morgan Energy Partners was contacted by the U.S. Coast Guard regarding a potential release of jet fuel in the Oakland, California area. Its northern California team responded and discovered that one of Kinder Morgan Energy Partners’ product pipelines had been damaged by a third party, which resulted in a release of jet fuel that migrated to the storm drain system and the Oakland estuary. Kinder Morgan Energy Partners has coordinated the remediation of the impacts from this release, and is investigating the identity of the third party who damaged the pipeline in order to obtain contribution, indemnity, and to recover any damages associated with the rupture. Kinder Morgan Energy Partners has recently been informed that the

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EPA, the San Francisco Bay Regional Water Quality Control Board, the California Department of Fish and Game, and possibly the County of Alameda are asserting civil penalty claims with respect to this release. Kinder Morgan Energy Partners is currently in settlement negotiations with these agencies. Kinder Morgan Energy Partners will vigorously contest any unsupported, duplicative or excessive civil penalty claims, but hopes to be able to resolve the demands by each governmental entity through out-of-court settlements.

Donner Summit, California

In April 2005, the SFPP pipeline in Northern California, which transports refined petroleum products to Reno, Nevada, experienced a failure in the line from external damage, resulting in a release of product that affected a limited area adjacent to the pipeline near the summit of Donner Pass. The release was located on land administered by the Forest Service, an agency within the U.S. Department of Agriculture. Initial remediation has been conducted in the immediate vicinity of the pipeline. All agency requirements have been met and the site will be closed upon completion of the remediation. Civil penalty claims on behalf of the EPA, the California Department of Fish and Game, and the Lahontan Regional Water Quality Control Board have been made. SFPP is currently in settlement negotiations with these agencies. SFPP will vigorously contest any unsupported, duplicative or excessive civil penalty claims, but hopes to be able to resolve the demands by each governmental entity through out-of-court settlements.

Baker California

In November 2004, near Baker, California, the CALNEV Pipeline experienced a failure in its pipeline from external damage, resulting in a release of gasoline that affected approximately two acres of land in the high desert administered by The Bureau of Land Management, an agency within the U.S. Department of the Interior. Remediation has been conducted and continues for product in the soils. All agency requirements have been met and the site will be closed upon completion of the soil remediation. The State of California Department of Fish & Game has alleged a small natural resource damage claim that is currently under review. CALNEV expects to work cooperatively with the Department of Fish & Game to resolve this claim.

Henrico County, Virginia

On April 17, 2006, Plantation Pipeline, which transports refined petroleum products across the southeastern United States and which is 51.17% owned and operated by Kinder Morgan Energy Partners, experienced a pipeline release of turbine fuel from its 12-inch pipeline. The release occurred in a residential area and impacted adjacent homes, yards and common areas, as well as a nearby stream. Drinking water sources were not impacted. The released product did not ignite and there were no deaths or injuries. Plantation currently estimates the amount of product released to be approximately 665 barrels. Immediately following the release, the pipeline was shut down and emergency remediation activities were initiated. Remediation and monitoring activities are ongoing under the supervision of the EPA and the Virginia Department of Environmental Quality pursuant to the terms of an Emergency Removal/Response Administrative Order issued by the EPA under section 311(c) of the Clean Water Act. Repairs to the pipeline were completed on April 19, 2006 with the approval of the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA, and pipeline service resumed on April 20, 2006. On April 20, 2006, the PHMSA issued a Corrective Action Order which, among other things, requires that Plantation maintain a 20% reduction in the operating pressure along the pipeline between the Richmond and Newington, Virginia pump stations. The cause of the release is currently under investigation.

Proposed Office of Pipeline Safety Civil Penalty and Compliance Order

On July 15, 2004, the U.S. Department of Transportation’s Office of Pipeline Safety (“OPS”) issued a Proposed Civil Penalty and Proposed Compliance Order concerning alleged violations of certain federal regulations concerning Kinder Morgan Energy Partners’ products pipeline integrity management program. The violations alleged in the proposed order are based upon the results of inspections of Kinder Morgan Energy Partners’ integrity management program at its products pipelines facilities in Orange, California and Doraville, Georgia conducted in April and June of 2003, respectively. As a result of the alleged violations, the OPS seeks to have Kinder Morgan Energy Partners implement a number of changes to its integrity management program and also seeks to impose a proposed civil penalty of approximately $0.3 million. Kinder Morgan Energy Partners has already addressed a number of the concerns identified by the OPS and intends to continue to work with the OPS to ensure that its integrity management program satisfies all applicable regulations. However, Kinder Morgan Energy Partners disputes some of the OPS findings and disagrees that civil penalties are appropriate, and therefore requested an administrative hearing on these matters according to the U.S. Department of Transportation regulations. An administrative hearing was held on April 11 and 12, 2005. Kinder Morgan Energy Partners has provided supplemental information to the hearing officer and to the OPS. It is anticipated that the decision in this matter and potential administrative order will be issued by the end of the fourth quarter of 2006.

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Pipeline and Hazardous Materials Safety Administration Corrective Action Order

On August 26, 2005, Kinder Morgan Energy Partners announced that it had received a Corrective Action Order issued by the PHMSA. The corrective order instructs Kinder Morgan Energy Partners to comprehensively address potential integrity threats along the pipelines that comprise its Pacific operations. The corrective order focused primarily on eight pipeline incidents, seven of which occurred in the state of California. The PHMSA attributed five of the eight incidents to “outside force damage,” such as third-party damage caused by an excavator or damage caused during pipeline construction.

Following the issuance of the corrective order, Kinder Morgan Energy Partners engaged in cooperative discussions with the PHMSA and reached an agreement in principle on the terms of a consent agreement with the PHMSA, subject to the PHMSA’s obligation to provide notice and an opportunity to comment on the consent agreement to appropriate state officials pursuant to 49 USC Section 60112(c). This comment period closed on March 26, 2006.

On April 10, 2006, Kinder Morgan Energy Partners announced the final consent agreement, which will, among other things, require Kinder Morgan Energy Partners to perform a thorough analysis of recent pipeline incidents, provide for a third-party independent review of its operations and procedural practices, and restructure its internal inspections program. Furthermore, Kinder Morgan Energy Partners has reviewed all of its policies and procedures and is currently implementing various measures to strengthen its integrity management program, including a comprehensive evaluation of internal inspection technologies and other methods to protect its pipelines. Kinder Morgan Energy Partners expects to spend approximately $90 million on pipeline integrity activities for its Pacific operations’ pipelines over the next five years. Of that amount, approximately $26 million is related to this consent agreement. We do not expect that compliance with the consent agreement will have a material adverse effect on our business, financial position, results of operations or cash flows.

General

Although no assurances can be given, we believe that we have meritorious defenses to all of these actions. Furthermore, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability. We also believe that these matters will not have a material adverse effect on our business, financial position, results of operations or cash flows.

Environmental Matters

Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc. and ST Services, Inc.

On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County. Kinder Morgan Energy Partners filed its answer to the complaint on June 27, 2003, in which it denied ExxonMobil’s claims and allegations as well as included counterclaims against ExxonMobil. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and owned currently by ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil performed the environmental site assessment of the terminal required prior to sale pursuant to state law. During the site assessment, ExxonMobil discovered items that required remediation and the New Jersey Department of Environmental Protection issued an order that required ExxonMobil to perform various remediation activities to remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is still remediating the site and has not been removed as a responsible party from the state’s cleanup order; however, ExxonMobil claims that the remediation continues because of GATX Terminals’ storage of a fuel additive, MTBE, at the terminal during GATX Terminals’ ownership of the terminal. When GATX Terminals sold the terminal to ST Services, the parties indemnified one another for certain environmental matters. When GATX Terminals was sold to Kinder Morgan Energy Partners, GATX Terminals’ indemnification obligations, if any, to ST Services may have passed to Kinder Morgan Energy Partners. Consequently, at issue is any indemnification obligation Kinder Morgan Energy Partners may owe to ST Services for environmental remediation of MTBE at the terminal. The complaint seeks any and all damages related to remediating MTBE at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit for remediating MTBE at the terminal. The parties have completed limited discovery. In October 2004, the judge assigned to the case removed himself from the case based on a conflict, and the new judge has ordered the parties to participate in mandatory mediation. The parties participated in a mediation on November 2, 2005, but no resolution was reached regarding the claims set out in the lawsuit. At this time, the parties are considering another mediation session but no date is confirmed.

Other Environmental

Kinder Morgan Transmix Company has been in discussions with the EPA regarding allegations by the EPA that it violated certain provisions of the Clean Air Act and the Resource Conservation & Recovery Act. Specifically, the EPA claims that Transmix failed to comply with certain sampling protocols at its Indianola, Pennsylvania transmix facility in violation of the

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Clean Air Act’s provisions governing fuel. The EPA further claims that Transmix improperly accepted hazardous waste at its transmix facility in Indianola. Finally, the EPA claims that Transmix failed to obtain batch samples of gasoline produced at its Hartford (Wood River), Illinois facility in 2004. In addition to injunctive relief that would require Transmix to maintain additional oversight of its quality assurance program at all of its transmix facilities, the EPA is seeking monetary penalties of $0.6 million.

We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

We are currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory authorities related to compliance with environmental regulations associated with our assets. We have established a reserve to address the costs associated with the cleanup.

We are also involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide.

See “—Pipeline Integrity and Ruptures” above for information with respect to the environmental impact of recent ruptures of some of our pipelines.

Although no assurance can be given, we believe that the ultimate resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur. Many factors may change in the future affecting our reserve estimates, such as regulatory changes, groundwater and land use near our sites, and changes in cleanup technology. As of March 31, 2006, we have accrued an environmental reserve of $66.9 million.

Intention to Assess Additional Sales Tax

Terasen Gas received a letter dated March 31, 2006 from the British Columbia Social Service tax authority indicating their intention to assess additional provincial sales tax on the Southern Crossing Pipeline, which was completed in 2000. The letter received does not indicate the amount to be assessed and no formal notice of assessment has been received. Any assessment received will be appealed and we believe this proposed assessment is without merit and will not have a material adverse impact on our business, financial position, results of operations or cash flows.

Other

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

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Item 2.  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. Further, unless the context requires otherwise, references to “Kinder Morgan Energy Partners” are intended to mean Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership in which we own the general partner interest and significant limited partner interests, and its consolidated subsidiaries. As discussed in Note 1(C) of the accompanying Notes to Consolidated Financial Statements, due to our adoption of EITF No. 04-5, effective as of January 1, 2006, Kinder Morgan Energy partners and its consolidated subsidiaries are included as consolidated subsidiaries of Kinder Morgan, Inc. in our consolidated financial statements. Accordingly, their accounts, balances and results of operations will be included in our consolidated financial statements for periods beginning on and after January 1, 2006, and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. As discussed in Note 5 of the accompanying Notes to Consolidated Financial Statements, we acquired Terasen Inc., referred to in this report as Terasen, on November 30, 2005. Our adoption of EITF No. 04-5 and our acquisition of Terasen affect the comparability of our results between periods. In addition, the following interim results may not be indicative of the results to be expected over the course of an entire year.

The following discussion should be read in conjunction with (i) the accompanying interim Consolidated Financial Statements and related Notes, (ii) our Annual Report on Form 10-K for the year ended December 31, 2005, including the Consolidated Financial Statements, related Notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations, (iii) Kinder Morgan Energy Partners’ Annual Report on Form 10-K for the year ended December 31, 2005 and (iv) Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, including the Consolidated Financial Statements, related Notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations in each report. Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 is filed as Exhibit 99.1 to this Form 10-Q.

Critical Accounting Policies and Estimates

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

In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible asset impairment charges, 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. Information regarding our critical accounting policies and estimates can be found in our 2005 Form 10-K and Kinder Morgan Energy Partners’ 2005 Form 10-K. There have not been any significant changes in these policies and estimates during the three months ended March 31, 2006.

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KMI Form 10-Q

Consolidated Financial Results

	Three Months Ended March 31,						Earnings Increase
	20061, 2			2005			(Decrease)
	(In millions except per share amounts)
Equity in Earnings of Kinder Morgan Energy Partners2, 3	$	-		$	154.0		$	(154.0	)
Segment Earnings:4
NGPL		127.0			114.2			12.8
Terasen Gas		115.7			-			115.7
Kinder Morgan Canada		28.2			-			28.2
Kinder Morgan Retail		28.0			33.1			(5.1	)
Power		5.6			4.4			1.2
Products Pipelines – KMP		104.8			-			104.8
Natural Gas Pipelines – KMP		127.5			-			127.5
CO2 – KMP		81.9			-			81.9
Terminals – KMP		72.7			-			72.7
Total Segment Earnings		691.4			305.7			385.7
Interest and Corporate Expenses, Net5, 6, 7		(401.1	)		(65.7	)		(335.4	)
Income From Continuing Operations Before Income Taxes4		290.3			240.0			50.3
Income Taxes4		95.8			94.9			0.9
Income From Continuing Operations		194.5			145.1			49.4
Loss From Discontinued Operations, Net of Tax		(0.8	)		(1.8	)		1.0
Net Income	$	193.7		$	143.3		$	50.4
Diluted Earnings (Loss) Per Common Share:
Income From Continuing Operations	$	1.44		$	1.17		$	0.27
Loss From Discontinued Operations		(0.01	)		(0.02	)		0.01
Total Diluted Earnings Per Common Share	$	1.43		$	1.15		$	0.28
Number of Shares Used in Computing Diluted
Earnings Per Common Share		135.0			124.4			10.6

_____________

¹

Operating results for 2006 include the results of Terasen, which we acquired on November 30, 2005. See Note 5 of the accompanying Notes to Consolidated Financial Statements.

²

Due to our adoption of EITF No. 04-5, beginning with the first quarter of 2006, the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our financial statements and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. See Note 1(C) of the accompanying Notes to Consolidated Financial Statements.

³

Equity in Earnings of Kinder Morgan Energy Partners for the three months ended March 31, 2005 includes a reduction in pre-tax earnings of approximately $10.3 million ($6.5 million after tax) resulting from litigation and environmental settlements by Kinder Morgan Energy Partners.

⁴

Segment earnings includes operating income before corporate costs plus earnings from equity method investments plus gains and losses on incidental sales of assets. For our business segments that are also segments of Kinder Morgan Energy Partners, also includes interest income, other, net and an aggregate of $5.5 million of income taxes allocated to the segments.

⁵

Results for the three months ended March 31, 2005 include a reduction in after-tax minority interest expense of approximately $3.3 million resulting from litigation and environmental settlements by Kinder Morgan Energy Partners, as discussed in Note 3 above.

⁶

Results for the three months ended March 31, 2006 include a reduction in pre-tax earnings of approximately $22.3 million ($14.1 million after tax) resulting from non-cash charges to mark to market certain interest rate swaps.

⁷

Includes (i) general and administrative expenses, (ii) interest expense, (iii) minority interests and (iv) other, net.

Our income from continuing operations increased from $145.1 million in the first quarter of 2005 to $194.5 million in the first quarter of 2006, an increase of $49.4 million (34%). Our net income increased from $143.3 million in the first quarter of 2005 to $193.7 million in the first quarter of 2006, an increase of $50.4 million (35%). The items discussed in footnotes 3, 5 and 6 of the table above had the effect of decreasing results by $14.1 million and $3.2 million for the three months ended

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KMI Form 10-Q

March 31, 2006 and 2005, respectively. The remaining $60.3 million increase in our income from continuing operations for the first quarter of 2006, relative to 2005, principally resulted from (i) our acquisition of Terasen on November 30, 2005, (ii) increased earnings from Kinder Morgan Energy Partners, net of associated minority interests and (iii) increased earnings from our Natural Gas Pipeline Company of America (NGPL) business segment. These positive impacts were partially offset by increased interest expense. Please refer to the individual business segment discussions included elsewhere herein for additional information regarding business segment results. Refer to the headings “Interest and Corporate Expenses, Net,” “Earnings from Kinder Morgan Energy Partners”, “Income Taxes – Continuing Operations” and “Discontinued Operations” included elsewhere in management’s discussion and analysis for additional information regarding these items.

Diluted earnings per common share from continuing operations increased from $1.17 in the first quarter of 2005 to $1.44 in the first quarter of 2006, an increase of $0.27 (23%). This increase reflected, in addition to the financial and operating impacts discussed preceding, an increase of 10.6 million (8.5%) in average shares outstanding. The increase in average shares outstanding resulted from the net effects of (i) 12.5 million shares issued to acquire Terasen on November 30, 2005, (ii) decreases in shares outstanding due to our share repurchase program (see Note 10 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(A) and 2 of the accompanying Notes to Consolidated Financial Statements). Total diluted earnings per common share increased from $1.15 in 2005 to $1.43 in 2006, an increase of $0.28 (24%).

Results of Operations

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

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

Several of our business segments are also segments of Kinder Morgan Energy Partners. For each of the Kinder Morgan Energy Partners business segments, a comparison of current year results to prior year results is available in Kinder Morgan Energy Partners’ Form 10-Q for the first quarter of 2006. Therefore, we have incorporated by reference certain portions of Kinder Morgan Energy Partners’ Form 10-Q as noted in the individual business segment discussions following.

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KMI Form 10-Q

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
Terasen Natural Gas Distribution	The regulated sale and transportation of natural gas to residential, commercial and industrial customers in British Columbia, Canada	Terasen Gas
Petroleum Pipelines	The ownership and operation of crude and refined petroleum pipelines, principally located in Canada, and a one-third interest in the Express System, a crude pipeline system	Kinder Morgan Canada
Kinder Morgan Retail Natural Gas Distribution	The regulated sale and transportation of natural gas to residential, commercial and industrial customers in Nebraska, Wyoming and Colorado, the sales of natural gas to certain utility customers under the Choice Gas program and the operation of a small distribution system in Hermosillo, Mexico	Kinder Morgan Retail
Power Generation	The ownership and operation of natural gas-fired electric generation facilities	Power
Petroleum Products Pipelines (Kinder Morgan Energy Partners)	The ownership and operation of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus associated product terminals and petroleum pipeline transmix processing facilities	Products Pipelines – KMP
Natural Gas Pipelines (Kinder Morgan Energy Partners)	The ownership and operation of major interstate and intrastate natural gas pipeline and storage systems	Natural Gas Pipelines – KMP
CO2 (Kinder Morgan Energy Partners)	The production, transportation and marketing of carbon dioxide (CO2) to oil fields that use CO2 to increase production of oil; plus ownership interests in and/or operation of oil fields in West Texas; plus the ownership and operation of a crude oil pipeline system in West Texas	CO2 - KMP
Liquids and Bulk Terminals (Kinder Morgan Energy Partners)	The ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities that together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products	Terminals - KMP

The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to our consolidated operations and described in Note 1 of Notes to Consolidated Financial Statements included in our 2005

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KMI Form 10-Q

Form 10-K and Note 2 of Notes to Consolidated Financial Statements included in Kinder Morgan Energy Partners’ 2005 Form 10-K, except that (i) certain items below the “Operating Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance, (ii) equity in earnings of equity method investees (other than Kinder Morgan Energy Partners in periods prior to January 1, 2006) are included in segment earnings (these equity method earnings are included in “Other Income and (Expenses)” in the accompanying interim Consolidated Statements of Operations), (iii) certain items included in operating income (such as general and administrative expenses) are not considered by management in its evaluation of business segment performance, (iv) gains and losses from incidental sales of assets are included in segment earnings and (v) business segments that are also segments of Kinder Morgan Energy Partners include certain other income and expenses and income taxes in their segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on segment earnings in relation to the level of capital employed. In addition, because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

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

Natural Gas Pipeline Company of America

	Three Months Ended March 31,				Increase
	2006		2005		(Decrease)
	(In millions except systems throughput)
Operating Revenues	$	258.1	$	206.5	$	51.6
Gas Purchases and Other Costs of Sales	$	75.2	$	40.6	$	34.6
Segment Earnings	$	127.0	$	114.2	$	12.8
Systems Throughput (Trillion Btus)		434.0		444.9		(10.9	)

NGPL’s segment earnings increased from $114.2 million in the first quarter of 2005 to $127.0 million in the first quarter of 2006, an increase of $12.8 million (11%). Segment earnings for the first quarter of 2006 were positively impacted, relative to 2005, by (i) increased transportation and storage margins in 2006 due, in part, to successful re-contracting of transportation and storage services and (ii) increased margins from operational gas sales. These positive impacts were partially offset by (i) a $2.2 million increase in operations and maintenance expense, principally due to increased electric compression costs and other compressor station expenses, (ii) a $1.7 million increase in depreciation and amortization expense and (iii) a $0.2 million increase in property tax expense. NGPL’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs. Total system throughput volumes decreased by 10.9 trillion Btus in the first quarter of 2006, relative to 2005, due principally to warmer weather. The decrease in systems throughput in the first quarter of 2006, relative to 2005, 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.

In the first quarter of 2006, NGPL received certificate approval from the Federal Energy Regulatory Commission (“FERC”) for the $63 million expansion at its North Lansing field in east Texas that will add 10 Bcf of storage service capacity.  Construction is underway and the project is expected to be in service in spring 2007.  Additionally, incremental service began in April 2006 on the $35 million expansion that will increase storage service capacity by 10 Bcf at the Sayre facility in Oklahoma, and service began May 1, 2006 on the $21 million Amarillo cross-haul line expansion, which adds 51,000 dekatherms per day (Dth/day) of transportation capacity.

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. Please refer to our 2005 Form 10-K for additional information regarding NGPL.

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KMI Form 10-Q

Terasen Gas

	Three Months Ended
	March 31, 2006
	(In millions except systems throughput)
Operating Revenues		$	591.8
Gas Purchases and Other Costs of Sales		$	417.8
Segment Earnings		$	115.7
Systems Throughput (Trillion Btus)			68.0

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.’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. Please refer to our 2005 Form 10-K for additional information regarding Terasen Gas.

Kinder Morgan Canada

	Three Months Ended
	March 31, 2006
	(In millions except systems throughput)
Operating Revenues		$	48.8
Segment Earnings		$	28.2
Systems Throughput (MMBbl)			41.7

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’s operations consist primarily of the Trans Mountain pipeline, the Corridor pipeline and a one-third interest in the Express System.

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 proposed agreement, to take effect as of January 1, 2006. The proposed agreement will also govern the financial arrangements for the Pump Station Expansion and Anchor Loop projects. The 2006-2010 ITS is subject to National Energy Board (“NEB”) approval, and Kinder Morgan Canada and the CAPP are working 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 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 will begin in the summer of 2006 so that the expansion can be in service by April 2007.

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KMI Form 10-Q

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. The NEB has set August 8, 2006, as the date when a public hearing of the application will commence. An NEB decision would then be expected before the end of 2006.

On May 2, 2006, Kinder Morgan Canada announced the start of a binding open season for the second major stage of its West Coast expansion of the Trans Mountain pipeline system. Known as TMX-2, this proposed project will add 100,000 bpd of incremental capacity to the Trans Mountain pipeline system, bringing the pipeline’s total capacity to approximately 400,000 bpd. The TMX-2 open season began on May 2, 2006, and will close on June 15, 2006. TMX-2 is part of a multi-staged expansion designed to link growing western Canadian oil production with West Coast and offshore markets. The project consists of two pipeline loops: (1) 252 kilometers of 36-inch pipe in Alberta between Edmonton and Edson, and (2) 243 kilometers of 30 and 36-inch pipe in British Columbia between Rearguard and Darfield, north of Kamloops. The proposed loops will generally follow the existing 24-inch Trans Mountain pipeline. New pump stations and storage tank facilities will also be required for the TMX-2 project. Pending shipper commitments and regulatory approvals, the TMX-2 project will be in service in late 2009. Please refer to our 2005 Form 10-K for additional information regarding Kinder Morgan Canada.

Kinder Morgan Retail

	Three Months Ended March 31,				Increase
	2006		2005		(Decrease)
	(In millions except systems throughput)
Operating Revenues	$	140.6	$	121.1	$	19.5
Gas Purchases and Other Costs of Sales	$	94.5	$	70.7	$	23.8
Segment Earnings	$	28.0	$	33.1	$	(5.1	)
Systems Throughput (Trillion Btus)1		15.7		15.8		(0.1	)

¹ Excludes transport volumes of intrastate pipelines.

Kinder Morgan Retail’s segment earnings decreased from $33.1 million in the first quarter of 2005 to $28.0 million in the first quarter of 2006, a decrease of $5.1 million (15%). Segment earnings were negatively impacted in the first quarter of 2006, relative to 2005, by (i) timing differences caused by a change in the revenue accrual process as discussed below, (ii) a $0.4 million increase in operations and maintenance expense and (iii) a $0.5 million increase in depreciation expense, due to increased plant in service. The increase in operating revenues in 2006, relative to 2005, was principally due to increased natural gas commodity prices in 2006 (which is accompanied by a corresponding increase in gas purchase costs).

Kinder Morgan Retail implemented an automated meter reading system over its approximate 245,000 customer base during 2005. Due to this implementation and its associated effects on our meter reading processes, our methodology for accruing estimated unbilled revenues (revenues for our natural gas distribution deliveries for which meters have not been read) has changed. We expect this change to have minimal impact over the course of an entire year.

On February 28, 2006, Kinder Morgan Retail filed a general rate increase application with the Wyoming Public Service Commission seeking an additional $7.94 million of revenue per year from its Wyoming gas utility operations. A final commission decision on the application is expected within 10 months of the filing date. Please refer to our 2005 Form 10-K for additional information regarding Kinder Morgan Retail.

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KMI Form 10-Q

Power

	Three Months Ended March 31,				Increase
	2006		2005		(Decrease)
	(In millions)
Operating Revenues	$	10.3	$	9.3	$	1.0
Gas Purchases and Other Costs of Sales	$	0.8	$	1.3	$	(0.5	)
Segment Earnings	$	5.6	$	4.4	$	1.2

Power’s segment earnings increased from $4.4 million in the first quarter of 2005 to $5.6 million in the first quarter of 2006, an increase of $1.2 million (27%). Segment earnings for the first quarter of 2006 were positively impacted, relative to 2005, by (i) approximately $0.8 million of increased margins from our Greeley power facility resulting, in part, from the reduction of plant availability and the associated resale of natural gas supplies at favorable prices, (ii) $0.3 million in legal costs incurred in 2005 in connection with the Wrightsville power facility and (iii) $0.2 million of earnings in 2006 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. Please refer to our 2005 Form 10-K for additional information regarding Power.

Products Pipelines - KMP

	Three Months Ended
	March 31, 2006
	(In millions)
Operating Revenues		$	180.5
Gas Purchases and Other Costs of Sales		$	3.4
Segment Earnings		$	104.8

Due to our adoption of EITF No. 04-5 (see Note 1(C) of the accompanying Notes to Consolidated Financial Statements), the results of Kinder Morgan Energy Partners’ Products Pipelines business segment are included in our operating results beginning with the first quarter of 2006. Further information regarding the results of this segment is included under the caption “Results of Operations – Products Pipelines” of Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 53 to 56 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, which is incorporated herein by reference.

Natural Gas Pipelines - KMP

	Three Months Ended
	March 31, 2006
	(In millions)
Operating Revenues		$	1,830.0
Gas Purchases and Other Costs of Sales		$	1,666.7
Segment Earnings		$	127.5

Due to our adoption of EITF No. 04-5 (see Note 1(C) of the accompanying Notes to Consolidated Financial Statements), the results of Kinder Morgan Energy Partners’ Natural Gas Pipelines business segment are included in our operating results beginning with the first quarter of 2006. Further information regarding the results of this segment is included under the caption “Results of Operations – Natural Gas Pipelines” of Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 57 to 59 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, which is incorporated herein by reference.

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KMI Form 10-Q

CO2 - KMP

	Three Months Ended
	March 31, 2006
	(In millions)
Operating Revenues		$	174.7
Gas Purchases and Other Costs of Sales		$	1.2
Segment Earnings		$	81.9

Due to our adoption of EITF No. 04-5 (see Note 1(C) of the accompanying Notes to Consolidated Financial Statements), the results of Kinder Morgan Energy Partners’ CO₂ business segment are included in our operating results beginning with the first quarter of 2006. Further information regarding the results of this segment is included under the caption “Results of Operations – CO₂” of Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 59 to 61 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, which is incorporated herein by reference.

Terminals - KMP

	Three Months Ended
	March 31, 2006
	(In millions)
Operating Revenues		$	206.4
Gas Purchases and Other Costs of Sales		$	5.9
Segment Earnings		$	72.7

Due to our adoption of EITF No. 04-5 (see Note 1(C) of the accompanying Notes to Consolidated Financial Statements), the results of Kinder Morgan Energy Partners’ Terminals business segment are included in our operating results beginning with the first quarter of 2006. Further information regarding the results of this segment is included under the caption “Results of Operations – Terminals” of Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 62 to 64 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, which is incorporated herein by reference.

Interest and Corporate Expenses, Net

	Three Months Ended March 31,						Earnings Increase
	2006			2005			(Decrease)
	(In millions)
General and Administrative Expense	$	(102.2	)	$	(16.7	)	$	(85.5	)
Interest Expense, Net		(181.4	)		(35.8	)		(145.6	)
Interest Expense – Deferrable Interest Debentures		(5.5	)		(5.5	)		-
Interest Expense – Capital Securities		(2.1	)		-			(2.1	)
Minority Interests		(90.1	)		(11.7	)		(78.4	)
Loss on Mark-to-market Interest Rate Swaps		(22.3	)		-			(22.3	)
Gain on Sale of Kinder Morgan Management Shares		-			4.5			(4.5	)
Other, Net		2.5			(0.5	)		3.0
	$	(401.1	)	$	(65.7	)	$	(335.4	)

“Interest and Corporate Expenses, Net” was an expense of $401.1 million in the first quarter of 2006, compared to an expense of $65.7 million in the first quarter of 2005. This increase in net expenses was principally due to (i) the inclusion of the accounts, balances and results of operations of Kinder Morgan Energy Partners in our consolidated financial statements due to our adoption of EITF No. 04-5 (see Note 1(C) of the accompanying Notes to Consolidated Financial Statements) and (ii) the acquisition of Terasen on November 30, 2005 (see Note 5 of the accompanying Notes to Consolidated Financial Statements).

The $85.5 million increase in general and administrative expense in the first quarter of 2006, relative to 2005, was due to (i)

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KMI Form 10-Q

$60.9 million of general and administrative expense of Kinder Morgan Energy Partners being included in our consolidated financial statements due to our adoption of EITF No. 04-5, (ii) $22.1 million of general and administrative expense of Terasen and (iii) a $2.5 million increase in other general and administrative expense due, in part, to proceeds received in 2005 in connection with the settlement of claims in the Enron bankruptcy proceeding.

The $147.7 million increase in total interest expense in the first quarter of 2006, relative to 2005, was due to (i) $75.4 million of interest expense of Kinder Morgan Energy Partners being included in our consolidated financial statements due to our adoption of EITF No. 04-5, (ii) $68.7 million of interest expense resulting from (1) interest on Terasen’s existing debt, including debt issued during the first quarter of 2006 and (2) interest on incremental debt issued during the fourth quarter of 2005 to acquire Terasen and (iii) a $3.6 million increase in other interest expense resulting from higher effective interest rates, partially offset by lower debt balances.

The $78.4 million increase in minority interests in the first quarter of 2006, relative to 2005, was due to (i) $75.4 million of minority interests of Kinder Morgan Energy Partners being included in our consolidated financial statements due to our adoption of EITF No. 04-5 (minority interest represents that portion of Kinder Morgan Energy Partners’ earnings attributable to limited partner interests, other than limited partner interests held by Kinder Morgan, Inc. and its subsidiaries), (ii) a $2.9 million increase in minority interests of Kinder Morgan Management due, in part, to our 2005 sales of Kinder Morgan Management shares that we owned and (iii) a $0.1 million increase in other minority interests, principally Triton Power.

During the first quarter of 2006, we recorded a pre-tax charge of $22.3 million ($14.1 million after tax) related to the financing of the Terasen acquisition. The charge was necessary because certain hedges put in place related to the debt financing for the acquisition did not qualify for hedge treatment under Generally Accepted Accounting Principles (“GAAP”), thus requiring that they be marked-to-market, resulting in a non-cash charge to income. These hedges have now been effectively terminated and replaced with agreements that qualify for hedge accounting treatment (see Note 12 of the accompanying Notes to Consolidated Financial Statements).

During the first quarter of 2005, we sold 0.4 million Kinder Morgan Management shares that we owned, receiving net proceeds of $17.5 million. In conjunction with the sale, we recorded a pre-tax gain of $4.5 million (see Note 6 of the accompanying Notes to Consolidated Financial Statements).

Earnings from Kinder Morgan Energy Partners

The impact on our pre-tax earnings from our investment in Kinder Morgan Energy Partners during the first quarter of 2005 when we accounted for Kinder Morgan Energy Partners on the equity method, was as follows:

	Three Months Ended
	March 31, 2005
	(In millions)
General Partner Interest, Including Minority Interest in the Operating Limited Partnerships		$	113.9
Limited Partner Units (Kinder Morgan Energy Partners)			10.7
Limited Partner i-units (Kinder Morgan Management)			29.4
			154.0
Pre-tax Minority Interest in Kinder Morgan Management			(21.5	)
Pre-tax Earnings from Investment in Kinder Morgan Energy Partners		$	132.5

As discussed in Note 1(C) of the accompanying Notes to Consolidated Financial Statements, due to our adoption of EITF No. 04-5, beginning with the first quarter of 2006, the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our consolidated financial statements and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. The inclusion of Kinder Morgan Energy Partners as a consolidated subsidiary affects the reported amounts of our consolidated revenues and expenses and our reported segment earnings. However, after taking into account the associated minority interests, the adoption of EITF No. 04-5 has no impact on our income from continuing operations or our net income.

Income Taxes – Continuing Operations

The income tax provision increased from $94.9 million in the first quarter of 2005 to $101.3 million in the first quarter of 2006, an increase of $6.4 million (6.7%) due principally to an increase in tax provision attributable to our Terasen operations

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and the inclusion of Kinder Morgan Energy Partners as a consolidated subsidiary partially offset by the tax benefits associated with our Terasen acquisition structure.

Discontinued Operations

On November 30, 2005, we acquired Terasen (see Note 5 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 during the second quarter of 2006. Our consolidated results for the three months ended March 31, 2006 include a $0.7 million loss from discontinued operations, net of tax, from these operations for the first quarter of 2006.

During 1999, we adopted and implemented a plan to discontinue a number of lines of business. During 2000, we essentially completed the disposition of these discontinued operations. In March 2006 and March 2005, we recorded incremental losses of approximately $103,000 (net of tax benefit of $60,000) and $1.8 million (net of tax benefit of $1.0 million), respectively, to increase previously recorded liabilities to reflect updated estimates.

Note 8 of the accompanying Notes to Consolidated Financial Statements contains additional information on these matters.

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, quarterly cash dividends to our common shareholders and quarterly distributions to Kinder Morgan Energy Partners’ public common unitholders. Our capital expenditures (other than sustaining capital expenditures), our common stock repurchases and our quarterly cash dividends to our common shareholders are discretionary. We expect to fund these expenditures with existing cash and cash flows from operating activities. In addition to utilizing cash generated from operations, we could meet these cash requirements through borrowings under our credit facility or by issuing short-term commercial paper, long-term notes or additional shares of common stock. In addition, Kinder Morgan Energy Partners and Terasen Inc. could meet their respective cash requirements with cash from operations and through borrowings under their respective credit facilities or by issuing short-term commercial paper or bankers’ acceptances. Furthermore, Kinder Morgan Energy Partners could issue additional units.

Invested Capital

The following table illustrates the sources of our invested capital. Our ratio of net debt to total capital increased in the first quarter of 2006 due to the implementation of EITF No. 04-5, which resulted in the prospective inclusion of the accounts, balances and results of operations of Kinder Morgan Energy Partners in our consolidated financial statements. Although the total debt on our consolidated balance sheet increased as a result of including Kinder Morgan Energy Partners’ debt balances with ours, Kinder Morgan, Inc. has not assumed any additional obligations with respect to Kinder Morgan Energy Partners’ debt. See Note 1(C) of the accompanying Notes to Consolidated Financial Statements for information regarding EITF No. 04-5. Our ratio of net debt to total capital increased in the fourth quarter of 2005 as the result of the acquisition of Terasen as discussed under “Significant Financing Transactions” following.

The discussion under the heading “Liquidity and Capital Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our 2005 Form 10-K and in Kinder Morgan Energy Partners’ 2005 Form 10-K includes a comprehensive discussion of (i) our investments in and obligations to unconsolidated entities, (ii) our contractual obligations and (iii) our contingent liabilities. These disclosures, which reflected balances and contractual arrangements existing as of December 31, 2005, also reflect current balances and contractual arrangements except for changes discussed following. Changes in our long-term and short-term debt are discussed under “Net Cash Flows from Financing Activities” following and in Note 9 of the accompanying Notes to Consolidated Financial Statements.

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KMI Form 10-Q

	March 31,			December 31,
	2006			2005			2004			2003
	(Dollars in millions)
Long-term Debt:
Outstanding Notes and Debentures	$	11,163.2		$	6,286.8		$	2,258.0		$	2,837.5
Deferrable Interest Debentures Issued to Subsidiary Trusts		283.6			283.6			283.6			283.6
Capital Securities		107.4			107.2			-			-
Value of Interest Rate Swaps1		(22.7	)		51.8			88.2			88.2
		11,531.5			6,729.4			2,629.8			3,209.3
Minority Interests		2,688.1			1,247.3			1,105.4			1,010.1
Common Equity, Excluding Accumulated Other Comprehensive Loss		4,113.1			4,051.4			2,919.5			2,691.8
		18,332.7			12,028.1			6,654.7			6,911.2
Value of Interest Rate Swaps		22.7			(51.8	)		(88.2	)		(88.2	)
Capitalization		18,355.4			11,976.3			6,566.5			6,823.0
Short-term Debt, Less Cash and Cash Equivalents2		1,454.1			841.4			328.5			121.8
Invested Capital	$	19,809.5		$	12,817.7		$	6,895.0		$	6,944.8
Capitalization:
Outstanding Notes and Debentures		60.9%			52.5%			34.4%			41.6%
Minority Interests		14.6%			10.4%			16.8%			14.8%
Common Equity		22.4%			33.8%			44.5%			39.4%
Deferrable Interest Debentures Issued to Subsidiary Trusts		1.5%			2.4%			4.3%			4.2%
Capital Securities		0.6%			0.9%			-%			-%
Invested Capital:
Net Debt3, 4		63.7%			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		36.3%			44.4%			62.5%			57.4%

 _____________

¹

See “Significant Financing Transactions” following.

²

Cash and cash equivalents netted against short-term debt were $183.6 million, $116.6 million, $176.5 million and $11.1 million for March 31, 2006 and December 31, 2005, 2004 and 2003, respectively.

³

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

⁴

Our ratio of net debt to invested capital at March 31, 2006, not including the effects of consolidating Kinder Morgan Energy Partners, was 54.7%.

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KMI Form 10-Q

Short-term Liquidity

Our principal sources of short-term liquidity are our revolving bank facilities, our commercial paper and bankers’ acceptance programs (which are supported by our revolving bank facilities) and cash provided by operations. The following represents the revolving, unsecured credit facilities that were available to Kinder Morgan, Inc. and its respective subsidiaries, commercial paper and bankers’ acceptance programs outstanding and available borrowing capacity under the facilities after applicable letters of credit.

			At March 31, 2006				At April 28, 2006
	Credit Facility Capacity	Term	Short-term Debt Outstanding		Available Borrowing Capacity		Short-term Debt Outstanding			Available Borrowing Capacity
			(U.S. Dollars in millions)
Kinder Morgan, Inc.	$800	five-year	$	-	$	733.0		$	-		$	733.0
Kinder Morgan Energy Partners	$1,600 and $250	five-year and 9-month		1,051.3		339.5			1,231.3			159.5
Rockies Express Pipeline LLC	$2,000	five-year		-		-			-			2,000.0
Terasen1	C$450	364-day		94.2		221.6			110.0			225.7
Terasen Gas Inc.	C$500	364-day		160.1		237.5			126.1			282.2
Terasen Pipelines (Corridor) Inc.	C$225	364-day		122.4		70.2			126.1			75.1

¹

Short-term debt outstanding at March 31, 2006 and April 28, 2006 consisted of bankers’ acceptances.

These facilities can be used for the respective entity’s general corporate purposes and as backup for that entity’s respective commercial paper and bankers’ acceptance programs. Additionally, at March 31, 2006 and April 28, 2006, we had a C$20 million demand facility associated with Terasen Pipelines (Corridor) Inc.’s credit facility put in place for overdraft purposes and short-term cash management.

Our current maturities of long-term debt of $209.7 million at March 31, 2006 represents (i) $5.0 million of current maturities of our 6.50% Series Debentures due September 1, 2013, (ii) $5.7 million of current maturities under Kinder Morgan Texas Pipeline, L.P.’s 5.23% Series Notes due January 2, 2014, (iii) $5.0 million of current maturities under Central Florida Pipe Line LLC’s 7.84% Series Notes due July 23, 2006, (iv) $2.0 million of current maturities under Terasen Gas Inc.’s capital lease obligations, (v) $85.6 million of Terasen’s 4.85% Series 2 Notes due May 8, 2006, (vi) $85.6 million of Terasen Gas Inc.’s 6.15% Series 16 Notes due July 31, 2006, (vii) $17.1 million of Terasen Gas Inc.’s 9.75% Series D Notes due December 17, 2006 and (viii) $3.7 million of current maturities relating to TGVI’s Canadian government loans. Current maturities of Terasen and its subsidiaries are denominated in Canadian dollars but are reported here in U.S. dollars converted at the March 31, 2006 Bank of Canada closing rate of 0.8562 U.S. dollars per Canadian dollar. Apart from our notes payable and current maturities of long-term debt, our current liabilities, net of our current assets, represents an additional short-term obligation of approximately $132.0 million at March 31, 2006. 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

On August 14, 2001, we announced a program to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million, $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 March 31, 2006, we had repurchased a total of approximately $906.8 million (14,934,300 shares) of our outstanding common stock under the program, of which $31.5 million (339,800 shares) were repurchased in the three months ended March 31, 2006. We have ceased additional share repurchases in 2006 in order to fund capital projects, primarily in Canada.

On February 22, 2006, Kinder Morgan Energy Partners entered into a nine-month $250 million credit facility due November 21, 2006 with a syndicate of financial institutions, and Wachovia Bank, National Association is the administrative agent. Borrowings under the credit facility can be used for general corporate purposes and as backup for Kinder Morgan Energy Partners’ commercial paper program and include financial covenants and events of default that are common in such arrangements.

On January 13, 2006, TGVI entered into a five-year C$350 million unsecured committed revolving credit facility with a syndicate of banks. TGVI issued banker’s acceptances under this facility to completely refinance TGVI’s former term facility and intercompany advances from Terasen. The banker’s acceptances have terms not to exceed 180 days at the end of which time they are replaced by new banker’s acceptances. The facility can 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, TGVI entered into a C$20 million seven-year unsecured

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KMI Form 10-Q

committed non-revolving credit facility with one bank. This facility will be utilized for purposes of refinancing any annual prepayments that TGVI may be required to make on non-interest bearing government contributions. The terms and conditions are primarily the same as the aforementioned TGVI facility except this facility ranks junior to repayment of TGVI’s Class B subordinated debt, which is held by its parent company, Terasen. At March 31, 2006, TGVI had issued bankers’ acceptances under the C$350 million credit facility with an average term of less than three months. While the bankers’ acceptances are short term, the underlying credit facility on which the bankers’ acceptances are committed is open through January 2011. Accordingly, borrowings outstanding at March 31, 2006 of $271.4 million under the $350 million credit facility have been classified as long-term debt in our accompanying interim Consolidated Balance Sheet at a weighted-average interest rate of 4.51%. For the three months ended March 31, 2006, average borrowings were $256.0 million at a weighted-average rate of 4.29%. No borrowings were made under the $20 million credit facility during the three months ended March 31, 2006.

On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion five-year, unsecured revolving credit facility due April 28, 2011. This credit facility will support a planned $2.0 billion commercial paper program, and borrowings under the planned commercial paper program will reduce the borrowings allowed under the credit facility. As of April 28, 2006, there were no borrowings under the credit facility, and terms of the commercial paper program were being negotiated. Borrowings under the credit facility and commercial paper program will be primarily used to finance the construction of the Rockies Express interstate natural gas pipeline, and the borrowings will not reduce the borrowings allowed under Kinder Morgan Energy Partners’ credit facilities.

Rockies Express Pipeline LLC is a limited liability company owned 66 2/3% and controlled by Kinder Morgan Energy Partners. Sempra Energy holds the remaining 33 1/3% ownership interest. Both Kinder Morgan Energy Partners and Sempra have agreed to guarantee borrowings under the Rockies Express credit facility in the same proportion as their respective percentage ownership of the member interests in Rockies Express Pipeline LLC.

On February 10, 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 Kinder Morgan Finance Company, ULC’s 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 SFAS No. 133.

On February 24, 2006, Terasen terminated its fixed-to-floating interest rate swap agreements associated with its 6.30% and 5.56% Medium Term Notes due 2008 and 2014, respectively, with a notional value of C$195 million, and received proceeds of C$2.2 million. The cumulative loss recognized of C$2.3 million upon early termination of these fair value hedges is recorded under the caption “Value of Interest Rate Swaps” in the accompanying Consolidated Balance Sheet and will be amortized to earnings over the original period of the swap transactions. Additionally, Terasen 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 and qualify for the “shortcut” method of accounting prescribed for qualifying hedges under SFAS No. 133.

As of March 31, 2006 we had outstanding the following interest rate swap agreements that qualify for fair value hedge accounting under SFAS No. 133:

(i)

fixed-to-floating interest rate swap agreements with notional principal amounts of $375 million, $425 million and $275 million, respectively which were entered into on February 10, 2006. These swaps effectively convert 50% of the interest expense associated with Kinder Morgan Finance Company, ULC’s 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,

(ii)

fixed-to-floating interest rate swap agreements at Terasen, with a notional principal amount of C$195 million, which effectively convert a majority of its 6.30% and 5.56% Medium Term Notes due December 2008 and September 2014, respectively, from fixed rates to floating rates,

(iii)

fixed-to-floating interest rate swap agreements, 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 with a combined notional principal amount of $1.25 billion,

(iv)

fixed-to-floating interest rate swap agreements under Kinder Morgan Energy Partners having a combined notional principal amount of $2.1 billion which effectively convert the interest expense associated with the following series of its senior notes from fixed rates to floating rates:

·

$200 million principal amount of its 5.35% senior notes due August 15, 2007;

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KMI Form 10-Q

·

$250 million principal amount of its 6.30% senior notes due February 1, 2009;

·

$200 million principal amount of its 7.125% senior notes due March 15, 2012;

·

$250 million principal amount of its 5.0% senior notes due December 15, 2013;

·

$200 million principal amount of its 5.125% senior notes due November 15, 2014;

·

$300 million principal amount of its 7.40% senior notes due March 15, 2031;

·

$200 million principal amount of its 7.75% senior notes due March 15, 2032;

·

$400 million principal amount of its 7.30% senior notes due August 15, 2033; and

·

$100 million principal amount of its 5.80% senior notes due March 15, 2035.

As of March 31, 2006, we had outstanding the following interest rate swaps that are not 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 or shippers.

(i)

Terasen Gas Inc. has 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.

(ii)

TGVI has floating-to-fixed interest rate swap agreements, with a notional principal amount of C$65 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. The interest swaps mature in October and November of 2008.

(iii)

Terasen Pipelines (Corridor) Inc. has 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.

In February 2006 we entered into a series of transactions to effectively terminate our 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 a series of 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 SFAS No. 133. We recognized 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 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.

Interest in Kinder Morgan Energy Partners

At March 31, 2006, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management, LLC we owned, approximately 29.4 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 14.3 million common units, 5.3 million Class B units and 9.7 million i-units, represent approximately 13.3 percent of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2 percent interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 15.0 percent of Kinder Morgan Energy Partners’ total equity interests at March 31, 2006.

Prior to our adoption of EITF No. 04-5, we accounted for our investment in Kinder Morgan Energy Partners under the equity method of accounting. Due to our adoption of EITF No. 04-5, beginning with the first quarter of 2006, the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our consolidated financial statements and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. The adoption of EITF No. 04-5 affects the reported amounts of our consolidated revenues and expenses and our reported segment earnings. However, after taking into account the associated minority interests, the adoption of EITF No. 04-5 has no impact on our income from continuing operations or our net income.

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KMI Form 10-Q

CASH FLOWS

The following discussion of cash flows should be read in conjunction with the accompanying interim Consolidated Statements of Cash Flows and related supplemental disclosures, and the Consolidated Statements of Cash Flows and related supplemental disclosures included in our 2005 Form 10-K. As discussed in Note 1(C) of the accompanying Notes to Consolidated Financial Statements, due to our adoption of EITF No. 04-5, beginning with the first quarter of 2006, the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our consolidated financial statements and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. Further information regarding the cash flows of Kinder Morgan Energy Partners is included under the caption “Financial Condition” of Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 67 to 70 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, which is incorporated herein by reference.

Net Cash Flows from Operating Activities

“Net Cash Flows Provided by Operating Activities” increased from $32.3 million in the first quarter 2005 to $437.6 million in the first quarter 2006, an increase of $405.3 million. This positive variance is principally due to (i) an increase of $401.4 million of net income, net of non-cash items including depreciation and amortization, deferred income taxes, undistributed earnings from equity investments, minority interests in income of consolidated subsidiaries, net gains and losses on sales of assets, mark-to-market interest rate swap loss and losses on disposal of discontinued operations ($319.0 million and $66.3 million of this $401.5 million increase are attributable to Kinder Morgan Energy Partners and Terasen, respectively), (ii) a $112.2 million increase in cash relative to net changes in working capital items, of which Kinder Morgan Energy Partners contributed a decrease of $81.4 million and Terasen contributed an increase of $35.2 million, (iii) a net decreased use of cash of $35.7 million for gas in underground storage, of which Kinder Morgan Energy Partners contributed an increased use of cash of $36.2 million and Terasen contributed $69.6 million of cash inflows and (iv) the fact that 2005 included a $25.0 million pension payment. These positive impacts were partially offset by (i) a $103.0 million decrease in distributions received from equity investments, of which the inclusion of the accounts, balances and results of operations of Kinder Morgan Energy Partners in our consolidated financial statements contributed a decrease of $123.4 million, (ii) a $37.1 million use of cash attributable to Terasen rate stabilization accounts, (iii) a $14.7 million increase of payments made for natural gas liquids inventory entirely attributable Kinder Morgan Energy Partners and (iv) a decrease of $5.7 million in 2006 cash attributable to deferred purchased gas costs. Cash flows attributable to deferred purchased gas costs vary with the relationship between the amount actually paid for natural gas and the amount currently included in regulated rates. This difference is recovered or refunded through subsequent rate adjustments. Significant period-to-period variations in cash used or generated from gas in storage transactions are due to changes in injection and withdrawal volumes as well as fluctuations in natural gas prices.

Net Cash Flows from Investing Activities

“Net Cash Flows (Used in) Provided By Investing Activities” changed from a source of $18.5 million in the first quarter 2005 to a use of $557.0 million in the first quarter 2006, an increased use of cash of $575.5 million. This increased use of cash is principally due to (i) $240.0 million of cash used to acquire Entrega Pipeline LLC, (ii) an additional $9.7 million attributable to the acquisition of Terasen (See Note 5 of the accompanying Notes to Consolidated Financial Statements), (iii) a $244.4 million increased use of cash for capital expenditures, of which $193.7 million and $32.5 million are attributable to Kinder Morgan Energy Partners and Terasen, respectively, (iv) $38.9 million during 2006 of investments in versus $17.2 million during 2005 of proceeds from margin deposits associated with hedging activities utilizing energy derivative instruments, of which an investment of $33.1 million is attributable to Kinder Morgan Energy Partners, (v) the fact that 2005 included $17.5 million of proceeds from the sale of Kinder Morgan Management, LLC shares (see Note 6 of the accompanying Notes to Consolidated Financial Statements) and (vi) $9.8 million for investments in underground natural gas storage volumes and payments made for natural gas liquids line-fill, all of which is attributable to Kinder Morgan Energy Partners. Partially offsetting these negative impacts is a $6.8 million increase in proceeds from sales of other assets net of removal costs.

Net Cash Flows from Financing Activities

“Net Cash Flows Provided by (Used in) Financing Activities” increased from a use of $217.1 million in the first quarter 2005 to a source of $174.7 million in the first quarter 2006, an increase of $391.8 million. This increase is principally due to (i) the fact that 2005 included $500 million of cash used to retire our $500 million 6.65% Senior Notes, (ii) $274.6 million of proceeds received in 2006 from the issuance of TGVI’s Floating Rate Syndicated Credit Facility, (See Note 9 of the accompanying Notes to Consolidated Financial Statements), (iii) a $119.2 million decrease in cash paid during 2006 to repurchase our common shares, (iv) a $30.3 million increase in short-term debt, of which $485.1 million of additional borrowing is attributable to Kinder Morgan Energy Partners and a $208.8 million reduction in short-term debt is attributable to Terasen and (v) $90.7 million of contributions from minority interest owners, primarily Sempra Energy’s $80.0 million

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KMI Form 10-Q

contribution for its 33 1/3% share of the purchase price of Entrega Pipeline LLC. Partially offsetting these factors were (i) the fact that 2005 included $248.5 million of proceeds, net of issuance costs, from the issuance of our 5.15% Senior Notes due March 1, 2015, (ii) $181.9 million of cash used to retire TGVI’s Syndicated Credit Facility (See Note 9 of the accompanying Notes to Consolidated Financial Statements), (iii) $115.5 million of minority interest distributions, principally Kinder Morgan Energy Partners’ distribution to common unit owners, (iv) a $30.7 million increase in cash paid for dividends in 2006, principally due to the increased dividends declared per share, (v)  a decrease of $20.3 million for issuance of our common stock, principally due to a reduction of employee stock option exercises and (vi) a $4.2 million use of cash during 2006 for short-term advances to unconsolidated affiliates versus a $13.9 million source of cash during 2005 for short-term advances from unconsolidated affiliates, principally Kinder Morgan Energy Partners, during 2005.

Minority Interests Distributions to Kinder Morgan Energy Partners’ Common Unit Holders

Kinder Morgan Energy Partners’ partnership agreement requires that it distribute 100% of “Available Cash,” as defined in its partnership agreement, to its partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available Cash consists generally of all of Kinder Morgan Energy Partners’ cash receipts, including cash received by its operating partnerships and net reductions in reserves, less cash disbursements and net additions to reserves and amounts payable to the former general partner of SFPP, in respect of its remaining 0.5% interest in SFPP.

Kinder Morgan Management, as the delegate of Kinder Morgan G.P., Inc., our wholly owned subsidiary and the general partner of Kinder Morgan Energy Partners, is granted discretion to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Kinder Morgan Management determines Kinder Morgan Energy Partners’ quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to Kinder Morgan Energy Partners’ limited partners with 2% retained by Kinder Morgan G.P., Inc. as Kinder Morgan Energy Partners’ general partner. These distribution percentages are modified to provide for incentive distributions to be retained by Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners in the event that quarterly distributions to unitholders exceed certain specified targets.

Available cash for each quarter is distributed:

·

first, 98% to the owners of all classes of units pro rata and 2% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;

·

second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;

·

third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 15% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and

·

fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units in cash and to Kinder Morgan Management as owners of i-units in the equivalent number of i-units, and 50% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners.

On February 14, 2006, Kinder Morgan Energy Partners paid a quarterly distribution of $0.80 per unit for the quarterly period ended December 31, 2005, of which $114.4 million was paid to the public holders (included in minority interests) of Kinder Morgan Energy Partners’ common units.

On April 19, 2006, Kinder Morgan Energy Partners declared a quarterly distribution of $0.81 per unit for the quarterly period ended March 31, 2006. The distribution will be paid on May 15, 2006, to unitholders of record as of April 28, 2006.

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

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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 pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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;

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·

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 and the fruition of contingencies referred to in the accompanying Notes to Consolidated Financial Statements.

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” of our annual report on Form 10-K and Kinder Morgan Energy Partners’ annual report on Form 10-K, each for the year ended December 31, 2005, for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

In the first quarter of 2006, our Value-at-Risk model was modified to include the operations of Kinder Morgan Energy Partners and Terasen. As the result of implementing EITF No. 04-5 our consolidated financial statements now include the accounts, balances and results of operations of Kinder Morgan Energy Partners. Terasen was acquired on November 30, 2005 and historically was not required to provide an analysis of its market risk in its disclosure and did not have the ability to calculate it at that time.

Our Value-at-Risk model 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 95% 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 95% probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk amount presented. Value-at-Risk at March 31, 2006, which nets the change in our financial derivatives against the change in our physical commodities, was $1.8 million.

Our calculated Value-at-Risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio 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 during the year. In addition, as discussed preceding, we enter into these derivatives solely for the purpose of mitigating the risks that accompany our normal business activities and, therefore, the change in the market value of our portfolio of derivatives is, with the exception of hedging inefficiency, offset by changes in the value of the underlying physical transactions.

Item 4.

Controls and Procedures.

As of March 31, 2006, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting

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during the quarter ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.

Legal Proceedings.

See Note 15 of the accompanying Notes to Consolidated Financial Statements in Part I, Item 1, which is incorporated herein by reference.

Item 1A.

Risk Factors.

There have been no material changes in the risk factors set forth in our Annual Report on Form 10-K or Kinder Morgan Energy Partners’ Annual Report on Form 10-K, each for the year ended December 31, 2005.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

See Note 10 of the accompanying Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Item 3.

Defaults Upon Senior Securities.

None.

Item 4.

Submission of Matters to a Vote of Security Holders.

None.

Item 5.

Other Information.

None.

Item 6.

Exhibits.

4.1

Certain instruments with respect to the long-term debt of Kinder Morgan, Inc. and its consolidated subsidiaries that relate to debt that does not exceed 10% of the total assets of Kinder Morgan, Inc. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan, Inc. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.

10.1

Nine-Month Credit Agreement dated as of February 22, 2006 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.9 to Kinder Morgan Energy Partners, L.P.’s Form 10-K for 2005, filed on March 16, 2006).

10.2*

Form of 2005 Credit Agreement dated as of January 13, 2006 among Terasen Gas (Vancouver Island) Inc., the lenders party thereto and RBC Capital Markets as Lead Arranger and Book Runner

31.1*

Section 13a – 14(a) / 15d – 14(a) Certification of Chief Executive Officer

31.2*

Section 13a – 14(a) / 15d – 14(a) Certification of Chief Financial Officer

32.1*

Section 1350 Certification of Chief Executive Officer

32.2*

Section 1350 Certification of Chief Financial Officer

99.1*

Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the three months ended March 31, 2006

________________

*Filed herewith

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KMI Form 10-Q

SIGNATURE

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 thereunto duly authorized.

	KINDER MORGAN, INC. (Registrant)
May 10, 2006	/s/ Kimberly A. Dang
	Kimberly A. Dang Vice President and Chief Financial Officer

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