10-Q

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.

3

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.

5

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 account ing 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 conso lidated 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 t o 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 interr upted 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 commerci al 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. Furth er 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 cu stomers 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.

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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 r equired 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 pr incipally 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 Stateme nts 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 befo re 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 ear nings 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 ass ociated 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

26

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.

27

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. dol lar.

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% an d 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 pro tected 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 customer s, 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 file d 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 with out 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 ha ve 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 rate s 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 s tatement (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

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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 l ines 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, 2 006, 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 thi s 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 19 98. 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 or der 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 earning s 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& #146;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 respons e 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 Marath on 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 th ese 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 1 2, 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 judgme nt 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 o f 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 dis trict 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, forfei ture, 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 violat ion 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, 200 4).

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 Multidi strict 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 o f 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 allege d 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. Plainti ff 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 pur ported 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 c ustomer 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 th is 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 h as 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 an d 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 cl aims 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 “n o 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 incid ent 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 s truck 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 M atamoros 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 unt il 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 sectio n 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 con sent 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 acti vities 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 A ct, 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 chan ges 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) busin ess 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 tariff s. 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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KMI Form 10-Q

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 operation s 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. dol lar.

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 $3 5.2 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 relat ionship 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 Se mpra 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 so urce 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

70

KMI Form 10-Q

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;

71

KMI Form 10-Q

·

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 tr ansactions.

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 an d 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

72

KMI Form 10-Q

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

73

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

74

EX-10.2

Exhibit 10.2

TERASEN GAS (VANCOUVER ISLAND) INC.

as Borrower

- and -

ROYAL BANK OF CANADA

as Administrative Agent

- and -

THOSE INSTITUTIONS WHOSE NAMES ARE SET FORTH
ON THE EXECUTION PAGES HEREOF UNDER THE
HEADING "LENDERS"

as Lenders

______________________________________________________________________________

2005 CREDIT AGREEMENT

______________________________________________________________________________

RBC CAPITAL MARKETS

Lead Arranger and Bookrunner

NATIONAL BANK FINANCIAL

Syndication Agent

THE BANK OF NOVA SCOTIA

Documentation Agent

______________________________________________________________________________

Dated for reference January 13, 2006

TABLE OF CONTENTS

Page

ARTICLE 1

INTERPRETATION

1

1.1

Defined Terms

1

1.2

Interpretation

30

ARTICLE 2

THE CREDIT FACILITY

30

2.1

Credit Facility

30

2.2

Amortization

35

2.3

Voluntary Reductions

36

2.4

Payments

36

2.5

Computations

38

2.6

Fees

38

2.7

Interest on Overdue Amounts

39

2.8

Account Debit Authorization

39

2.9

Administrative Agent’s Discretion on Allocation

40

2.10

Funding

40

2.11

Rollover and Conversion

40

ARTICLE 3

ADVANCES

42

3.1

Advances

42

3.2

Making the Advances (except Swingline Advances)

42

3.3

Interest on Advances

42

ARTICLE 4

BANKERS’ ACCEPTANCES

43

4.1

Acceptances

43

4.2

Drawdown Request

44

4.3

Form of Bankers’ Acceptances

44

4.4

Completion of Bankers’ Acceptance

45

4.5

Bankers' Acceptance Marketing

45

4.6

Stamping Fee

46

4.7

Payment at Maturity

47

4.8

Power of Attorney Respecting Bankers’ Acceptances

47

TABLE OF CONTENTS

(continued)

Page

4.9

Prepayments

47

4.10

Default

48

4.11

Non-Acceptance Lenders

48

ARTICLE 5

LETTERS OF CREDIT

48

5.1

Letters of Credit Commitment

48

5.2

Fronted Letters of Credit

49

5.3

POA Letters of Credit

49

5.4

Notice of Insurance

52

5.5

Form of Letters of Credit

53

5.6

Procedure for Issuance of Letters of Credit

53

5.7

Payment of Amounts Drawn Under Letters of Credit

53

5.8

Fees

54

5.9

Obligations Absolute

55

5.10

Indemnification; Nature of Lenders’ Duties

56

5.11

Default, Maturity, etc

57

ARTICLE 6

CLOSING CONDITIONS

58

6.1

Closing Conditions to Initial Availability

58

6.2

General Conditions for Accommodations

60

6.3

Conversions and Rollovers

61

6.4

Deemed Representation

61

6.5

Conditions Solely for the Benefit of the Lenders

61

6.6

No Waiver

61

ARTICLE 7

REPRESENTATIONS AND WARRANTIES

61

7.1

Existence

61

7.2

Capacity

62

7.3

Authority

62

7.4

Authorization, Governmental Approvals, etc

62

7.5

Enforceability

62

TABLE OF CONTENTS

(continued)

Page

7.6

No Breach

62

7.7

Subsidiaries

62

7.8

Immunity, etc.

63

7.9

Litigation

63

7.10

Books and Records

63

7.11

Compliance

63

7.12

Latest Annual Financial Statements

64

7.13

Ibid

65

7.14

Contingent Liabilities

65

7.15

Franchises, etc.

65

7.16

Ownership of Property

65

7.17

Intellectual Property

65

7.18

Title

65

7.19

Leases

65

7.20

Material Agreements

66

7.21

Taxes

66

7.22

Material Adverse Effect

66

7.23

Pari Passu

66

7.24

Information

67

ARTICLE 8

COVENANTS

67

8.1

Affirmative Covenants

67

8.2

Negative Covenants

71

8.3

Financial Covenants

73

8.4

Administrative Agent May Perform Covenants

73

ARTICLE 9

CHANGES IN CIRCUMSTANCES

74

9.1

Provisions to Apply

74

9.2

Indemnification re Matching Funds

74

TABLE OF CONTENTS

(continued)

Page

ARTICLE 10

EVENTS OF DEFAULT

75

10.1

Events of Default

75

10.2

Effect

78

10.3

Right of Set-Off

79

10.4

Currency Conversion After Acceleration

79

ARTICLE 11

THE ADMINISTRATIVE AGENT AND THE LENDERS

79

11.1

Provisions to Apply

79

ARTICLE 12

MISCELLANEOUS

79

12.1

Sharing of Payments; Records

79

12.2

Amendments, etc

83

12.3

Notices, etc

84

12.4

Expenses and Indemnity

85

12.5

Judgment Currency

85

12.6

Governing Law, etc.

86

12.7

Successors and Assigns

86

12.8

Conflict

86

12.9

Confidentiality

86

12.10

Severability

86

12.11

Prior Understandings

87

12.12

Time of Essence

87

12.13

Counterparts

88

SCHEDULES

1

Lenders and Commitments

2

Accommodation Request

3

Repayment/Cancellation Notice

4

Model Credit Agreement Provisions

5

Compliance Certificate

6

Required Notice

7

Form of Opinion

8

Form of Terasen Funding Agreement

9

Form of POA Letter of Credit

10

Form of Power of Attorney

THIS AGREEMENT is dated for reference January 13, 2006.

AMONG:

TERASEN GAS (VANCOUVER ISLAND) INC.

as Borrower

OF THE FIRST PART

AND:

ROYAL BANK OF CANADA

as Administrative Agent

OF THE SECOND PART

AND:

THOSE INSTITUTIONS WHOSE NAMES ARE SET FORTH ON THE EXECUTION PAGES HEREOF UNDER THE HEADING "LENDERS"

as Lenders

OF THE THIRD PART

WHEREAS the Borrower has requested that the Lenders make available to it the Credit Facility, and the Lenders have agreed to do so on the terms and conditions set forth herein;

NOW THEREFORE, in consideration of the mutual covenants and agreements herein set forth and other good and valuable consideration, the receipt and sufficiency whereof are hereby acknowledged, the parties agree as follows:

ARTICLE 1
INTERPRETATION

1.1

Defined Terms.  As used in this agreement, including the recital and the schedules, unless there is something in the subject matter or the context inconsistent therewith, in addition to the definitions set forth in the Provisions, the following terms shall have the following meanings:

(1)

"Accommodation" means:

- 2 -

(a)

an Advance by a Lender made on the occasion of a Borrowing pursuant to an Accommodation Request (whether given or deemed to be given) or otherwise made or deemed to have been made pursuant hereto;

(b)

the creation of Bankers’ Acceptances on the occasion of a Drawing (or the making of a BA Equivalent Loan) pursuant to an Accommodation Request; and

(c)

the issue of a Letter of Credit, either by the Issuing Bank on behalf of the Lenders or by the Lenders on a several basis, on the occasion of an Issuance pursuant to an Accommodation Request;

and includes an Advance and a Bankers’ Acceptance resulting from a Rollover or Conversion (whether requested or deemed to have been requested hereunder) or otherwise effected pursuant hereto.  Each type of Borrowing and each type of Letter of Credit is a "type" of Accommodation, as are Bankers’ Acceptances.

(2)

"Accommodation Request" means a notice of request for a Borrowing, a Drawing and/or an Issuance substantially in the form of schedule 2 annexed hereto, or such other form as the Administrative Agent may from time to time specify.

(3)

"Administrative Agent" means RBC and any successor administrative agent appointed in accordance with Article 11.

(4)

"Advance" means an advance of monies (other than and excluding Discount Proceeds) made or deemed to have been made by a Lender under the Credit Facility and includes an Advance resulting from a Conversion or Rollover (whether requested or deemed to have been requested hereunder) or otherwise effected pursuant hereto, including a Swingline Advance.  An Advance may be denominated in US Dollars (a "US Dollar Advance") or Cdn. Dollars (a "Canadian Dollar Advance").  A Canadian Dollar Advance shall be designated a "Prime Rate Advance" and a US Dollar Advance shall be designated from time to time, as requested or deemed to have been requested by the Borrower, a "LIBOR Advance" or a "Base Rate Advance".  Each of a Prime Rate Advance, a LIBOR Advance and a Base Rate Advance is a "type" of Advance.

(5)

"Affiliate" has the meaning set forth in the Provisions.  Notwithstanding the foregoing, neither the Administrative Agent nor any Lender shall be deemed to be an Affiliate of the Borrower or any Affiliate thereof solely by reason of its agency function or lending relationship.

- 3 -

(6)

“Applicable Law” has the meaning set forth in the Provisions.

(7)

"Applicable Margin" means, in respect of the following types of Accommodation or the unadvanced portion of a Commitment, the following corresponding margins and fees expressed as basis points per annum:

Level	Rating	BAs, LIBOR and LCs	Prime Rate & Base Rate	Standby Fee if < 50% drawn	Standby Fee if > 50% drawn
I	A2/A or higher	40 bps	0 bps	10 bps	8 bps
II	A3/A (low)	45 bps	0 bps	11.25 bps	9 bps
III	Baa1/BBB (high)	55 bps	0 bps	13.75 bps	11 bps
IV	Baa2/BBB	70 bps	0 bps	17.5 bps	14 bps
V	Baa3/BBB (low)	95 bps	0 bps	25 bps	20 bps
VI	Lower than Baa3/BBB (low) or unrated	150 bps	50 bps	37.5 bps	30 bps

For the purposes of determining the Applicable Margin, the following shall apply:

(a)

If Ratings are provided by both Rating Agencies and are at two different levels, the Applicable Margin shall be calculated at the level corresponding to the higher of the Ratings; provided that, if such Ratings are not at adjacent levels, the Applicable Margin shall be calculated at the average of the margins that would otherwise apply.

(b)

The Applicable Margin shall be determined from time to time by the Administrative Agent based solely upon deliveries made pursuant to Section 6.1(11) or 8.1(12)(b), whose determination shall be conclusive and binding for all purposes hereof, absent demonstrated error.  The Administrative Agent shall provide notice to the Borrower and the Lenders of any change in the Applicable Margin as so determined by it.

(c)

A change in Applicable Margin necessitated by a change in or absence of a Rating shall have effect as regards Base Rate Advances, Prime Rate Advances or LIBOR Advances then outstanding on the effective day of such change or the first day of such absence (each, a "change effective day"), shall have effect as regards fees to be paid by the Borrower as referred to in Sections

- 4 -

2.6(a) and 5.8(1) on the change effective day, shall have effect as regards fresh Accommodations obtained by the Borrower on or after the change effective day and shall not affect the stamping fees for outstanding Bankers’ Acceptances.

(d)

In the absence of a Rating, level VI shall apply.

(8)

“Applicable Percentage” has the meaning set forth in the Provisions.

(9)

“Available Earnings” means, as at any date of determination, the consolidated net income of the Borrower for the period of four consecutive fiscal quarters ended on such date (before extraordinary items):

(a)

plus taxes on income;

(b)

plus depreciation and amortization expenses (including amortization of debt issuance expenses);

(c)

plus Interest Expense;

(d)

plus any Interest expenses on Class B Instruments or Subordinated Debt (to the extent deducted);

(e)

less the portion of such consolidated net income to be applied by the Borrower to the amortization, if any, of the Revenue Deficiency Deferral Account in accordance with the Special Direction;

(f)

plus the amount of the Annual Revenue Deficiency funded by Terasen (or any successor) under VINGPA during such period.

(10)

"BA Equivalent Loan" means, in relation to a Drawing, a loan in Canadian Dollars made to the Borrower by a Non-Acceptance Lender as part of the Drawing in accordance with the provisions of Section 4.11.

(11)

"Bankers’ Acceptance" means a depository bill, as defined by the Depository Bills and Notes Act (Canada), drawn by the Borrower, denominated in Canadian Dollars and accepted by a Lender as a bankers’ acceptance, as evidenced by such Lender’s endorsement thereof at the request of the Borrower pursuant to an Accommodation Request and includes a Bankers’ Acceptance resulting from a Conversion or Rollover.

(12)

"Base Rate" means, at any time, the greater of:

- 5 -

(a)

the rate of interest per annum established and reported by RBC from time to time as the reference rate of interest it charges to customers for US Dollar loans made by it in Canada; and

(b)

the sum of (i) the Federal Funds Effective Rate, plus (ii) 100 basis points per annum;

as to which a certificate of the Administrative Agent, absent manifest error, shall be conclusive evidence from time to time.  With each quoted or published change in such rate aforesaid of RBC there shall be a corresponding change in the rate of interest payable under this agreement, should such changed rate exceed that set forth in paragraph (b) of this definition, all without the necessity of any notice thereof to the Borrower or any other Person.

(13)

"basis point", “bp” and "b.p." each mean one one-hundredth (1/100) of one per cent, or .01%.

(14)

“BCUC” means the British Columbia Utilities Commission.

(15)

"Beneficiary" means, in respect of any Letter of Credit, the beneficiary specified therein.

(16)

"Borrower" means Terasen Gas (Vancouver Island) Inc.

(17)

"Borrowing" means a borrowing consisting of one or more Advances.  Prime Rate Advances, LIBOR Advances and Base Rate Advances are each a "type" of Borrowing.

(18)

"Business Day" means:

(a)

in respect of LIBOR Advances and payments in connection therewith, a London Business Day which is also a day on which banks are open for business in New York City, Vancouver and Toronto;

(b)

in respect of Base Rate Advances, a day (other than Saturday or Sunday) on which banks are open for business in New York City, Vancouver and Toronto; and

(c)

for all other purposes of this agreement, a day (other than Saturday or Sunday) on which banks are open for business in Vancouver and Toronto.

- 6 -

(19)

"C$ Equivalent Indebtedness" means, on any date in respect of any Indebtedness denominated in US Dollars, the equivalent amount of such Indebtedness expressed in Cdn. Dollars determined on the basis of the rate of exchange used for purposes of the Borrower’s balance sheet as at the end of the Financial Quarter ended on or most recently ended prior to such date; provided that, if the Borrower has entered into a Hedge Instrument which protects it against increases in the value of US Dollars as against Cdn. Dollars in respect of such Indebtedness, the Cdn. Dollar equivalent of such Indebtedness shall be reduced by any related deferred hedging asset or increased by any related deferred hedging liability determined in accordance with GAAP and shown on the Borrower’s consolidated balance sheet as at the end of such Financial Quarter.

(20)

"C$ Equivalent Principal Outstanding" means, at any time, the amount equal to:

(a)

when used in a context pertaining to Accommodations made by a single Lender, the Principal Outstanding in favour of such Lender; and

(b)

when used elsewhere in this agreement with reference to the Credit Facility as a whole, the Principal Outstanding in favour of all Lenders;

in each case calculated and expressed in Cdn. Dollars, with each US Dollar obligation converted for purposes of such calculation into the C$ Equivalent Indebtedness.

(21)

“Calculation Date” means each of the Closing Date and the last day of each Financial Quarter.

(22)

"Canadian Dollars", "Cdn. Dollars", "Cdn. $", "C$" and "$" each mean lawful money of Canada.

(23)

"Capital Lease" means a lease of (or other agreement conveying the right to use) real and/or personal property, which lease is required to be classified and accounted for as a capital lease on a balance sheet of the lessee under GAAP (including the Canadian Institute of Chartered Accountants Handbook Section 3065).

(24)

"Capital Lease Obligations" means, as to any Person, the obligations of such Person to pay rent or other amounts under a Capital Lease and, for purposes of this agreement, the amount of such obligations shall be the capitalized amount thereof (that is, the amount in effect corresponding to the principal of such obligations), determined in accordance with GAAP

- 7 -

(including the Canadian Institute of Chartered Accountants Handbook Section 3065).

(25)

"Cash Equivalents" means:

(a)

marketable, direct obligations of the United States of America, of Canada or of any political agency or subdivision thereof maturing within 365 days of the date of purchase;

(b)

commercial paper maturing within 180 days from the date of purchase thereof, and rated:

(i)

in the United States "P-2" or better by Moody’s or "A-2" or better by S&P; or

(ii)

in Canada "A-1 low" or better by S&P or "R-1 low" or better by DBRS; or

(iii)

in any of the foregoing cases the equivalent thereof by any other recognized rating agency; and

(c)

certificates of deposit maturing within 365 days of the date of purchase issued by or acceptances accepted or Guaranteed by a bank to which the Bank Act (Canada) applies having at the time of acquisition a combined capital, surplus or undistributed profits of at least C$2 billion.

(26)

"CDOR Rate" means, on any day, the annual rate of discount determined by the Administrative Agent which is equal to the simple average of the yield rates per annum (calculated on the basis of a year of 365 days and calculated to two decimal places with .005 or more being rounded upward) applicable to bankers’ acceptances denominated in Canadian Dollars having, where applicable, comparable issue dates and maturity dates as the Bankers’ Acceptances proposed to be issued by the Borrower displayed and identified as such on the "CDOR Page" (or any display substituted therefor) of Reuters Monitor Money Rates Service at approximately 10:00 a.m. (Toronto time) on that day or, if that day is not a Business Day, then on the immediately preceding Business Day (as adjusted by the Administrative Agent after 10:00 a.m. (Toronto time) to ref lect any error in the posted average annual rate of discount); provided, however, if those rates do not appear on the CDOR Page (or the display substituted therefor), then the CDOR Rate shall be the annual rate of discount determined by the Administrative Agent which is equal to the simple average of the yield rates per annum (calculated on the basis of a year of 365 days and calculated to two decimal places with .005 or more

- 8 -

being rounded upward) applicable to those bankers’ acceptances in a comparable amount to the Bankers’ Acceptances proposed to be issued by the Borrower, quoted by three of the five largest (as to total assets) Schedule I Banks (as selected by the Administrative Agent) as of 10:00 a.m. (Toronto time) on that day or, if that day is not a Business Day, on the immediately preceding Business Day.  Each determination of the CDOR Rate by the Administrative Agent shall be conclusive and binding, absent demonstrated error.

(27)

“Charter Documents” means, in respect of any Person, the certificate and articles of incorporation or similar formation documents, by-laws, unanimous shareholders agreement and other organizational or governing documents of such Person.

(28)

“Class A Instruments” and “Class B Instruments” shall each have the respective meaning set forth in the VINGPA.

(29)

"Closing Date" means January 13, 2006 or such other date as shall be mutually agreed by the Borrower and the Lenders.

(30)

"Commitment" means, for a Lender in respect of the Credit Facility, the amount set forth opposite such Lender’s name under the heading “Commitment” on schedule 1 annexed hereto to the extent not permanently reduced, cancelled or terminated pursuant to this agreement.

(31)

"Compliance Certificate" means a certificate of a Senior Financial Officer pursuant to Section 8.1(11)(c) substantially in the form of schedule 5 annexed hereto.

(32)

“Contaminants” means substances, pollutants and wastes which:

(a)

pollute or are otherwise harmful to the environment;

(b)

are defined as contaminants, pollutants, radioactive waste, hazardous substances, hazardous waste, hazardous or toxic under any applicable Environmental Law; or

(c)

are construed as having an “adverse effect”, through impairment of or damage to the environment, human health or safety or property under any applicable Environmental Law.

(33)

"Control" has the meaning set forth in the Provisions.

(34)

"Conversion" means, in respect of any Drawing or type of Borrowing, the conversion of the method for calculating interest, discount rates or fees

- 9 -

thereon from one method to another in accordance with Section 2.11, and includes a conversion from a Prime Rate Advance to a Drawing and vice-versa and a conversion from a LIBOR Advance to a Base Rate Advance and vice-versa.  In addition, the repayment in full by the Borrower of the Principal Outstanding under an Accommodation in one currency and the concurrent making of an Accommodation in another currency, whereby the aggregate C$ Equivalent Principal Outstanding remains the same before and after such transactions, shall also be considered to be a Conversion for all purposes of this agreement.

(35)

"Coverage Ratio" at any time means the ratio of X to Y for the Borrower, with each component calculated on a consolidated basis, where:

(a)

"X" is Available Earnings determined for the four consecutive Financial Quarters ending at such time or immediately prior thereto, as the case may be, for which the Borrower has provided or is required prior to such time to provide a Compliance Certificate; and

(b)

"Y" is the Interest Expense for such four Financial Quarters.

(36)

"Credit Facility" means the revolving term credit facility to be provided by the Lenders to the Borrower as contemplated by Article 2.

(37)

"Credit Facility Documents" means this agreement, Bankers’ Acceptances, Letters of Credit and all other documents (for clarity, excluding the Terasen Funding Agreement) necessary to implement the financing comprised in the Credit Facility.

(38)

"DBRS" means Dominion Bond Rating Service Limited and, if such Person shall at any time cease to provide Ratings in respect of companies of the nature of the Borrower, means any other company or organization designated by the Borrower that is acceptable to the Lenders, acting reasonably, which shall provide a Rating of the long-term corporate credit and/or long-term unsecured debt of the Borrower on a basis consistent with and using the same nomenclature as Dominion Bond Rating Service Limited or that is otherwise acceptable to the Lenders, acting reasonably.

(39)

"Default" has the meaning set forth in the Provisions.

(40)

"Discount Proceeds" means, in respect of Bankers’ Acceptances to be purchased by a Lender, the result (rounded to the nearest whole cent, with one-half of one cent and more being rounded up) obtained by multiplying the aggregate Face Amount of such Bankers’ Acceptances by a price (rounded up or down to the third decimal place, with .0005 or

- 10 -

more being rounded up) determined by dividing one by the sum of one plus the product of (x) the applicable Discount Rate multiplied by (y) a fraction, the numerator of which is the number of days in the term to maturity of such Bankers’ Acceptances and the denominator of which is 365.

(41)

"Discount Rate" means:

(a)

with respect to an issue of Bankers’ Acceptances accepted by a Lender that is a Schedule I Bank, the CDOR Rate; and

(b)

with respect to an issue of Bankers’ Acceptances accepted by a Lender that is not a Schedule I Bank, the lesser of:

(i)

the CDOR Rate plus seven basis points; and

(ii)

the annual rate, expressed as a percentage, determined by the Administrative Agent as the average discount rate for bankers’ acceptances having a comparable face value in Cdn. Dollars and a comparable issue and maturity date to the face value and issue and maturity date of that issue of Bankers’ Acceptances calculated on the basis of a year of 365 days accepted by the Reference Lenders at or about 10:00 a.m. (Toronto time) on the date of issue of those Bankers’ Acceptances.

(42)

"Drawing" means the creation or making of one or more Bankers’ Acceptances in pursuance of an Accommodation Request.

(43)

"Drawing Date" means any Business Day fixed in accordance with the provisions of this agreement for a Drawing.

(44)

"Environmental Laws" means any Requirement of Law relating, in whole or in part, to the protection or enhancement of the environment or imposing liability as a result of adverse effects to the environment, including occupational safety, product liability, public health and public safety.

(45)

"Equivalent Amount" means, on a particular date in respect of any amount (the "original amount") expressed in a particular currency (the "original currency"), the equivalent amount expressed in a second designated currency (the "second currency") determined by reference to the Bank of Canada noon rate at which the original currency may be exchanged into the second currency as published on the Reuters Screen page BOFC.  In the event that such rate does not appear on such Reuters

- 11 -

page, such rate shall be ascertained by reference to any other means (as selected by the Administrative Agent) by which such rate is quoted or published from time to time by the Bank of Canada; provided that, if at the time of any such determination, for any reason, no such exchange rate is being quoted or published, the Administrative Agent may use such reasonable method as it considers appropriate to ascertain such rate, and the resulting determination shall be conclusive absent manifest error.

(46)

"Event of Default" means any of the events specified in Section 10.1.

(47)

“Existing Facility” means the credit facilities set out in the credit agreement dated January 9, 1996 between the Borrower (then called Centra Gas British Columbia Inc.) and the lenders thereto.

(48)

"Excluded Taxes" has the meaning set forth in the Provisions.

(49)

"Face Amount" means, in respect of a Bankers’ Acceptance, the amount payable to the holder thereof on its maturity and, in respect of a Letter of Credit, the maximum amount that may from time to time be payable to the Beneficiary thereof, and where used in a context referring to more than one Bankers’ Acceptance and/or Letter of Credit means the aggregate of the Face Amounts thereof.

(50)

"Federal Funds Effective Rate" means, for any day, the weighted average (rounded upwards, if necessary, to the next 1/100 of 1%) of the annual rates of interest on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

(51)

"Financial Quarter" means a period of three consecutive months ending on and including March 31, June 30, September 30 or December 31, as the case may be.

(52)

"Financial Year" means a financial year commencing on January 1 of each calendar year and ending on and including December 31 of such year.

(53)

"GAAP" means, in relation to any Person at any time, accounting principles generally accepted in Canada as recommended in the Handbook of the Canadian Institute of Chartered Accountants or its successor, applied on a basis consistent with the most recent audited

- 12 -

financial statements of such Person and, if applicable, its consolidated subsidiaries (except for changes approved by the auditors of such Person; provided that the calculations of the Leverage Ratio and the Coverage Ratio, including the constituent elements thereof, shall be made without regard to any change in GAAP with effect on or after January 1, 2005).

(54)

“Government Repayable Contributions” means the British Columbia Repayable Contribution in the amount of $25 million and the Canada Repayable Contribution in the amount of $50 million defined in the PCEPA.

(55)

“Governmental Approval” means any franchise, licence, qualification, authorization, consent, exemption, waiver, right, permit or other approval of any Governmental Authority, binding on or affecting the Person referred to in the context in which the term is used or binding on or affecting the property of such Person, in each case whether or not having the force of law.

(56)

“Governmental Authority” has the meaning set forth in the Provisions.

(57)

"Guarantee" means, with respect to any Person, any obligation of such Person directly or indirectly guaranteeing any indebtedness or other obligation of any other Person and, without limiting the generality of the foregoing, includes any obligation, direct or indirect, contingent or otherwise, of such Person:

(a)

to purchase or pay (or advance or supply funds for the purchase or payment of) such indebtedness or other obligation of such other Person (whether arising by virtue of partnership, joint venture or similar arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, or to maintain financial condition or otherwise); or

(b)

entered into for purposes of assuring in any manner the obligee of such indebtedness or other obligation of the payment or performance (or payment of damages in the event of non-performance) thereof or to protect such obligee against loss in respect thereof (in whole or in part);

provided that the foregoing shall exclude endorsement of negotiable instruments for collection or deposit in the ordinary course of business.

(58)

"Hedge Instrument" means:

- 13 -

(a)

any interest rate or foreign exchange risk management agreement or product, including interest rate or currency exchange or swap agreements, futures contracts, forward rate agreements, interest rate cap agreements and interest rate collar agreements, options and all other agreements or arrangements designed to protect against fluctuations in interest rates or currency exchange rates; and

(b)

forward purchase and sale contracts, options and other hedging products designed to be effective as a hedge against fluctuations in the price of natural gas.

(59)

"Hedging Obligations" means, with respect to any Person, payment or delivery obligations under Hedge Instruments.

(60)

"Increased Costs" means any amounts payable by the Borrower to the Administrative Agent or a Lender under any of:

(a)

Sections 5.10, 8.1(14) and 9.2 of the body of this agreement; and

(b)

Sections 3.1, 3.2, 3.3 and 9 of the Provisions.

(61)

“Indebtedness” means, with respect to any Person at any time, any of the following (without duplication):

(a)

the amount of all indebtedness for borrowed moneys of such Person (including Purchase Money Obligations);

(b)

the amount of all obligations of such Person evidenced by notes payable, drafts accepted representing extensions of credit, bonds, debentures or other similar instruments, to the extent such obligations would be considered indebtedness for borrowed moneys in accordance with GAAP;

(c)

all obligations of such Person, whether or not contingent, with respect to or under any bankers’ acceptance facility or, except where the same secures payment of trade payables incurred in the ordinary course of business, any letter of credit facility or similar facility, including any liability arising under any indemnity obligation pertaining thereto;

(d)

the amount of the deferred purchase price of property or services, other than trade payables incurred in the ordinary course of business;

- 14 -

(e)

Capital Lease Obligations of such Person;

(f)

shares in the capital of such Person redeemable at the option of the holder, or which by their terms or otherwise are required to be redeemed, at the time of determination of Indebtedness;

(g)

all indebtedness of other Persons secured by a Lien on any Property of such Person, whether or not such indebtedness is assumed by such Person; provided that the amount of such indebtedness shall be the lesser of:

(i)

the fair market value of such Property at such date of determination; and

(ii)

the amount of such indebtedness; and

(h)

all other debt (other than trade payables incurred in the ordinary course of business) upon which interest charges are customarily paid by such person; and

(i)

any Guarantee by such Person in any manner of any part or all of an obligation included in clauses (a) to (h) above.

The amount of Indebtedness of any Person at any date shall be the outstanding balance at such date (without duplication) of all unconditional obligations as described above and, with respect to contingent obligations, the maximum liability upon the occurrence of the contingency giving rise to the obligation; provided that:

(x)

the amount at any time of indebtedness issued with original issue discount shall be the accreted amount thereof determined in accordance with GAAP; and

(xi)

Indebtedness shall not include any liability for unpaid taxes not yet due.

(62)

"Indebtedness for Borrowed Monies" means Indebtedness other than:

(a)

Indebtedness constituted by uncalled letters of credit the deposit of which constitutes a Permitted Lien under paragraph (g), (i) or (o)  of the definition thereof, or a Guarantee of the obligations of another Person in respect of uncalled letters of credit the deposit of which would, if this agreement were applicable, constitute a Permitted Lien;

- 15 -

(b)

Indebtedness contemplated by item (f) of the definition of Indebtedness; and

(c)

Indebtedness contemplated by items (g) and (h) of such definition where the underlying Indebtedness secured by the Lien or subject to the Guarantee is of the nature described in item (f) of such definition.

(63)

“Institutional Indebtedness” means at any time of determination the aggregate Indebtedness for Borrowed Monies of the Borrower (including current maturities), including each of the following:

(a)

the Principal Outstanding; and

(b)

the principal outstanding under the PCEPA Repayment Facility;

but excluding:

(c)

Government Repayable Contributions;

(d)

Class A Instrument and Class B Instruments; and

(e)

Subordinated Debt.

(64)

"Intercompany Debt" means the aggregate principal amount and accrued interest owed by the Borrower to Terasen or an Affiliate of Terasen as at the Closing Date or, for the purpose of calculating Interest Expense for any period prior to the Closing Date, the aggregate principal amount owed by the Borrower to Terasen or to an Affiliate of Terasen at any time during such period.

(65)

“Interest” means interest (including capitalized and non-capitalized interest and the interest component of  Capital Lease Obligations but excluding interest which has been capitalized in accordance with normal regulatory principles), stamping fees, the difference between the proceeds of sale and face value of Bankers’ Acceptances, stand-by fees and all other similar costs of borrowing.

(66)

"Interest Expense" means, as at any date of determination, the amount equal to the aggregate Interest on all Institutional Indebtedness paid or accrued during the period of four consecutive Financial Quarters ended on or immediately prior to such date; provided that, with respect to the calculation of Interest Expense for any period prior to the Closing Date, such calculation shall be made on a pro forma basis as if the Institutional Indebtedness outstanding during such period (i) included the amount

- 16 -

drawn under the Credit Facility to repay the Existing Facility and the Intercompany Debt, and (ii) excluded the Indebtedness under the Existing Facility and the Intercompany Debt.

(67)

"Interest Period" means, for each LIBOR Advance, a period commencing:

(a)

in the case of the initial Interest Period for such Advance, on the date of such Advance; and

(b)

in the case of any subsequent Interest Period for such Advance in accordance with a Rollover, on the last day of the immediately preceding Interest Period;

and ending in either case on the last day of such period as shall be selected by the Borrower pursuant to the provisions below.

If a Base Rate Advance is converted to a LIBOR Advance, the initial Interest Period for such LIBOR Advance shall commence on the date of such Conversion.  The duration of each Interest Period for a LIBOR Advance shall be one, two, three or six months (subject to availability), as the Borrower may select in the applicable Accommodation Request, or such other period to which the Lenders may agree.  No Interest Period may be selected which would end on a day after the Maturity Date or, in the opinion of the Administrative Agent, conflict with any repayment stipulated herein.  Whenever the last day of an Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day; provided that, if such extension would cause the last day of such Interest Period to o ccur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day.

(68)

"ISP98" means the International Standby Practices ISP98, as published by the International Chamber of Commerce and in effect from time to time.

(69)

"Issuance" means the issuance of one or more Letters of Credit made pursuant to an Accommodation Request.

(70)

"Issue Date" means any Business Day fixed in accordance with the provisions of this agreement for an Issuance.

(71)

"Issuing Bank" has the meaning set forth in the Provisions and, for this purpose, RBC shall be the Issuing Bank.

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(72)

"Lenders" means those financial institutions whose names are set forth on the execution pages hereof under the heading "Lenders", and their respective successors and assigns.

(73)

"Lenders’ Counsel" means Stikeman Elliott LLP or such other law firm or firms as may from time to time be chosen by the Lenders to act on their behalf in connection with the Credit Facility.

(74)

"Lending Office” or “lending office" means, in respect of a particular Lender, the branch or office whose address is set forth in schedule 1 annexed hereto, or such other branch as such Lender may designate from time to time by notice given to the Administrative Agent and the Borrower.

(75)

"Letter of Credit" means a standby or commercial letter of credit or a letter of guarantee for a specified amount in Canadian Dollars or US Dollars issued by the Issuing Bank on behalf of the Lenders at the request and upon the indemnity of the Borrower pursuant to Article 5 and (subject to Section 5.5(b)) having a term to maturity from the date of issuance thereof of no more than 365 days.

(76)

"Leverage Ratio" at any time means the ratio of X to Y for the Borrower, with each component calculated on a consolidated basis, where:

(a)

"X" is Institutional Indebtedness outstanding at that time; and

(b)

"Y" is Total Capitalization at that time.

(77)

"LIBOR", with respect to any Interest Period, means:

(a)

the rate of interest (expressed as an annual rate on the basis of a 360 day year) determined by the Administrative Agent to be the arithmetic mean (rounded up to the nearest 0.01%) of the offered rates for deposits in US Dollars for a period equal to the particular Interest Period, which rates appear on:

(i)

Page 3750 of the Telerate screen; or

(ii)

if such Telerate screen page is not readily available to the Administrative Agent, the Reuters screen LIBO page;

in either case as of 11:00 a.m. (London time) on the second London Business Day before the first day of that Interest Period; or

- 18 -

(b)

if neither such Reuters screen page nor Telerate screen page is readily available to the Administrative Agent for any reason, the rate of interest determined by the Administrative Agent which is equal to the simple average of the rates of interest (expressed as a rate per annum on the basis of a year of 360 days and rounded up to the nearest 0.01%) at which three of the five largest (as to total assets) Schedule I Banks (as selected by the Administrative Agent) would be prepared to offer leading banks in the London interbank market a deposit in US Dollars for a term coextensive with that Interest Period in an amount substantially equal to the relevant LIBOR Advance at or about 10:00 a.m. (Toronto time) on the second London Business Day before the first day of such Interest Period.

(78)

"Lien" means any mortgage, pledge, lien, hypothecation, security interest or other encumbrance or charge (whether fixed, floating or otherwise) or title retention, and any deposit of moneys under any agreement or arrangement whereby such moneys may be withdrawn only upon fulfilment of any condition as to the discharge of any other indebtedness or other obligation to any creditor, or any right of or arrangement of any kind with any creditor (other than as contemplated under the PCEPA) to have its claims satisfied prior to other creditors with or from the proceeds of any properties, assets or revenues of any kind now owned or later acquired.

(79)

"London Business Day" means a day (other than Saturday or Sunday) which is a day for trading by and between banks in US Dollar deposits in the London Eurodollar interbank market.

(80)

"Majority Lenders" means Lenders whose respective individual Commitments aggregate at least two-thirds (2/3) of the total Commitments of all Lenders under the Credit Facility.

(81)

"Material Adverse Effect" means a material adverse effect on:

(a)

the business, Property, operations or condition (financial or otherwise) of the Borrower;

(b)

the Borrower's ability to perform its obligations under any Credit Facility Document; or

(c)

the Borrower's ability to perform its material obligations under any Material Agreement.

(82)

“Material Agreements” means each of:

- 19 -

(a)

the VINGPA;

(b)

the PCEPA; and

(c)

the Wheeling Agreement.

(83)

"Maturity Date" means the fifth anniversary of the Closing Date.

(84)

"Moody’s" means Moody’s Investors Service, Inc. and, if such Person shall at any time cease to provide Ratings in respect of companies of the nature of the Borrower, means any other company or organization designated by the Borrower that is acceptable to the Lenders, acting reasonably, which shall provide a Rating of the long-term corporate credit and/or long-term unsecured debt of the Borrower on a basis consistent with and using the same nomenclature as Moody’s Investors Service, Inc. or that is otherwise acceptable to the Lenders, acting reasonably.

(85)

"Non-Acceptance Discount Rate" means, for any day, the Discount Rate that is the lesser of the rates described in paragraph (b)(i) and (b)(ii) of the definition of Discount Rate; provided that, if at any relevant time there are no Reference Lenders, the Non-Acceptance Discount Rate will be the Discount Rate in paragraph (b)(i) of that definition.

(86)

"Non-Acceptance Lender" has the meaning set forth in Section 4.11.

(87)

"Notice" means, as the context requires, an Accommodation Request or a Repayment/Cancellation Notice.

(88)

"Obligations" means at any time in respect of the Credit Facility, the amount equal to the sum of:

(a)

the Principal Outstanding under the Credit Facility;

(b)

all accrued and unpaid interest thereon and all interest on accrued and unpaid interest; and

(c)

all accrued and unpaid fees, expenses, costs, indemnities, Increased Costs and other amounts payable to the Lenders or the Administrative Agent pursuant to the provisions of any Credit Facility Document or the Terasen Funding Agreement or otherwise in respect of the Credit Facility.

(89)

"Participant" has the meaning set forth in the Provisions.

- 20 -

(90)

"Payment Account" means:

(a)

for US Dollars:

JPMorgan Chase Bank, New York, New York

ABA 021000021, Swift code: CHASUS33

For further credit to:

Swift Address:  ROYCCAT2

Beneficiary: RBCCM Agency Services,

A/C #:  /00002-408-919-9

Toronto, Ontario

Ref: Terasen Gas (Vancouver Island) Inc.

(b)

 for Cdn. Dollars:

Royal Bank of Canada

Swift Address:  ROYCCAT2

Favour:  /00002-266-760-8

RBCCM Agency Services,

Toronto, Ontario

Ref: Terasen Gas (Vancouver Island) Inc.

or such other places or accounts as may be agreed by the Administrative Agent and the Borrower from time to time and notified to the Lenders.

(91)

“PCEPA” means the Pacific Coast Energy Pipeline Agreement between Her Majesty the Queen in Right of Canada, Her Majesty the Queen in Right of the Province of British Columbia and the Borrower (then called Pacific Coast Energy Corporation) dated December 14, 1995.

(92)

“PCEPA Repayment Facility” means the $20,000,000 facility provided by RBC to refinance 65% (or such other percentage as may be approved by the BCUC as the appropriate percentage of debt to be included in the Borrower’s capital structure) of the annual repayment of the Government Repayable Contributions.

(93)

"Permitted Liens" means, in respect of any Person at any time, any one or more of the following:

(a)

Liens for taxes, assessments or other governmental charges not yet due or, if due, the validity of which is being contested by the Borrower in good faith and Liens for the excess of the amount of any past due taxes for which a final assessment has not been received over the amount of such taxes as estimated and paid by the Borrower;

(b)

Liens or privileges arising out of judgments or awards not giving rise to an Event of Default with respect to which the Borrower shall in good faith be prosecuting an appeal or proceedings for review

- 21 -

and with respect to which it shall within 30 Business Days have secured a stay of execution pending completion of such appeal or proceedings for review;

(c)

Liens and charges (including builders’, warehousemen's, carriers' and other similar Liens) incidental to construction or current operations which have not at such time been filed pursuant to Applicable Law against the Borrower or relate to obligations not due or delinquent or which are being contested by the Borrower in good faith;

(d)

undetermined or inchoate liens and charges incidental to the operations of the Borrower which have not been registered against the assets of the Borrower and which relate to obligations not due or delinquent;

(e)

reservations, limitations, provisos and conditions expressed in any grant from the Crown, and statutory exceptions to title;

(f)

easements, rights-of-way and servitudes (including easements, rights-of-way and servitudes for sewers, drains, railways, pipelines, gas or water mains or electric light and power or telephone, cable television and telegraph conduits, poles, wires and cables) and other restrictions and minor title defects or irregularities which will not in the aggregate materially and adversely impair the use of the property concerned for the purpose for which it is held by the Borrower;

(g)

security given by the Borrower to a public utility or municipality or other Governmental Authority when required by such utility or municipality or other Governmental Authority in connection with the operations of the Borrower in the ordinary course of its business;

(h)

the right reserved to or vested in any municipality or other Governmental Authority by the terms of any lease, licence, franchise, grant or permit acquired by the Borrower, or by any statutory provision, to terminate any such lease, licence, franchise, grant or permit or to require annual or other periodic payments as a condition of the continuance thereof;

(i)

the encumbrance resulting from the deposit of cash, letters of credit or securities in connection with any of the Liens described in paragraphs (a), (b) or (c) of this definition pending a final

- 22 -

determination as to the existence or amount of any obligation referred to therein, or in connection with contracts, bids, tenders, leases or expropriation proceedings, or to secure workers’ compensation, unemployment insurance, surety or appeal bonds, costs of litigation when required by Applicable Law and public and statutory obligations;

(j)

any other Liens of a nature similar to those referred to in the foregoing paragraphs (a) to (h), inclusive, of this definition which do not have and could not reasonably be expected to have a Material Adverse Effect;

(k)

Liens on property or shares of a Person at the time that such Person becomes a subsidiary of the Borrower; provided, however, that the Lien may not extend to any other property or assets owned by any subsidiary and such Liens are not created, incurred or assumed in connection with, or in contemplation of, or to provide credit support in connection with, such Person becoming a subsidiary;

(l)

Liens on property or assets at the time the Borrower acquires the property or assets, including any acquisition by means of an amalgamation, merger or consolidation with or into the Borrower; provided, however, that the Lien may not extend to any other property or assets owned by the Borrower and such Liens are not created, incurred or assumed in connection with, or in contemplation of, or to provide credit support in connection with, such acquisition;

(m)

Liens to secure any refinancing, extension, renewal or replacement as a whole, or in part, of any Indebtedness secured by any Lien referred to in the foregoing paragraphs (k) and (l) of this definition;

(n)

Liens securing Purchase Money Obligations and Capital Lease Obligations in an aggregate amount at any time not to exceed $10 million;

(o)

any security interest in cash or marketable securities pledged, or a letter of credit provided, to secure obligations of the Borrower under purchase contracts for natural gas or under Hedge Instruments entered into to hedge against fluctuations in the price of natural gas;

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(p)

Liens encumbering property under construction arising from progress or partial payments made by a customer of the Borrower relating to such property;

(q)

any interest or title of a lessor in the property subject to any lease; and liens or rights of distress reserved in or exercisable under leases for payment of rent or other compliance with the terms of the lease; and

(r)

Liens in favour of customs and revenue authorities arising under Applicable Law to secure payment of customs or import duties in connection with the importation of goods.

(94)

"Permitted Merger" means a transaction otherwise prohibited by Section 8.2(2) where the following conditions are satisfied:

(a)

the surviving entity and the Lenders shall have agreed to such amendments to the Credit Facility Documents (and, if such transaction involves Terasen, such amendments to the Terasen Funding Agreement) as shall be required in order:

(i)

to preserve the rights and interests of the Lenders as senior unsecured creditors; and

(ii)

to ensure that the financial tests and calculations contemplated by the Credit Facility Documents shall have the same economic effect with respect to the surviving entity as is the case with the Borrower immediately prior to such transaction, it being acknowledged that it is not intended that the ratios required under Section 8.3 be altered but rather that the components of such ratios are measured with consistent economic effect both before and after such transaction;

(b)

both immediately before and (having regard to the agreed amendments pursuant to paragraph (a)) immediately after such transaction there shall be no Default or Event of Default that has occurred and is continuing;

(c)

prior to such transaction, the Borrower shall have obtained a Ratings affirmation (which is equal to or greater than its then current Rating) with respect to the surviving entity’s senior publicly-rated debt;

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(d)

no such transaction shall affect the validity or enforceability of any Credit Facility Document or the Terasen Funding Agreement (except in the case of a merger or amalgamation of the Borrower and Terasen, in which case the Junior Obligations as defined in the Terasen Funding Agreement shall be extinguished by operation of law); and

(e)

the Borrower shall deliver to the Administrative Agent promptly following such transaction a certificate of a Senior Financial Officer and an opinion of counsel to the Borrower, each stating that such transaction complies herewith and each being otherwise in form and substance reasonably acceptable to the Administrative Agent.

(95)

"Person" has the meaning set forth in the Provisions.

(96)

"Prime Rate" means, at any time, the greater of:

(a)

the rate of interest per annum established and reported by RBC from time to time as the reference rate of interest it charges to customers for Canadian Dollar loans made by it in Canada; and

(b)

the sum of:

(i)

the average one month bankers’ acceptance rate as quoted on Reuters Service page CDOR as at 10:00 a.m. (Toronto time) on such day, expressed as a rate per annum; plus

(ii)

100 basis points;

as to which a certificate of the Administrative Agent, absent manifest error, shall be conclusive evidence from time to time.  With each quoted or published change in such rate aforesaid of RBC there shall be a corresponding change in any rate of interest payable under this agreement based on the Prime Rate should such changed rate exceed that set forth in paragraph (b) of this definition, all without the necessity of any notice thereof to the Borrower or any other Person.

(97)

"Principal Outstanding" means, at any time, the amount equal to:

(a)

when used in a context pertaining to Accommodations made by a single Lender under the Credit Facility, the sum of:

(i)

the aggregate principal amount of all Advances and BA Equivalent Loans then outstanding made by such Lender; and

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(ii)

the Face Amount of all Accommodations then outstanding made by such Lender by way of Bankers’ Acceptances (whether or not held by such Lender) and Letters of Credit (including such Lender’s pro rata interest in Letters of Credit issued by the Issuing Bank); and

(b)

when used elsewhere in this agreement with reference to the Credit Facility as a whole, the sum of:

(i)

the aggregate principal amount of all Advances and BA Equivalent Loans then outstanding made by the Lenders; and

(ii)

the Face Amount of all Accommodations then outstanding made by the Lenders by way of Bankers’ Acceptances (whether or not held by the respective Lenders) and Letters of Credit;

provided that, for the purposes of calculating standby and utilisation fees payable under Section 2.6, the principal amount of Swingline Advances shall not be considered to be Principal Outstanding.

(98)

"Property" means any property, assets, rights or interests of any nature whatsoever, real or personal, moveable or immoveable, tangible or intangible, and wheresoever situate.

(99)

“Provisions” means the Model Credit Agreement Provisions annexed hereto as schedule 4.

(100)

"Purchase Money Obligation" means indebtedness under any purchase money mortgage, pledge or other purchase money Lien entered into in the ordinary course of business and secured upon property acquired by a Person.

(101)

"Rating" means, with respect to a Person, the credit rating assigned by a Rating Agency to the long-term senior unsecured debt of such Person.

(102)

“Rating Agencies” means, at any time, DBRS and Moody’s.

(103)

“RBC” means Royal Bank of Canada, a Canadian chartered bank.

(104)

"receiver" includes a receiver, receiver/manager and receiver and manager.

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(105)

"Reference Lenders" means any two Lenders as selected by the Administrative Agent from time to time and that are acceptable to the Borrower which are banks under Schedule II of the Bank Act (Canada).

(106)

"Repayment/Cancellation Notice" means a notice in the form of or to substantially similar effect as schedule 3 annexed hereto, given to the Administrative Agent by the Borrower pursuant to any relevant provision of this agreement.

(107)

"Required Notice", when used with respect to a type of Accommodation, a payment, prepayment or reduction of the Commitments hereunder, means such number of days’ notice to the Administrative Agent as is set forth in schedule 6 annexed hereto.

(108)

“Requirement of Law” means, as to any Person, the Charter Documents  of such Person, and any international, Canadian or United States federal, provincial, state or local statute, law, regulation, order, rule, by-law, proclamation, consent, decree, judgment, permit, license, code, covenant, deed restriction, common law (including the law of equity), treaty, convention, ordinance or determination of an arbitrator or a court or other competent authority, or guidelines or requirements of any Governmental Authority (whether or not having the force of law and including consent decrees as to which such Person is a party or otherwise subject, and administrative orders which affect such Person) in each case applicable to or binding upon such Person or any of the Property of such Person.

(109)

“Revenue Deficiency Deferral Account” has the meaning set forth in the Special Direction.

(110)

"Rollover" means, in respect of a Borrowing by way of LIBOR Advances, the continuation thereof or any portion thereof for a succeeding Interest Period and, in respect of a Drawing, the issuance of a further Drawing on any day in a Face Amount not exceeding the Face Amount of the Drawing maturing on that day, the proceeds of which are used to pay (directly or indirectly) the maturing Drawing, all as contemplated by Section 2.11.

(111)

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.

(112)

"Schedule I Bank", "Schedule II Bank" or "Schedule III Bank" mean a bank under (as the case may be) Schedule I or II of the Bank Act (Canada) or an authorized foreign bank under Schedule III of the Bank Act (Canada).

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(113)

"Senior Financial Officer" means the Chief Financial Officer, Vice President Finance, Controller, Treasurer or Assistant Treasurer of the Borrower.

(114)

“Senior Officer” means the President, Chairman, any Vice-President or a Senior Financial Officer of the Borrower.

(115)

“Special Direction” means the direction issued by the Lieutenant Governor in Council of the Province of British Columbia to the BCUC pursuant to the Vancouver Island Natural Gas Pipeline Act (British Columbia) in connection with the VINGPA.

(116)

"Subordinated Debt" means Indebtedness of the Borrower which:

(a)

is subordinated to the prior payment in full of the Obligations as provided in this definition;

(b)

will not be cross-defaulted or cross-accelerated by the Credit Facility;

(c)

may not be accelerated prior to the date that is the earlier of:

(i)

the date following the date on which all of the Obligations and the obligations of the Borrower under the PCEPA Repayment Facility have been paid in full and the commitments of the Lenders hereunder and the commitment of the lender under the PCEPA Repayment Facility have been terminated; and

(ii)

six months after the later of:

(A)

the Maturity Date; and

(B)

the “Maturity Date” as defined in the PCEPA Repayment Facility;

(d)

may not contain covenants or events of default more onerous than those contained in this agreement;

(e)

will provide that any amount received by the holders of such Indebtedness within three months of an Event of Default will, upon the Obligations being declared or becoming due and payable pursuant to Section 10.2(1) or (2), be paid to the Administrative Agent on behalf of the Lenders;

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(f)

will require that notice of default thereunder be provided to the Administrative Agent; and

(g)

will permit interest on and principal of such Indebtedness to be paid or prepaid only if Sections 8.2(5)(d) and (e) are complied with as if the applicable payment were a Distribution.

(117)

"subsidiary" means, at any time with respect to a Person, any other Person, if at such time such first-mentioned Person owns, directly or indirectly, more than 50% of the capital in such other Person entitled ordinarily to vote in the election of the board of directors of, or Persons performing similar functions for, such other Person.

(118)

"Swingline" means that portion of the Credit Facility to be made available by the Swingline Lender to the Borrower as described in Section 2.1(6), and "Swingline Advance" has the meaning set forth in Section 2.1(6).

(119)

"Swingline Amount" means C$10 million (or the Equivalent Amount in US Dollars) to the extent not permanently reduced, cancelled or terminated pursuant to this agreement.

(120)

"Swingline Lender" means TD Bank acting in its capacity as the Lender of Swingline Advances under Section 2.1(6) or, as the case may be, any replacement Lender of Swingline Advances agreed by the Borrower, the Administrative Agent and such replacement Lender.

(121)

"Taking" means the expropriation, condemnation or taking by eminent domain or similar authority, or by any proceeding or purchase in lieu or anticipation thereof, of any property or asset or any right, title or interest therein by any Governmental Authority.

(122)

"TD Bank" means The Toronto-Dominion Bank, a Canadian chartered bank.

(123)

“Terasen” means Terasen Inc.

(124)

“Terasen Funding Agreement” means the agreement so entitled of even date between, inter alia, Terasen and the Administrative Agent, substantially in the form of schedule 8 annexed hereto.

(125)

"this agreement", "herein", "hereof", "hereto" and "hereunder" and similar expressions mean and refer to this agreement as supplemented or amended and not to any particular Article, Section, paragraph, schedule or other portion hereof; and the expressions "Article", "Section",

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"paragraph" and "schedule" followed by a number or letter mean and refer to the specified Article, Section, paragraph or schedule of this agreement.

(126)

“Total Capitalization” means, as at any date of determination, the aggregate of the Borrower’s:

(a)

common equity (including retained earnings and contributed surplus);

(b)

preferred shares other than Class A Instruments;

(c)

the accumulated provision for deferred income taxes, if any;

(d)

Institutional Indebtedness; and

(e)

Subordinated Debt.

(127)

"US Dollars", "United States Dollars" and "US$" each mean lawful money of the United States of America in same day immediately available funds or, if such funds are not available, the form of money of the United States of America that is customarily used in the settlement of international banking transactions on the day payment is due hereunder.

(128)

"Uniform Customs" means the Uniform Customs and Practice for Documentary Credits, as published by the International Chamber of Commerce and in effect from time to time.

(129)

“VINGPA” means the Vancouver Island Natural Gas Pipeline Agreement between Her Majesty the Queen in Right of the Province of British Columbia, Westcoast Energy Inc., Pacific Coast Energy Corporation, Centra Gas British Columbia Inc., Centra Gas Vancouver Island Inc., and Centra Gas Victoria Inc. dated December 14, 1995, as amended by the Novation Agreement dated March 7, 2002 between Westcoast Energy Inc., Her Majesty the Queen in Right of the Province of British Columbia, the Borrower (then called Centra Gas British Columbia Inc.), Westcoast Power Holdings Inc., CGBC Holdings Inc. and Terasen (then called BC Gas Inc.).

(130)

“Wheeling Agreement” means the agreement dated for reference July 3, 1989 (as amended by letter agreements dated June 29, 1993 and November 30, 1993) between BC Gas Inc. (now called Terasen Gas Inc.) and the Borrower (then called Pacific Coast Energy Corporation) pursuant to which Terasen Gas Inc. permits the Borrower to transport natural gas along its transmission system from Huntingdon to Coquitlam.

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1.2

Interpretation.  In addition to those matters set forth in Section 2(1) of the Provisions:

(1)

Inclusion Rules.  In this agreement, in the computation of periods of time from a specified date to a later specified date, unless otherwise expressly stated, the word "from" means "from and including" and the words "to" and "until" each mean "to but excluding".

(2)

Ibid.  Where in this agreement a notice must be given a number of days prior to a specified action, the day on which such notice is given shall be included and the day of the specified action shall be excluded.

(3)

Accounting Terms.  All accounting terms not specifically defined herein shall be construed in accordance with GAAP.

(4)

Incorporation of Schedules.  Schedules 1 to 10 annexed hereto shall, for all purposes hereof, form an integral part of this agreement.

(5)

Agreements. Reference to any agreement, instrument, Governmental Approval or other document shall include reference to such agreement, instrument, Governmental Approval or other document as the same may have been heretofore or may from time to time hereafter be amended, supplemented, replaced or restated.

(6)

Interpretation not Affected by Headings, etc.  The division of this agreement into Articles and Sections and the insertion of headings are for convenience of reference only and shall not affect the construction or interpretation hereof.

(7)

General Provisions as to Certificates and Opinions, etc.  Whenever the delivery of a certificate is a condition precedent to the taking of any action by the Administrative Agent or any Lender hereunder, the truth and accuracy of the facts and the diligent and good faith determination of the opinions stated in such certificate shall in each case be conditions precedent to the right of the Borrower to have such action taken, and any certificate executed by the Borrower shall be deemed to represent and warrant that the facts stated in such certificate are true, accurate and complete.

ARTICLE 2
THE CREDIT FACILITY

2.1

Credit Facility.

(1)

Commitment.  Subject to the terms and conditions herein set forth:

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(a)

the Credit Facility is to be made available by the Lenders to the Borrower on a revolving basis in the principal amount of up to but not exceeding C$350 million, of which the Swingline Amount will be made available by way of Swingline Advances by the Swingline Lender only;

(b)

the Credit Facility shall be available:

(i)

in Canadian Dollars by way of Prime Rate Advances, Bankers’ Acceptances or Letters of Credit; and

(ii)

in US Dollars by way of Base Rate Advances, LIBOR Advances or Letters of Credit;

(c)

each Lender shall make Accommodations available under the Credit Facility pro rata on the basis of the relevant percentage as set forth in schedule 1 annexed hereto, under “Swingline” in the case of Swingline Advances and under “Balance of Credit Facility” in the case of Advances that are not Swingline Advances;

(d)

in no event shall a Lender be obligated to make Accommodations available under the Credit Facility if after making such Accommodations the C$ Equivalent Principal Outstanding of that Lender’s Accommodations would exceed that Lender’s Commitment;

(e)

for greater certainty and notwithstanding Section 2.1(6), in no event shall the C$ Equivalent Principal Outstanding of the Swingline Lender’s Accommodations under the Credit Facility (including the entire Principal Outstanding by way of Swingline Advances) exceed the Swingline Lender’s Commitment; and

(f)

each Lender shall make Accommodations available to the Borrower through its relevant Lending Office.

(2)

Purposes.  The Credit Facility shall be used only for the following purposes:

(a)

in part to repay and cancel the Existing Facility and the Intercompany Debt; and

(b)

for general corporate purposes, including capital expenditures.

In the event that the Borrower wishes to utilize proceeds of one or more Accommodations under the Credit Facility to, or to provide funds to any

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subsidiary, Affiliate or other Person to, finance an offer to acquire (which shall include an offer to purchase securities, solicitation of an offer to sell securities, an acceptance of an offer to sell securities, whether or not the offer to sell was solicited, or any combination of the foregoing) outstanding securities of any Person (the “Target”) which constitutes a “take-over bid” pursuant to applicable corporate or securities legislation (in any case, a “Takeover Bid”) and if the Takeover Bid is, under Applicable Law, such as to require the board of directors or like body of the Target to prepare a directors circular or like document that includes either a recommendation to accept or to reject the Takeover Bid or a statement that they are unable to make or are not making a recommendation, then either:

(c)

prior to or concurrently with delivery to the Administrative Agent of any Accommodation Request, the proceeds of which are intended to be utilized as aforesaid, the Borrower shall provide to the Administrative Agent evidence satisfactory to the Administrative Agent (acting reasonably) that the board of directors or like body of the Target, or the holders of all of the securities of the Target, has or have approved, accepted, or recommended to security holders acceptance of, the Takeover Bid;

or:

(d)

the following steps shall be followed:

(i)

at least five Business Days prior to the delivery to the Administrative Agent of such Accommodation Request, the Borrower shall advise the Administrative Agent (who shall promptly advise each Lender) of the particulars of such Takeover Bid;

(ii)

within three Business Days of being so advised, each Lender shall notify the Administrative Agent of such Lender’s determination as to whether it is willing to fund under such Accommodation Request; provided that, in the event such Lender does not so notify the Administrative Agent within such three Business Day period, such Lender shall be deemed to have notified the Administrative Agent that it is not so willing to fund; and

(iii)

the Administrative Agent shall promptly notify the Borrower of each such Lender’s determination;

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and in the event that any Lender (each, a “Declining Lender”) has notified or is deemed to have notified the Administrative Agent that it is not willing to fund under such Accommodation Request, then such Declining Lender shall have no obligation to fund under such Accommodation Request, notwithstanding any other provision of this agreement to the contrary; provided, however, that each other Lender (each, a “Financing Lender”) which has advised the Administrative Agent it is willing to fund under such Accommodation Request shall have an obligation, up to the amount of its unused Commitment under the Credit Facility, to fund under such Accommodation Request, and such funding shall be provided by each Financing Lender in accordance with the ratio, determined prior to the provision of such funding, that the Commitment of such Financing Lende r bears to the aggregate the Commitments of all the Financing Lenders.

If Accommodations are provided in the manner contemplated by the foregoing paragraph and there are Declining Lenders, subsequent Accommodations under the Credit Facility shall be funded firstly by Declining Lenders having unused Commitments, and subsequent repayments under the Credit Facility shall be applied firstly to Financing Lenders, in each case until such time as the proportion that the amount of each Lender’s Principal Outstanding bears to the aggregate Principal Outstanding is equal to such proportion which would have been in effect but for the application of this Section 2.1(2).

For greater certainty, in no event shall a Declining Lender be obligated to purchase any participation in accordance with Section 12.1(2) to the extent that the shortfall in such Declining Lender’s share of outstanding Obligations under the Credit Facility is attributable to the operation of this Section 2.1(2).

(3)

Availability Period.  Subject to the terms and conditions herein set forth, Accommodations will be made available by way of multiple draws from time to time up to the Business Day immediately preceding the Maturity Date.

(4)

Minimum Amounts.  Subject to the Majority Lenders in any specific instance waiving such requirement, the following minimum amounts shall apply in respect of certain Borrowings and Drawings requested under each Accommodation Request (excluding Swingline Advances):

(a)

the aggregate of the Prime Rate Advances requested in any Borrowing shall be at least C$1 million and a whole multiple of C$500,000;

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(b)

each Bankers’ Acceptance shall be in a Face Amount of at least C$100,000 and a whole multiple thereof;

(c)

the aggregate of the Face Amount of Bankers’ Acceptances requested in any Drawing shall be at least C$5 million and a whole multiple of C$1 million;

(d)

the aggregate of the Base Rate Advances requested in any Borrowing shall be at least US$1 million and a whole multiple of US$500,000; and

(e)

the aggregate of the LIBOR Advances requested in any Borrowing shall be at least US$5 million and a whole multiple of US$1 million.

(5)

Revolving Nature.  The Credit Facility is a so-called "revolving" facility and amounts may be repaid thereunder and subsequently made the subject of a further Accommodation (subject to compliance with the terms and conditions of this agreement).

(6)

Swingline Advances.

(a)

In the event that the Borrower has a requirement for a Prime Rate Advance or a Base Rate Advance in same day funds in an amount up to the Swingline Amount (or the Equivalent Amount in US Dollars) in the aggregate, the Borrower may (subject to satisfaction of applicable terms and conditions hereof) obtain such Advance (in this Section 2.1(6), a “Swingline Advance”) from the Swingline Lender alone.

(b)

Each Swingline Advance:

(i)

may be made on the same day’s telephone request made on or before 1:00 pm (Toronto time) on such day in the case of Swingline Advances denominated in Canadian Dollars, and 12:00 noon (Toronto time) on such day in the case of Swingline Advances denominated in US Dollars, by the Borrower providing to the Swingline Lender the same information as would be contained in a Borrowing Notice (which shall be deemed to have been so provided); or

(ii)

shall be made by the Swingline Lender, without notice from or to the Borrower, in respect of any overdraft in any one or more of the Borrower’s accounts with the Swingline Lender by deposit to such account of an amount at least equal to such overdraft.

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(c)

The Borrower shall ensure that the aggregate C$ Equivalent Principal Outstanding of all Swingline Advances does not exceed the Swingline Amount at any time.

(d)

[intentionally deleted]

(e)

[intentionally deleted]

(f)

[intentionally deleted]

(g)

The Swingline Lender acknowledges that the standby and utilisation fees under Section 2.6(a) and (b) will be calculated on the basis of each Lender’s Commitment, excluding the Swingline Lender’s Commitment with respect to the Swingline Amount. Payment of such fees on the Swingline Lender’s Commitment with respect to the Swingline Amount will be made in a manner to be agreed between the Borrower and the Swingline Lender.

2.2

Amortization.  

(1)

General.  The Principal Outstanding and all other Obligations under the Credit Facility will become due and payable in full on the Maturity Date.

(2)

Foreign Exchange Fluctuations.  If at any time the C$ Equivalent Principal Outstanding under the Credit Facility shall exceed 105% of the aggregate Commitments of the Lenders or if at any time the C$ Equivalent Principal Outstanding under the Credit Facility shall have exceeded for a 30 day period 103% of the aggregate Commitments of the Lenders, in either case solely by virtue of a change in the Equivalent Amount in Cdn. Dollars of Accommodations made in US Dollars, the Borrower shall forthwith following demand therefor by the Administrative Agent pay to the Administrative Agent such amount as is required to reduce such Principal Outstanding to such aggregate Commitments; provided that, for the purposes of the calculation of Principal Outstanding and Commitments under the foregoing provisions of this Section 2.2(2), there shall be deducted from each of Principal Outstanding and Commitments the Equivalent Amount in Canadian Dollars of such Principal Outstanding in US Dollars as shall enjoy the benefit of a Hedge Instrument which protects the Borrower against increases in the value of US Dollars as against Cdn. Dollars; provided further that, in the event that following repayment of all outstanding Prime Rate Advances and Base Rate Advances there remains an excess attributable to the outstanding principal amount under LIBOR Advances or the Face Amount of outstanding Bankers’ Acceptances or Letters of Credit, such excess amount shall be paid by the Borrower to the

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Administrative Agent, and shall be held by the Administrative Agent (pending the expiry of subsisting Interest Periods, the maturity of Bankers’ Acceptances or the termination of Letters of Credit, as the case may be) in a trust account and invested in Cash Equivalents as determined by the Administrative Agent in its discretion (provided that, in making any such determination, the Administrative Agent shall consider, acting reasonably, any request of the Borrower as to the nature of such investments) and applied against the obligations of the Borrower in respect of such LIBOR Advances, Bankers’ Acceptances or Letters of Credit as they come due.

2.3

Voluntary Reductions. The Borrower shall have the right at any time and from time to time, without penalty or bonus, upon delivery of a Repayment/Cancellation Notice to the Administrative Agent on the Required Notice, to terminate the whole or reduce in part on a permanent basis the unused portion of the Commitments of the Lenders in respect of the Credit Facility (pro rata among such Lenders on the basis of their respective Commitments); provided that each partial reduction shall be in an aggregate minimum amount of C$5 million and multiples in excess thereof of C$1 million.

2.4

Payments.

(1)

Payment Account.  The Borrower shall make each payment to be made hereunder, following delivery of (where applicable) a Repayment/Cancellation Notice and on the Required Notice, not later than 2:00 p.m. (Toronto time) in the currency of the Accommodation or other Obligation in respect of which such payment is made (be it Canadian Dollars or US Dollars) on the day (subject to Section 2.4(2)) when due, in same day funds, by deposit of such funds to the Payment Account.

(2)

Business Day.  Subject to the next following sentence, whenever any payment hereunder is due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of interest or fees, as the case may be.  If any such extension would cause any payment of interest or fees on an Accommodation to be made in the next following calendar month, such payment shall be made on the last preceding Business Day.

(3)

Application.  Unless otherwise provided herein, all amounts received by the Administrative Agent on account of the Obligations shall be applied by the Administrative Agent as follows:

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(a)

first, to fulfil the Borrower’s obligation to pay accrued and unpaid interest due and owing (including interest on overdue interest and on other amounts), excluding interest accruing on BA Equivalent Loans;

(b)

second, to fulfil the Borrower’s obligation to pay any fees which are due and owing to the Lenders hereunder (including those fees set forth in Section 2.6), and any Increased Costs and other unpaid costs, expenses and other amounts payable to the Administrative Agent and the Lenders in connection with any of the Credit Facility Documents;

(c)

third, to fulfil the Borrower’s obligation to pay interest accruing on BA Equivalent Loans and any amounts due and owing on account of Principal Outstanding under the Credit Facility (including in respect of the Face Amount of outstanding Bankers’ Acceptances and Letters of Credit); and

(d)

fourth, to the Borrower or as any court of competent jurisdiction may otherwise direct.

(4)

Pro Rata Basis.  All payments of principal, interest and fees herein set forth, unless otherwise expressly stipulated, shall be made for the account of, and distributed by the Administrative Agent to, the Lenders pro rata on the basis of their respective Commitments.

(5)

Netting. If on any date liquidated amounts (other than interest and fees) would be payable under this agreement in the same currency by the Borrower to certain Lenders and by such Lenders to the Borrower, then on such date, at the election of and upon notice from the Administrative Agent stating that netting is to apply to such payments, each such party’s obligations to make payment of any such amount will be automatically satisfied and discharged and, if the aggregate amount that would otherwise have been payable by the Borrower to such Lenders exceeds the aggregate amount that would otherwise have been payable by such Lenders to the Borrower or vice versa, such obligations shall be replaced by an obligation upon the Borrower or such Lenders by whom the larger aggregate amount would have been payable to pay to the other the excess of the large r aggregate amount over the smaller aggregate amount.

(6)

Payments Free of Set-off.  Except as set forth in Section 2.4(5), each payment made by the Borrower on account of the Obligations shall be made without set-off or counterclaim.

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2.5

Computations.  

(1)

Basis.  All computations of:

(a)

interest based on the Prime Rate and the Base Rate shall be made by the Administrative Agent on the basis of a year of 365 days or, in the case of a leap year, 366 days and the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest is payable; and

(b)

interest based on LIBOR shall be made by the Administrative Agent on the basis of a year of 360 days and the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest is payable.

Computations of fees under Sections 2.6(a) and (b), 4.6 and 5.8(1) and (2) shall be made by the Administrative Agent on the basis of a year of 365 days or, in the case of a leap year and only with respect to fees under Sections 2.6(a) and (b) and 5.8(1) and (2), 366 days and the actual number of days (including the first day but excluding the last day) occurring in the period for which such fees are payable.  Each determination by the Administrative Agent of an amount of interest, Discount Proceeds or fees payable by the Borrower hereunder shall be conclusive and binding for all purposes, absent demonstrated error.

(2)

Interest Act (Canada).  For purposes of disclosure pursuant to the Interest Act (Canada), the yearly rate of interest to which any rate of interest based on LIBOR is equivalent may be determined by multiplying the applicable rate by a fraction, the numerator of which is the number of days to the same calendar date in the next calendar year (or 365 days if the calculation is made as of February 29) and the denominator of which is 360.

2.6

Fees.  The Borrower shall pay to the Administrative Agent (or, in the circumstances contemplated by Section 2.1(6)(g), the Swingline Lender) the following fees, calculated as follows:

(a)

a standby fee (for the account of the Lenders pro rata on the basis of their respective Commitments under the Credit Facility) payable by the Borrower in Cdn. Dollars quarterly in arrears on the third Business Day of the first month following the end of each Financial Quarter, and on the Maturity Date, calculated from the Closing Date on a daily basis on the difference between the aggregate C$ Equivalent Principal Outstanding (converted for purposes of such calculation into the Equivalent Amount in Cdn. Dollars as at the

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last day of such Financial Quarter) under the Credit Facility and the aggregate Commitments, at the rate set forth in the definition of Applicable Margin;

(b)

a utilisation fee (for the account of the Lenders pro rata on the basis of their respective Commitments under the Credit Facility) payable by the Borrower in Cdn. Dollars quarterly in arrears on the third Business Day of the first month following the end of each Financial Quarter, and on the Maturity Date, calculated from the Closing Date on the aggregate C$ Equivalent Principal Outstanding (converted for purposes of such calculation into the Equivalent Amount in Cdn. Dollars as at the last day of such Financial Quarter) under the Credit Facility, at the rate of 5 bps per annum; such utilisation fee shall be calculated on a daily basis but only in respect of a day where the aggregate C$ Equivalent Principal Outstanding is equal to or exceeds 50% of the aggregate Commitments under the “Balance of the Credit Facility” as set forth in schedule 1 an nexed hereto; and

(c)

the fees agreed with the Administrative Agent in an agreement of even date.

2.7

Interest on Overdue Amounts.  Except as otherwise provided in this agreement, each amount owed by the Borrower to a Lender which is not paid when due (whether at stated maturity, on demand, by acceleration or otherwise) shall bear interest (both before and after maturity, default and judgment), from the date on which such amount is due until such amount is paid in full, payable on demand, at a rate per annum equal at all times to the Base Rate (in the case of amounts denominated in US Dollars) or the Prime Rate (in the case of amounts denominated in Cdn. Dollars), in each case plus the Applicable Margin plus a further two percent (2%) per annum.

2.8

Account Debit Authorization.  The Borrower authorizes and directs each of the Administrative Agent and the Swingline Lender, in its respective discretion, to automatically debit, by mechanical, electronic or manual means, the bank accounts of the Borrower maintained with RBC (for so long as RBC is Administrative Agent hereunder) or TD Bank (for so long as TD Bank is Swingline Lender hereunder) and designated by the Borrower in writing for all amounts due and payable under this agreement on account of principal, interest and fees comprised in the Obligations.

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2.9

Administrative Agent’s Discretion on Allocation.  In the event that it is not practicable to:

(a)

allocate an Accommodation pro rata in accordance with Section 3.2 or 4.1(2) by reason of the occurrence of circumstances described in Section 3.1 or 3.2 of the Provisions; or

(b)

allocate a Drawing among the Lenders in accordance with Section 4.1(2) by reason of the need to ensure that the aggregate amount of Bankers’ Acceptances required to be accepted hereunder complies with the minimum amounts or increments set forth in Section 2.1(4);

the Administrative Agent is authorized by the Borrower and each Lender to make such allocation as the Administrative Agent determines in its sole and unfettered discretion may be equitable in the circumstances, subject in all cases to Section 2.1. All fees in respect of any such Drawing, and fees payable under Section 2.6(a), shall be adjusted, as among the Lenders, by the Administrative Agent accordingly.

2.10

Funding.  Section 6 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated.

2.11

Rollover and Conversion.  

(1)

General.  Subject to the terms and conditions of this agreement, the Borrower may from time to time request that any Drawing or type of Borrowing or any portion thereof be rolled over or converted in accordance with the provisions hereof.

(2)

Request.  Each request by the Borrower for a Rollover or Conversion shall be made by the delivery of a duly completed and executed Accommodation Request to the Administrative Agent with the Required Notice and the provisions of Articles 3 or 4 shall apply to each request for a Rollover or Conversion as if such request were a request thereunder for an Advance or a Drawing (as the case may be).

(3)

Effective Date.  Each Rollover or Conversion of a LIBOR Advance or Bankers’ Acceptance shall be made effective as of, in the case of a LIBOR Advance, the last day of the subsisting Interest Period and, in the case of a Bankers’ Acceptance, the maturity date applicable thereto.

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(4)

Failure to Elect.  If the Borrower does not deliver an Accommodation Request at or before the time required by Section 2.11(2) and:

(a)

in the case of a Bankers’ Acceptance fails to give the Required Notice that it will pay to the Administrative Agent for the account of the applicable Lender the Face Amount thereof on the maturity date or if the Borrower gives such notice but fails to act in accordance with it, the Borrower shall be deemed to have requested a Conversion of the Face Amount thereof to a Prime Rate Advance and all of the provisions hereof relating to a Prime Rate Advance shall apply thereto; or

(b)

in the case of a LIBOR Advance, fails to give the Required Notice that it will pay to the Administrative Agent for the account of the applicable Lender the principal amount thereof at the end of the relevant Interest Period or if the Borrower gives such notice but fails to act in accordance with it, the Borrower shall be deemed to have requested a Rollover of such Advance to either a LIBOR Advance having an Interest Period of one month (and all of the provisions hereof applicable to LIBOR Advances shall apply thereto) (in the case of a failure to deliver an Accommodation Request and give the Required Notice) or a Base Rate Advance (in the case of a failure to act in accordance with a notice).

(5)

Continuing Obligation.  A Rollover or Conversion shall not constitute a repayment of the relevant Accommodation or a re-borrowing by the Borrower but shall result in a change in the basis of calculation of interest, discounts or fees (as the case may be) for, and/or currency of, such Accommodation.  However, where a Conversion takes place from a US Dollar Advance to a Canadian Dollar Advance, or vice versa, the same may be effected only by the Borrower repaying the entire Principal Outstanding under the existing Advance (together with all accrued and unpaid interest thereon), in the currency of such existing Advance, and receiving the proceeds of the new Advance in the currency of such new Advance.

(6)

Limit.  Notwithstanding any other provision of this agreement, at no time shall there be more than 20 separate maturity dates, in aggregate, for all LIBOR Advances and Bankers’ Acceptances outstanding under the Credit Facility.

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ARTICLE 3
ADVANCES

3.1

Advances.  

(1)

Commitment.  Each Lender agrees (on a several basis with the other Lenders, up to the amount of such Lender’s Commitment thereunder), on the terms and conditions herein set forth, from time to time on any Business Day, to make Advances under the Credit Facility prior to the cancellation or termination thereof.

(2)

Amounts.  The aggregate principal amount of each Borrowing shall comply with Section 2.1(4).

3.2

Making the Advances (except Swingline Advances).  

(1)

Notice.  Each Borrowing shall be made on the Required Notice given not later than 1:00 p.m. (Toronto time) by the Borrower to the Administrative Agent, and the Administrative Agent shall give to each Lender prompt notice thereof and of such Lender’s rateable portion of each type of Borrowing to be made under the Borrowing.  Each such notice of a Borrowing shall be given by way of an Accommodation Request or by telephone (confirmed promptly in writing), with the same information as would be contained in an Accommodation Request, including the requested date of such Borrowing and the aggregate amount of each type of Borrowing comprising such Borrowing.

(2)

Lender Funding.  Each Lender shall, before noon (Toronto time) on the date of the requested Borrowing, deposit to the relevant Payment Account in same day funds such Lender’s rateable portion (subject to Section 2.9) of each type of Borrowing comprising such Borrowing (in Canadian Dollars, in the case of Prime Rate Advances, and in US Dollars, in the case of LIBOR Advances and Base Rate Advances).  Promptly upon receipt by the Administrative Agent of such funds and upon fulfilment of the applicable conditions set forth in Article 6, the Administrative Agent will make such funds available to the Borrower by debiting such account (or causing such account to be debited), and by crediting such account of the Borrower as shall be agreed with the Administrative Agent (or causing such account to be credited) with such Advances.

3.3

Interest on Advances.  The Borrower shall pay interest on the unpaid principal amount of each Advance at the following rates per annum:

(1)

Prime Rate Advances.  If and so long as such Advance is a Prime Rate Advance, at a rate per annum equal at all times to the sum of the Prime

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Rate in effect from time to time plus the Applicable Margin, calculated on the daily principal amount outstanding under such Prime Rate Advance and payable in Cdn. Dollars in arrears:

(a)

monthly on the third Business Day of each month with respect to the previous calendar month (calculated as at the last day of such previous calendar month); and

(b)

when such Prime Rate Advance becomes due and payable in full.

(2)

Base Rate Advances.  If and so long as such Advance is a Base Rate Advance, at a rate per annum equal at all times to the sum of the Base Rate in effect from time to time plus the Applicable Margin, calculated on the daily principal amount outstanding under such Base Rate Advance and payable in US Dollars in arrears:

(a)

monthly on the third Business Day of each month with respect to the previous calendar month (calculated as at the last day of such previous calendar month); and

(b)

when such Base Rate Advance becomes due and payable in full.

(3)

LIBOR Advances.  If and so long as such Advance is a LIBOR Advance, at a rate per annum equal at all times during each Interest Period for such LIBOR Advance to the sum of LIBOR for such Interest Period plus the Applicable Margin, calculated on the daily principal amount outstanding under such LIBOR Advance and payable (as the case may be) in US Dollars:

(a)

at the end of each Interest Period (except where such Interest Period exceeds three months in duration, in which case such interest shall be payable on the dates falling every three months following the commencement of the Interest Period and, finally, at the end of such Interest Period); and

(b)

when such LIBOR Advance becomes due and payable in full or is converted to a Base Rate Advance.

ARTICLE 4
BANKERS’ ACCEPTANCES

4.1

Acceptances.  

(1)

Commitment.  Subject to Section 4.11, each Lender agrees (on a several basis with the other Lenders, up to the amount of such Lender’s

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Commitment), on the terms and conditions herein set forth, from time to time on any Business Day, to accept and purchase Bankers’ Acceptances under the Credit Facility prior to the cancellation or termination thereof.

(2)

Amounts.  Each Drawing shall be in an aggregate Face Amount not less than the minimum amount (or requisite multiple in excess thereof) set forth in Section 2.1(4) and shall consist of the creation by the Borrower of Bankers’ Acceptances on the same day, effected or arranged by the Lenders in accordance with Section 4.4, rateably according to their respective Commitments (subject to Section 2.9).

4.2

Drawdown Request.  

(1)

Notice.  Each Drawing shall be made on the Required Notice given not later than 1:00 p.m. (Toronto time) by the Borrower to the Administrative Agent and the Administrative Agent shall give to each Lender prompt notice thereof (including the marketing Option as set forth in Section 4.5) and of such Lender’s rateable portion thereof.  Each such notice of a Drawing shall be given by way of an Accommodation Request or by telephone (confirmed promptly in writing) with the same information as would be contained in an Accommodation Request, including the requested Drawing Date, the Face Amounts of the Drawing and the  marketing Option as set forth in Section 4.5.

(2)

Maturity.  The Borrower shall not request in an Accommodation Request a term for Bankers’ Acceptances under the Credit Facility which would end on a date subsequent to the Maturity Date or that would conflict with any repayment stipulated herein.

4.3

Form of Bankers’ Acceptances.  

(1)

Form.  Each Bankers’ Acceptance shall:

(a)

be in a Face Amount allowing for conformance with Section 2.1(4);

(b)

be dated the Drawing Date;

(c)

mature and be payable by the Borrower (in common with all other Bankers’ Acceptances created in connection with such Drawing) on a Business Day which occurs one, two, three or six months after the date thereof, subject to availability; and

(d)

be in a form satisfactory to the relevant Lender.

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(2)

Grace.  Each Borrower hereby waives presentment for payment and any other defence to payment of any amounts due in respect of any Bankers’ Acceptance, and hereby renounces, and shall not claim, any days of grace for the payment of any Bankers’ Acceptance.

4.4

Completion of Bankers’ Acceptance.  Upon receipt of the notice from the Administrative Agent pursuant to Section 4.2(1), each Lender is thereupon authorized to execute Bankers’ Acceptances as the duly authorized attorney of the Borrower pursuant to Section 4.8, in accordance with the particulars provided by the Administrative Agent.

4.5

Bankers’ Acceptance Marketing.  In each Accommodation Request for a Drawing, the Borrower shall elect one of the marketing options (in this Article 4, each an "Option") described in this Section 4.5. The Borrower may elect to market Bankers' Acceptances as follows:

(1)

Option #1

(a)

On the relevant Drawing Date, the Borrower shall obtain quotations regarding the sale of the Bankers' Acceptances to be accepted by the Lenders and shall accept such of the offers as it deems appropriate, but in any event shall accept offers equal to the full amount of the Bankers’ Acceptances to be accepted by the Lenders in respect of the Drawing.

(b)

The Borrower shall provide the Administrative Agent with details regarding the sale of the Bankers' Acceptances described in (1)(a) above whereupon the Administrative Agent shall promptly notify the Lenders of:

(i)

the identity of the purchasers of such Bankers' Acceptances;

(ii)

the amounts being purchased by such purchasers;

(iii)

the discount rate transacted by the Borrower and such purchasers;

(iv)

the net cash proceeds realized from the purchase and sale of such Bankers' Acceptances; and

(v)

the stamping fees applicable to such Drawing as set forth in Section 4.6;

(including each Lenders' share thereof).

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(2)

Option #2

(a)

On the relevant Drawing Date, the Borrower shall obtain quotations regarding the sale of the Bankers' Acceptances to be accepted by Lenders that are Schedule I Banks and shall accept such of the offers in respect of such Lenders' Bankers' Acceptances as it deems appropriate, but in any event shall accept offers equal to the full amount of the Bankers' Acceptances to be accepted by such Lenders in respect of the Drawing. The provisions of (1)(b) above (Option #1) shall apply in such circumstances, mutatis mutandis.

(b)

Each Lender that is not a Schedule I Bank shall purchase all Bankers' Acceptances accepted by it on the relevant Drawing Date at the Discount Rate.

(3)

Option #3

Each Lender shall purchase all Bankers' Acceptances accepted by it on the relevant Drawing Date at the Discount Rate.

Each Lender shall, for same day value on the Drawing Date specified by the Borrower in the applicable Accommodation Request, credit the relevant Payment Account (for the account of the Borrower) with (as applicable):

(x)

the applicable Discount Proceeds of the Bankers’ Acceptances purchased by that Lender; and

(y)

the net cash proceeds realized from the purchase of such Bankers' Acceptances by a Person that is not a Lender;

in each case less the stamping fee set forth in Section 4.6. Promptly upon receipt by the Administrative Agent of such funds and upon fulfilment of the applicable conditions set forth in Article 6, the Administrative Agent will make such funds available to the Borrower by debiting such account (or causing such account to be debited), and by crediting such account as shall be agreed with the Borrower (or causing such account to be credited) with such Discount Proceeds and net cash proceeds less such stamping fee.

Each Lender may at any time and from time to time purchase, hold, sell, rediscount or otherwise dispose of any Bankers’ Acceptance and no such dealing shall prejudice or impair the Borrower’s obligations under Section 4.7.

4.6

Stamping Fee.  The Borrower shall pay to the Administrative Agent in respect of each Drawing (for the account of the Lenders, pro rata on the basis of their

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respective Commitments, subject to Section 2.9) a stamping fee in Cdn. Dollars.  Such stamping fee shall be payable by the Borrower in full on the Drawing Date, and shall be calculated on the Face Amount of such Bankers’ Acceptances on the basis of the number of days in the term of such Bankers’ Acceptances (including the Drawing Date but excluding the maturity date) at a rate per annum equal to the applicable percentage set forth under "Bankers’ Acceptances" in the definition of Applicable Margin.

4.7

Payment at Maturity.  The Borrower shall pay to the Administrative Agent, and there shall become due and payable, on the maturity date for each Bankers’ Acceptance an amount in same day funds equal to the Face Amount of the Bankers’ Acceptance.  The Borrower shall make each payment hereunder in respect of Bankers’ Acceptances by deposit of the required funds to the relevant Payment Account.  Upon receipt of such payment, the Administrative Agent will promptly thereafter cause such payment to be distributed to the Lenders rateably (based on the proportion that the Face Amount of Bankers’ Acceptances accepted by a Lender maturing on the relevant date bears to the Face Amount of Bankers’ Acceptances accepted by all the Lenders maturing on such date).  Such payment to the Administrative Agent shall satisfy the Borro wer’s obligations under a Bankers’ Acceptance to which it relates and the accepting institution shall thereafter be solely responsible for the payment of such Bankers’ Acceptance.

4.8

Power of Attorney Respecting Bankers’ Acceptances.  In order to facilitate issues of Bankers’ Acceptances pursuant to this agreement, the Borrower authorizes each Lender, and for this purpose appoints each Lender its lawful attorney (with full power of substitution), to complete, sign and endorse drafts issued in accordance with Section 4.4 on its behalf in handwritten or by facsimile or mechanical signature or otherwise and, once so completed, signed and endorsed, and following acceptance of them as Bankers’ Acceptance under this agreement, then purchase, discount or negotiate such Bankers’ Acceptances in accordance with the provisions of this Article 4. Drafts so completed, signed, endorsed and negotiated on behalf of the Borrower by any Lender shall bind the Borrower as fully and effectively as if so performed by an authorized o fficer of the Borrower.

4.9

Prepayments.  Except as required by Section 4.10, no payment of the Face Amount of a Bankers’ Acceptance shall be made by the Borrower to a Lender prior to the maturity date thereof. Any such required payment made before the applicable maturity date shall be held by the Administrative Agent in a cash collateral account and invested in Cash Equivalents as security to provide for or to secure payment of the Face Amount of such outstanding Bankers’ Acceptance upon maturity.  Any such required payment made before the applicable maturity date by the Borrower to the Administrative Agent, to the extent of the amount thereof, shall satisfy the Borrower’s obligations under the Bankers’ Acceptance to

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which it relates as to a like amount.  The accepting institution shall thereafter be solely responsible for the payment of the Bankers’ Acceptance and shall indemnify and hold the Borrower harmless against any liabilities, costs or expenses incurred by the Borrower as a result of any failure by such Lender to pay the Bankers’ Acceptance as to such like amount in accordance with its terms.

4.10

Default.  Upon the occurrence of an Event of Default and the Administrative Agent declaring the Obligations to be due and payable pursuant to Section 10.2, and notwithstanding the date of maturity of any outstanding Bankers’ Acceptances, an amount equal to the Face Amount of all outstanding Bankers’ Acceptances which the Lenders are required to honour shall thereupon forthwith become due and payable by the Borrower to the Administrative Agent.

4.11

Non-Acceptance Lenders.  The parties acknowledge that a Lender (a "Non-Acceptance Lender") may not be permitted by Applicable Law to, or may not by virtue of customary market practices, stamp or accept commercial drafts. A Non-Acceptance Lender shall, in lieu of accepting and purchasing Bankers’ Acceptances, make a BA Equivalent Loan.  The amount of each BA Equivalent Loan shall be equal to the Discount Proceeds which would be realized from a hypothetical sale of those Bankers’ Acceptances which that Non-Acceptance Lender would otherwise be required to accept and purchase as part of such Drawing.  To determine the amount of those Discount Proceeds, the hypothetical sale shall be deemed to take place at the Non-Acceptance Discount Rate for that BA Equivalent Loan.  Any BA Equivalent Loan shall be made on the re levant Drawing Date, and shall remain outstanding for the term of the relevant Bankers’ Acceptances.  For greater certainty, concurrently with the making of a BA Equivalent Loan, a Non-Acceptance Lender shall be entitled to deduct therefrom an amount equal to the stamping fee which that Lender would otherwise be entitled to receive pursuant to Section 4.6 as part of that BA Equivalent Loan if that BA Equivalent Loan was a Bankers’ Acceptance, based on the amount of principal and interest payable on the maturity date of that BA Equivalent Loan.  On the maturity date for the Bankers’ Acceptances required by the Borrower, the Borrower shall pay to each Non-Acceptance Lender the amount of such Lender’s BA Equivalent Loan plus interest on the principal amount of that BA Equivalent Loan calculated at the applicable Non-Acceptance Discount Rate (in effect the date such BA Equivalent Loan was made) from the date of acceptance to but excluding the maturity date of that BA Equivalent Loan .

ARTICLE 5
LETTERS OF CREDIT

5.1

Letters of Credit Commitment.  Each Lender agrees (on a several basis with the other Lenders up to the amount of such Lender’s Commitment), on the terms and conditions herein set forth, from time to time on any Business Day, to issue

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Letters of Credit under the Credit Facility, for the account of the Borrower prior to the cancellation or termination thereof; provided that at no time shall the C$ Equivalent Principal Outstanding with respect to the Face Amount of outstanding Letters of Credit exceed collectively C$40 million.

Letters of Credit shall be issued by way of, as selected by the Borrower, either:

(a)

a Letter of Credit (in this Article 5, a “Fronted Letter of Credit”) issued by the Issuing Bank on behalf of the Lenders on a “fronting” basis as contemplated by Section 5.2; or

(b)

a Letter of Credit issued by the Administrative Agent in accordance with Section 5.3 (in this Article 5, a “POA Letter of Credit”).

Whenever the term “LC issuer” is used in this Article 5, such term shall refer to, as applicable, either the Issuing Bank with respect to a Fronted Letter of Credit or the Administrative Agent with respect to a POA Letter of Credit.

5.2

Fronted Letters of Credit.  In the event that a Fronted Letter of Credit shall be issued on behalf of the Lenders by the Issuing Bank:

(a)

the Principal Outstanding in respect of such Letter of Credit shall be considered to be allocated among the Lenders pro rata on the basis of their respective Commitments, and on the basis that each such Lender is liable to, and by entering into this agreement agrees to, indemnify and hold harmless the Issuing Bank in relation to the Issuing Bank’s liability as issuer of such Letter of Credit to the extent of the amount of such pro rata share of such liability;

(b)

for greater certainty and without limiting the generality of Section 12.1, the Principal Outstanding among the Lenders shall be adjusted in the circumstances and in the manner contemplated by Section 12.1 in order to reflect the Issuance by the Issuing Bank on behalf of such Lenders.

5.3

POA Letters of Credit.  The provisions of this Section 5.3 shall apply to POA Letters of Credit.

(1)

Issuance on behalf of Lenders.  Each POA Letter of Credit shall be issued by the Administrative Agent on behalf of all Lenders as a single multi-Lender Letter of Credit, but the obligation of each Lender thereunder shall be several, and not joint, based upon its pro rata share (on the basis of its Commitment) in effect on the date of issuance of such POA Letter of Credit, subject to any changes resulting from a change in such pro rata share after the date of issuance of the POA Letter of Credit that are

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effected in accordance with the terms of the POA Letter of Credit.  Each POA Letter of Credit shall include the provisions contained in, and shall be substantially in the form of, Schedule 9 annexed hereto, and shall otherwise be in a form satisfactory to the Administrative Agent.  Without the unanimous consent of the Lenders, no POA Letter of Credit shall be issued which varies the several and not joint nature of the liability of each Lender thereunder.

(2)

Administrative Agent as Agent and Attorney.  Each POA Letter of Credit shall be executed and delivered by the Administrative Agent in the name and on behalf of, and as attorney-in-fact for, each Lender party to such Letter of Credit.  The Administrative Agent shall act under each POA Letter of Credit as the agent of each Lender to:

(a)

receive documents presented by the Beneficiary under such POA Letter of Credit;

(b)

determine whether such documents are in compliance with the terms and conditions of such POA Letter of Credit; and

(c)

notify such Lender and the Borrower that a valid drawing has been made and the date that the related payment under such POA Letter of Credit is to be made; provided that the Administrative Agent (in such capacity) shall have no obligation or liability for any payment to be made under any POA Letter of Credit and each POA Letter of Credit shall expressly so provide.

(3)

Power of Attorney.  Each Lender hereby appoints and designates the Administrative Agent as its attorney-in-fact, acting through any duly authorized officer of the Administrative Agent, to execute and deliver each POA Letter of Credit to be issued by such Lender hereunder in the name and on behalf of such Lender.  Each Lender shall furnish to the Agent a power of attorney in the form of Schedule 10 annexed hereto, which may be presented as evidence of the Administrative Agent’s power to act but which shall not, as between the Lender and the Administrative Agent, vary the power of the Administrative Agent as established in this agreement.  In addition, promptly upon the request of the Administrative Agent, each Lender will furnish to the Administrative Agent such other evidence as any Beneficiary of any POA Letter of Credit may reaso nably request in order to demonstrate that the Administrative Agent has the power to act as attorney-in-fact for such Lender to execute and deliver such POA Letter of Credit.  The Borrower and the Lenders agree that each POA Letter of Credit shall provide that all documents presented thereunder shall be delivered to the Administrative Agent and that all

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payments thereunder shall be made by the Lenders obligated thereon through the Administrative Agent.  Each Lender shall be severally liable under each POA Letter of Credit in proportion to its pro rata share (on the basis of its Commitment) on the date of issuance of such POA Letter of Credit and each POA Letter of Credit shall specify each Lender’s share of the amount payable thereunder.

(4)

Documents and Payment Demands.  The Borrower and each Lender hereby authorize the Administrative Agent to review on behalf of each Lender each document presented under each POA Letter of Credit.  The determination of the Administrative Agent as to the conformity of any documents presented under a POA Letter of Credit to the requirements of such POA Letter of Credit shall be conclusive and binding on the Borrower and each Lender; provided that the Administrative Agent acts in accordance with the standards of reasonable care specified in the Uniform Customs.  The Administrative Agent shall, within a reasonable time following its receipt thereof, examine all documents purporting to represent a demand for payment under any POA Letter of Credit.  The Administrative Agent shall promptly after such examination:

(a)

notify each of the Lenders obligated under such POA Letter of Credit and the Borrower by telephone (confirmed in writing) of such demand for payment and of each Lender’s share of such payment;

(b)

deliver to each Lender and the Borrower a copy of each document purporting to represent a demand for payment under such POA Letter of Credit; and

(c)

notify each Lender and the Borrower whether the demand for payment was properly made under such POA Letter of Credit.

(5)

Drawings.  With respect to any drawing determined by the Administrative Agent to have been properly made under a POA Letter of Credit, each Lender will  make a payment under the POA Letter of Credit in accordance with its liability under the POA Letter of Credit and this agreement.  The payment shall be made to the Payment Account or such other account as the Administrative Agent designates by notice to the Lenders.  The Administrative Agent will promptly make any such payment available to the Beneficiary of such POA Letter of Credit.  Promptly following any payment by any Lender in respect of any POA Letter of Credit, the Administrative Agent will notify the Borrower of such payment, but any failure to give or delay in giving such notice shall not relieve the Borrower of its obligation to reimburse the Lenders with

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respect to any such payment.  The responsibility of the Administrative Agent and the Lenders in connection with any document presented for payment under any POA Letter of Credit shall, in addition to any payment obligation expressly provided in such POA Letter of Credit, be limited to determining that the documents delivered under such Letter of Credit in connection with such presentment are in conformity with such POA Letter of Credit.  The Administrative Agent shall not be required to make any payment under a POA Letter of Credit in excess of the amount received by it from the Lenders for such payment.

(6)

Reimbursement by Borrower.  The Borrower shall pay to the Administrative Agent (for the account of the Lenders) the amount paid to a Beneficiary upon a drawing under a POA Letter of Credit (in this Section 5.3(6), the “drawn amount”) on the date of such drawing.  The Administrative Agent, on behalf of the Lenders, shall be entitled to receive interest on the drawn amount at the rate applicable to Prime Rate Advances (if the drawn amount was in Canadian Dollars) or the rate applicable to Base Rate Advances (if the drawn amount was in US Dollars) for the period from and including the date the drawn amount was paid to a Beneficiary pursuant to the drawing to but excluding the date on which such payment (including interest) is made to Administrative Agent.

(7)

Notice regarding Potential Automatic Renewal.  Without limiting the other provisions of this agreement, if a Default or an Event of Default has then occurred and is continuing, the Administrative Agent shall notify the Lenders 30 days before any applicable deadline for notifying the Beneficiary of a POA Letter of Credit that it will not be renewed, in order to avoid automatic renewal in accordance with the terms of the POA Letter of Credit.

5.4

Notice of Issuance.

(1)

Notice.  Each Issuance shall be made on the Required Notice, given in the form of an Accommodation Request not later than 1:00 p.m. (Toronto time) by the Borrower to the Administrative Agent.  The Administrative Agent shall give prompt notice to the Lenders of their rateable share of such Issuance.

(2)

Other Documents. In addition, the Borrower shall execute and deliver the LC Issuer’s customary form of letter of credit indemnity agreement; provided that, if there is any inconsistency between the terms of this agreement and the terms of such customary form of indemnity agreement, the terms of this agreement shall prevail.

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5.5

Form of Letter of Credit.  Each Letter of Credit to be issued hereunder shall:

(a)

be dated the Issue Date;

(b)

have an expiration date on a Business Day which occurs no more than 365 days after the Issue Date (provided that Letters of Credit may have a term in excess of 365 Days if the LC Issuer shall agree); and

(c)

comply with the definition of Letter of Credit and shall otherwise be satisfactory in form and substance to the LC Issuer.

Except to the extent otherwise expressly provided herein or in another Credit Facility Document, the Uniform Customs or, as the case may be, ISP98 shall apply to and govern each Letter of Credit.

5.6

Procedure for Issuance of Letters of Credit.  

(1)

Issue.  On the Issue Date, the LC Issuer will complete and issue one or more Letters of Credit in favour of the Beneficiary as specified by the Borrower in its Accommodation Request.

(2)

Time for Honour.  No Letter of Credit shall require payment against a conforming draft to be made thereunder on the same Business Day upon which such draft is presented, if such presentation is made after 11:00 a.m. (Toronto time) on such Business Day.

(3)

Text.  Prior to the Issue Date, the Borrower shall specify a precise description of the documents and the verbatim text of any certificate to be presented by the Beneficiary prior to payment under the Letter of Credit.  The LC Issuer may require changes in any such documents or certificate, acting reasonably.

(4)

Conformity.  In determining whether to pay under a Letter of Credit, the  LC Issuer shall be responsible only to determine that the documents and certificates required to be delivered under such Letter of Credit have been delivered and that they comply on their face with the requirements of such Letter of Credit.

5.7

Payment of Amounts Drawn Under Letters of Credit.  In the event of any request for a drawing under any Letter of Credit, the LC Issuer may notify the Borrower (with a copy of the notice to the Administrative Agent) on or before the date on which it intends to honour such drawing.  The Borrower (whether or not such notice is given) shall reimburse the LC Issuer on demand by the LC Issuer,

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in the relevant currency, an amount, in same day funds, equal to the amount of such drawing.

Unless the Borrower notifies the LC Issuer and the Administrative Agent, prior to 1:00 p.m. (Toronto time) on the second Business Day following receipt by the Borrower of the notice from the LC Issuer referred to in the preceding paragraph, that the Borrower intends to reimburse the LC Issuer for the amount of such drawing with funds other than the proceeds of Advances:

(a)

the Borrower shall be deemed to have given an Accommodation Request to the Administrative Agent requesting the relevant Lenders to make a Prime Rate Advance on the third Business Day following the date on which such notice is provided by the LC Issuer to the Borrower in an amount equal to the amount of such drawing; and

(b)

subject to the terms and conditions of this agreement (including those set forth in Article 6), the Lenders shall, on the next Business Day following the date of such drawing, make such Advance in accordance with Article 3 and the Administrative Agent shall apply the proceeds thereof to the reimbursement of the LC Issuer for the amount of such drawing.

5.8

Fees.  

(1)

Issue Fee. The Borrower shall on the fifth Business Day following the end of each Financial Quarter and on the termination of each Letter of Credit pay to the Administrative Agent in relation to each such Letter of Credit for the account of the Lenders a fee in respect of each Letter of Credit outstanding during any portion of such Financial Quarter equal to that specified under "Issuance fee" in the definition of "Applicable Margin" multiplied by an amount equal to the undrawn portion of the Face Amount of each such Letter of Credit, such fee to be payable in the currency of issue and determined for a period equal to the number of days during such Financial Quarter that each such Letter of Credit was outstanding.

(2)

Fronting Fee.  In addition, the Borrower shall on the fifth Business Day following the end of each Financial Quarter and on the Maturity Date pay to the Administrative Agent for the account of the Issuing Bank a fronting fee in respect of each Fronted Letter of Credit issued by the Issuing Bank and outstanding during any portion of such Financial Quarter equal to 15 basis points per annum multiplied by an amount equal to the undrawn portion of the Face Amount of each such Fronted Letter of Credit, such fee

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to be determined for a period equal to the number of days during such Financial Quarter that each such Fronted Letter of Credit was outstanding.

(3)

Administrative Fee. The Borrower shall pay to the LC Issuer, upon the issuance, amendment or transfer of each Letter of Credit, the LC Issuer’s standard documentary and administrative charges for issuing, amending or transferring standby or commercial letters of credit or letters of guarantee of a similar amount, term and risk.

5.9

Obligations Absolute.  The obligation of the Borrower to reimburse the LC Issuer for drawings made under any Letter of Credit shall be unconditional and irrevocable and shall be fulfilled strictly in accordance with the terms of this agreement under all circumstances, including:

(a)

any lack of validity or enforceability of any Letter of Credit;

(b)

the existence of any claim, set-off, defence or other right which the Borrower may have at any time against a Beneficiary or any transferee of any Letter of Credit (or any Persons for whom any such transferee may be acting), the LC Issuer, any Lender or any other Person, whether in connection with this agreement, the Credit Facility Documents, the Terasen Funding Agreement, the transactions contemplated herein and therein or any unrelated transaction (including any underlying transaction between the Borrower or an Affiliate and the Beneficiary of such Letter of Credit);

(c)

any draft, demand, certificate or other document presented under any Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect;

(d)

payment by the LC Issuer under any Letter of Credit against presentation of a demand, draft or certificate or other document which does not comply with the terms of such Letter of Credit (provided that such payment does not breach the standards of reasonable care specified in the Uniform Customs or disentitle the LC Issuer to reimbursement under ISP98, in each case as stated on its face to be applicable to the respective Letter of Credit); or

(e)

the fact that a Default or an Event of Default shall have occurred and be continuing.

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5.10

Indemnification; Nature of Lenders’ Duties.  

(1)

Indemnity.  In addition to amounts payable as elsewhere provided in this Article 5, the Borrower hereby agrees to protect, indemnify, pay and save each Lender and their respective directors, officers, employees, agents and representatives harmless from and against any and all claims, demands, liabilities, damages, losses, costs, charges and expenses (including legal fees and expenses) which the indemnitee may incur or be subject to as a consequence, direct or indirect, of:

(a)

the issuance of any Letter of Credit, other than as a result of the breach of the standards of reasonable care specified in the Uniform Customs or where the LC Issuer would not be entitled to the foregoing indemnification under ISP98, in each case as stated on its face to be applicable to such Letter of Credit; or

(b)

the failure of the indemnitee to honour a drawing under any Letter of Credit as a result of any act or omission, whether rightful or wrongful, of any present or future de jure or de facto Official Body (all such acts or omissions called in this Section 5.10, "Government Acts").

(2)

Risk.  As between the Borrower, on the one hand, and the Lenders, on the other hand, the Borrower assumes all risks of the acts and omissions of, or misuse of the Letters of Credit issued hereunder by, the respective Beneficiaries of such Letters of Credit and, without limitation of the foregoing, neither the LC Issuer nor any Lender shall be responsible for:

(a)

the form, validity, accuracy, genuineness or legal effect of any document submitted by any party in connection with the application for and issuance of such Letters of Credit, even if it should in fact prove to be in any or all respects invalid, inaccurate, fraudulent or forged;

(b)

the invalidity or insufficiency of any instrument transferring or assigning or purporting to transfer or assign any such Letter of Credit or the rights or benefits thereunder or proceeds thereof, in whole or in part, which may prove to be invalid or ineffective for any reason;

(c)

errors, omissions, interruptions or delays in transmission or delivery of any messages, by fax, electronic transmission, mail, cable, telegraph, telex or otherwise, whether or not they are in cipher;

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(d)

errors in interpretation of technical terms;

(e)

any loss or delay in the transmission or otherwise of any document required in order to make a drawing under any such Letter of Credit or of the proceeds thereof;

(f)

the misapplication by the Beneficiary of any such Letter of Credit of the proceeds of any drawing under such Letter of Credit; and

(g)

any consequences arising from causes beyond the control of any Lender, including any Government Acts.

None of the above shall affect, impair or prevent the vesting of any of the Lenders’ rights or powers hereunder.  No action taken or omitted by any Lender under or in connection with any Letter of Credit issued by it or the related certificates, if taken or omitted in good faith, shall put any Lender under any resulting liability to the Borrower (provided that the LC Issuer acts in accordance with the standards of reasonable care specified in the Uniform Customs and otherwise as may be required under ISP98, in each case as stated on its face to be applicable to the respective Letter of Credit).

5.11

Default, Maturity, etc.  Upon the earlier of the Maturity Date and the Administrative Agent declaring the Obligations to be due and payable pursuant to Section 10.2, and notwithstanding the expiration date of any outstanding Letters of Credit, an amount equal to the Face Amount of all outstanding Letters of Credit, and all accrued and unpaid fees owing by the Borrower in respect of the Issuance of such Letters of Credit pursuant to Section 5.8, if any, shall thereupon forthwith become due and payable by the Borrower to the Administrative Agent and, except for any amount payable in respect of unpaid fees as aforesaid, such amount shall be held in a trust account by the Administrative Agent and invested in Cash Equivalents and applied against amounts payable under such Letters of Credit in respect of any drawing thereunder.

The Borrower shall pay to the Administrative Agent the aforesaid amount in respect of both any Letter of Credit outstanding hereunder and any Letter of Credit which is the subject matter of any order, judgment, injunction or other such determination (in this Section 5.11, a "Judicial Order") restricting payment by the LC Issuer under and in accordance with such Letter of Credit or extending the LC Issuer’s liability under such Letter of Credit beyond the expiration date stated therein.  Payment in respect of each such Letter of Credit shall be due in the currency in which such Letter of Credit is stated to be payable.

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Subject to Section 2.4(5), the Administrative Agent shall with respect to each such Letter of Credit, upon the later of:

(a)

the date on which any final and non-appealable order, judgment or other such determination has been rendered or issued either terminating the applicable Judicial Order or permanently enjoining the LC Issuer from paying under such Letter of Credit; and

(b)

the earlier of:

(i)

the date on which either the original counterpart of the Letter of Credit is delivered to the Administrative Agent for cancellation or the LC Issuer is released by the Beneficiary from any further obligations in respect thereof; and

(ii)

the expiry (to the extent permitted by any Applicable Law) of such Letter of Credit;

pay to the Borrower an amount equal to the difference between the amount paid to the Administrative Agent by the Borrower pursuant to this Section 5.11 and the aggregate amount paid by the LC Issuer under such Letter of Credit.

ARTICLE 6
CLOSING CONDITIONS

6.1

Closing Conditions to Initial Availability.  The Borrower shall not be entitled to an Accommodation under the Credit Facility unless the conditions precedent set forth in this Section 6.1 have been satisfied, fulfilled or otherwise met to the satisfaction of the Lenders on the Closing Date.

(1)

Documents.  The Credit Facility Documents (other than Bankers’ Acceptances and Letters of Credit yet to be issued) and the Terasen Funding Agreement shall have been executed and delivered to the Administrative Agent.

(2)

Constating Documents.  The Administrative Agent shall have received certified copies of the constating documents of the Borrower.

(3)

Resolutions.  The Administrative Agent shall have received certified copies of resolutions of the board of directors (or, where applicable, executive, audit or other relevant committee thereof) of the Borrower authorizing the execution and delivery of each Credit Facility Document to which it is a party and the Terasen Funding Agreement, and of the board of directors of Terasen authorizing the execution and delivery of the Terasen Funding Agreement.

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(4)

Incumbency.  The Administrative Agent shall have received a certificate of the secretary or an assistant secretary of the Borrower certifying the names and the true signatures of the officers authorized to sign the Credit Facility Documents to which it is a party and the Terasen Funding Agreement.  The Administrative Agent shall have received a certificate of the secretary or an assistant secretary of Terasen certifying the names and the true signatures of the officers authorized to sign the Terasen Funding Agreement.

(5)

Good Standing.  The Administrative Agent shall have received a certificate of good standing in respect of the Borrower from the British Columbia Registrar of Companies.

(6)

Representations and Warranties.  All of the representations and warranties of the Borrower contained herein or in any other Credit Facility Document, or of Terasen in the Terasen Funding Agreement, shall be true and correct in all material respects on and as of the Closing Date as though made on and as of such date and the Administrative Agent shall have received a certificate of a Senior Officer or of an officer of Terasen, respectively, so certifying to the Lenders.

(7)

No Default.  No Default or Event of Default shall have occurred and be continuing, and the Administrative Agent shall have received a certificate of a Senior Officer so certifying to the Lenders.

(8)

Financial Statements.  The Administrative Agent shall have received the most recent annual audited financial statements of the Borrower, together with a Compliance Certificate as at September 30, 2005 confirming compliance with Section 8.3 on a pro forma basis consistent with the definition of Interest Expense.

(9)

Material Agreements.  The Administrative Agent shall have received copies of the Material Agreements, certified to be true and complete by a Senior Officer.

(10)

Fees.  The Administrative Agent and the Lenders shall have received payment of all fees and all reimbursable expenses then due.

(11)

Ratings.  The Administrative Agent shall have received confirmation of the Rating or Ratings issued as of the Closing Date (and the relevant rating report).

(12)

Opinions.  The Administrative Agent shall have received an opinion of counsel to the Borrower and Terasen substantially in the form of schedule 7 annexed hereto and shall have received the favourable opinion of

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Lenders’ Counsel in form and substance satisfactory to the Administrative Agent with respect to the matters covered by the aforementioned opinion and such other matters as the Administrative Agent shall reasonably request.

(13)

Existing Facilities.  All commitments under the Existing Credit Facility shall have been terminated or shall concurrently be terminated.

(14)

Security. All Liens other than Permitted Liens shall have been discharged or, in the case of Liens securing obligations under the Existing Facility, satisfactory arrangements for the discharge of such Liens following repayment of the Existing Facility shall have been made.

(15)

Other.  The Administrative Agent shall have received such supporting and other certificates and documentation as the Lenders may reasonably request.

6.2

General Conditions for Accommodations.  The Borrower shall not be entitled to any Accommodations (other than by Conversion or Rollover) after the Closing Date unless and until the conditions precedent set forth in this Section 6.2 have been satisfied, fulfilled or otherwise met to the satisfaction of the Lenders.

(1)

Documents.  The Credit Facility Documents (other than Bankers’ Acceptances and Letters of Credit yet to be issued) and the Terasen Funding Agreement shall have been executed and delivered to the Administrative Agent.

(2)

Representations and Warranties.  All of the representations and warranties contained herein or in any other Credit Facility Document shall be true and correct in all material respects on and as of such date as though made on and as of such date (unless expressly stated to be made as of the Closing Date or some other specified date) and (except in the case of Swingline Advances) a Senior Financial Officer shall so certify to the Lenders in the applicable Accommodation Request.

(3)

No Default.  No Default or Event of Default shall have occurred and be continuing and (except in the case of Swingline Advances) the Administrative Agent shall have received a certificate of a Senior Financial Officer so certifying to the Lenders.

(4)

Fees.  The Administrative Agent and the Lenders shall have received payment of all fees and all reimbursable expenses then due.

(5)

Other.  The Lenders shall have received such supporting and other certificates and documentation as the Lenders may reasonably request.

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6.3

Conversions and Rollovers.  The obligation of the Lenders to make any Accommodation by Conversion or Rollover under the Credit Facility shall be subject to the condition precedent that no Default or Event of Default shall have occurred and be continuing, and (except in the case of Swingline Advances) a Senior Financial Officer shall so certify to the Lenders in the applicable Accommodation Request.

6.4

Deemed Representation.  Each of the giving of any Accommodation Request and the acceptance or use by the Borrower of the proceeds of any Accommodation shall be deemed to constitute a representation and warranty by the Borrower that, on the date of such Accommodation Request and on the date of any Accommodation being provided and after giving effect thereto, the applicable conditions precedent set forth in this Article 6 shall have been satisfied, fulfilled or otherwise met.

6.5

Conditions Solely for the Benefit of the Lenders.  All conditions precedent to the entitlement of the Borrower to any Accommodations hereunder are solely for the benefit of the Lenders, and no other Person shall have standing to require satisfaction or fulfilment of any condition precedent or that it be otherwise met and no other Person shall be deemed to be a beneficiary of any such condition, any and all of which may be freely waived in whole or in part by the Lenders at any time the Lenders deem it advisable to do so in their sole discretion.

6.6

No Waiver.  The making of any Accommodations without one or more of the conditions precedent set forth in this Article 6 having been satisfied, fulfilled or otherwise met shall not constitute a waiver by the Lenders of any such condition, and the Lenders reserve the right to require that each such condition be satisfied, fulfilled or otherwise met prior to the making of any subsequent Accommodations.

ARTICLE 7
REPRESENTATIONS AND WARRANTIES

The Borrower (i) represents and warrants to the Lenders as set forth in this Article 7, (ii) acknowledges that the Lenders are relying thereon in entering into this agreement and providing Accommodations from time to time, (iii) agrees that no investigation at any time made by or on behalf of the Lenders shall diminish in any respect whatsoever their right to rely thereon, and (iv) agrees that all representations and warranties shall be valid and effective as of the date when given or deemed to have been given and to such extent shall survive the execution and delivery of this agreement and the provision of Accommodations from time to time.

7.1

Existence.  The Borrower has been duly incorporated and is a validly existing corporation under the laws of Canada or a province of Canada and is duly

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licensed or qualified and authorized to do business in the Province of British Columbia and is in good standing with respect to all required corporate and similar filings.

7.2

Capacity.  The Borrower has full corporate right, power and authority to enter into, and perform its obligations under, each Credit Facility Document to which it is or will be a party and the Terasen Funding Agreement, and the Borrower has full corporate power and authority to own and operate its Properties and to carry on its business as now conducted.

7.3

Authority.  The execution and delivery by the Borrower of the Credit Facility Documents to which it is or will be a party and the Terasen Funding Agreement and the consummation by the Borrower of the transactions contemplated hereby and thereby have been duly authorized by the directors of the Borrower.

7.4

Authorization, Governmental Approvals, etc.  Neither the nature of the Borrower or its business or Property, nor any circumstance in connection with the entering into and performance of the Credit Facility Documents to which it is or will be a party and the Terasen Funding Agreement, is such as to require any Governmental Approval that has not yet been obtained on the part of the Borrower in connection with the execution, delivery and performance of such Credit Facility Documents or the Terasen Funding Agreement, except for any such Governmental Approvals that, if applied individually or in the aggregate, do not have and would not reasonably be expected to have a Material Adverse Effect.

7.5

Enforceability.  This agreement has been duly executed and delivered by the Borrower and constitutes, and each other Credit Facility Document to which it is or will be a party and each other document hereby or thereby contemplated when executed by it will constitute, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms, subject to such customary qualifications as shall be set forth in the opinion of counsel to the Borrower delivered pursuant to Section 6.1(12).

7.6

No Breach.  The entering into and compliance by the Borrower with all of the provisions of the Credit Facility Documents to which it is or will be a party and the Terasen Funding Agreement are legal, do not violate any provisions of any Requirement of Law and do not result in any breach of any of the provisions of, or constitute a default under, or result in the creation of any Lien on any Property of the Borrower under the provisions of, any Charter Document of the Borrower or any agreement or instrument (including the Material Agreements) to which the Borrower is a party or by which it or its Property may be bound.

7.7

Subsidiaries.  As at the Closing Date, the Borrower:

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(a)

is a wholly-owned subsidiary of Terasen; and

(b)

has no subsidiaries.

7.8

Immunity, etc.  The Borrower is subject to the relevant commercial law of the Province of British Columbia and the law of Canada which is applicable therein and is generally subject to suit and it is not immune nor does any of its Property or revenues enjoy any right of immunity from any judicial proceedings, including attachment prior to judgment, attachment in aid of execution, execution of judgment or otherwise, except that, in respect of payments of Royalty Revenue and Interruptible Incentive under the VINGPA, the remedies of injunction and specific performance are not available against the Province of British Columbia by virtue of the Crown Proceeding Act (British Columbia), nor may enforcement proceedings by way of execution or attachment, or other process of that nature, be taken against the Province of British Columbia.

7.9

Litigation.  At the Closing Date, there are no actions, suits, claims or proceedings pending or (to its knowledge) threatened against the Borrower at law or in equity or before or by any Governmental Authority which have a reasonable likelihood of being determined adversely and which, individually or in the aggregate, if adversely determined have or would reasonably be expected to have a Material Adverse Effect.

7.10

Books and Records.  The Borrower maintains books, records and accounts in reasonable detail which accurately and fairly reflect its transactions and business affairs and permit preparation of financial statements in accordance with GAAP.

7.11

Compliance.  Except as otherwise disclosed in writing to the Lenders prior to the Closing Date, as at the Closing Date:

(a)

no Default or Event of Default has occurred and is continuing; and

(b)

the Borrower is not in default with respect to any Requirement of Law to the extent that the sanctions, consequences and penalties resulting from such defaults, if applied individually or in the aggregate, have or would reasonably be expected to have a Material Adverse Effect;

(c)

the Borrower:

(i)

is not in violation of, nor has any liability under, any Environmental Law applicable to the Borrower;

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(ii)

is not aware of the presence, release or disposal of any hazardous substances at any of its prior or currently owned, leased or operated Property;

(iii)

is not subject to any litigation, investigation, order or proceeding in connection with hazardous substances or Environmental Laws; and

(iv)

is not subject to any environmental, health or safety condition;

which, for any of the foregoing, individually or in the aggregate, has or would reasonably be expected to have a Material Adverse Effect;

(d)

the Borrower has obtained all Governmental Approvals which are necessary to carry on its business as now being conducted and each such Governmental Approval is in full force and effect, has not been surrendered, forfeited or become void or voidable, and there are no defaults under any Governmental Approval of the Borrower to the extent that failure to obtain such Governmental Approval or the sanctions, consequences and penalties resulting from such defaults, if applied individually or in the aggregate, have or would reasonably be expected to have a Material Adverse Effect; and

(e)

the Borrower is not in default, nor is there in existence an event or condition which, with the giving of notice, the passage of time, the making of any determination or any combination of the foregoing would be a default, under:

(i)

any Indebtedness;

(ii)

any Material Agreement; or

(iii)

any other agreement or instrument to which it is a party or by which it or its Property may be bound;

which defaults, if applied individually or in the aggregate, have or would reasonably be expected to have a Material Adverse Effect.

7.12

Latest Annual Financial Statements.  The audited financial statements of the Borrower as of and for the year ended December 31, 2004, copies of which have been delivered to the Administrative Agent, were prepared in accordance with GAAP as at the date of such financial statements and as at the Closing Date

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present fairly, as at the date of such financial statements, the financial position of the Borrower.

7.13

Ibid.  Each financial statement of the Borrower delivered in connection with the Credit Facility has been prepared in accordance with GAAP as at the date thereof (subject, in the case of quarterly statements, to the absence of notes and to year end audit adjustments) and fairly presents the financial condition of the Borrower as of and for the period ended on the date of the financial statement.

7.14

Contingent Liabilities.  The Borrower has no material contingent liabilities other than Guarantees, letters of credit and other obligations entered into in the normal course of business.

7.15

Franchises, etc.  Except for Governmental Approvals and Material Agreements, the Borrower has all other franchises, permits, approvals, validations, licences and other like interests, rights and authorities necessary to carry on its business as now being conducted and as proposed to be conducted, and there are no defaults under any of such franchises, permits, approvals, validations, licenses or other interests, rights or authorities to the extent that the failure to have or obtain any such franchise, permit, approval, validation, license or other authority or the sanctions, consequences and penalties from such defaults, if applied individually or in the aggregate, have or would reasonably be expected to have a Material Adverse Effect.

7.16

Ownership of Property.  The Borrower maintains all Property (including easements, rights of way and other real property rights) necessary to carry on its business in all material respects as now being conducted.

7.17

Intellectual Property.  The Borrower owns or possesses all patents, trademarks, service marks, trade names, copyrights, licenses and rights with respect to the foregoing necessary for the conduct of its business, without any known conflict with the rights of others which, if determined against the Borrower, if applied individually or in the aggregate, have or would reasonably be expected to have a Material Adverse Effect.

7.18

Title.  The Borrower has good title to all real property which it purports to own in fee simple and to all personal property which it purports to own in like manner, free from all Liens except for Permitted Liens, except where the failure to have such good title, if applied individually or in the aggregate, does not have and would not reasonably be expected to have a Material Adverse Effect.

7.19

Leases.  The Borrower enjoys peaceful and undisturbed possession under all material leasehold and similar interests under which the Borrower is a lessee or is operating, and all of such leases are valid and subsisting and the Borrower is

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not in default with respect to any leases save for defaults which, if applied individually or in the aggregate, do not have and would not reasonably be expected to have a Material Adverse Effect.

7.20

Material Agreements.  Each Material Agreement is in full force and effect, unamended save with respect to amendments which have been delivered to the Administrative Agent on or before the Closing Date or notified to the Administrative Agent in accordance with the Credit Facility Documents. The Borrower has neither waived any of its rights under any Material Agreement nor released any party from its obligations with respect thereto, except in accordance with the Credit Facility Documents. Neither the Borrower nor, to the best of its knowledge, any other party is in default under the terms of any Material Agreement, except for defaults which, individually or in the aggregate, do not have and would not reasonably be expected to have a Material Adverse Effect.

7.21

Taxes.  Except for circumstances which, individually or in the aggregate, do not have and would not reasonably be expected to have a Material Adverse Effect:

(a)

all tax returns required to be filed by the Borrower in any jurisdiction have been filed;

(b)

all taxes, assessments, fees and other governmental charges upon the Borrower or upon any of its Property, which are due and payable, have been paid on a timely basis or within appropriate extension periods or are being contested in good faith by appropriate proceedings (and in respect of which adequate provision has been made on its books);

(c)

the Borrower has collected, deducted, withheld and remitted to the proper taxing authorities when due all taxes, workers compensation assessments, employment insurance assessments, fees and other similar amounts required to be collected, deducted, withheld and remitted; and

(d)

the Borrower does not know of any proposed additional tax assessments against it for which adequate provision has not been made on its books which have a reasonable likelihood of being adversely determined.

7.22

Material Adverse Effect.  Since September 30, 2005 and up to the Closing Date, there has been no event or condition that constitutes or would reasonably be expected to constitute a Material Adverse Effect.

7.23

Pari Passu.  The payment Obligations of the Borrower under this agreement and each other Credit Facility Document to which it is a party rank at least pari passu

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in right of payment with all of its other unsecured and unsubordinated indebtedness, other than any such indebtedness which is preferred by mandatory provisions of Applicable Law.

7.24

Information.  All information supplied to the Lenders by the Borrower on or before the Closing Date is, with respect to factual matters, true and correct in all material respects and is, with respect to projections, forecasts and other matters being the subject of opinion, believed on reasonable grounds to be true and correct in all material respects and, to the extent based upon assumptions, such assumptions are believed to be reasonable in the circumstances.

ARTICLE 8
COVENANTS

8.1

Affirmative Covenants.  Until the Obligations are paid and satisfied in full and this agreement has been terminated, and in addition to any other covenants herein set forth, the Borrower covenants as set forth in this Section 8.1.

(1)

Maintain Existence.  The Borrower shall maintain and preserve its corporate existence and right to carry on business and use reasonable commercial efforts to maintain, preserve, renew and extend all rights, powers, privileges and franchises necessary to the proper conduct of its business as now being conducted.

(2)

Compliance with Laws, etc.  The Borrower shall comply with all Requirements of Law (including for greater certainty all Environmental Laws) relating to its business where failure to comply, individually or in the aggregate, has or would reasonably be expected to have a Material Adverse Effect.

(3)

Payment of Taxes and Claims.  The Borrower shall pay and discharge when due:

(a)

all taxes, assessments and governmental charges or levies imposed upon it, its income or its Property ; and

(b)

all lawful claims which, if unpaid, might become a Lien upon its Property;

provided that the Borrower shall not be required to pay any such tax, assessment, charge, levy or claim, the payment of which is being contested in good faith and by proper proceedings that will stay the forfeiture or sale of any Property and with respect to which adequate reserves are maintained.

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(4)

Governmental Approvals.  The Borrower shall obtain (to the extent not in existence on the date hereof) all Governmental Approvals necessary for the operation of its business as presently conducted and comply in all material respects with the covenants, terms and conditions set out in such Governmental Approvals, unless failure to so obtain or non-compliance, individually or in the aggregate, does not have and would not reasonably be expected to have a Material Adverse Effect.

(5)

Material Agreements.  The Borrower will comply in all material respects with the covenants, terms and conditions set out in the Material Agreements, save where such failure to comply, individually or in the aggregate when considered with all other such failures, does not have and would not reasonably be expected to have a Material Adverse Effect.

(6)

Insurance.  Subject to reasonable commercial efforts having regard to market conditions, the Borrower shall maintain with reputable insurers, insurance with respect to its properties and business against such liabilities, casualties, risks and contingencies and in such amounts as are customary for companies engaged in the same or similar businesses and, at the written request of the Administrative Agent, will provide evidence thereof to the Administrative Agent.

(7)

Keeping of Books.  The Borrower shall keep at all times proper books of record and account in which full, true and correct entries shall be made of all dealings or transactions of or in relation to the business and affairs of the Borrower in accordance with GAAP.

(8)

Conduct of Business.  The Borrower shall carry on and conduct its business in accordance with sound business practices and shall maintain its material assets in reasonable repair and working order.

(9)

Pay Obligations to Lenders.  The Borrower shall duly and punctually pay or cause to be paid to the Administrative Agent for the account of each Lender all principal, interest, stamping fees for Bankers’ Acceptances, standby fees and other fees and amounts payable by it hereunder on the dates, at the places and in the moneys and manner set forth herein.

(10)

Use of Proceeds.  It will use the proceeds of all Accommodations made available to it only for the purposes set forth in Section 2.1(2).

(11)

Financial and Other Reporting. The Borrower will deliver to the Administrative Agent the following:

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(a)

no later than 60 days after the end of each of the first three Financial Quarters, financial statements for that Financial Quarter on an unaudited basis;

(b)

no later than 120 days after the end of each Financial Year, financial statements for that Financial Year on an audited basis;

(c)

with each of the financial statements in (a) and (b) above, a Compliance Certificate signed by a Senior Financial Officer; and

(d)

such other information as the Administrative Agent shall from time to time reasonably request.

(12)

Notice of Certain Events. The Borrower will notify the Administrative Agent in writing of the following:

(a)

as soon as practicable upon the occurrence thereof, any Default or Event of Default;

(b)

promptly, any decision (for whatever reason) by a Rating Agency to cease providing a Rating, any change in a Rating by either Rating Agency, or any new such Rating;

(c)

as soon as practicable after the Borrower obtains knowledge thereof, notice of any action, suit, claim or proceeding pending or (to its knowledge) threatened against the Borrower at law or in equity or before or by any Governmental Authority which has a reasonable likelihood of being determined adversely and which, if adversely determined, would reasonably be expected to have a Material Adverse Effect;

(d)

as soon as practicable after the Borrower obtains knowledge thereof, notice of any ruling from the BCUC which has or would reasonably be expected to have a Material Adverse Effect;

(e)

from time to time the names of those officers of the Borrower who have been duly authorized to sign Bankers' Acceptances, notes, instruments, agreements and certificates hereunder; and

(f)

promptly after the Borrower obtains knowledge thereof, written notice of any proposed amendment to, or other material dealing with or development concerning, the Special Direction, save where such amendment, dealing or development does not have and would not reasonably be expected to have a Material Adverse Effect.

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(13)

Notices re: Material Agreements.  The Borrower shall provide to the Administrative Agent:

(a)

within 60 days after the end of each Financial Quarter, copies of all amendments to Material Agreements during such Financial Quarter;

(b)

promptly after same has been received, any written notice received by the Borrower regarding an alleged default by the Borrower under any Material Agreement, save where the allegation of such default does not have a reasonable likelihood of being sustained or, if sustained, individually or in the aggregate when considered with all other such defaults, does not have and would not reasonably be expected to have a Material Adverse Effect;

(c)

as soon as practicable, written notice of any default by the Borrower under any Material Agreement, save where such default, individually or in the aggregate when considered with all other such defaults, does not have and would not reasonably be expected to have a Material Adverse Effect; and

(d)

promptly after the Borrower obtains knowledge thereof, written notice of any default by any other party to a Material Agreement, save where such default, individually or in the aggregate when considered with all other such defaults, does not have and would not reasonably be expected to have a Material Adverse Effect.

(14)

Environmental Indemnity.  The Borrower will forthwith on demand fully indemnify, defend and save the Administrative Agent, the Lenders and their Affiliates and their respective shareholders, directors, officers, employees, advisors, consultants, counsel and agents (each, an “Indemnified Party”) harmless from and against any and all losses and expenses (including interest and, to the extent permitted by applicable law, penalties, fines and monetary sanctions actually incurred) which an Indemnified Party suffers or incurs as a result of or otherwise in respect of any environmental claim or liability of any kind which arises out of the execution, delivery or performance of, or the enforcement or exercise of any right under, any Credit Facility Document, including any claim in nuisance, negligence, strict liability or other cause of actio n arising out of a discharge of a Contaminant into the environment and any fines or orders of any kind that may be levied or made pursuant to an Environmental Law, in each case relating to or otherwise arising out of any of the assets or business of the Borrower whether or not any Indemnified Party is in charge, management or control of all or any part thereof.

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The foregoing indemnity shall not apply in favour of an Indemnified Party in respect of losses and expenses arising as a result of the gross negligence or wilful misconduct of such Indemnified Party or any Person acting for or on behalf of such Indemnified Party or in respect of losses and expenses arising as a result of the operation of any of the assets or business of the Borrower by an Indemnified Party in a manner that is not at least substantially as environmentally sound as would be the case if operated in accordance with general industry practice or to the standard that the Borrower operated such assets or business.

The provisions of this Section 8.1(14) shall survive the termination of this agreement and the repayment of all Obligations.

(15)

Environmental Compliance Orders.  Upon receipt, the Borrower will notify the Administrative Agent and make available for inspection and review on a confidential basis by representatives of the Lenders, copies of all written orders, directions, claims or complaints by a Governmental Authority:

(a)

relating to the environmental condition of the Borrower’s assets, or

(b)

relating to non-compliance with any Environmental Law;

where failure to comply with or resolve such orders, claims or complaints has or would be reasonably expected to have a Material Adverse Effect.

(16)

Further Assurances.  It will at its cost and expense, upon request of the Administrative Agent, duly execute and deliver, or cause to be duly executed and delivered, to the Administrative Agent such further instruments and do and cause to be done such further acts as may be necessary or proper in the reasonable opinion of the Administrative Agent to carry out more effectually the provisions and purposes of this agreement and the other Credit Facility Documents.

8.2

Negative Covenants.  Until the Obligations are paid and satisfied in full and this agreement has been terminated, and in addition to any other covenants herein set forth, the Borrower covenants and agrees that it will not take any of the actions set forth in this Section 8.2 or permit or suffer same to occur without the prior written consent of the Majority Lenders pursuant to Section 12.2.

(1)

Liens.  The Borrower will not create, incur,  assume or otherwise become liable for or permit to exist any Lien on any of its Property other than Permitted Liens.

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(2)

Merger, etc.  Except for Permitted Mergers, the Borrower will not merge, consolidate or amalgamate with or into, or sell, convey, transfer, lease or otherwise dispose of (in one transaction or a series of transactions and other than by way of Permitted Liens) all or substantially all of its assets to, any other Person.

(3)

Business.  The Borrower will not change the nature of its principal business from that of the ownership and operation of a regulated natural gas transmission and distribution utility and regulated and unregulated business activities related thereto.

(4)

Dispositions.  Except for sales in the normal course of business, the Borrower shall not dispose of any Property except to an arm's length purchaser at fair market value, or to a non-arm's length purchaser on terms no less favourable to the Borrower than would be the case in an arm’s length transaction, and in any event shall not dispose of any Property where such disposition constitutes or would reasonably be expected to constitute a Material Adverse Effect.

(5)

Distributions.  The Borrower shall not take any of the following actions (each, a “Distribution”):

(a)

pay any dividends on its outstanding shares (except for stock dividends);

(b)

reduce its capital; or

(c)

make any payments on account of its obligations under any Class A Instruments or Class B Instruments (except for the issuance of additional Class A Instruments or Class B Instruments);

provided that, once in each Financial Quarter in the case of (a) and (b) and once annually in the case of (c), a Distribution may be made where the following conditions apply (and the Borrower shall deliver to the Lenders a certificate signed by a Senior Financial Officer certifying that):

(d)

immediately after such Distribution, the Leverage Ratio would comply with Section 8.3; and

(e)

both immediately before and immediately after such Distribution there shall be no Default or Event of Default that has occurred and is continuing;

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provided further that, in the event that the conditions set forth in (d) and (e) above are satisfied, payments on account of Subordinated Debt may be made without restriction as to frequency.

(6)

Material Agreements.  The Borrower will not:

(a)

waive or release any right under any Material Agreement, save where such waiver or release, individually or in the aggregate when considered with all other such waivers and releases, does not have and would not reasonably be expected to have a Material Adverse Effect; or

(b)

amend any Material Agreement in an adverse manner, save where such amendment, individually or in the aggregate when considered with all other such amendments, does not have and would not reasonably be expected to have a Material Adverse Effect.

(7)

Hedges.  The Borrower shall not enter into any Hedge Instruments for speculative purposes.

(8)

Payment of Junior Obligations. The Borrower shall not make payments on account of the Junior Obligations (as defined in the Terasen Funding Agreement) if to do so would be contrary to the terms of the Terasen Funding Agreement.

8.3

Financial Covenants.  As at each Calculation Date:

(a)

the Leverage Ratio shall not exceed 0.7 to 1; and

(b)

the Coverage Ratio shall be at least 2.0 to 1.

8.4

Administrative Agent May Perform Covenants.  If the Borrower shall fail to perform or observe any covenant on its part contained herein or in any other Credit Facility Document, the Administrative Agent may, in its sole discretion acting reasonably, and shall upon the instructions of the Majority Lenders, in either case subject to it having been indemnified to its satisfaction, perform (or cause to be performed), any of the said covenants capable of being performed by the Administrative Agent and, if any such covenant requires the payment or expenditure of money, the Administrative Agent may make such payment or expenditures with its own funds or with money borrowed for that purpose (but the Administrative Agent shall be under no obligation to do so); provided that the Administrative Agent shall first have provided written notice of its intention to t he Borrower and a reasonable opportunity (not to exceed 20 days, or such longer period as the Lenders shall approve) to cure the failure.  All amounts paid by the Administrative Agent pursuant to this Section 8.4 shall be repaid by the

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Borrower to the Administrative Agent on demand therefor, and shall form part of the Obligations.  No payment or performance under this Section 8.4 shall relieve the Borrower from any Event of Default.

ARTICLE 9
CHANGES IN CIRCUMSTANCES

9.1

Provisions to Apply. Section 3 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated.

9.2

Indemnification re Matching Funds.  The Borrower shall promptly pay to each Lender any amounts required to compensate such Lender for any breakage or similar cost, loss, cost of redeploying funds or other cost or expense suffered or incurred by such Lender  as a result of:

(a)

any payment being made by the Borrower in respect of a LIBOR Advance or a Bankers’ Acceptance (due to acceleration hereunder or a mandatory repayment or prepayment of principal or for any other reason) on a day other than the last day of an Interest Period or the maturity date applicable thereto; provided that, where the event giving rise to such payment is a mandatory repayment or prepayment, the Borrower may at its option instead deposit the amount of the repayment or prepayment to a trust account pending expiry of the existing Interest Period or (as the case may be) maturity of outstanding Bankers Acceptances, and the monies in such trust account shall be invested in Cash Equivalents and applied by the Administrative Agent to the required repayment or prepayment on the expiry of such Interest Period or maturity of such Bankers Acceptance;

(b)

the Borrower’s failure to give Notice in the manner and at the times required hereunder; or

(c)

the failure of the Borrower to fulfil or honour, before the date specified for any Accommodation, the applicable conditions set forth in Article 6 or to accept an Accommodation after delivery of an Accommodation Request in the manner and at the time specified in such Accommodation Request.

A certificate of such Lender submitted to the Borrower (with a copy to the Administrative Agent) as to the amount necessary to so compensate such Lender shall be conclusive evidence, absent demonstrated error, of the amount due from the Borrower to such Lender.

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ARTICLE 10
EVENTS OF DEFAULT

10.1

Events of Default.  Each of the events set forth in this Section 10.1 shall constitute an "Event of Default".

(1)

Payment.  The Borrower shall fail:

(a)

to pay the principal amount of any Advance or BA Equivalent Loan when the same becomes due and payable;

(b)

to reimburse any Lender in respect of any Bankers’ Acceptance or Letter of Credit, or pay the Face Amount thereof, when required hereunder; or

(c)

to pay any interest or fees hereunder when the same becomes due and payable;

and, in the case of (a) or (b), such failure shall remain unremedied for a period of one Business Day after notice from the Administrative Agent to the Borrower or, in the case of (c), such failure shall remain unremedied for a period of three Business Days after notice from the Administrative Agent to the Borrower.

(2)

Representations and Warranties Incorrect.  Any of the representations or warranties made or deemed to have been made by the Borrower in any Credit Facility Document, or by Terasen in the Terasen Funding Agreement, shall prove to be or have been incorrect in any material respect when made or deemed to have been made, and the Borrower or Terasen, as the case may be, fails to cure such incorrect representation or warranty within 30 days of receiving notice from the Administrative Agent in connection therewith.

(3)

Failure to Perform Certain Covenants.  The Borrower shall fail to perform or observe any covenant contained in any Credit Facility Document on its part to be performed or observed or otherwise applicable to it; provided that, if such failure is capable of being remedied, no Event of Default shall have occurred as a result thereof unless and until such failure shall have remained unremedied for 30 days after the earlier of (i) written notice thereof given to the Borrower by the Administrative Agent, and (ii) such time as the Borrower is aware of same.

(4)

Indebtedness.  Either:

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(a)

the Borrower fails to pay the principal of any Indebtedness (excluding the obligations under the Credit Facility) which is outstanding in an aggregate principal amount exceeding $10 million (or the Equivalent Amount in any other currency) when such amount becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise) beyond any applicable grace period; or

(b)

any other event occurs or condition exists (including a failure to pay the premium or interest on such Indebtedness) and continues after the applicable grace period, if any, specified in any agreement or instrument relating to any such Indebtedness which is outstanding in an aggregate principal amount exceeding $10 million (or the Equivalent Amount in any other currency) without waiver of such failure by the holder of such Indebtedness on or before the expiration of such period, as a result of which such holder accelerates such Indebtedness.

(5)

Judgment.  Any judgment or order for the payment of money in excess of $10,000,000 (or the Equivalent Amount in any other currency) is rendered against the Borrower and remains unsatisfied or unstayed for more than 30 Business Days.

(6)

Bankruptcy, etc.  The Borrower does not pay its debts generally as they become due or admits its inability to pay its debts generally  as they become due or makes a general assignment for the benefit of creditors or commits any other act of bankruptcy (within the meaning of the Bankruptcy and Insolvency Act (Canada) or equivalent or analogous law of any foreign jurisdiction) or any proceedings are instituted by or against the Borrower seeking to adjudicate it a bankrupt or declare it insolvent or seeking administration, liquidation, winding-up, reorganization, compromise, arrangement, adjustment, protection, relief or composition of it or with respect to its debts, whether by voluntary arrangement, scheme of arrangement or otherwise, under any Applicable Law relating to bankruptcy, insolvency or reorganization or relief with respect to deb tors or other similar matters, or seeking the appointment of a receiver, manager, administrator, administrative receiver, receiver and manager, trustee, custodian or other similar official for it or for any substantial part of its Property, or the Borrower takes corporate action to authorize any of the actions set forth in this Section 10.1(6) (excluding proceedings against the Borrower being contested by the Borrower in good faith by appropriate proceedings so long as enforcement sought in such proceedings remains stayed, none of the relief sought is granted (either on an interim or permanent basis), and such proceedings are dismissed,

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stayed or withdrawn within 30 Business Days of the Borrower receiving notice of the institution thereof).

(7)

Execution.  Any one or more Persons shall take possession of any Property of the Borrower or any one or more seizures, executions, garnishments, sequestrations, distresses, attachments or other equivalent processes are issued or levied against any Property of the Borrower, in each case in relation to claims in the aggregate in excess of $10,000,000 (or the Equivalent Amount in another currency), and such Property is not released within 30 Business Days or such shorter period as would permit such Property to be sold, foreclosed upon or forfeited thereunder.

(8)

Carry on Business.  The Borrower shall cease or threaten to cease to carry on its business or shall dispose or threaten to dispose of all or substantially all of its assets whether by one transaction or a series of transactions, except as permitted hereunder.

(9)

VINGPA.  Terasen (or a successor owner of the Borrower as permitted by Section 10.1(12)(b) below) is in default of any of its funding obligations under the VINGPA, or any other obligation which would entitle the Province of British Columbia to suspend Royalty Revenue payments under the VINGPA.

(10)

Terasen Funding Agreement. Terasen (or a successor owner of the Borrower as permitted by Section 10.1(12)(b) below) is in default under the Terasen Funding Agreement.

(11)

Credit Facility Documents.  Any Credit Facility Document shall (except in accordance with its terms), in whole or in material part, terminate, cease to be effective or cease to be the legally valid, binding and enforceable obligation of the Borrower, or the Borrower shall, directly or indirectly, contest in any manner such effectiveness, validity, binding nature or enforceability; or the Terasen Funding Agreement shall (except in accordance with its terms), in whole or in material part, terminate, cease to be effective or cease to be the legally valid, binding and enforceable obligation of Terasen, or Terasen shall, directly or indirectly, contest in any manner such effectiveness, validity, binding nature or enforceability.

(12)

Control Event.  At any time while the VINGPA is in effect, the Borrower (except as a result of a Permitted Merger) shall cease to be a wholly-owned direct or indirect subsidiary of either:

(a)

Terasen; or

(b)

another Person:

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(i)

whose public unsecured debt had, at the time of acquisition from Terasen, a Rating at least as high as Terasen’s public unsecured debt at such time; and

(ii)

who, at the time of acquisition from Terasen, was directly or indirectly engaged in the utility or other infrastructure business.

10.2

Effect.  

(1)

General.  Upon the occurrence and continuance of an Event of Default, except as provided in Section 10.2(2), the Administrative Agent:

(a)

shall, at the request of the Majority Lenders, by notice to the Borrower cancel all obligations of the Lenders in respect of the Commitments (whereupon no further Accommodations may be made and any Accommodation Request given with respect to an Accommodation occurring on or after the date of such notice or request shall cease to have effect); and

(b)

shall, at the request of the Majority Lenders, by notice to the Borrower declare the Obligations to be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower.

(2)

Specific Defaults. If any Event of Default specified in Section 10.1(6) shall occur with respect to the Borrower, then all obligations of the Lenders in respect of the Commitments shall be automatically cancelled and the Obligations shall be forthwith due and payable, all as if the request and notice specified in each of Sections 10.2(1)(a) and 10.2(1)(b) had been received and given by the Administrative Agent.

(3)

Enforcement.  Upon the occurrence of an Event of Default and acceleration of the Obligations, the Administrative Agent may, and shall at the request of the Majority Lenders, commence such legal action or proceedings as it may deem expedient, all without any additional notice, presentation, demand, protest, notice of dishonour, or any other action, notice of all of which the Borrower hereby expressly waives to the extent permitted by Applicable Law.  The rights and remedies of the Administrative Agent and the Lenders hereunder and under the other Credit Facility Documents  and the Terasen Funding Agreement are cumulative and are in addition to and not in substitution for any other rights or remedies provided by Applicable Law; provided that nothing herein contained shall permit any

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Lender to take any steps which, pursuant to this agreement, may only be undertaken by or with the consent of all Lenders or the Majority Lenders.

10.3

Right of Set-Off.  Section 4 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated.

10.4

Currency Conversion After Acceleration.  At any time following the occurrence of an Event of Default and the acceleration of the Obligations, each Lender shall be entitled to convert, with two Business Days’ prior notice to the Borrower, its unpaid and outstanding US Dollar Advances, or any of them, to Prime Rate Advances.  Any such conversion shall be calculated so that the resulting Prime Rate Advances shall be the Equivalent Amount in Cdn. Dollars on the date of conversion of the amount of US Dollars so converted.  Any accrued and unpaid interest denominated in US Dollars at the time of any such conversion shall be similarly converted to Cdn. Dollars, and such Prime Rate Advances and accrued and unpaid interest thereon shall thereafter bear interest in accordance with Article 3.

ARTICLE 11
THE ADMINISTRATIVE AGENT AND THE LENDERS

11.1

Provisions to Apply.  Section 7 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated.

ARTICLE 12
MISCELLANEOUS

12.1

Sharing of Payments; Records.

(1)

Adjustments; Issuing Bank.  Upon the occurrence of an Event of Default, adjustments shall be made among the Lenders as set forth in this Section 12.1(1).

(a)

The Lenders shall make such adjusting payments amongst themselves in the manner contemplated by Section 12.1(2) as may be required to ensure their respective participations in outstanding Advances under the Credit Facility reflect their respective Commitments under the Credit Facility on the basis of the column entitled “Total Credit Facility” in schedule 1 annexed hereto.

If a Letter of Credit is drawn upon which results in a payment by the Issuing Bank thereunder (in this Section 12.1(1), an "LC Payment"), the Issuing Bank will promptly request the Administrative Agent on behalf of the Borrower (and for this purpose the Issuing Bank is irrevocably authorized by the

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Borrower to do so) for a Borrowing by way of a Prime Rate Advance from the Lenders pursuant to Article 3 to reimburse the Issuing Bank for such LC Payment.  The Lenders are irrevocably directed by the Borrower to make any Prime Rate Advance if so requested by the Issuing Bank and pay the proceeds thereof directly to the Administrative Agent for the account of the Issuing Bank.  Each Lender unconditionally agrees to pay to the Administrative Agent for the account of the Issuing Bank such Lender’s rateable portion of each Advance requested by the Issuing Bank on behalf of the Borrower to repay LC Payments made by the Issuing Bank.

(b)

Except as provided in Section 12.1(1)(d), the obligations of each Lender under Section 12.1(1)(a) are unconditional, shall not be subject to any qualification or exception whatsoever and shall be performed in accordance with the terms and conditions of this agreement under all circumstances including:

(i)

any lack of validity or enforceability of the Borrower’s obligations under Section 2.1(6);

(ii)

the occurrence of any Default or Event of Default or the exercise of any rights by the Administrative Agent under Section 10.2; and

(iii)

the absence of any demand for payment being made, any proof of claim being filed, any proceeding being commenced or any judgment being obtained by a Lender or the Issuing Bank against the Borrower.

(c)

If a Lender (a "Defaulting Lender") fails to make payment on the due date therefor of any amount due from it for the account of another Lender or the Issuing Bank pursuant to Section 12.1(1)(a) (the balance thereof for the time being unpaid being referred to in this Section 12.1(1)(c) as an "overdue amount") then, until such other Lender or the Issuing Bank has received payment of that amount (plus interest as provided below) in full (and without in any way limiting the rights of such other Lender or the Issuing Bank in respect of such failure):

(i)

such other Lender or the Issuing Bank shall be entitled to receive any payment which the Defaulting Lender would otherwise have been entitled to receive in respect of the

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Credit Facility or otherwise in respect of any Credit Facility Document or the Terasen Funding Agreement; and

(ii)

the overdue amount shall bear interest payable by the Defaulting Lender to such other Lender or the Issuing Bank at the rate payable by the Borrower in respect of the Obligations which gave rise to such overdue amount.

(d)

If for any reason an Advance may not be made pursuant to Section 12.1(1)(a) to reimburse the Issuing Bank as contemplated thereby, then promptly upon receipt of notification of such fact from the Administrative Agent, each relevant Lender shall deliver to the Administrative Agent for the account of the Issuing Bank in immediately available funds the purchase price for such Lender’s participation interest in the relevant unreimbursed LC Payments (including interest then accrued thereon and unpaid by the Borrower).  Without duplication, each Lender shall, upon demand by the Issuing Bank made to the Administrative Agent, deliver to the Administrative Agent for the account of the Issuing Bank interest on such Lender’s rateable portion from the date of payment by the Issuing Bank of such unreimbursed LC Payments until the date of delivery of such funds to the Issuing Bank by such Lender at a rate per annum equal to the one month CDOR (if reimbursement is to be made in Canadian Dollars) for such period.  Such payment shall only, however, be made by the Lenders in the event and to the extent the Issuing Bank has not been reimbursed in full by the Borrower for interest on the amount of such unreimbursed LC Payments.

(e)

The Issuing Bank shall, forthwith upon its receipt of any reimbursement (in whole or in part) by the Borrower for any unreimbursed LC Payments in relation to which other Lenders have purchased a participation interest pursuant to Section 12.1(1)(d), or of any other amount from the Borrower or any other Person in respect of such payment (other than pursuant to Section 2.1(6)), transfer to such other Lender such other Lender’s rateable share of such reimbursement or other amount.  In the event that any receipt by the Issuing Bank of any reimbursement or other amount is found to have been a transfer in fraud of creditors or a preferential payment under any applicable insolvency legislation or is otherwise required to be returned, such Lender shall promptly return to the Issuing Bank any portion thereof previously transferred to it by the Issuing Bank, without in terest to the extent

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that interest is not payable by the Issuing Bank in connection therewith.

(2)

Sharing.  If:

(a)

any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off pursuant to Section 10.3 or at law or equity, or otherwise) on account of any Accommodation made by it (other than Increased Costs paid to it) in excess of its rateable share of payments on account of such Accommodation; or

(b)

(without regard to outstanding Increased Costs) any Lender shall at the time of acceleration of the Obligations have outstanding Obligations which are less than its rateable share of all outstanding Obligations;

then such Lender shall forthwith purchase from the other Lenders such participations in the Accommodations made by such other Lenders as shall be necessary to cause such purchasing Lender to share the excess payment or be owed the outstanding Obligations rateably with such other Lenders.

In the case of paragraph (a) of this Section 12.1(2), if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each other Lender shall be rescinded and each Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such other Lender’s rateable share (according to the proportion that the amount such other Lender’s required repayment bears to the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered.

Any Lender purchasing a participation from another Lender pursuant to this Section 12.1 may, to the fullest extent permitted by Applicable Law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

(3)

Records.  The Principal Outstanding and C$ Equivalent Principal Outstanding under the Credit Facility, the unpaid interest accrued thereon, the interest rate or rates applicable to any unpaid principal amounts, the duration of such application, the date of acceptance or issue, Face Amount and maturity of all Bankers’ Acceptances and Letters of

- 83 -

Credit and the Commitments shall at all times be ascertained from the records of the Administrative Agent, which shall be conclusive absent demonstrated error.

12.2

Amendments, etc.  

(1)

Amendments - General.  Subject to Section 12.2(2), no amendment or waiver of any provision of this agreement or of any other Credit Facility Document or the Terasen Funding Agreement, nor any consent to any departure by the Borrower or any Affiliate herefrom or therefrom, shall in any event be effective unless the same shall be in writing and signed by the Majority Lenders (or by the Administrative Agent on their authorization), and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given.

(2)

Amendments - Unanimous.  No instrument shall, unless in writing and signed by all the Lenders (or by the Administrative Agent on their authorization):

(a)

waive any of the conditions specified in Article 6;

(b)

increase the Commitment of any Lender or subject any Lender to any additional obligation;

(c)

change the principal of, or interest on, or discount rate applicable to any Accommodation or any fees hereunder;

(d)

amend the Maturity Date or otherwise postpone any date fixed for any payment of principal of, or interest on, any Accommodation or any fees hereunder, or subordinate the Obligations or any portion thereof to any Indebtedness;

(e)

amend the terms of Section 8.2(3) or this Section 12.2, provided that any waiver of a breach of Section 8.2(3) need only be approved under Section 12.2(1);

(f)

amend the definition of "Majority Lenders"; or

(g)

except as permitted by Sections 2.3 or 8.2(2), permit a change in the Borrower or an assignment or transfer of any of its rights or obligations under any Credit Facility Document.

(3)

Amendments - Administrative Agent.  No amendment, waiver or consent shall, unless in writing and approved by the Administrative Agent in addition to the Majority Lenders, affect the rights or duties of the

- 84 -

Administrative Agent under any Credit Facility Document or the Terasen Funding Agreement.

(4)

Issuing Bank. No amendment, waiver or consent shall, unless approved by the Issuing Bank, affect the rights or obligations of the Issuing Bank with respect to Letters of Credit.

(5)

Swingline Lender. No amendment, waiver or consent shall, unless approved by the Swingline Lender, affect the rights or obligations of the Swingline Lender with respect to Swingline Advances.

(6)

Other Approvals.  For greater certainty, any approval of a Person specifically required by any of Sections 12.2(3) to (5), inclusive, shall be in addition to any other approval required by this agreement.

12.3

Notices, etc.

(1)

Provisions to Apply. Section 8 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated. The addresses of the Borrower and the Administrative Agent are as set forth below (until notified otherwise in accordance with this agreement):

if to the Borrower:

Terasen Gas (Vancouver Island) Inc.

16705 Fraser Highway

Surrey, British Columbia

V3S 2X7

Attention: Vice President & Chief Financial Officer

Fax number: (604) 592-7890

if to the Administrative Agent:

Royal Bank of Canada

Agency Services Group

12th Floor, South Tower

Royal Bank Plaza

200 Bay Street

Toronto, Ontario

M5J 2W7

Attention: Manager, Agency

Fax number:  (416) 842-4023

- 85 -

(2)

Deliveries.  All deliveries of financial statements and other documents to be made by the Borrower to the Lenders hereunder shall be made by making delivery of such financial statements and documents to the Administrative Agent (in sufficient copies for the Administrative Agent and each Lender) to the address in Section 12.3(1) or to such other address as the Administrative Agent may from time to time notify to the Borrower. All such deliveries shall be effective only upon actual receipt.

(3)

Notice Irrevocable.  Each Notice shall be irrevocable and binding on the Borrower.  

(4)

Reliance.  The Administrative Agent may act upon the basis of telephonic notice believed by it in good faith to be from the Borrower prior to receipt of a Notice. In the event of conflict between the Administrative Agent’s record of the applicable terms of any Accommodation and such Notice, the Administrative Agent’s record shall prevail, absent demonstrated error.

(5)

No Waiver; Remedies.  No failure on the part of the Administrative Agent or any of the Lenders to exercise, and no delay in exercising, any right under any Credit Facility Document shall operate as a waiver thereof, nor shall any single or partial exercise of any right under any Credit Facility Document preclude any other or further exercise thereof or the exercise of any other right.  The remedies herein and therein provided are cumulative and not exclusive of any remedies provided by Applicable Law.

12.4

Expenses and Indemnity.  Section 9 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated.

12.5

Judgment Currency.  

(1)

Exchange Rate.  If, for the purposes of obtaining judgment in any court, it is necessary to convert a sum due hereunder to the Administrative Agent or a Lender in one currency (in this Section 12.5, the "Original Currency") into another currency (in this Section 12.5, the "Judgment Currency"), the parties agree, to the fullest extent that they may effectively do so, that the rate of exchange used shall be that at which in accordance with normal banking procedures the Administrative Agent or such Lender could purchase the Original Currency with the Judgment Currency on the Business Day preceding that on which final judgment is paid or satisfied.

(2)

Obligation.  The obligations of the Borrower in respect of any sum due in the Original Currency from it to the Administrative Agent or a Lender under any Credit Facility Document shall, notwithstanding any judgment

- 86 -

in any Judgment Currency, be discharged only to the extent that, on the Business Day following receipt by the Administrative Agent or such Lender of any sum adjudged to be so due in such Judgment Currency, the Administrative Agent or such Lender may in accordance with normal banking procedures purchase the Original Currency with such Judgment Currency.  If the amount of the Original Currency so purchased is less than the sum originally due to the Administrative Agent or such Lender in the Original Currency, the Borrower agrees, as a separate obligation and notwithstanding any such judgment, to indemnify the Administrative Agent or such Lender against such loss and, if the amount of the Original Currency so purchased exceeds the sum originally due to the Administrative Agent or such Lender in the Original Currency, the Administrative Agent or such Lender agrees to rem it such excess to the Borrower.

12.6

Governing Law, etc.  Sections 11 and 12 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated.  This agreement shall be governed by and construed in accordance with the laws of the Province of British Columbia and the laws of Canada applicable therein.

12.7

Successors and Assigns.  Section 10 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated. An assignment fee of C$3,500 shall be paid to the Administrative Agent by the assignor Lender in the case of (and as a condition precedent to the effectiveness of) an assignment.

12.8

Conflict.  In the event of a conflict between the provisions of this agreement and the provisions of any other Credit Facility Document, the provisions of this agreement shall prevail.

12.9

Confidentiality.  Section 14 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated.

12.10

Severability.  The provisions of this agreement are intended to be severable. If any provision of this agreement shall be held invalid or unenforceable in whole or in part in any jurisdiction, such provision shall, as to such jurisdiction, be ineffective to the extent of such invalidity or unenforceability without in any manner affecting the validity or enforceability thereof in any other jurisdiction or the remaining provisions hereof in any jurisdiction.

- 87 -

12.11

Prior Understandings.  This agreement supersedes all prior understandings and agreements, whether written or oral, among the parties relating to the transactions provided for herein.

12.12

Time of Essence.  Time shall be of the essence hereof.

(balance of page intentionally blank)

- 88 -

12.13

Counterparts.  Section 13 of the Provisions shall for all purposes of this agreement apply in the circumstances therein contemplated..

IN WITNESS WHEREOF the parties have caused this agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

BORROWER:
TERASEN GAS (VANCOUVER ISLAND) INC.
Per:
	Authorized Signatory
Per:
	Authorized Signatory

ADMINISTRATIVE AGENT:
ROYAL BANK OF CANADA
Per:
	Authorized Signatory

- 89 -

LENDERS:

ROYAL BANK OF CANADA
Per:	__________________________________
	Authorized Signatory
Per:	__________________________________
	Authorized Signatory
THE BANK OF NOVA SCOTIA
Per:	__________________________________
	Authorized Signatory
Per:	__________________________________
	Authorized Signatory
NATIONAL BANK OF CANADA
Per:	__________________________________
	Authorized Signatory
Per:	__________________________________
	Authorized Signatory
MERRILL LYNCH CAPITAL CANADA INC.
Per:	__________________________________
	Authorized Signatory

- 90 -

CANADIAN IMPERIAL BANK OF COMMERCE
Per:	__________________________________
	Authorized Signatory
Per:	__________________________________
	Authorized Signatory
CITIBANK, N.A., CANADIAN BRANCH
Per:	__________________________________
	Authorized Signatory
BANK OF TOKYO-MITSUBISHI UFJ (CANADA)
Per:	__________________________________
	Authorized Signatory
Per:	__________________________________
	Authorized Signatory
THE TORONTO-DOMINION BANK
Per:	__________________________________
	Authorized Signatory
Per:	__________________________________
	Authorized Signatory

EX-31.1

Exhibit 31.1

KINDER MORGAN, INC.
CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934,
AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

	I, Richard D. Kinder, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Kinder Morgan, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 10, 2006
	/s/ Richard D. Kinder
	Richard D. Kinder Chairman and Chief Executive Officer

EX-31.2

Exhibit 31.2

KINDER MORGAN, INC.
CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934,
AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

	I, Kimberly A. Dang, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Kinder Morgan, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 10, 2006
	/s/ Kimberly A. Dang
	Kimberly A. Dang Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

KINDER MORGAN, INC.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906

OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Kinder Morgan, Inc. (the “Company”) for the period ended March 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to Kinder Morgan, Inc. and will be retained by Kinder Morgan, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Dated:  May 10, 2006	/s/ Richard D. Kinder
	Richard D. Kinder Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.2

KINDER MORGAN, INC.

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Kinder Morgan, Inc. (the “Company”) for the period ended March 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to Kinder Morgan, Inc. and will be retained by Kinder Morgan, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Dated:  May 10, 2006	/s/ Kimberly A. Dang
	Kimberly A. Dang Vice President and Chief Financial Officer

EX-99.1

Exhibit 99.1

                                  F O R M 10-Q

                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

              [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

              [ ] 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: 1-11234

                       KINDER MORGAN ENERGY PARTNERS, L.P.

             (Exact name of registrant as specified in its charter)

            DELAWARE                                            76-0380342

  (State or other jurisdiction                               (I.R.S. Employer

of incorporation or organization)                           Identification No.)

               500 Dallas Street, Suite 1000, Houston, Texas 77002

               (Address of principal executive offices)(zip code)

        Registrant's telephone number, including area code: 713-369-9000

     Indicate by check mark whether the registrant (1) has filed all reports

required to be filed by Section 13 or 15(d) of the Securities Exchange Act of

1934 during the preceding 12 months (or for such shorter period that the

registrant was required to file such reports), and (2) has been subject to such

filing requirements for the past 90 days. Yes [X] No

     Indicate by check mark whether the registrant is a large accelerated filer,

an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of

the Securities Exchange Act of 1934). Large accelerated filer [X] Accelerated

filer [ ] Non-accelerated filer [ ]

     Indicate by check mark whether the registrant is a shell company (as

defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]

     The Registrant had 157,019,676 common units outstanding as of April 28,

2006.

                                        1

<PAGE>

                       KINDER MORGAN ENERGY PARTNERS, L.P.

                                TABLE OF CONTENTS

                                                                           Page

                                                                          Number

                          PART I. FINANCIAL INFORMATION

Item 1:  Financial Statements (Unaudited)..................................  3

           Consolidated Statements of Income-Three Months Ended

             March 31, 2006 and 2005.......................................  3

           Consolidated Balance Sheets - March 31, 2006 and

             December 31, 2005.............................................  4

           Consolidated Statements of Cash Flows - Three Months

             Ended March 31, 2006 and 2005.................................  5

           Notes to Consolidated Financial Statements......................  6

Item 2:  Management's Discussion and Analysis of Financial

           Condition and Results of Operations............................. 52

           Critical Accounting Policies and Estimates...................... 52

           Results of Operations........................................... 52

           Financial Condition............................................. 65

           Information Regarding Forward-Looking Statements................ 72

Item 3:  Quantitative and Qualitative Disclosures About Market Risk........ 74

Item 4:  Controls and Procedures........................................... 74

                           PART II. OTHER INFORMATION

Item 1:  Legal Proceedings................................................. 75

Item 1A: Risk Factors...................................................... 75

Item 2:  Unregistered Sales of Equity Securities and Use of Proceeds....... 75

Item 3:  Defaults Upon Senior Securities................................... 75

Item 4:  Submission of Matters to a Vote of Security Holders............... 75

Item 5:  Other Information................................................. 75

Item 6:  Exhibits.......................................................... 75

         Signature......................................................... 77

                                       2

<PAGE>

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                     (In Thousands Except Per Unit Amounts)

                                   (Unaudited)

                                                   Three Months  Ended March 31,

                                                   ------------  ---------------

                                                       2006           2005

                                                    ----------   ---------------

Revenues

  Natural gas sales................................... $1,691,392    $1,352,615

  Services............................................    509,502       443,425

  Product sales and other.............................    190,707       175,892

                                                       ----------    ----------

                                                        2,391,601     1,971,932

                                                       ----------    ----------

Costs and Expenses

  Gas purchases and other costs of sales..............  1,677,231     1,337,770

  Operations and maintenance..........................    173,382       138,540

  Fuel and power......................................     50,923        41,940

  Depreciation, depletion and amortization............     92,721        85,027

  General and administrative..........................     60,883        73,852

  Taxes, other than income taxes......................     31,267        25,826

                                                       ----------    ----------

                                                        2,086,407     1,702,955

                                                       ----------    ----------

Operating Income......................................    305,194       268,977

Other Income (Expense)

  Earnings from equity investments....................     24,721        26,072

  Amortization of excess cost of equity investments...     (1,414)       (1,417)

  Interest, net.......................................    (75,706)      (58,727)

  Other, net..........................................      1,775        (1,321)

Minority Interest.....................................     (2,370)       (2,388)

                                                       ----------    ----------

Income Before Income Taxes............................    252,200       231,196

Income Taxes..........................................     (5,491)       (7,575)

                                                       ----------    ----------

Net Income............................................ $  246,709    $  223,621

                                                       -=========    ==========

General Partner's interest in Net Income.............. $  129,528    $  111,727

Limited Partners' interest in Net Income..............    117,181       111,894

                                                       ----------    ----------

Net Income............................................ $  246,709    $  223,621

                                                       ==========    ==========

Basic and Diluted Limited Partners' Net Income per     $     0.53    $     0.54

                                                       ==========    ==========

Unit..................................................

Weighted average number of units used in computation

of Limited

  Partners' Net Income per unit:

Basic.................................................    220,753       207,528

                                                       ==========    ==========

Diluted...............................................    221,080       207,584

                                                       ==========    ==========

Per unit cash distribution declared................... $     0.81    $     0.76

                                                       ==========    ==========

       The accompanying notes are an integral part of these consolidated

                             financial statements.

                                       3

<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                 (In Thousands)

                                   (Unaudited)

                                                       March 31,   December 31,

                                                       ---------   ------------

                                                          2006        2005

                                                          ----        ----

                                     ASSETS

Current Assets

  Cash and cash equivalents........................  $    32,636  $    12,108

  Restricted deposits..............................       33,100            -

  Accounts, notes and interest receivable, net

     Trade.........................................      784,806    1,011,716

     Related parties...............................        3,659        2,543

  Inventories

     Products......................................       15,367       18,820

     Materials and supplies........................       13,851       13,292

  Gas imbalances

     Trade.........................................       13,781       18,220

     Related parties...............................        3,111            -

  Gas in underground storage.......................       45,616        7,074

  Other current assets.............................       93,177      131,451

                                                     -----------  -----------

                                                       1,039,104    1,215,224

                                                     -----------  -----------

Property, Plant and Equipment, net.................    9,210,903    8,864,584

Investments........................................      434,684      419,313

Notes receivable

  Trade............................................        1,438        1,468

  Related parties..................................       92,003      109,006

Goodwill...........................................      798,959      798,959

Other intangibles, net.............................      216,588      217,020

Deferred charges and other assets..................      227,572      297,888

                                                     -----------  -----------

Total Assets.......................................  $12,021,251  $11,923,462

                                                     ===========  ===========

                        LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities

  Accounts payable

     Cash book overdrafts.......................     $    42,198  $    30,408

     Trade......................................         681,252      996,174

     Related parties............................           5,370       16,676

  Current portion of long-term debt.............               -            -

  Accrued interest..............................          42,898       74,886

  Accrued taxes.................................          40,862       23,536

  Deferred revenues.............................          12,281       10,523

  Gas imbalances

     Trade......................................          13,189       22,948

     Related parties............................               -        1,646

  Accrued other current liabilities.............         643,703      632,088

                                                     -----------  -----------

                                                       1,481,753    1,808,885

                                                     -----------  -----------

Long-Term Liabilities and Deferred Credits

  Long-term debt

     Outstanding................................       5,704,920    5,220,887

     Market value of interest rate swaps........          10,239       98,469

                                                     -----------  -----------

                                                       5,715,159    5,319,356

  Deferred revenues.............................           5,846        6,735

  Deferred income taxes.........................          70,632       70,343

  Asset retirement obligations..................          42,721       42,417

  Other long-term liabilities and deferred credits     1,086,598    1,019,655

                                                     -----------  -----------

                                                       6,920,956    6,458,506

                                                     -----------  -----------

Commitments and Contingencies (Note 3)

Minority Interest...............................         131,087       42,331

                                                     -----------  -----------

Partners' Capital

  Common Units..................................       2,638,137    2,680,352

  Class B Units.................................         108,165      109,594

  i-Units.......................................       1,814,526    1,783,570

  General Partner...............................         122,021      119,898

  Accumulated other comprehensive loss..........      (1,195,394)  (1,079,674)

                                                     -----------  -----------

                                                       3,487,455    3,613,740

                                                     -----------  -----------

Total Liabilities and Partners' Capital.........     $12,021,251  $11,923,462

                                                     ===========  ===========

        The accompanying notes are an integral part of these consolidated

                             financial statements.

                                       4

<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

         (Increase/(Decrease) in Cash and Cash Equivalents In Thousands)

                                   (Unaudited)

                                                           Three Months Ended

                                                                March 31,

                                                         ----------------------

                                                             2006       2005

                                                         ----------  ----------

Cash Flows From Operating Activities

  Net income............................................ $  246,709  $  223,621

  Adjustments to reconcile net income to net cash

  provided by operating activities:

    Depreciation, depletion and amortization............     92,721      85,027

    Amortization of excess cost of equity investments...      1,414       1,417

    Earnings from equity investments....................    (24,721)    (26,072)

  Distributions from equity investments.................     22,378      13,386

  Changes in components of working capital:

    Accounts receivable.................................    236,029      49,284

    Other current assets................................    (22,329)    (10,239)

    Inventories.........................................      2,898      (2,245)

    Accounts payable....................................   (326,208)    (95,343)

    Accrued liabilities.................................    (44,324)    (12,429)

    Accrued taxes.......................................     17,397      15,636

  Other, net............................................    (25,950)     17,464

                                                         ----------  ----------

Net Cash Provided by Operating Activities...............    176,014     259,507

                                                         ----------  ----------

Cash Flows From Investing Activities

  Acquisitions of assets................................   (240,000)     (6,476)

  Additions to property, plant and equip. for

  expansion and maintenance projects....................   (193,663)   (143,808)

  Sale of investments, property, plant and equipment,

  net of removal costs..................................       (272)      2,900

  Investments in margin deposits........................    (33,100)    (18,096)

  Contributions to equity investments...................         (2)        (18)

  Natural gas stored underground and natural gas

  liquids line-fill.....................................     (9,833)     (1,905)

  Other.................................................     (2,988)       (588)

                                                         ----------  ----------

Net Cash Used in Investing Activities...................   (479,858)   (167,991)

                                                         ----------  ----------

Cash Flows From Financing Activities

  Issuance of debt......................................  1,148,000   1,327,433

  Payment of debt.......................................   (664,267) (1,182,630)

  Debt issue costs......................................       (450)     (4,477)

  Increase (Decrease) in cash book overdrafts...........     11,789      (8,560)

  Proceeds from issuance of common units................         83       1,167

  Contributions from minority interest..................     91,043         409

  Distributions to partners:

    Common units........................................   (125,873)   (109,191)

    Class B units.......................................     (4,251)     (3,932)

    General Partner.....................................   (127,405)   (107,585)

    Minority interest...................................     (3,477)     (2,761)

  Other, net............................................       (838)     (1,389)

                                                         ----------  ----------

Net Cash Provided by (Used in) Financing Activities.....    324,354     (91,516)

                                                         ----------  ----------

Effect of exchange rate changes on cash and cash

equivalents.............................................         18          --

                                                         ----------  ----------

Increase (Decrease) in Cash and Cash Equivalents........     20,528          --

Cash and Cash Equivalents, beginning of period..........     12,108          --

                                                         ----------  ----------

Cash and Cash Equivalents, end of period................ $   32,636  $       --

                                                         ==========  ==========

Noncash Investing and Financing Activities:

  Contribution of net assets to partnership

  investments........................................... $   17,003  $       --

  Assets acquired by the assumption of liabilities...... $       --  $      284

        The accompanying notes are an integral part of these consolidated

                             financial statements.

                                       5

<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                   (Unaudited)

1.  Organization

  General

     Unless the context requires otherwise, references to "we," "us," "our" or

the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. and

its consolidated subsidiaries. We have prepared the accompanying unaudited

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 which are solely

normal and recurring adjustments that are, in the opinion of our management,

necessary for a fair presentation of our financial results for the interim

periods. You should read these 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.

     Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management,

LLC

     Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of

Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware

corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,

Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report.

     Kinder Morgan Management, LLC, a Delaware limited liability company, was

formed on February 14, 2001. Our general partner owns all of Kinder Morgan

Management, LLC's voting securities and, pursuant to a delegation of control

agreement, our general partner delegated to Kinder Morgan Management, LLC, to

the fullest extent permitted under Delaware law and our partnership agreement,

all of its power and authority to manage and control our business and affairs,

except that Kinder Morgan Management, LLC cannot take certain specified actions

without the approval of our general partner. Under the delegation of control

agreement, Kinder Morgan Management, LLC manages and controls our business and

affairs and the business and affairs of our operating limited partnerships and

their subsidiaries. Furthermore, in accordance with its limited liability

company agreement, Kinder Morgan Management, LLC's activities are limited to

being a limited partner in, and managing and controlling the business and

affairs of us, our operating limited partnerships and their subsidiaries. Kinder

Morgan Management, LLC is referred to as "KMR" in this report.

     Basis of Presentation

     Our consolidated financial statements include our accounts and those of our

operating partnerships and their majority-owned and controlled subsidiaries. All

significant intercompany items have been eliminated in consolidation.

     Net Income Per Unit

     We compute Basic Limited Partners' Net Income per Unit by dividing our

limited partners' interest in net income by the weighted average number of units

outstanding during the period. Diluted Limited Partners' Net Income per Unit

reflects the maximum potential dilution that could occur if units whose issuance

depends on the market price of the units at a future date were considered

outstanding, or if, by application of the treasury stock method, options to

issue units were exercised, both of which would result in the issuance of

additional units that would then share in our net income.

                                       6

<PAGE>

2.  Acquisitions and Joint Ventures

     During the first three months of 2006, we completed the following

acquisition. The acquisition was 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 this

acquisition 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. We

contributed $160.0 million, which corresponded to our 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,

Entegra 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 our 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, we 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.

     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, we paid EnCana approximately $4.6 million

in cash as consideration for purchase prince 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 thousands):

        Purchase price:

          Cash paid, including transaction costs..........  $ 240,000

          Liabilities assumed.............................         --

                                                            ---------

          Total purchase price............................  $ 240,000

                                                            =========

        Allocation of purchase price:

          Current assets..................................  $      --

          Property, plant and equipment...................    240,000

          Deferred charges and other assets...............         --

                                                            ---------

                                                            $ 240,000

     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 since

January 1, 2005, including the one 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. Amounts presented below are

in thousands, except for the per unit amounts:

                                       7

<PAGE>

                                                              Pro Forma

                                                    Three Months Ended March 31,

                                                    ----------------------------

                                                         2006           2005

                                                    ------------   -------------

                                                            (Unaudited)

Revenues..........................................  $  2,398,260   $  2,004,783

Operating Income..................................       305,331        277,706

Net Income........................................  $    245,656   $    228,690

Basic Limited Partners' Net Income per unit.......  $       0.53   $       0.56

Diluted Limited Partners' Net Income per unit.....  $       0.53   $       0.56

     Acquisitions Subsequent to March 31, 2006

     Oil and Gas Properties

     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 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 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.

     April 2006 Terminal Assets

     In April 2006, we 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 our 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 our existing Texas petroleum

coke terminal operations and maximizes the value of our existing deepwater

terminal by providing customers with both rail and vessel transportation options

for bulk products. Thirdly, we 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 our

existing rail transloading operations. All of the acquired assets are included

in our Terminals 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

business segment.

3.   Litigation, Environmental and Other Contingencies

     Federal Energy Regulatory Commission Proceedings

     SFPP, L.P.

     SFPP, L.P., referred to in this report as SFPP, is the subsidiary limited

partnership that owns our 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 our Pacific operations' pipeline systems.

                                       8

<PAGE>

     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 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.

                                       9

<PAGE>

     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. We 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,

L.P. 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, L.P. 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 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.

                                       10

<PAGE>

     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:

     o    Navajo's argument that its prior settlement with SFPP's predecessor

          did not limit its right to seek reparations;

     o    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;

     o    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

     o    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 our Rocky Mountain 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).

                                       11

<PAGE>

   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 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

                                       12

<PAGE>

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.

     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

                                       13

<PAGE>

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 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

                                       14

<PAGE>

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.

     We 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. We

now assume 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 our Pacific operations in the FERC Docket Nos. OR92-8

and OR96-2 proceedings. In 2005, we recorded an accrual of $105.0 million for an

expense attributable to an increase in our reserves related to our rate case

liability. We had previously estimated the combined annual impact of the rate

reductions and the payment of reparations sought by shippers 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 will be less than 15 cents per unit. The actual, partial year

impact on 2006 distributable cash flow per unit will likely be closer to 5 cents

per unit.

     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.

                                       15

<PAGE>

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 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,

                                       16

<PAGE>

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

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

                                       17

<PAGE>

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 CPUC complaints 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. Shippers on our pipelines do 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 such challenges 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).

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     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.

     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

                                       19

<PAGE>

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 (78th 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.

     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

                                       20

<PAGE>

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 (8th 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.

     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, L.P. 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.

                                       21

<PAGE>

     In April 2006, we paid UPRR $15.3 million in satisfaction of our rental

obligations through December 31, 2003. However, we do not believe that the

assessment of interest awarded Southern Pacific Transportation Company on rental

amounts owing as of May 7, 1997 was proper, and we are seeking appellate review

of the interest award.

     In addition, SFPP, L.P. 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 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 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 10th 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

                                       22

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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 10th Circuit Court of

Appeals.

     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 "Kinder Morgan Defendants"). The complaint purports to

bring a class action on behalf of those who purchased natural gas from the

CenterPoint defendants 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 (189th

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

                                       23

<PAGE>

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

14th 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.

     Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No.

2005-36174 (333rd 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 report 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. 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, we announced that the Federal Bureau of Investigation is

conducting an investigation related to our coal terminal facilities located in

Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves

certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal

terminals that occurred from 1997 through 2001. During this time period, we sold

excess coal from these two terminals for our 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, we collected, and, from 1997 through 2001, we subsequently sold, excess

coal for our own account, as we believed we were entitled to do under

then-existing customer contracts.

     We have conducted an internal investigation of the allegations and

discovered no evidence of wrongdoing or improper activities at these two

terminals. Furthermore, we have contacted customers of these terminals during

the applicable time period and have offered to share information with them

regarding our excess coal sales. Over the five year period from 1997 to 2001, we

moved almost 75 million tons of coal through these terminals, of which less than

1.4 million tons were sold for our own account (including both excess coal and

coal purchased on the open market). We have not added to our inventory of excess

coal since 1999 and we have not sold coal for our own account since 2001, except

for minor amounts of scrap coal. We are fully cooperating with federal law

enforcement authorities in this investigation. In September 2005 and subsequent

thereto, we 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 our 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

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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. In addition, a complaint was filed by the city of Cincinnati,

described further below.

     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 we had a legal

duty to monitor the movement of the railcar en route to our terminal and

guarantee its timely arrival in a safe and stable condition.

     On October 28, 2005, we filed an answer denying the material allegations of

the complaint. On December 1, 2005, the plaintiffs filed a motion for class

certification. On December 12, 2005, we 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

our motion for additional time to conduct class discovery. The court has not

established a scheduling order or trial date, and discovery is ongoing.

     On September 6, 2005, the city of Cincinnati, the plaintiff, 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 reported 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, Kinder Morgan filed a motion to dismiss the parens patriae

claim. On December 15, 2005, Kinder Morgan filed a motion for summary judgment.

The plaintiff has not responded to either motion. A trial date has not been set.

     Leukemia Cluster Litigation

     We are 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, our own preliminary

investigation, and the positive results of investigations conducted by State and

Federal agencies, we believe that the claims against us in these matters are

without merit and intend 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, we were 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

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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 9th Circuit. On March 15, 2004, the 9th 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 9th Circuit. On November 17, 2003, the 9th 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 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 9th Circuit. On March 31, 2006, the 9th 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 9th

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 us

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

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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 us 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 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

     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, L.P. 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

                                       27

<PAGE>

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. We 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, L.P. 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 us relating to this incident

assessing civil fines of $140,000 based upon our 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 us which also alleges

that we 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 our work site, nor did we 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 we have 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 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 SFPP/Kinder Morgan 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

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<PAGE>

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

SFPP/Kinder Morgan 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 SFPP/Kinder Morgan's 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 our investigation of the cause of the rupture of SFPP, LP's

petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and

fire, we have denied liability for the resulting deaths, injuries and damages,

are vigorously defending against such claims, and seeking contribution and

indemnity from the responsible parties.

     Cordelia, California

     On April 28, 2004, SFPP, L.P. 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, 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, we were contacted by the U.S. Coast Guard regarding a

potential release of jet fuel in the Oakland, California area. Our northern

California team responded and discovered that one of our product pipelines had

been damaged by a third party, which resulted in a release of jet fuel which

migrated to the storm drain system and the Oakland estuary. We have coordinated

the remediation of the impacts from this release, and are 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.

The United States Environmental Protection Agency, 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. We are currently in settlement negotiations with these

agencies. We will vigorously contest any unsupported, duplicative or excessive

civil penalty claims, but hope to be able to resolve the demands by each

governmental entity through out-of-court settlements.

     Donner Summit, California

     In April 2005, our 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. We have received

civil penalty claims on behalf of the United States Environmental

                                       29

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Protection Agency, the California Department of Fish and Game, and the Lahontan

Regional Water Quality Control Board. We are currently in settlement

negotiations with these agencies. We will vigorously contest any unsupported,

duplicative or excessive civil penalty claims, but hope to be able to resolve

the demands by each governmental entity through out-of-court settlements.

     Baker California

     In November 2004, near Baker, California, our 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 us, 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

United States Environmental Protection Agency (referred to in this report as 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

our products pipeline integrity management program. The violations alleged in

the proposed order are based upon the results of inspections of our integrity

management program at our 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 us implement a number of

changes to our integrity management program and also seeks to impose a proposed

civil penalty of approximately $0.3 million. We have already addressed a number

of the concerns identified by the OPS and intend to continue to work with the

OPS to ensure that our integrity management program satisfies all applicable

regulations. However, we dispute some of the OPS findings and disagree 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. We

have 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.

     Pipeline and Hazardous Materials Safety Administration Corrective Action

Order

     On August 26, 2005, we announced that we had received a Corrective Action

Order issued by the PHMSA. The corrective order instructs us to comprehensively

address potential integrity threats along the pipelines that comprise our

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

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third-party damage caused by an excavator or damage caused during pipeline

construction.

     Following the issuance of the corrective order, we engaged in cooperative

discussions with the PHMSA and we 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, we announced the final consent agreement, which will,

among other things, require us to perform a thorough analysis of recent pipeline

incidents, provide for a third-party independent review of our operations and

procedural practices, and restructure our internal inspections program.

Furthermore, we have reviewed all of our policies and procedures and are

currently implementing various measures to strengthen our integrity management

program, including a comprehensive evaluation of internal inspection

technologies and other methods to protect our pipelines. We expect to spend

approximately $90 million on pipeline integrity activities for our 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 our

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. We filed our answer to the

complaint on June 27, 2003, in which we 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 us, GATX Terminals' indemnification obligations, if any,

to ST Services may have passed to us. Consequently, at issue is any

indemnification obligation we 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 dismissed 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.

                                       31

<PAGE>

     Other Environmental

     Our Kinder Morgan Transmix Company has been in discussions with the United

States Environmental Protection Agency 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 we failed to comply with certain

sampling protocols at our Indianola, Pennsylvania transmix facility in violation

of the Clean Air Act's provisions governing fuel. The EPA further claims that we

improperly accepted hazardous waste at our transmix facility in Indianola.

Finally, the EPA claims that we failed to obtain batch samples of gasoline

produced at our Hartford (Wood River), Illinois facility in 2004. In addition to

injunctive relief that would require us to maintain additional oversight of our

quality assurance program at all of our transmix facilities, the EPA is seeking

monetary penalties of $0.6 million.

     Our review of assets related to Kinder Morgan Interstate Gas Transmission

LLC indicates possible environmental impacts from petroleum and used oil

releases into the soil and groundwater at nine sites. Additionally, our review

of assets related to Kinder Morgan Texas Pipeline and Kinder Morgan Tejas

indicates possible environmental impacts from petroleum releases into the soil

and groundwater at nine sites. Further delineation and remediation of any

environmental impacts from these matters will be conducted. Reserves have been

established to address these issues.

     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 $50.1 million.

     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.

                                       32

<PAGE>

4.  Asset Retirement Obligations

     We account for our legal obligations associated with the retirement of

long-lived assets pursuant to Statement of Financial Accounting Standards No.

143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides

accounting and reporting guidance for legal obligations associated with the

retirement of long-lived assets that result from the acquisition, construction

or normal operation of a long-lived asset.

     SFAS No. 143 requires companies to record a liability relating to the

retirement and removal of assets used in their businesses. Under SFAS No. 143,

the fair value of asset retirement obligations are recorded as liabilities on a

discounted basis when they are incurred, which is typically at the time the

assets are installed or acquired. Amounts recorded for the related assets are

increased by the amount of these obligations. Over time, the liabilities will be

accreted for the change in their present value and the initial capitalized costs

will be depreciated over the useful lives of the related assets. The liabilities

are eventually extinguished when the asset is taken out of service.

     In our CO2 business segment, we are required to plug and abandon oil and

gas wells that have been removed from service and to remove our surface wellhead

equipment and compressors. As of March 31, 2006, we have recognized asset

retirement obligations in the aggregate amount of $41.9 million relating to

these requirements at existing sites within our CO2 business segment.

     In our Natural Gas Pipelines business segment, if we were to cease

providing utility services, we would be required to remove surface facilities

from land belonging to our customers and others. Our Texas intrastate natural

gas pipeline group has various condensate drip tanks and separators located

throughout its natural gas pipeline systems, as well as inactive gas processing

plants, laterals and gathering systems which are no longer integral to the

overall mainline transmission systems, and asbestos-coated underground pipe

which is being abandoned and retired. Our Kinder Morgan Interstate Gas

Transmission system has compressor stations which are no longer active and other

miscellaneous facilities, all of which have been officially abandoned. We

believe we can reasonably estimate both the time and costs associated with the

retirement of these facilities. As of March 31, 2006, we have recognized asset

retirement obligations in the aggregate amount of $1.6 million relating to the

businesses within our Natural Gas Pipelines business segment.

     We have included $0.8 million of our total asset retirement obligations as

of March 31, 2006 with "Accrued other current liabilities" in our accompanying

consolidated balance sheet. The remaining $42.7 million obligation is reported

separately as a non-current liability. No assets are legally restricted for

purposes of settling our asset retirement obligations. A reconciliation of the

beginning and ending aggregate carrying amount of our asset retirement

obligations for each of the three months ended March 31, 2006 and 2005 is as

follows (in thousands):

                                              Three Months Ended March 31,

                                              ----------------------------

                                                    2006         2005

                                              -------------  -------------

        Balance at beginning of period.........   $ 43,227    $ 38,274

          Liabilities incurred.................         58        (238)

          Liabilities settled..................       (350)       (233)

          Accretion expense....................        596         520

          Revisions in estimated cash flows....         --          --

                                                  --------    --------

        Balance at end of period...............   $ 43,531    $ 38,323

                                                  ========    ========

5.  Distributions

     On February 14, 2006, we paid a cash distribution of $0.80 per unit to our

common unitholders and our Class B unitholders for the quarterly period ended

December 31, 2005. KMR, our sole i-unitholder, received 997,180 additional

i-units based on the $0.80 cash distribution per common unit. The distributions

were declared on January 18, 2006, payable to unitholders of record as of

January 31, 2006.

     On April 19, 2006, we declared a cash 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. Our common unitholders

and Class B unitholders will receive cash. KMR will receive a distribution in

the form of additional

                                       33

<PAGE>

i-units based on the $0.81 distribution per common unit. The number of i-units

distributed will be 1,093,826. For each outstanding i-unit that KMR holds, a

fraction of an i-unit (0.018566) will be issued. The fraction was determined by

dividing:

     o    $0.81, the cash amount distributed per common unit

          by

     o    $43.629, the average of KMR's shares' closing market prices from April

          11-25, 2006, the ten consecutive trading days preceding the date on

          which the shares began to trade ex-dividend under the rules of the New

          York Stock Exchange.

6.      Intangibles

     Our intangible assets include goodwill, lease value, contracts, customer

relationships and agreements. Excluding goodwill, our other 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 our accompanying consolidated balance sheets. For our investments in

affiliated entities that are included in our consolidation, the excess cost over

underlying fair value of net assets is referred to as goodwill and reported

separately as "Goodwill" in our accompanying consolidated balance sheets.

According to the provisions of SFAS No. 142, "Goodwill and Other Intangible

Assets," goodwill is not subject to amortization but must be tested for

impairment at least annually.

     Following is information related to our intangible assets subject to

amortization and our goodwill (in thousands):

                                             March 31,    December 31,

                                                2006          2005

                                             ---------    ------------

          Goodwill

            Gross carrying amount......... $  813,101     $  813,101

            Accumulated amortization......    (14,142)       (14,142)

                                           ----------     ----------

            Net carrying amount...........    798,959        798,959

                                           ----------     ----------

          Lease value

            Gross carrying amount.........      6,592          6,592

            Accumulated amortization......     (1,204)        (1,168)

                                           ----------     ----------

            Net carrying amount...........      5,388          5,424

                                           ----------     ----------

          Contracts and other

            Gross carrying amount.........    224,250        221,250

            Accumulated amortization......    (13,050)        (9,654)

                                           ----------     ----------

            Net carrying amount...........    211,200        211,596

                                           ----------     ----------

          Total intangibles, net.......... $1,015,547     $1,015,979

                                           ==========     ==========

   Amortization expense on our intangibles consisted of the following (in

thousands):

                                          Three Months Ended March 31,

                                              2006            2005

                                          -----------      -----------

             Lease value...............     $    36          $   36

             Contracts and other.......       3,396             330

                                            -------          ------

             Total amortization........     $ 3,432          $  366

                                            =======          ======

     As of March 31, 2006, our weighted average amortization period for our

intangible assets was approximately 19.3 years. Our estimated amortization

expense for these assets for each of the next five fiscal years is approximately

$13.3 million, $13.2 million, $12.0 million, $11.8 million and $11.7 million,

respectively.

     There were no changes in the carrying amount of our goodwill for the three

months ended March 31, 2006. The carrying amount of our goodwill as of March 31,

2006 and as of December 31, 2005 is summarized as follows (in thousands):

                                       34

<PAGE>

                           Products   Natural Gas

                           Pipelines   Pipelines    CO2    Terminals    Total

                           ---------   ---------    ---    ---------    -----

Balance as of

March 31, 2006 and

December 31, 2005........  $ 263,182  $ 288,435  $ 46,101  $ 201,241  $ 798,959

                           =========  =========  ========  =========  =========

     In addition, pursuant to ABP No. 18, any premium paid by an investor, which

is analogous to goodwill, must be identified. For the investments we account for

under the equity method of accounting, this premium or excess cost over

underlying fair value of net assets is referred to as equity method goodwill.

According to the provisions of SFAS No. 142, equity method goodwill is not

subject to amortization but rather to impairment testing in accordance with

Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for

Investments in Common Stock." The impairment test under APB No. 18 considers

whether the fair value of the equity investment as a whole, not the underlying

net assets, has declined and whether that decline is other than temporary.

Therefore, in addition to our annual impairment test of goodwill, we

periodically reevaluate the amount at which we carry the excess of cost over

fair value of net assets accounted for under the equity method. As of both March

31, 2006 and December 31, 2005, we have reported $138.2 million in equity method

goodwill within the caption "Investments" in our accompanying consolidated

balance sheets.

     We also, periodically, reevaluate the difference between the fair value of

net assets accounted for under the equity method and our proportionate share of

the underlying book value (that is, the investee's net assets per its financial

statements) of the investee at date of acquisition. In almost all instances,

this differential, relating to the discrepancy between our share of the

investee's recognized net assets at book values and at current fair values,

represents our share of undervalued depreciable assets, and since those assets

(other than land) are subject to depreciation, we amortize this portion of our

investment cost against our share of investee earnings. We reevaluate this

differential, as well as the amortization period for such undervalued

depreciable assets, to determine whether current events or circumstances warrant

adjustments to our carrying value and/or revised estimates of useful lives in

accordance with APB Opinion No. 18.

7.   Debt

     Our outstanding short-term debt as of March 31, 2006 was $1,060.8 million.

The balance consisted of:

     o    $1,051.3 million of commercial paper borrowings;

     o    a $5.7 million portion of 5.23% senior notes (our subsidiary, Kinder

          Morgan Texas Pipeline, L.P., is the obligor on the notes); and

     o    a $5 million portion of 7.84% senior notes (our subsidiary, Central

          Florida Pipe Line LLC, is the obligor on the notes); and

     o    an offset of $1.2 million (which represents the net of other

          borrowings and the accretion of discounts on our senior note

          issuances).

     As of March 31, 2006, we intended and had the ability to refinance all of

our short-term debt on a long-term basis under our unsecured long-term credit

facility. Accordingly, such amounts have been classified as long-term debt in

our accompanying consolidated balance sheet.

     The weighted average interest rate on all of our borrowings was

approximately 5.527% during the first quarter of 2006 and 4.901% during the

first quarter of 2005.

     Credit Facility

     As of March 31, 2006, we had two credit facilities:

     o    a $1.6 billion unsecured five-year credit facility due August 18,

          2010; and

                                       35

<PAGE>

     o    a $250 million unsecured nine-month credit facility due November 21,

          2006.

     We entered into our nine-month credit facility on February 22, 2006, and

this facility contains borrowing rates and restrictive financial covenants that

are similar to the borrowing rates and covenants under our $1.6 billion bank

facility. Our credit facilities are with a syndicate of financial institutions,

and Wachovia Bank, National Association is the administrative agent. There were

no borrowings under either credit facility as of March 31, 2006, and there were

no borrowings under our five-year credit facility as of December 31, 2005.

     The amount available for borrowing under our credit facilities as of March

31, 2006 was reduced by:

     o    our outstanding commercial paper borrowings ($1,051.3 million as of

          March 31, 2006);

     o    a combined $394 million in five letters of credit that support our

          hedging of commodity price risks associated with the sale of natural

          gas, natural gas liquids, oil and carbon dioxide;

     o    a combined $49 million in two letters of credit that support

          tax-exempt bonds; and

     o    $16.2 million of other letters of credit supporting other obligations

          of us and our subsidiaries.

     Interest Rate Swaps

     Information on our interest rate swaps is contained in Note 10.

     Commercial Paper Program

     As of December 31, 2005, our commercial paper program provided for the

issuance of up to $1.6 billion of commercial paper. In April 2006, we increased

our commercial paper program by $250 million to provide for the issuance of up

to $1.85 billion. As of March 31, 2006, we had $1,051.3 million of commercial

paper outstanding with an average interest rate of 4.6854%. Borrowings under our

commercial paper program reduce the borrowings allowed under our credit

facilities.

     Debt Issuances 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 our credit facilities.

     Rockies Express Pipeline LLC is a limited liability company owned 66 2/3%

and controlled by us. Sempra Energy holds the remaining 33 1/3% ownership

interest. Both we and Sempra have agreed to guarantee borrowings under the

Rockies Express credit facility in the same proportion as our percentage

ownership of the member interests in Rockies Express Pipeline LLC.

     Contingent Debt

     We apply the provisions of Financial Accounting Standards Board

Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements

for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our

agreements that contain guarantee or indemnification clauses. These disclosure

provisions expand those required by SFAS No. 5, "Accounting for Contingencies,"

by requiring a guarantor to disclose certain types of guarantees, even if the

likelihood of requiring the guarantor's performance is remote. The following is

a description of our contingent debt agreements.

                                       36

<PAGE>

     Cortez Pipeline Company Debt

     Pursuant to a certain Throughput and Deficiency Agreement, the partners of

Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a

subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline

Company - 13% partner) are required, on a several, percentage ownership basis,

to contribute capital to Cortez Pipeline Company in the event of a cash

deficiency. The Throughput and Deficiency Agreement contractually supports the

borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez

Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund

cash deficiencies at Cortez Pipeline Company, including cash deficiencies

relating to the repayment of principal and interest on borrowings by Cortez

Capital Corporation. Parent companies of the respective Cortez Pipeline Company

partners further severally guarantee, on a percentage basis, the obligations of

the Cortez Pipeline Company partners under the Throughput and Deficiency

Agreement.

     Due to our indirect ownership of Cortez Pipeline Company through Kinder

Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez

Capital Corporation. Shell Oil Company shares our several guaranty obligations

jointly and severally; however, we are obligated to indemnify Shell for

liabilities it incurs in connection with such guaranty. With respect to Cortez's

long-term revolving credit facility, Shell is released of its guaranty

obligations on December 31, 2006. Furthermore, with respect to Cortez's

short-term commercial paper program and Series D notes, we must use commercially

reasonable efforts to have Shell released of its guaranty obligations by

December 31, 2006. If we are unable to obtain Shell's release in respect of the

Series D Notes by that date, we are required to provide Shell with collateral (a

letter of credit, for example) to secure our indemnification obligations to

Shell.

     As of March 31, 2006, the debt facilities of Cortez Capital Corporation

consisted of:

     o    $75 million of Series D notes due May 15, 2013;

     o    a $125 million short-term commercial paper program; and

     o    a $125 million five-year committed revolving credit facility due

          December 22, 2009 (to support the above-mentioned $125 million

          commercial paper program).

     As of March 31, 2006, Cortez Capital Corporation had $87.1 million of

commercial paper outstanding with an average interest rate of 4.6332%, the

average interest rate on the Series D notes was 7.14%, and there were no

borrowings under the credit facility.

     Red Cedar Gathering Company Debt

     In October 1998, Red Cedar Gathering Company sold $55 million in aggregate

principal amount of Senior Notes due October 31, 2010. The $55 million was sold

in 10 different notes in varying amounts with identical terms.

     The Senior Notes are collateralized by a first priority lien on the

ownership interests, including our 49% ownership interest, in Red Cedar

Gathering Company. The Senior Notes are also guaranteed by us and the other

owner of Red Cedar Gathering Company jointly and severally. The principal is to

be repaid in seven equal installments beginning on October 31, 2004 and ending

on October 31, 2010. As of March 31, 2006, $39.3 million in principal amount of

notes were outstanding.

     Nassau County, Florida Ocean Highway and Port Authority Debt

     Nassau County, Florida Ocean Highway and Port Authority is a political

subdivision of the State of Florida. During 1990, Ocean Highway and Port

Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal

amount of $38.5 million for the purpose of constructing certain port

improvements located in Fernandino Beach, Nassau County, Florida. The bond

indenture is for 30 years and allows the bonds to remain outstanding until

December 1, 2020. A letter of credit was issued as security for the Adjustable

Demand Revenue Bonds and was guaranteed by the parent company of Nassau

Terminals LLC, the operator of the port facilities. In July 2002, we

                                       37

<PAGE>

acquired Nassau Terminals LLC and became guarantor under the letter of credit

agreement. In December 2002, we issued a $28 million letter of credit under our

credit facilities and the former letter of credit guarantee was terminated.

Principal payments on the bonds are made on the first of December each year, and

corresponding reductions are made to the letter of credit. As of March 31, 2006,

this letter of credit had an outstanding balance under our credit facility of

$24.9 million.

     Certain Relationships and Related Transactions

     In conjunction with our acquisition of Natural Gas Pipelines assets from

KMI on December 31, 1999 and 2000, KMI became a guarantor of approximately

$522.7 million of our debt. In conjunction with our acquisition of all of the

partnership interests in TransColorado Gas Transmission Company from two

wholly-owned subsidiaries of KMI on November 1, 2004, KMI became a guarantor of

approximately $210.8 million of our debt. Thus, KMI was a guarantor of a total

of approximately $733.5 million of our debt as of March 31, 2006, and KMI would

be obligated to perform under this guarantee only if we and/or our assets were

unable to satisfy our obligations.

     For additional information regarding our debt facilities, see Note 9 to our

consolidated financial statements included in our Form 10-K for the year ended

December 31, 2005.

8.   Partners' Capital

     As of March 31, 2006 and December 31, 2005, our partners' capital consisted

of the following limited partner units:

                                                March 31,    December31,

                                                  2006          2005

                                               -----------   -----------

          Common units.......................  157,015,376   157,005,326

          Class B units......................    5,313,400     5,313,400

          i-units............................   58,915,553    57,918,373

                                               -----------   -----------

            Total limited partner units......  221,244,329   220,237,099

                                               ===========   ===========

     The total limited partner units represent our limited partners' interest

and an effective 98% economic interest in us, exclusive of our general partner's

incentive distribution rights. Our general partner has an effective 2% interest

in us, excluding its incentive distribution rights.

     As of March 31, 2006, our common unit totals consisted of 142,659,641 units

held by third parties, 12,631,735 units held by KMI and its consolidated

affiliates (excluding our general partner), and 1,724,000 units held by our

general partner. As of December 31, 2005, our common unit total consisted of

142,649,591 units held by third parties, 12,631,735 units held by KMI and its

consolidated affiliates (excluding our general partner) and 1,724,000 units held

by our general partner.

     On both March 31, 2006 and December 31, 2005, our Class B units were held

entirely by a wholly-owned subsidiary of KMI and our i-units were held entirely

by KMR. All of our Class B units were issued to a wholly-owned subsidiary of KMI

in December 2000. The Class B units are similar to our common units except that

they are not eligible for trading on the New York Stock Exchange.

     Our i-units are a separate class of limited partner interests in us. All of

our i-units are owned by KMR and are not publicly traded. In accordance with its

limited liability company agreement, KMR's activities are restricted to being a

limited partner in us, and controlling and managing our business and affairs and

the business and affairs of our operating limited partnerships and their

subsidiaries. Through the combined effect of the provisions in our partnership

agreement and the provisions of KMR's limited liability company agreement, the

number of outstanding KMR shares and the number of i-units will at all times be

equal.

     Under the terms of our partnership agreement, we agreed that we will not,

except in liquidation, make a distribution on an i-unit other than in additional

i-units or a security that has in all material respects the same rights and

privileges as our i-units. The number of i-units we distribute to KMR is based

upon the amount of cash we distribute to the owners of our common units. When

cash is paid to the holders of our common units, we will issue

                                       38

<PAGE>

additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by

KMR will have a value based on the cash payment on the common unit.

     The cash equivalent of distributions of i-units will be treated as if it

had actually been distributed for purposes of determining the distributions to

our general partner. We will not distribute the cash to the holders of our

i-units but will retain the cash for use in our business. If additional units

are distributed to the holders of our common units, we will issue an equivalent

amount of i-units to KMR based on the number of i-units it owns. Based on the

preceding, KMR received a distribution of 997,180 i-units from us on February

14, 2006. These additional i-units distributed were based on the $0.80 per unit

distributed to our common unitholders on that date.

     For the purposes of maintaining partner capital accounts, our partnership

agreement specifies that items of income and loss shall be allocated among the

partners, other than owners of i-units, in accordance with their percentage

interests. Normal allocations according to percentage interests are made,

however, only after giving effect to any priority income allocations in an

amount equal to the incentive distributions that are allocated 100% to our

general partner. Incentive distributions are generally defined as all cash

distributions paid to our general partner that are in excess of 2% of the

aggregate value of cash and i-units being distributed.

     Incentive distributions allocated to our general partner are determined by

the amount quarterly distributions to unitholders exceed certain specified

target levels. Our distribution of $0.80 per unit paid on February 14, 2006 for

the fourth quarter of 2005 required an incentive distribution to our general

partner of $125.6 million. Our distribution of $0.74 per unit paid on February

14, 2005 for the fourth quarter of 2004 required an incentive distribution to

our general partner of $106.0 million. The increased incentive distribution to

our general partner paid for the fourth quarter of 2005 over the distribution

paid for the fourth quarter of 2004 reflects the increase in the amount

distributed per unit as well as the issuance of additional units.

     Our declared distribution for the first quarter of 2006 of $0.81 per unit

will result in an incentive distribution to our general partner of approximately

$128.3 million. This compares to our distribution of $0.76 per unit and

incentive distribution to our general partner of approximately $111.1 million

for the first quarter of 2005.

9.   Comprehensive Income

     SFAS No. 130, "Accounting for Comprehensive Income," requires that

enterprises report a total for comprehensive income. For each of the three

months ended March 31, 2006 and March 31, 2005, the difference between our net

income and our comprehensive income resulted from unrealized gains or losses on

derivatives utilized for hedging purposes and from foreign currency translation

adjustments. For more information on our hedging activities, see Note 10. Our

total comprehensive income is as follows (in thousands):

                                                       Three Months Ended

                                                           March 31,

                                                     ---------------------

                                                       2006          2005

                                                     ---------   ---------

        Net income.................................  $ 246,709   $ 223,621

        Foreign currency translation adjustments...        119        (227)

        Change in fair value of derivatives

        used for hedging purposes..................   (218,012)   (556,835)

        Reclassification of change in fair

        value of derivatives to net income.........    102,173      60,920

                                                     ---------   ---------

          Total other comprehensive income/(loss)..   (115,720)   (496,142)

                                                     ---------   ---------

        Comprehensive income/(loss)................  $ 130,989   $(272,521)

                                                     =========   =========

10.  Risk Management

     Energy Commodity Price Risk Management

     Certain of our business activities expose us to risks associated with

changes in the market price of natural gas, natural gas liquids and crude oil.

We use energy financial instruments to reduce our risk of changes in the prices

of

                                       39

<PAGE>

natural gas, natural gas liquids and crude oil markets, as discussed below.

These risk management instruments are also called derivatives, which are defined

as a financial instrument or other contract which derives its value from the

value of some other (underlying) financial instrument, variable or asset.

Examples of derivative instruments include the following: forward contracts,

futures contracts, options and swaps (also called contracts for differences).

     Pursuant to our management's approved risk management policy, we use energy

financial instruments as a hedging (offset) mechanism against the volatility of

energy commodity prices caused by shifts in the supply and demand for a

commodity, as well as its location. Characteristically, we use energy financial

instruments to hedge or reduce our exposure to price risk associated with:

     o    pre-existing or anticipated physical natural gas, natural gas liquids

          and crude oil sales;

     o    natural gas purchases; and

     o    system use and storage.

     Our risk management activities are primarily used in order to protect our

profit margins and our risk management policies prohibit us from engaging in

speculative trading. Commodity-related activities of our risk management group

are monitored by our risk management committee, which is charged with the review

and enforcement of our management's risk management policy.

     Specifically, our risk management committee is a separately designated

standing committee comprised of 15 executive-level employees of KMI or KMGP

Services Company, Inc. whose job responsibilities involve operations exposed to

commodity market risk and other external risks in the ordinary course of

business. Our risk management committee is chaired by our President and is

charged with the following three responsibilities:

     o    establish and review risk limits consistent with our risk tolerance

          philosophy;

     o    recommend to the audit committee of our general partner's delegate any

          changes, modifications, or amendments to our risk management policy;

          and

     o    address and resolve any other high-level risk management issues.

     A derivative contract's cash flow or fair value fluctuates and varies based

on the changes in one or more underlying variables (for example, a specified

interest rate, commodity price, or other variable), and the contract is based on

one or more notional amounts or payment provisions or both (for example, a

number of commodities, shares, or other units specified in a derivative

instrument). While the value of the underlying variable changes due to changes

in market conditions, the notional amount remains constant throughout the life

of the derivative contract. Together, the underlying and the notional amounts

determine the amount of settlement, and, in some cases, whether or not a

settlement is required.

     Current accounting standards require derivatives to be reflected as assets

or liabilities at their fair market values and current market values should be

used to track changes in derivative holdings; that is, mark-to-market valuation

should be employed. The fair value of our risk management instruments reflects

the estimated amounts that we would receive or pay to terminate the contracts at

the reporting date, thereby taking into account the current unrealized gains or

losses on open contracts. We have available market quotes for substantially all

of the financial instruments that we use, including: commodity futures and

options contracts, fixed price swaps, and basis swaps.

     Furthermore, if a company uses derivatives to hedge the fair value of an

asset, liability, or firm commitment, then reporting changes in the fair value

of the hedged item as well as in the value of the derivative is appropriate. In

SFAS No. 133, the Financial Accounting Standards Board defined these hedges as

fair value hedges, and the balance sheet impact for a fair value hedge results

in both the derivative (asset or liability) and the hedged item being reported

at fair value. When changes in the value of the derivative exactly offset

changes in the value of the hedged item, there should be no impact on earnings

(net income); however, when the derivative is not effective in exactly

offsetting changes in the value of the hedged item, then the ineffective amount

should be included in earnings.

                                       40

<PAGE>

     To be considered effective, changes in the value of the derivative or its

resulting cash flows must substantially offset changes in the value or cash

flows of the item being hedged. A perfectly effective hedge is one in which

changes in the value of the derivative exactly offset changes in the value of

the hedged item or expected cash flow of the future transactions in reporting

periods covered by the hedging instrument. The ineffective portion of the gain

or loss and any component excluded from the computation of the effectiveness of

the derivative instrument is reported in earnings immediately.

     Our energy commodity derivatives hedge the commodity price risks derived

from our normal business activities, which include the sale of natural gas,

natural gas liquids and crude oil, and these derivatives have been designated by

us as cash flow hedges as defined by SFAS No. 133. A cash flow hedge uses a

derivative to hedge the anticipated future cash flow of a transaction that is

expected to occur but whose value is uncertain. With a cash flow hedge, it is

the cash flow from an expected future transaction that is being hedged (as

opposed to the value of an asset, liability, or firm commitment) and so there is

no balance sheet entry for the hedged item.

     According to the provisions of SFAS No. 133, the FASB allows for special

accounting treatment for cash flow hedges--the change in the fair value of the

hedging instrument (derivative), to the extent that the hedge is effective, is

initially reported as a component of other comprehensive income (outside "Net

Income" reported in our consolidated statements of income). Other comprehensive

income consists of those financial items that are included in "Accumulated other

comprehensive loss" in our accompanying consolidated balance sheets but not

included in our net income. Thus, in highly effective cash flow hedges, where

there is no ineffectiveness, other comprehensive income changes by exactly as

much as the derivatives and there is no impact on earnings. When the hedged

forecasted transaction does take place and affects earnings, the effective part

of the hedge is also recognized in the income statement, and the earlier

recognized amounts are removed from "Accumulated other comprehensive loss." If

the forecasted transaction results in an asset or liability, amounts in

"Accumulated other comprehensive loss" should be reclassified into earnings when

the asset or liability affects earnings through cost of sales, depreciation,

interest expense, etc.

     The gains and losses that are included in "Accumulated other comprehensive

loss" in our accompanying consolidated balance sheets are primarily related to

the derivative instruments associated with our hedging of anticipated future

cash flows from the sales and purchases of natural gas, natural gas liquids and

crude oil. As described above, these gains and losses are reclassified into

earnings as the hedged sales and purchases take place. During the three months

ended March 31, 2006, we reclassified $102.2 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 $60.9 million of Accumulated other comprehensive loss into earnings

as a result of hedged forecasted transactions occurring during the period.

     None of the reclassification of Accumulated other comprehensive loss into

earnings during the first three months of 2006 or 2005 resulted from 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, but rather resulted from the hedged forecasted transactions actually

affecting earnings (for example, when the forecasted sales and purchases

actually occurred). For all of our derivatives combined, approximately $437.3

million of the Accumulated other comprehensive loss balance of $1,195.4 million

as of March 31, 2006 is expected to be reclassified into earnings during the

next twelve months.

     As discussed above, the part of the change in the value of derivatives that

are not effective in offsetting undesired changes in expected cash flows (the

ineffective portion) is required to be recognized currently in earnings.

Accordingly, we recognized a loss of $0.2 million during the first quarter of

2006, and a loss of $0.2 million during the first quarter of 2005 as a result of

ineffective hedges. All gains and losses recognized as a result of ineffective

hedges are reported within the captions "Natural gas sales" and "Gas purchases

and other costs of sales" in our accompanying consolidated statements of income.

For each of the three months ended March 31, 2006 and 2005, we did not exclude

any component of the derivative instruments' gain or loss from the assessment of

hedge effectiveness.

     The fair values of our energy financial instruments are included in our

accompanying consolidated balance sheets within "Other current assets,"

"Deferred charges and other assets," "Accrued other current liabilities," "Other

                                       41

<PAGE>

long-term liabilities and deferred credits," and, as of December 31, 2005 only,

"Accounts payable-Related parties." The following table summarizes the fair

values of our energy financial instruments associated with our commodity market

risk management activities and included on our accompanying consolidated balance

sheets as of March 31, 2006 and December 31, 2005 (in thousands):

                                          March 31,      December 31,

                                            2006            2005

                                        -----------    --------------

  Derivatives-net asset/(liability)

    Other current assets................ $  85,789       $ 109,437

    Deferred charges and other assets...    25,459          47,682

    Accounts payable-Related parties....        --         (16,057)

    Accrued other current liabilities...  (514,992)       (507,306)

    Other long-term liabilities and

    deferred credits.................... $(791,307)      $(727,929)

     Our over-the-counter swaps and options are instruments we entered into with

counterparties outside centralized trading facilities such as a futures, options

or stock exchange. These contracts are with a number of parties, all of which

had investment grade credit ratings as of March 31, 2006. We both owe money and

are owed money under these financial instruments. Defaults by counterparties

under over-the-counter swaps and options could expose us to additional commodity

price risks in the event that we are unable to enter into replacement contracts

for such swaps and options on substantially the same terms. Alternatively, we

may need to pay significant amounts to the new counterparties to induce them to

enter into replacement swaps and options on substantially the same terms. While

we enter into derivative transactions principally with investment grade

counterparties and actively monitor their credit ratings, it is nevertheless

possible that from time to time losses will result from counterparty credit risk

in the future.

     In addition, in conjunction with the purchase of exchange-traded

derivatives or when the market value of our derivatives with specific

counterparties exceeds established limits, we are required to provide collateral

to our counterparties, which may include posting letters of credit or placing

cash in margin accounts. As of March 31, 2006, we had five outstanding letters

of credit totaling $394 million in support of our hedging of commodity price

risks associated with the sale of natural gas, natural gas liquids and crude

oil. As of December 31, 2005, we had five outstanding letters of credit totaling

$534 million in support of our hedging of commodity price risks. As of March 31,

2006, our margin deposits associated with our commodity contract positions and

over-the-counter swap partners totaled $33.1 million; as of December 31, 2005,

we had no cash margin deposits associated with our commodity contract positions

and over-the-counter swap partners.

     Certain of our business activities expose us to foreign currency

fluctuations. However, due to the limited size of this exposure, we do not

believe the risks associated with changes in foreign currency will have a

material adverse effect on our business, financial position, results of

operations or cash flows. As a result, we do not significantly hedge our

exposure to fluctuations in foreign currency.

     Interest Rate Risk Management

     In order to maintain a cost effective capital structure, it is our policy

to borrow funds using a mix of fixed rate debt and variable rate debt. As of

both March 31, 2006 and December 31, 2005, we were a party to interest rate swap

agreements with notional principal amounts of $2.1 billion. We entered into

these agreements for the purposes of:

     o    hedging the interest rate risk associated with our fixed rate debt

          obligations; and

     o    transforming a portion of the underlying cash flows related to our

          long- term fixed rate debt securities into variable rate debt in order

          to achieve our desired mix of fixed and variable rate debt.

     Since the fair value of fixed rate debt varies with changes in the market

rate of interest, we enter into swaps to receive fixed and pay variable

interest. Such swaps result in future cash flows that vary with the market rate

of interest, and therefore hedge against changes in the fair value of our fixed

rate debt due to market rate changes.

                                       42

<PAGE>

     As of March 31, 2006, a notional principal amount of $2.1 billion of these

agreements effectively converts the interest expense associated with the

following series of our senior notes from fixed rates to variable rates based on

an interest rate of LIBOR plus a spread:

     o    $200 million principal amount of our 5.35% senior notes due August 15,

          2007;

     o    $250 million principal amount of our 6.30% senior notes due February

          1, 2009;

     o    $200 million principal amount of our 7.125% senior notes due March 15,

          2012;

     o    $250 million principal amount of our 5.0% senior notes due December

          15, 2013;

     o    $200 million principal amount of our 5.125% senior notes due November

          15, 2014;

     o    $300 million principal amount of our 7.40% senior notes due March 15,

          2031;

     o    $200 million principal amount of our 7.75% senior notes due March 15,

          2032;

     o    $400 million principal amount of our 7.30% senior notes due August 15,

          2033; and

     o    $100 million principal amount of our 5.80% senior notes due March 15,

          2035.

     These swap agreements have termination dates that correspond to the

maturity dates of the related series of senior notes, therefore, as of March 31,

2006, the maximum length of time over which we have hedged a portion of our

exposure to the variability in the value of this debt due to interest rate risk

is through March 15, 2035.

     The swap agreements related to our 7.40% senior notes contain mutual

cash-out provisions at the then-current economic value every seven years. The

swap agreements related to our 7.125% senior notes contain cash-out provisions

at the then-current economic value in March 2009. The swap agreements related to

our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out

provisions at the then-current economic value every five or seven years.

     Our interest rate swaps have been designated as fair value hedges as

defined by SFAS No. 133. As discussed above, SFAS No. 133 designates derivatives

that hedge a recognized asset or liability's exposure to changes in their fair

value as fair value hedges and the gain or loss on fair value hedges are to be

recognized in earnings in the period of change together with the offsetting loss

or gain on the hedged item attributable to the risk being hedged. The effect of

that accounting is to reflect in earnings the extent to which the hedge is not

effective in achieving offsetting changes in fair value.

     Our interest rate swaps meet the conditions required to assume no

ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them

using the "shortcut" method prescribed by SFAS No. 133 for fair value hedges of

a fixed rate asset or liability using an interest rate swap. Accordingly, we

adjust the carrying value of each swap to its fair value each quarter, with an

offsetting entry to adjust the carrying value of the debt securities whose fair

value is being hedged. We record interest expense equal to the variable rate

payments under the swaps. Interest expense is accrued monthly and paid

semi-annually. When there is no ineffectiveness in the hedging relationship,

employing the shortcut method results in the same net effect on earnings,

accrual and payment of interest, net effect of changes in interest rates, and

level-yield amortization of hedge accounting adjustments as produced by

explicitly amortizing the hedge accounting adjustments on the debt.

     The differences between the fair value and the original carrying value

associated with our interest rate swap agreements, that is, the derivatives'

changes in fair value, are included within "Deferred charges and other assets"

and "Other long-term liabilities and deferred credits" in our accompanying

consolidated balance sheets. The offsetting entry to adjust the carrying value

of the debt securities whose fair value was being hedged is recognized as

"Market value of interest rate swaps" on our accompanying consolidated balance

sheets.

                                       43

<PAGE>

     The following table summarizes the net fair value of our interest rate swap

agreements associated with our interest rate risk management activities and

included on our accompanying consolidated balance sheets as of March 31, 2006

and December 31, 2005 (in thousands):

                                                March 31,      December 31,

                                                  2006             2005

                                               ----------      ------------

  Derivatives-net asset/(liability)

    Deferred charges and other assets........  $  51,406       $ 112,386

    Other long-term liabilities and

    deferred credits.........................    (41,167)        (13,917)

                                               ---------       ---------

      Market value of interest rate swaps....  $  10,239       $  98,469

                                               =========       =========

     We are exposed to credit related losses in the event of nonperformance by

counterparties to these interest rate swap agreements. While we enter into

derivative transactions primarily with investment grade counterparties and

actively monitor their credit ratings, it is nevertheless possible that from

time to time losses will result from counterparty credit risk. As of March 31,

2006, all of our interest rate swap agreements were with counterparties with

investment grade credit ratings.

11.  Reportable Segments

     We divide our operations into four reportable business segments:

     o    Products Pipelines;

     o    Natural Gas Pipelines;

     o    CO2; and

     o    Terminals.

     We evaluate performance principally based on each segments' earnings before

depreciation, depletion and amortization, which exclude general and

administrative expenses, third-party debt costs and interest expense,

unallocable interest income and minority interest. Our reportable segments are

strategic business units that offer different products and services. Each

segment is managed separately because each segment involves different products

and marketing strategies.

     Our Products Pipelines segment derives its revenues primarily from the

transportation and terminaling of refined petroleum products, including

gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas

Pipelines segment derives its revenues primarily from the sale, transmission,

storage and gathering of natural gas. Our CO2 segment derives its revenues

primarily from the production, sale, and transportation of crude oil from fields

in the Permian Basin of West Texas and from the transportation and marketing of

carbon dioxide used as a flooding medium for recovering crude oil from mature

oil fields. Our Terminals segment derives its revenues primarily from the

transloading and storing of refined petroleum products and dry and liquid bulk

products, including coal, petroleum coke, cement, alumina, salt, and chemicals.

     Financial information by segment follows (in thousands):

                                                    Three Months Ended

                                                        March 31,

                                               -------------------------

                                                   2006           2005

                                               -----------   -----------

  Revenues

    Products Pipelines........................ $   180,526   $   171,283

    Natural Gas Pipelines.....................   1,829,996     1,472,892

    CO2.......................................     174,691       163,163

    Terminals.................................     206,388       164,594

                                               -----------   -----------

    Total consolidated revenues..............  $ 2,391,601   $ 1,971,932

                                               ===========   ===========

                                       44

<PAGE>

                                                    Three Months Ended

                                                        March 31,

                                               -------------------------

                                                   2006           2005

                                               -----------   -----------

Operating expenses(a)

   Products Pipelines........................  $    60,647   $    52,056

   Natural Gas Pipelines.....................    1,697,766     1,357,095

   CO2.......................................       58,609        49,509

   Terminals.................................      115,781        85,416

                                               -----------   -----------

   Total consolidated operating expenses.....  $ 1,932,803   $ 1,544,076

                                               ===========   ===========

Depreciation, depletion and amortization

   Products Pipelines........................  $    20,242   $    19,394

   Natural Gas Pipelines.....................       15,933        14,758

   CO2.......................................       39,272        38,702

   Terminals.................................       17,274        12,173

                                               -----------   -----------

   Total consol. depreciation, depletion

   and amortization..........................  $    92,721   $    85,027

                                               ===========   ===========

Earnings from equity investments

   Products Pipelines........................  $     7,865   $     8,385

   Natural Gas Pipelines.....................       11,162         8,430

   CO2.......................................        5,658         9,248

   Terminals.................................           36             9

                                               -----------   -----------

   Total consolidated equity earnings.......   $    24,721   $    26,072

                                               ===========   ===========

Amortization of excess cost of equity

investments

   Products Pipelines........................  $       841   $       844

   Natural Gas Pipelines.....................           69            69

   CO2.......................................          504           504

   Terminals.................................            -             -

                                               -----------   -----------

   Total consol. amortization of excess

   cost of investments.......................  $     1,414   $     1,417

                                               ===========   ===========

Interest income

   Products Pipelines........................  $     1,111   $     1,149

   Natural Gas Pipelines.....................          150           171

   CO2.......................................            -             -

   Terminals.................................            -             -

                                               -----------   -----------

   Total segment interest income............         1,261         1,320

   Unallocated interest income...............          603           172

                                               -----------   -----------

   Total consolidated interest income.......   $     1,864   $     1,492

                                               ===========   ===========

Other, net - income (expense)

   Products Pipelines........................  $        95   $       142

   Natural Gas Pipelines.....................          302          (254)

   CO2.......................................            1             1

   Terminals.................................        1,377        (1,210)

                                               -----------   ------------

   Total consolidated Other, net - income

   (expense).................................  $     1,775   $    (1,321)

                                               ===========   ============

Income tax benefit (expense)

   Products Pipelines........................  $    (3,055)  $    (3,301)

   Natural Gas Pipelines.....................         (312)         (457)

   CO2.......................................          (73)          (45)

   Terminals.................................       (2,051)       (3,772)

                                               ------------  ------------

   Total consolidated income tax benefit

   (expense).................................  $    (5,491)  $    (7,575)

                                               ============  ============

Segment earnings

   Products Pipelines........................  $   104,812   $   105,364

   Natural Gas Pipelines.....................      127,530       108,860

   CO2.......................................       81,892        83,652

   Terminals.................................       72,695        62,032

                                               -----------   -----------

   Total segment earnings(b).................      386,929       359,908

   Interest and corporate administrative

   expenses(c)...............................     (140,220)     (136,287)

                                               ------------  ------------

   Total consolidated net income............   $   246,709   $   223,621

                                               ===========   ===========

                                       45

<PAGE>

                                                    Three Months Ended

                                                        March 31,

                                                -------------------------

                                                   2006           2005

                                                -----------      --------

Segment earnings before depreciation,

depletion, amortization and amortization of

excess cost of equity investments(d)

   Products Pipelines........................  $   125,895   $   125,602

   Natural Gas Pipelines.....................      143,532       123,687

   CO2.......................................      121,668       122,858

   Terminals.................................       89,969        74,205

                                               -----------   -----------

   Total segment earnings before DD&A........      481,064       446,352

   Total consol. depreciation, depletion

   and amortization..........................      (92,721)      (85,027)

   Total consol. amortization of excess

   cost of investments.......................       (1,414)       (1,417)

   Interest and corporate administrative

   expenses..................................     (140,220)     (136,287)

                                               -----------   -----------

   Total consolidated net income.............  $   246,709   $   223,621

                                               ===========   ===========

Capital expenditures

   Products Pipelines........................  $    56,705   $    41,070

   Natural Gas Pipelines.....................       20,469         9,659

   CO2.......................................       74,197        52,557

   Terminals.................................       42,292        40,522

                                               -----------   -----------

   Total consolidated capital expenditures(e)  $   193,663   $   143,808

                                               ===========   ===========

                                                March 31,    December 31,

                                                ---------    ------------

                                                  2006          2005

                                                ---------    ------------

Assets

   Products Pipelines........................  $ 3,881,020   $ 3,873,939

   Natural Gas Pipelines.....................    4,186,027     4,139,969

   CO2.......................................    1,770,149     1,772,756

   Terminals.................................    2,098,814     2,052,457

                                               -----------   -----------

   Total segment assets.....................    11,936,010    11,839,121

   Corporate assets(f).......................       85,241        84,341

                                               -----------   -----------

   Total consolidated assets................   $12,021,251   $11,923,462

                                               ===========   ===========

(a)  Includes natural gas purchases and other costs of sales, operations and

     maintenance expenses, fuel and power expenses and taxes, other than income

     taxes.

(b)  Includes revenues, earnings from equity investments, income taxes,

     allocable interest income and other, net, less operating expenses,

     depreciation, depletion and amortization, and amortization of excess cost

     of equity investments.

(c)  Includes unallocated interest income, interest and debt expense, general

     and administrative expenses and minority interest expense.

(d)  Includes revenues, earnings from equity investments, income taxes,

     allocable interest income and other, net, less operating expenses.

(e)  Includes sustaining capital expenditures of $25,665 and $24,209 for the

     three months ended March 31, 2006 and 2005, respectively. Sustaining

     capital expenditures are defined as capital expenditures which do not

     increase the capacity of an asset.

(f)  Includes cash, cash equivalents, restricted deposits and certain

     unallocable deferred charges.

     We do not attribute interest and debt expense to any of our reportable

business segments. For the three months ended March 31, 2006 and 2005, we

reported (in thousands) total consolidated interest expense of $77,570 and

$60,219, respectively.

12.  Pensions and Other Post-retirement Benefits

     In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk

Terminals, Inc. in 1998, we acquired certain liabilities for pension and

post-retirement benefits. We provide medical and life insurance benefits to

current employees, their covered dependents and beneficiaries of SFPP and Kinder

Morgan Bulk Terminals. We also provide the same benefits to former salaried

employees of SFPP. Additionally, we will continue to fund these costs

                                       46

<PAGE>

for those employees currently in the plan during their retirement years. SFPP's

post-retirement 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 post-retirement benefit plan

includes the following components (in thousands):

                                              Other Post-retirement Benefits

                                              ------------------------------

                                               Three Months Ended March 31,

                                              ------------------------------

                                                  2006              2005

                                              ------------      ------------

      Net periodic benefit cost

      Service cost.........................       $  2             $  2

      Interest cost........................         67               77

      Expected return on plan assets.......        ---               --

      Amortization of prior service cost...        (29)             (29)

      Actuarial (gain).....................       (113)            (127)

                                                  -----            -----

      Net periodic benefit cost............       $(73)            $(77)

                                                  =====            =====

     Our net periodic benefit cost for the first quarter of 2006 was a credit of

$73,000, which resulted in increases to income, largely due to the amortization

of an unrecognized net actuarial gain and to the amortization of a negative

prior service cost, primarily related to the following:

     o    there have been changes to the plan for both 2004 and 2005 which

          reduced liabilities, creating a negative prior service cost that is

          being amortized each year; and

     o    there was a significant drop in 2004 in the number of retired

          participants reported as pipeline retirees by Burlington Northern

          Santa Fe, which holds a 0.5% special limited partner interest in SFPP,

          L.P.

     As of March 31, 2006, we estimate our overall net periodic post-retirement

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.

13.  Related Party Transactions

     Plantation Pipe Line Company

     We own 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.

We loaned Plantation $97.2 million, which corresponds to our 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. We funded our loan of $97.2 million with

borrowings under our 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 both March 31, 2006 and December 31, 2005, 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 sheets, and we included the remaining

$92.0 million balance within "Notes receivable-Related parties."

                                       47

<PAGE>

     Coyote Gas Treating, LLC

     We own 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. We are the managing

partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in

outstanding borrowings under its 364-day credit facility with funds borrowed

from its owners. We loaned Coyote $17.1 million, which corresponds to our 50%

ownership interest, in exchange for a one-year note receivable bearing interest

payable monthly at 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, we reduced our investment in the note by $0.1

million to account for our share of investee losses in excess of the carrying

value of our equity investment in Coyote, and as of December 31, 2005, we

included the principal amount of $17.0 million related to this note within

"Notes Receivable-Related Parties" on our consolidated balance sheet.

     In March 2006, Enterprise and we agreed to a resolution that would transfer

Coyote Gulch's notes payable to Enterprise and us to members' equity. According

to the provisions of this resolution, we then contributed the principal amount

of $17.0 million related to our note receivable to our equity investment in

Coyote Gulch. The $17.0 million amount is included within "Investments" on our

consolidated balance sheet as of March 31, 2006.

14.  Regulatory Matters

     FERC Policy statement re: Use of Gas Basis Differentials for Pricing

     On July 25, 2003, the FERC issued a Modification to Policy Statement

stating that FERC regulated natural gas pipelines will, on a prospective basis,

no longer be permitted to use gas basis differentials to price negotiated rate

transactions. Effectively, we will no longer be permitted to use commodity price

indices to structure transactions on our FERC regulated natural gas pipelines.

Negotiated rates based on commodity price indices in existing contracts will be

permitted to remain in effect until the end of the contract period for which

such rates were negotiated. Moreover, in subsequent orders in individual

pipeline cases, the FERC has allowed negotiated rate transactions using pricing

indices so long as revenue is capped by the applicable maximum rate(s). 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.

     Accounting for Integrity Testing Costs

     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 was 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:

     o    prepare a plan to implement the program;

     o    identify high consequence areas;

     o    develop and maintain a record keeping system; and

                                       48

<PAGE>

     o    inspect affected pipeline segments.

     The costs of modifying the pipeline to permit in-line inspections, such as

installing pig launchers and receivers, are to be capitalized, as are certain

costs associated with developing or enhancing computer software or to add or

replace other items of plant.

     The Interstate Natural Gas Association of America sought rehearing of the

FERC's June 30, 2005 order. The FERC denied INGAA's request for rehearing on

September 19, 2005. On December 15, 2005, INGAA filed with the United States

Court of Appeals for the District of Columbia Circuit, in docket No. 05-1426, a

petition for review asking the court whether the FERC lawfully ordered that

interstate pipelines subject to FERC rate regulation and related accounting

rules 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.

     The implementation of this FERC order on January 1, 2006, had no material

impact on our financial position, results of operations, or cash flows in the

first quarter of 2006. Our Kinder Morgan Interstate Gas Transmission system

expects an increase of approximately $0.8 million in operating expenses in 2006

related to pipeline integrity management programs due to its implementation of

this FERC order on January 1, 2006, which will cause KMIGT to expense certain

program costs that previously were capitalized.

     In addition, our intrastate natural gas pipelines located within the State

of Texas are not FERC-regulated but instead follow accounting regulations

promulgated by the Railroad Commission of Texas. We will maintain our current

accounting procedures with respect to our accounting for pipeline integrity

testing costs for our intrastate natural gas pipelines.

     Selective Discounting

     On November 22, 2004, the FERC issued a notice of inquiry seeking comments

on its policy of selective discounting. Specifically, the FERC is asking 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. Comments were

filed by numerous entities, including Natural Gas Pipeline Company of America (a

Kinder Morgan, Inc. affiliate), on March 2, 2005. Several reply comments have

subsequently been filed. By an order issued on May 31, 2005, the FERC reaffirmed

its existing policy on selective discounting by interstate pipelines without

change. Several entities filed for rehearing; however, 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 District Group/Midwest Region

Gas Task Force Association.

     Index of Customer Audit

     On July 14, 2005, the FERC commenced an audit of TransColorado Gas

Transmission Company, as well as a number of other interstate gas pipelines, to

test compliance with the FERC's requirements related to the filing and posting

of the Index of Customers report. On September 21, 2005, the FERC's staff issued

a draft audit report which cited two minor issues with TransColorado's Index of

Customers filings and postings. Subsequently, on October 11, 2005, the FERC

issued a final order which closed its examination, citing the minor issues

contained in its draft report and approving the corrective actions planned or

already taken by TransColorado. TransColorado has implemented corrective actions

and has applied those actions to its most recent Index of Customer filing, dated

October 1, 2005. No further compliance action is expected and TransColorado

anticipates operating in compliance with applicable FERC rules regarding the

filing and posting of its future Index of Customers reports.

     Notice of Proposed Rulemaking - Market Based Storage Rates

     On December 22, 2005, the FERC issued a notice of proposed rulemaking to

amend its regulations by establishing two new methods for obtaining market based

rates for underground natural gas storage services. First,

                                       49

<PAGE>

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. Secondly, 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. Such modifications would be allowed provided the

FERC finds that the market based rates are in the public interest, are necessary

to encourage the construction of needed storage capacity, and that customers are

adequately protected from the abuse of market power. KMI's Natural Gas Pipeline

Company of America and our Kinder Morgan Interstate Gas Transmission LLC, as

well as numerous other parties, filed comments on the notice of proposed

rulemaking on February 27, 2006.

15.  Recent Accounting Pronouncements

     SFAS No. 123R

     On December 16, 2004, the Financial Accounting Standards Board issued SFAS

No. 123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No.

123, "Accounting for Stock-Based Compensation," and requires companies to

expense the value of employee stock options and similar awards. Significant

provisions of SFAS No. 123R include the following:

     o    share-based payment awards result in a cost that will be measured at

        fair value on the awards' grant date, based on the estimated number of

        awards that are expected to vest. Compensation cost for awards that vest

        would not be reversed if the awards expire without being exercised;

     o    when measuring fair value, companies can choose an option-pricing

          model that appropriately reflects their specific circumstances and the

          economics of their transactions;

     o    companies will recognize compensation cost for share-based payment

          awards as they vest, including the related tax effects. Upon

          settlement of share-based payment awards, the tax effects will be

          recognized in the income statement or additional paid-in capital; and

     o    public companies are allowed to select from three alternative

          transition methods - each having different reporting implications.

     For us, this Statement became effective January 1, 2006. However, we have

not granted common unit options or made any other share-based payment awards

since May 2000, and as of December 31, 2005, all outstanding options to purchase

our common units were fully vested. Therefore, the adoption of this Statement

did not have an effect on our consolidated financial statements due to the fact

that we have reached the end of the requisite service period for any

compensation cost resulting from share-based payments made under our common unit

option plan.

     SFAS No. 154

     On June 1, 2005, the FASB issued SFAS No. 154, "Accounting Changes and

Error Corrections." This Statement replaces Accounting Principles Board Opinion

No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in

Interim Financial Statements." SFAS No. 154 applies to all voluntary changes in

accounting principle, and changes the requirements for accounting for and

reporting of a change in accounting principle.

     SFAS No. 154 requires retrospective application to prior periods' financial

statements of a voluntary change in accounting principle unless it is

impracticable. In contrast, APB No. 20 previously required that most voluntary

changes in accounting principle be recognized by including in net income of the

period of the change the cumulative effect of changing to the new accounting

principle. The FASB believes the provisions of SFAS No. 154 will improve

financial reporting because its requirement to report voluntary changes in

accounting principles via retrospective application, unless impracticable, will

enhance the consistency of financial information between periods.

                                       50

<PAGE>

     The provisions of this Statement are effective for accounting changes and

corrections of errors made in fiscal years beginning after December 15, 2005

(January 1, 2006 for us). The Statement does not change the transition

provisions of any existing accounting pronouncements, including those that are

in a transition phase as of the effective date of this Statement. Adoption of

this Statement did not have any immediate effect on our consolidated financial

statements, and we will apply this guidance prospectively.

     EITF 04-5

     In June 2005, the Emerging Issues Task Force reached a consensus on Issue

No. 04-5, or EITF 04-5, "Determining Whether a General Partner, or the General

Partners as a Group, Controls a Limited Partnership or Similar Entity When the

Limited Partners Have Certain Rights." EITF 04-5 provides guidance for purposes

of assessing whether certain limited partners rights might preclude a general

partner from controlling a limited partnership.

     For general partners of all new limited partnerships formed, and for

existing limited partnerships for which the partnership agreements are modified,

the guidance in EITF 04-5 is effective after June 29, 2005. For general partners

in all other limited partnerships, the guidance is effective no later than the

beginning of the first reporting period in fiscal years beginning after December

15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an

effect on our consolidated financial statements.

     SFAS No. 155

     On February 16, 2006, the FASB issued SFAS No. 155, "Accounting for Certain

Hybrid Financial Instruments." This Statement amends SFAS No. 133, "Accounting

for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting

for Transfers and Servicing of Financial Assets and Extinguishments of

Liabilities." The Statement improves the financial reporting of certain hybrid

financial instruments by requiring more consistent accounting that eliminates

exemptions and provides a means to simplify the accounting for these

instruments. Specifically, it allows financial instruments that have embedded

derivatives to be accounted for as a whole (eliminating the need to bifurcate

the derivative form its host) if the holder elects to account for the whole

instrument on a fair value basis.

     The provisions of this Statement are effective for all financial

instruments acquired or issued after the beginning of an entity's first fiscal

year that begins after September 15, 2006 (January 1, 2007 for us). Adoption of

this Statement should not have any immediate effect on our consolidated

financial statements, and we will apply this guidance prospectively.

     SFAS No. 156

     On March 17, 2006, the FASB issued SFAS No. 156, "Accounting for Servicing

of Financial Assets." This Statement amends SFAS No. 140 and simplifies the

accounting for servicing assets and liabilities, such as those common with

mortgage securitization activities. Specifically, this Statement addresses the

recognition and measurement of separately recognized servicing assets and

liabilities, and provides an approach to simplify efforts to obtain hedge-like

(offset) accounting by permitting a servicer that uses derivative financial

instruments to offset risks on servicing to report both the derivative financial

instrument and related servicing asset or liability by using a consistent

measurement attribute--fair value.

     An entity should adopt this Statement as of the beginning of its first

fiscal year that begins after September 15, 2006 (January 1, 2007 for us).

Earlier adoption is permitted as of the beginning of an entity's fiscal year,

provided the entity has not yet issued financial statements, including interim

financial statements, for any period of that fiscal year. The effective date of

this Statement is the date an entity adopts the requirements of this Statement.

Adoption of this Statement should not have any immediate effect on our

consolidated financial statements, and we will apply this guidance

prospectively.

                                       51

<PAGE>

Item 2.  Management's Discussion and Analysis of Financial Condition and

Results of Operations.

     The following discussion and analysis of our financial condition and

results of operations provides you with a narrative on our financial results. It

contains a discussion and analysis of the results of operations for each segment

of our business, followed by a discussion and analysis of our financial

condition. The following discussion and analysis should be read in conjunction

with:

     o    our accompanying interim consolidated financial statements and related

          notes (included elsewhere in this report), and

     o    our consolidated financial statements, related notes and management's

          discussion and analysis of financial condition and results of

          operations included in our Annual Report on Form 10-K for the year

          ended December 31, 2005.

Critical Accounting Policies and Estimates

     Certain amounts included in or affecting our consolidated 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. These

estimates and assumptions affect the amounts we report for assets and

liabilities and our disclosure of contingent assets and liabilities at the date

of our financial statements. We routinely evaluate these estimates, 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. Any effects on our business, financial

position or results of operations resulting from revisions to these estimates

are recorded in the period in which the facts that give rise to the revision

become known.

     In preparing our consolidated 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, provisions

for uncollectible accounts receivable, exposures under contractual

indemnifications and various other recorded or disclosed amounts. Further

information about us and information regarding our accounting policies and

estimates that we consider to be "critical" can be found in our Annual Report on

Form 10-K for the year ended December 31, 2005. There have not been any

significant changes in these policies and estimates during the three months

ended March 31, 2006.

Results of Operations

     Consolidated

                                                    Three Months Ended March 31,

                                                    ----------------------------

                                                         2006          2005

                                                      -----------   ----------

                                                            (In thousands)

Earnings before depreciation, depletion and

amortization expense and amortization of

excess cost of equity investments

  Products Pipelines..................................$   125,895   $  125,602

  Natural Gas Pipelines...............................    143,532      123,687

  CO2.................................................    121,668      122,858

  Terminals...........................................     89,969       74,205

                                                      -----------   ----------

Segment earnings before depreciation,

depletion and amortization expense and

  amortization of excess cost of equity

  investments(a)......................................    481,064      446,352

  Depreciation, depletion and amortization

  expense.............................................    (92,721)     (85,027)

  Amortization of excess cost of equity investments...     (1,414)      (1,417)

  Interest and corporate administrative expenses(b)...   (140,220)    (136,287)

                                                      -----------   ----------

Net income............................................$   246,709   $  223,621

                                                      ===========   ==========

-------

(a)  Includes revenues, earnings from equity investments, income taxes,

     allocable interest income and other, net, less operating expenses.

(b)  Includes unallocated interest income, interest and debt expense, general

     and administrative expenses (including unallocated litigation and

     environmental expenses) and minority interest expense.

                                       52

<PAGE>

     Driven by improved natural gas sales and storage margins, higher natural

gas transportation revenues, and earnings contributions from bulk and liquids

terminal operations acquired since the first quarter of 2005, our consolidated

net income for the first quarter of 2006 was $246.7 million ($0.53 per diluted

unit), as compared to $223.6 million ($0.54 per diluted unit) in consolidated

net income for the first quarter of 2005. Total operating revenues earned in the

first quarter of 2006 totaled $2,391.6 million, a 21% improvement over revenues

of $1,971.9 million earned in the same quarter last year.

     Additionally, in the first quarter of 2006, we recognized a $5.6 million

increase in environmental expense associated with environmental liability

adjustments. The $5.6 million increase in environmental expense resulted in a

$4.9 million increase in expense to our Products Pipelines segment, a $0.7

million increase in expense to our Terminals business segment, a $0.1 million

increase in expense to our Natural Gas Pipelines business segment, and a $0.1

million decrease in expense to our CO2 business segment. The adjustment included

a $5.6 million increase in our overall accrued environmental and related claim

liabilities, and we included the additional expense within "Operations and

maintenance" in our accompanying consolidated statement of income for the three

months ended March 31, 2006.

     Because our partnership agreement requires us to distribute 100% of our

available cash to our partners on a quarterly basis (available cash consists

primarily of all our cash receipts, less cash disbursements and changes in

reserves), we consider each period's earnings before all non-cash depreciation,

depletion and amortization expenses, including amortization of excess cost of

equity investments, to be an important measure of our success in maximizing

returns to our partners. We also use this measure of profit and loss internally

for evaluating segment performance and deciding how to allocate resources to our

business segments. In the first quarter of 2006, our total segment earnings

before depreciation, depletion and amortization totaled $481.1 million, up 8%

from the $446.4 million in total segment earnings before depreciation, depletion

and amortization in last year's first quarter.

     Furthermore, we declared a cash distribution of $0.81 per unit for the

first quarter of 2006 (an annualized rate of $3.24). This distribution is almost

7% higher than the $0.76 per unit distribution we made for the first quarter of

2005. We hope to declare cash distributions of at least $3.28 per unit for 2006;

however, no assurance can be given that we will be able to achieve this level of

distribution. Our expectation does not take into account:

     o    any impact from rate reductions due to our Pacific operations' rate

          case, which we now estimate will be approximately $20 million in 2006;

          or

     o    the expected $45 million shortfall to our budgeted crude oil

          production at our SACROC field unit, as described below in "--CO2."

     Our general partner and our common and Class B unitholders receive

quarterly distributions in cash, while KMR, the sole owner of our i-units,

receives quarterly distributions in additional i-units. The value of the

quarterly per-share distribution of i-units is based on the value of the

quarterly per-share cash distribution made to our common and Class B

unitholders.

     Products Pipelines

                                                    Three Months Ended March 31,

                                                    ----------------------------

                                                         2006           2005

                                                     ------------   ------------

                                                        (In thousands, except

                                                        operating statistics)

  Revenues........................................  $   180,526      $  171,283

  Operating expenses(a)...........................      (60,647)        (52,056)

  Earnings from equity investments................        7,865           8,385

  Interest income and Other, net-income (expense)         1,206           1,291

  Income taxes....................................       (3,055)         (3,301)

                                                    -----------      ----------

    Earnings before depreciation, depletion and

    amortization expense and amortization of            125,895         125,602

      excess cost of equity investments...........

  Depreciation, depletion and amortization

  expense.........................................      (20,242)        (19,394)

  Amortization of excess cost of equity

  investments.....................................         (841)           (844)

                                                    -----------      ----------

    Segment earnings..............................  $   104,812      $  105,364

                                                    ===========      ==========

                                       53

<PAGE>

                                                    Three Months Ended March 31,

                                                    ----------------------------

                                                         2006           2005

                                                     ------------   ------------

  Gasoline (MMBbl)...............................         111.6            108.9

  Diesel fuel (MMBbl)............................          38.7             40.2

  Jet fuel (MMBbl)...............................          29.5             29.3

                                                     ----------       ----------

    Total refined product volumes (MMBbl)........         179.8            178.4

  Natural gas liquids (MMBbl)....................           9.8              9.6

                                                     ----------       ----------

    Total delivery volumes (MMBbl)(b)............         189.6            188.0

                                                     ==========       ==========

----------

(a)  Includes costs of sales, operations and maintenance expenses, fuel and

     power expenses and taxes, other than income taxes.

(b)  Includes Pacific, Plantation, North System, CALNEV, Central Florida,

     Cypress and Heartland pipeline volumes.

     Segment Earnings before Depreciation, Depletion and Amortization

     Our Products Pipelines segment reported earnings before depreciation,

depletion and amortization of $125.9 million for the first quarter of 2006,

essentially flat versus the $125.6 million of earnings before depreciation,

depletion and amortization in the first quarter of 2005. As referred to above in

"--Consolidated," the segment's 2006 earnings also include a charge of $4.9

million from the adjustment of our environmental liabilities. The segment's

overall $0.3 million increase in quarter-to-quarter segment earnings before

depreciation, depletion and amortization expenses primarily consisted of the

following:

     o    a $2.1 million (3%) increase from our combined West Coast refined

          petroleum products pipelines and terminal operations, which include

          our Pacific operations, our CALNEV Pipeline and our West Coast

          terminals. The overall increase reflected higher earnings before

          depreciation, depletion and amortization from our CALNEV Pipeline

          operations, driven by a $2.3 million (17%) increase in operating

          revenues. The increase in revenues was due to an almost 12% increase

          in product delivery volumes and to higher average tariff rates. The

          higher volumes in 2006 were attributable to both strong demand,

          primarily from the Las Vegas, Nevada market, and to service

          interruptions in the first quarter of 2005 resulting from adverse

          weather on the West Coast. The higher tariffs were due to a Federal

          Energy Regulatory Commission tariff index increase in July 2005

          (producer price index-finished goods adjustment).

          Earnings before depreciation, depletion and amortization expenses from

          our Pacific operations and West Coast terminal operations increased

          $0.3 million and decreased $0.3 million, respectively, in the first

          quarter of 2006 versus the first quarter of 2005. The increase in

          earnings from our Pacific operations was driven by a $5.4 million (7%)

          increase in operating revenues, but largely offset by incremental

          environmental expenses of $2.7 million and by a $2.0 million (26%)

          increase in fuel and power costs. The decrease in earnings before

          depreciation, depletion and amortization expense from our West Coast

          terminals related to higher property tax expense accruals in the first

          quarter of 2006, and to settlement income, recognized in the first

          quarter of 2005, related to sale negotiations on our Gaffey Street

          terminal, which was closed in the fourth quarter of 2004;

     o    a $0.9 million (13%) increase from our Southeast product terminal

          operations, primarily due to higher product inventory sales at higher

          average prices;

     o    a $0.8 million (7%) decrease from our approximate 51% ownership

          interest in Plantation Pipe Line Company, chiefly due to lower equity

          earnings. The decrease reflects lower overall net income earned by

          Plantation in the first quarter of 2006, due primarily to higher oil

          loss expenses related to higher product prices, and lower

          transportation revenues. Compared to last year's first quarter,

          Plantation's overall pipeline deliveries of refined products declined

          4% in 2006, due principally to warmer than normal winter weather, and

          partly to incremental volumes being diverted to competing pipelines in

          the first quarter of 2006 versus the first quarter of 2005; and

     o    a $0.6 million decrease from each of our North System, Central Florida

          Pipeline, and petroleum pipeline transmix processing operations. The

          decrease from our North System was primarily due to a 50% increase in

          fuel and power expenses, due to higher fuel and natural gas prices in

          first quarter 2006 versus first quarter 2005. The decrease from our

          Central Florida Pipeline was largely due to incremental environmental

          expenses

                                       54

<PAGE>

          of $1.1 million. The decrease from our transmix operations was

          primarily due to lower revenues as a result of a 7% decrease in

          overall processing volumes, largely due to a decrease at our

          Indianola, Pennsylvania transmix facility.

     Segment Details

     The segment reported revenues of $180.5 million in the first quarter of

2006 and $171.3 million in the first quarter of 2005. The $9.2 million (5%)

quarter-to-quarter increase in segment revenues was primarily due to the

following:

     o    a $5.4 million (7%) increase from our Pacific operations, consisting

          of a $3.5 million (6%) increase in refined product delivery revenues

          and a $1.9 million (9%) increase in product terminal revenues. The

          increase from product delivery revenues was due to an over 3% increase

          in mainline delivery volumes and an over 2% increase in average tariff

          rates, which included both the FERC approved 2005 annual indexed

          interstate tariff increase and a requested rate increase with the

          California Public Utility Commission.

          In November 2004, we filed an application with the CPUC requesting a

          $9 million increase in existing intrastate transportation rates to

          reflect the in-service date of our $95 million North Line expansion

          project. Pursuant to CPUC regulations, this increase automatically

          became effective as of December 22, 2004, but is being collected

          subject to refund, pending resolution of protests to the application

          by certain shippers. The CPUC may resolve the matter in the second

          quarter of 2006. The increase from terminal revenues was due to the

          higher transportation volumes and to incremental revenues from diesel

          lubricity-improving injection services that we began offering in May

          2005;

     o    a $2.3 million (17%) increase from our CALNEV Pipeline, as discussed

          above;

     o    a $1.7 million (13%) increase from our West Coast terminals, related

          to rent escalations, higher throughput barrels and rates at various

          locations, and additional tank capacity at our Los Angeles Harbor

          terminal;

     o    a $0.5 million (5%) increase from our Central Florida Pipeline, driven

          by an over 6% increase in the average tariff per barrel moved; and

     o    a $1.1 million (7%) decrease from our Southeast terminals, largely

          attributable to lower butane revenues (partially offset by lower

          butane purchases) related to changes in customer agreements, partly

          offset by higher revenues from expanded storage agreements from

          terminal operations we acquired in November 2004 from Charter Terminal

          Company and Charter-Triad Terminals, LLC.

     Combining all of the segment's operations, total delivery volumes of

refined petroleum products increased 0.8% in the first quarter of 2006, compared

to the first quarter of 2005. Increases on our Pacific and CALNEV systems were

offset by decreases on Plantation and Central Florida, due principally to warmer

winter weather in the Southeast. Gasoline volumes for all pipelines in this

segment were up 2.5% quarter-over-quarter, and excluding Plantation, segment

deliveries of gasoline, diesel fuel and jet fuel increased 0.9%, 4.7% and 7.3%,

respectively, in the first quarter of 2006, compared to the first quarter of

2005. Quarter-to-quarter deliveries of natural gas liquids were up 2.1%, as

higher volumes on our Cypress Pipeline more than offset a drop in volumes on our

North System. The increase from Cypress was due to increased demand from a

petrochemical plant in Lake Charles, Louisiana that is served by the pipeline;

the decrease from our North System was due to continued low demand for propane,

primarily due to warmer winter weather across the Midwest. The FERC has set the

oil pipeline tariff rate index increase that will apply beginning July 1, 2006,

at producer price index plus 1.3%, which will positively impact the results of

operations of our Products Pipelines segment beginning in the third quarter.

     The segment's combined operating expenses, which consist of all cost of

sales expenses, operating and maintenance expenses, fuel and power expenses, and

all tax expenses, excluding income taxes, increased $8.6 million (17%) in the

first quarter of 2006, compared to the same year-ago period. The overall

increase in operating expenses was mainly due to the following:

                                       55

<PAGE>

     o    a $5.2 million (28%) increase from our Pacific operations, due to the

          incremental environmental expenses of $2.7 million and the $2.0

          million increase in fuel and power costs described above, and to a

          $0.5 million increase in operating expenses mainly associated with

          increased terminal activities. The increase in fuel and power expenses

          was due to both product delivery volume and utility rate increases, in

          2006, and a utility rebate credit received in the first quarter of

          2005;

     o    a $1.8 million (42%) increase from our West Coast terminals, primarily

          related to incremental environmental expenses and to higher labor

          expenses, due to pay period timing differences and an increase in the

          number of employees;

     o    a $1.1 million (56%) increase from our Central Florida Pipeline

          operations, due to the first quarter 2006 environmental expense

          adjustments discussed above;

     o    a $0.8 million (16%) increase from our North System, due to higher

          fuel and power expenses and slightly higher natural gas liquids

          product losses;

     o    a $0.7 million (13%) increase from the operation of the Plantation

          Pipeline, due primarily to higher labor expenses following timing

          differences that resulted in an additional pay period in the first

          quarter of 2006 versus the first quarter of 2005; and

     o    a $2.0 million (27%) decrease from our Southeast terminals, largely

          attributable to lower butane purchases, discussed above, and higher

          fuel costs.

     The segment's equity investments consist of our approximate 51% interest in

Plantation Pipe Line Company, our 50% interest in the Heartland Pipeline

Company, and our 50% interest in Johnston County Terminal, LLC that was included

in our November 2004 Charter products terminals acquisition. Earnings from these

investments decreased $0.5 million (6%) in the first quarter of 2006, when

compared to the same period last year. The decrease was primarily due to a $0.7

million (10%) decrease in equity earnings from our investment in Plantation, due

to overall lower net income as described above.

     The segment's income from allocable interest income and other income and

expense items remained flat quarter-over-quarter, and income tax expenses

decreased $0.2 million (7%) in the first quarter of 2006, due primarily to the

lower pre-tax earnings from Plantation.

     Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of equity investments, increased $0.8 million (4%)

in the first quarter of 2006, when compared to the same period last year. The

increase was primarily due to incremental depreciation charges associated with

our Southeast terminal and Pacific operations' assets. The increase from our

Southeast terminals reflected additional depreciation charges related to our

final purchase price allocation, made in the fourth quarter of 2005, for

depreciable terminal assets we acquired in November 2004 from Charter Terminal

Company and Charter-Triad Terminals, LLC. The increase from our Pacific

operations related to higher depreciable costs as a result of the capital

spending we have made since the end of the first quarter of 2005.

                                       56

<PAGE>

     Natural Gas Pipelines

                                                    Three Months Ended March 31,

                                                    ----------------------------

                                                         2006           2005

                                                    -----------     -----------

                                                        (In thousands, except

                                                        operating statistics)

  Revenues......................................... $ 1,829,996     $ 1,472,892

  Operating expenses(a)............................  (1,697,766)     (1,357,095)

  Earnings from equity investments.................      11,162           8,430

  Interest income and Other, net-income (expense)..         452             (83)

  Income taxes.....................................        (312)           (457)

                                                    -----------     -----------

    Earnings before depreciation, depletion

    and amortization expense and amortization

      of excess cost of equity investments.........     143,532         123,687

  Depreciation, depletion and amortization

  expense..........................................     (15,933)        (14,758)

  Amortization of excess cost of equity

  investments......................................         (69)            (69)

                                                    -----------     -----------

    Segment earnings............................... $   127,530     $   108,860

                                                    ===========     ===========

  Natural gas transport volumes

  (Trillion Btus)(b)...............................       336.6           338.0

                                                    ===========     ===========

  Natural gas sales volumes (Trillion Btus)(c).....       223.5           226.6

                                                    ===========     ===========

----------

(a)  Includes natural gas purchases and other costs of sales, operations and

     maintenance expenses, fuel and power expenses and taxes, other than income

     taxes.

(b)  Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate

     natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.

(c)  Represents Texas intrastate natural gas pipeline group.

     Segment Earnings before Depreciation, Depletion and Amortization

     Our Natural Gas Pipelines segment reported earnings before depreciation,

depletion and amortization of $143.5 million in the first quarter of 2006, and

$123.7 million in earnings before depreciation, depletion and amortization in

the first quarter of 2005. The segment's overall $19.8 million (16%) increase in

the first quarter of 2006 versus the first quarter of 2005 primarily consisted

of the following:

     o    a $16.3 million (26%) increase from our Texas intrastate natural gas

          pipeline group, due primarily to improved margins from natural gas

          sales activities and higher natural gas transportation and storage

          demand revenues on our Kinder Morgan Texas and Kinder Morgan Tejas

          pipeline systems. Combined, these two systems reported a $14.4 million

          (25%) increase in quarter-to-quarter earnings before depreciation,

          depletion and amortization, driven by a $9.4 million (33%) increase in

          gross margin (revenues less cost of sales) from natural gas sales and

          purchases, higher transportation and storage revenues, and favorable

          settlements of pipeline transportation imbalances. Margin is defined

          as the difference between the prices at which we buy gas in our supply

          areas and the prices at which we sell gas in our market areas, less

          the cost of fuel to transport. We realize earnings by capturing the

          favorable differences between the changes in our gas sales prices,

          purchase prices and transportation costs, including fuel.

          In addition, our Texas intrastate group earns revenues from natural

          gas sales and transportation activities on our Mier-Monterrey Mexico

          and Kinder Morgan North Texas pipelines. Combined, these two systems

          reported a $1.9 million (38%) increase in earnings before

          depreciation, depletion and amortization in 2006 compared to 2005,

          primarily due to incremental gross margins from natural gas sales on

          our Kinder Morgan North Texas Pipeline;

     o    a $3.0 million (42%) increase from our 49% equity investment in the

          Red Cedar Gathering Company, related to Red Cedar's higher

          year-over-year net income in 2006 that was largely driven by higher

          prices on incremental sales of excess fuel gas and by higher natural

          gas gathering revenues;

     o    a $1.8 million (21%) increase from our TransColorado Pipeline, due

          primarily to higher gas transmission revenues, related to higher

          delivery volumes. The increase in volumes resulted from system

          improvements

                                       57

<PAGE>

          associated with an expansion, completed since the end of the first

          quarter of 2005, on the northern portion of the pipeline.

          TransColorado's north system expansion project was in-service on

          January 1, 2006, and provides for up to 300 million cubic feet per day

          of additional northbound transportation capacity;

     o    a $1.8 million (55%) increase from our Casper Douglas natural gas

          gathering and processing operations, due mainly to favorable gas

          imbalance gains and to comparative differences in hedge settlements

          associated with the rolling-off of older low price crude oil and

          propane positions at December 31, 2005; and

     o    a $3.6 million (22%) decrease from our Trailblazer Pipeline, due to

          timing differences on the settlements of pipeline transportation

          imbalances in the first quarter of 2006 versus the first quarter of

          2005. These pipeline imbalances were due to differences between the

          volumes nominated and volumes delivered at an inter-connecting point

          by the pipeline.

     Additionally, on April 18, 2006, we announced that we have entered into a

long-term agreement with CenterPoint Energy Resources Corp. to provide the

natural gas utility with firm transportation and storage services through our

Texas intrastate natural gas pipeline group. According to the provisions of the

agreement, CenterPoint Energy has contracted for one billion cubic feet per day

of natural gas transportation capacity and 16 billion cubic feet of natural gas

storage capacity, effective April 1, 2007. Currently, our Intrastate group is

pursuing projects to expand the transport and storage capabilities in its system

in order to take advantage of increasing gas production in East Texas and

pending liquefied natural gas supplies targeted for the Texas Gulf Coast.

     Segment Details

     Total segment operating revenues, including revenues from natural gas

sales, increased $357.1 million (24%) in the first quarter of 2006, compared to

the same year-earlier quarter. Combined operating expenses, including natural

gas purchase costs, increased $340.7 million (25%).

     The increases in revenues and operating expenses were largely due to higher

natural gas sales revenues and higher natural gas cost of sales, respectively,

due mainly to higher average natural gas prices in the first quarter of 2006,

and to the purchase and sales activities of our Texas intrastate natural gas

pipeline group. Although the Intrastate group's natural gas sales volumes

decreased 1% in the first quarter of 2006 versus the first quarter of 2005,

revenues from the sales of natural gas increased $339.9 million (25%);

similarly, the Texas intrastate group's costs of sales, including natural gas

purchase costs, increased $329.6 million (25%) in the first three months of 2006

versus the first three months of 2005.

     Changes in the segment's period-to-period sales revenues and costs of sales

are largely impacted by changes in energy commodity prices. However, due to the

fact that our Texas intrastate group sells natural gas in the same price

environment in which it is purchased, the increases in gas sales revenues are

largely offset by corresponding increases in gas purchase costs.

     For the comparative three month periods, the average price for natural gas

sold by our Kinder Morgan Texas and Kinder Morgan Tejas systems increased 28%

(from $5.93 per million British thermal units in 2005 to $7.57 per million

British thermal units in 2006). The increases in natural gas sales and costs of

sales from the Texas intrastate group also included incremental amounts of $19.1

million and $18.4 million, respectively, from our Kinder Morgan North Texas

Pipeline, due to the fact that the pipeline did not begin purchasing and selling

natural gas until June 2005.

     The purchase and sale activities of our Texas intrastate group result in

considerably higher revenues and operating expenses compared to the interstate

operations of our Rocky Mountain pipelines, which include our Kinder Morgan

Interstate Gas Transmission, Trailblazer, TransColorado and Rockies Express

pipelines. All four pipelines charge a transportation fee for gas transmission

service and have the authority to initiate natural gas sales for operational

purposes, but none engage in significant gas purchases for resale.

     Our Rockies Express Pipeline began limited interim service in the first

quarter of 2006 on its westernmost segment (the segment that extends from

Meeker, Colorado to Wamsutter, Wyoming). Construction of the second segment of

the pipeline (that extends from Wamsutter to Cheyenne, Wyoming) is scheduled to

begin this summer, and the entire line is expected to be in service by January

1, 2007. Our revenues and expenses will not be impacted

                                       58

<PAGE>

during the construction of the pipeline due to the fact that regulatory

accounting provisions require capitalization of revenues and expenses until the

second segment of the project is complete and in-service.

     We account for the segment's investments in Red Cedar Gathering Company,

Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity

method of accounting. In the first quarter of 2006, equity earnings from these

three investees increased $2.7 million (32%), when compared to the first quarter

of 2005. The increase was chiefly due to the $3.0 million increase in equity

earnings from Red Cedar, as described above.

     The segment's interest income and earnings from other income items

increased $0.5 million in the first quarter of 2006, compared to the first

quarter of 2005. The increase was mainly due to incremental litigation expense

accruals, recognized in the first quarter of 2005, by our Kinder Morgan North

Texas Pipeline.

     Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased $1.2 million (8%) in the

first quarter of 2006, when compared to the same period last year. The increase

was largely due to higher depreciation charges on our Kinder Morgan Texas system

due to the acquisition of our North Dayton, Texas natural gas storage facility

in August 2005. We allocated $64.1 million of our total purchase price of $109.4

million to our depreciable asset base.

     CO2

                                                    Three Months Ended March 31,

                                                    ---------------------------

                                                         2006           2005

                                                    -----------      ----------

                                                        (In thousands, except

                                                        operating statistics)

  Revenues.......................................   $   174,691      $  163,163

  Operating expenses(a)..........................       (58,609)        (49,509)

  Earnings from equity investments...............         5,658           9,248

  Other, net-income (expense)....................             1               1

  Income taxes...................................           (73)            (45)

                                                    -----------      ----------

    Earnings before depreciation, depletion

    and amortization expense and amortization

    of excess cost of equity investments.........       121,668         122,858

  Depreciation, depletion and amortization

  expense(b).....................................       (39,272)        (38,702)

  Amortization of excess cost of equity

  investments....................................          (504)           (504)

                                                    -----------      ----------

    Segment earnings.............................   $    81,892      $   83,652

                                                    ===========      ==========

Carbon dioxide delivery volumes (Bcf)(c).........         172.4           169.9

                                                    ===========      ==========

SACROC oil production (gross)(MBbl/d)(d).........          31.3            33.8

                                                    ===========      ==========

SACROC oil production (net)(MBbl/d)(e)...........          26.1            28.1

                                                    ===========      ==========

Yates oil production (gross)(MBbl/d)(d)..........          25.0            24.1

                                                    ===========      ==========

Yates oil production (net)(MBbl/d)(e)............          11.1            10.7

                                                    ===========      ==========

Natural gas liquids sales volumes

(net)(MBbl/d)(e).................................           9.3             9.7

                                                    ===========      ==========

Realized weighted average oil price

per Bbl(f)(g)....................................   $     30.47      $    28.81

                                                    ===========      ==========

Realized weighted average natural gas

liquids price per Bbl(g)(h)......................   $     41.35      $    33.97

                                                    ===========      ==========

----------

(a)  Includes costs of sales, operations and maintenance expenses, fuel and

     power expenses and taxes, other than income taxes.

(b)  Includes depreciation, depletion and amortization expense associated with

     oil and gas producing and gas processing activities in the amount of

     $34,590 for the first quarter of 2006 and $34,313 for the first quarter of

     2005. Includes depreciation, depletion and amortization expense associated

     with sales and transportation services activities in the amount of $4,682

     for the first quarter of 2006 and $4,389 for the first quarter of 2005.

(c)  Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos

     pipeline volumes.

(d)  Represents 100% of the production from the field. We own an approximate 97%

     working interest in the SACROC unit and an approximate 50% working interest

     in the Yates unit.

(e)  Net to Kinder Morgan, after royalties and outside working interests. (f)

     Includes all Kinder Morgan crude oil production properties. (g) Hedge

     gains/losses for oil and natural gas liquids are included with crude oil.

(h)  Includes production attributable to leasehold ownership and production

     attributable to our ownership in processing plants and third party

     processing agreements.

                                       59

<PAGE>

     Segment Earnings before Depreciation, Depletion and Amortization

     Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its

consolidated affiliates. The segment's primary businesses involve the

production, transportation and marketing of carbon dioxide, commonly called CO2,

and the production, marketing and transportation of crude oil, natural gas and

natural gas liquids. For the first quarter of 2006, the segment reported

earnings before depreciation, depletion and amortization of $121.7 million, down

a slight 1% from the $122.9 million of earnings before depreciation, depletion

and amortization reported for the first quarter last year. The overall $1.2

million decrease in quarter-to-quarter segment earnings before depreciation,

depletion and amortization included the following:

     o    a $6.6 million (8%) decrease in earnings before depreciation,

          depletion and amortization expenses from the segment's oil and natural

          gas producing activities, which include its natural gas processing

          activities. The decrease was largely attributable to a $10.0 million

          (18%) increase in combined operating expenses, due primarily to higher

          well workover expenses, higher fuel and power expenses, and higher

          property and severance taxes. The increase in operating expenses more

          than offset a $3.4 million (2%) increase in revenues, due primarily to

          increased prices on the sales of both natural gas liquids and crude

          oil, as discussed below; and

     o    a $5.4 million (15%) increase in earnings before depreciation,

          depletion and amortization from the segment's carbon dioxide sales and

          transportation activities. The increase was driven by higher revenues

          from carbon dioxide sales, higher carbon dioxide and crude oil

          pipeline transportation revenues, and higher oil field and processing

          plant service revenues.

     On a gross basis (meaning total quantity produced) combined daily oil

production from the two largest oil field units in which we hold ownership

interests decreased almost 3% in the first quarter of 2006, as compared to the

same prior-year period. The two oil field interests include our approximate 97%

working interest in the SACROC unit and our approximate 50% working interest in

the Yates oil field unit, both located in the Permian Basin area of West Texas.

Similarly, natural gas plant liquids product sales volumes decreased 4% in the

first quarter of 2006 when compared with the first quarter last year, largely

due to the quarter-to-quarter decrease in production from the SACROC unit.

     Average oil production increased by almost 4% quarter-over-quarter at

Yates, but decreased 7% at the SACROC unit. For the entire year of 2006,

production at Yates is expected to exceed our budgeted average oil production of

24.6 thousand barrels per day by approximately one thousand barrels per day. At

SACROC, the decline in production is specific to one section of the field that

is underperforming, and we now expect oil production to average approximately

three to four thousand barrels per day less for the year than its budget. As a

result of this projected shortfall at SACROC, we expect our CO2 segment to

underperform its annual published budget of segment earnings before

depreciation, depletion and amortization expenses by approximately 8%, or

approximately $45 million.

     However, we benefited from increases of 45%, 22% and 6%, respectively, in

our realized weighted average price of carbon dioxide, natural gas liquids and

crude oil per barrel in the first quarter of 2006, versus the first quarter of

2005. The increase in average sale prices for carbon dioxide in 2006 compared to

2005 was largely related to an overall improvement in energy prices and to

continuing strong demand for carbon dioxide from tertiary oil recovery projects.

We do not recognize profits on carbon dioxide sales to ourselves.

     The higher prices for natural gas liquids reflect favorable gas processing

margins, which is the relative difference in economic value (on an energy

content basis) between natural gas liquids as a separated liquid, on the one

hand, and as a portion of the residue natural gas stream, on the other hand. Had

we not used energy financial instruments to transfer commodity price risk, our

crude oil sale prices would have averaged $60.62 per barrel in the first quarter

of 2006, and $47.93 per barrel in the first quarter of 2005. Because we are

exposed to market risks related to the price volatility of crude oil, natural

gas and natural gas liquids, we mitigate our commodity price risk through a

long-term hedging strategy that is intended to generate more stable, predictable

realized prices. Our strategy involves the use and designation of energy

financial instruments (derivatives) as hedges to the exposure of fluctuating

expected future cash flows produced by unpredictable changes in crude oil and

natural gas liquids sales prices. All of our hedge gains and losses for crude

oil and natural gas liquids are included in our realized average price for oil;

none are allocated to natural gas liquids. For more information on our hedging

activities, see Note 10 to our consolidated financial statements, included

elsewhere in this report.

                                       60

<PAGE>

     Segment Details

     Our CO2 segment reported revenues of $174.7 million in the first quarter of

2006 and $163.2 million in the first quarter of 2005. The $11.5 million (7%)

quarter-to-quarter increase in segment revenues included increases of $4.9

million (16%) and $1.4 million (1%), respectively, in plant product and crude

oil sales revenues. As described above, the increases were attributable to

higher average prices partially offset by decreases in production.

     In addition, revenues from carbon dioxide sales increased $6.9 million

(92%) in the first quarter of 2006 versus the first quarter of 2005, due mainly

to higher average sale prices, discussed above, and to slightly higher sales

volumes. Carbon dioxide and crude oil pipeline transportation revenues increased

$1.2 million (9%) in the three month period of 2006 versus 2005, due primarily

to an over 1% increase in carbon dioxide delivery volumes and a $0.4 million

(6%) increase in crude oil transportation revenues from our Wink Pipeline. Oil

field and processing plant service revenues increased $0.6 million (21%) in the

first quarter of 2006 compared to the first quarter of 2005, largely due to

increased produced gas third-party processing fees in and around the SACROC oil

field unit.

     Partially offsetting the overall quarter-to-quarter increase in segment

revenues was a $4.1 million (66%) decrease in natural gas sales revenues,

attributable to lower sales volumes. The decrease in volumes sold was largely

due to natural gas volumes used at the power plant we constructed at the SACROC

oil field unit and placed in service in June 2005. As a result, we had lower

volumes of gas available for sale in the first quarter of 2006 versus the first

quarter last year.

     The segment's combined operating expenses increased $9.1 million (18%) in

the first quarter of 2006, versus the same prior-year period. The increase was

primarily the result of higher field operating and maintenance expenses,

property and production taxes, and fuel and power expenses.

     The increase in field operating and maintenance expenses was largely due to

higher well workover and completion expenses, including labor, related to

infrastructure expansions at the SACROC and Yates oil field units since the end

of the first quarter last year. Workover expenses relate to incremental

operating and maintenance charges incurred on producing wells in order to

restore or increase production. Workovers are often performed in order to

stimulate production, add pumping equipment, remove fill from the wellbore, to

mechanically repair the well, or for other reasons.

     The increase in property taxes was related to both increased asset

infrastructure and higher assessed property values since the end of the first

quarter of 2005. The increase in production (severance) taxes was driven by

higher crude oil revenues. The increase in fuel and power expenses was due to

increased carbon dioxide compression and equipment utilization, higher fuel

costs, and higher electricity expenses due to higher rates as a result of higher

fuel costs to electricity providers. Overall higher electricity costs were

partly offset by the benefits provided from the power plant we constructed at

the SACROC oil field unit, described above. KMI operates the power plant, which

provides the majority of SACROC's electricity needs, and we reimburse KMI for

its costs to operate and maintain the plant.

     Earnings from equity investments, representing the equity earnings from our

50% ownership interest in the Cortez Pipeline Company, decreased $3.6 million

(39%) in the first quarter of 2006, when compared to the first quarter of 2005.

The decrease was due to lower overall net income earned by Cortez. The lower

earnings were primarily due to lower carbon dioxide transportation revenues as a

result of lower average tariff rates, which more than offset an almost 3%

increase in carbon dioxide delivery volumes.

     Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased $0.6 million (1%) in the

first quarter of 2006, when compared to the same period last year. The increase

was due to higher depreciable costs, related to incremental capital spending

since March 2005.

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     Terminals

                                                    Three Months Ended March 31,

                                                    ----------------------------

                                                         2006           2005

                                                    -----------      ----------

                                                        (In thousands, except

                                                        operating statistics)

  Revenues.......................................   $   206,388      $  164,594

  Operating expenses(a)..........................      (115,781)        (85,416)

  Earnings from equity investments...............            36               9

  Other, net-income (expense)....................         1,377          (1,210)

  Income taxes...................................        (2,051)         (3,772)

                                                    -----------      ----------

    Earnings before depreciation, depletion

    and amortization expense and amortization

    of excess cost of equity investments.........        89,969          74,205

  Depreciation, depletion and amortization

  expense........................................       (17,274)        (12,173)

  Amortization of excess cost of equity

  investments....................................             -               -

                                                    -----------      ----------

    Segment earnings.............................   $    72,695      $   62,032

                                                    ===========      ===========

  Bulk transload tonnage (MMtons)(b).............          22.0            23.1

                                                    ===========      ==========

  Liquids leaseable capacity (MMBbl).............          42.8            36.6

                                                    ===========      ==========

  Liquids utilization %..........................          97.8%           96.7%

                                                    ===========      ==========

----------

(a)  Includes costs of sales, operations and maintenance expenses, fuel and

     power expenses and taxes, other than income taxes.

(b)  Volumes for acquired terminals are included for both periods.

     Segment Earnings before Depreciation, Depletion and Amortization

     Our Terminals segment includes the operations of our petroleum and

petrochemical-related liquids terminal facilities (other than those included in

our Products Pipelines segment) as well as all of our coal and dry-bulk material

services, including all transload, engineering and other in-plant services. For

the first three months of 2006 and 2005, the segment reported earnings before

depreciation, depletion and amortization of $90.0 million and $74.2 million,

respectively.

     Terminal operations acquired since the end of the first quarter of 2005 and

identified separately in post-acquisition periods included the following:

     o    our Texas petroleum coke terminals and repair shop assets, located in

          and around the Ports of Houston and Beaumont, Texas, acquired

          separately in April and September 2005, respectively;

     o    three terminals acquired separately in July 2005: our Kinder Morgan

          Staten Island terminal, a dry-bulk terminal located in Hawesville,

          Kentucky and a liquids/dry-bulk facility located in Blytheville,

          Arkansas;

     o    all of the ownership interests in General Stevedores, L.P., which

          operates a break-bulk terminal facility located along the Houston Ship

          Channel, acquired July 31, 2005; and

     o    our Kinder Morgan Blackhawk terminal located in Black Hawk County,

          Iowa, acquired in August 2005.

     Combined, these operations accounted for incremental amounts of earnings

before depreciation, depletion and amortization of $15.1 million, revenues of

$30.0 million and operating expenses of $14.9 million in the first quarter of

2006. Most of the increase in operating results from acquisitions was

attributable to our Texas petroleum coke bulk terminals, which we acquired from

Trans-Global Solutions, Inc. for an aggregate consideration of approximately

$247.2 million. The acquired assets include facilities at the Port of Houston,

the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship

Channel. Combined, these terminal operations accounted for incremental amounts

of earnings before depreciation, depletion and amortization of $13.0 million,

revenues of $24.7 million and operating expenses of $11.7 million in the first

quarter of 2006.

     For all other terminal operations (those owned during both years), earnings

before depreciation, depletion and amortization were essentially flat,

increasing $0.7 million (1%) in the first quarter of 2006 versus the first

quarter of

                                       62

<PAGE>

2005. The overall increase included a $2.3 million (14%) increase from our

Pasadena and Galena Park, Texas Gulf Coast liquids facilities, two large

terminals located on the Houston Ship Channel that serve as a distribution hub

for Houston's crude oil refineries. The increase was driven by higher revenues

from excess throughput charges, incremental sales of petroleum transmix, new

customer agreements and higher truck loading rack service fees. We also

benefited from record volumes of steel imports at our bulk terminal located in

Fairless Hills, Pennsylvania and record volumes of fertilizer imports at both

our Port Sutton, Florida terminal and our Elizabeth River bulk terminal located

in Chesapeake, Virginia.

     The overall increase in earnings from terminals owned both quarters was

offset by a $1.2 million (14%) decrease from our Lower Mississippi River

(Louisiana) region, largely due to a $2.3 million decrease from our

International Marine Terminals facility, a Louisiana partnership owned 66 2/3%

by us. IMT, located in Port Sulphur, Louisiana, suffered property damage and a

general loss of business due to the effects of Hurricane Katrina, which struck

the Gulf Coast in the third quarter of 2005.

     For our entire liquids terminals combined, total throughput volumes

decreased 3.6% in the first quarter of 2006, versus the same period in 2005. The

decrease was primarily due to lower petroleum volumes at our Pasadena terminal,

due in large part to the continued shutdown of a Texas-based refinery that was

impacted by Hurricane Rita, which struck the Texas-Louisiana Gulf Coast in the

third quarter of 2005; however, earnings before depreciation, depletion and

amortization were still up in first quarter 2006 versus first quarter 2005 due

to the factors discussed above. Through a combination of business acquisitions

and internal capital spending, we have increased our liquids leaseable capacity

by 6.2 million barrels (17%) since the end of the first quarter of 2005, while

at the same time, increasing our liquids utilization rate (the ratio of our

actual capacity to our estimated potential capacity) by 1.1%.

     Segment Details

     Segment revenues for all terminals owned during both three month periods

increased $11.8 million (7%) in the first quarter of 2006, when compared to the

same prior-year period. The quarter-to-quarter increase was primarily due to the

following:

     o    a $4.4 million (19%) increase from our Mid-Atlantic region, due

          primarily to higher steel volumes at our Fairless Hills terminal, and

          to higher tank rentals and cement and petroleum coke volumes at our

          Shipyard River terminal, located in Charleston, South Carolina;

     o    a $3.5 million (15%) increase from our Pasadena and Galena Park Gulf

          Coast facilities, as discussed above; and

     o    a $3.3 million (96%) increase from engineering and terminal design

          services, due to both incremental revenues from new clients and

          increased revenues from existing clients starting new projects due to

          economic growth.

     Operating expenses for all terminals owned during both quarters increased

$15.5 million (18%) in the first quarter of 2006, when compared to the first

quarter of 2005. The overall increase in segment operating expenses included

increases of:

     o    $4.9 million (26%) from our Louisiana terminals, largely due to

          additional insurance, property damage and demurrage expenses related

          to hurricanes Katrina and Rita;

     o    $3.6 million (110%) from engineering-related services, due primarily

          to higher salary, overtime and other employee-related expenses, as

          well as increased contract labor, all associated with the increased

          project work described above;

     o    $2.8 million (21%) from our Mid-Atlantic terminals, largely due to

          higher operating and maintenance expenses at our Fairless Hills

          terminal, due to the increase in steel products handled. This includes

          higher wharfage, trucking and general maintenance expenses;

                                       63

<PAGE>

     o    $1.4 million (10%) from our Midwest terminals, mainly due to a $0.5

          million increase at our Cora, Illinois coal terminal and a $0.4

          million increase at our Argo, Illinois liquids terminal facility. Both

          increases were largely due to higher operating and maintenance

          expenses--related to a 32% increase in coal transfer volumes at Cora,

          and a 15% increase in liquids throughput volume at Argo;

     o    $1.2 million (17%) from our Pasadena and Galena Park, Texas Gulf Coast

          terminals, due to incremental labor expenses, power expenses and

          permitting fees; and

     o    $1.1 million (18%) from our Southeast region, due primarily to higher

          labor and equipment maintenance at our Port Sutton, Florida bulk

          terminal, related to higher bulk tonnage.

     The segment's other income items increased $2.6 million in the first

quarter of 2006, versus the first quarter of 2005. The increase included

incremental income of $1.8 million, recognized in the first quarter of 2006,

related to a favorable settlement associated with our purchase of the Kinder

Morgan St. Gabriel terminal in September 2002. The overall increase in other

income also included a $1.2 million increase due to a disposal loss, recognized

in the first quarter of 2005, on warehouse property at our Elizabeth River bulk

terminal.

     The segment's income tax expenses decreased $1.7 million (46%) in the first

three months of 2006, compared to the first three months of 2005. The decrease

was due to lower taxable earnings from Kinder Morgan Bulk Terminals, Inc., the

tax-paying entity that owns many of our bulk terminal businesses.

     Compared to the first quarter of 2005, non-cash depreciation, depletion and

amortization charges increased $5.1 million (42%) in the first quarter of 2006.

In addition to increases associated with normal capital spending, the periodic

increase reflected higher depreciation charges due to the terminal acquisitions

we have made since the end of the first quarter of 2005. Collectively, these

terminal assets, described above, accounted for incremental depreciation

expenses of $4.3 million in the first quarter of 2006.

     Other

                                                    Three Months Ended March 31,

                                                    ----------------------------

                                                         2006           2005

                                                    ----------      ----------

                                                 (In thousands-income/(expense))

  General and administrative expenses............   $  (60,883)     $  (73,852)

  Unallocable interest, net......................      (76,967)        (60,047)

  Minority interest..............................       (2,370)         (2,388)

                                                    ----------      ----------

    Interest and corporate administrative expenses  $ (140,220)     $ (136,287)

                                                    ==========      ==========

     Items not attributable to any segment include general and administrative

expenses, unallocable interest income, interest expense and minority interest.

General and administrative expenses include such items as salaries and

employee-related expenses, payroll taxes, insurance, office supplies and

rentals, unallocated litigation and environmental expenses, and shared corporate

services, including accounting, information technology, human resources, and

legal fees.

     Our total general and administrative expenses decreased $13.0 million (18%)

in the first quarter of 2006, when compared to the first quarter of 2005. The

overall decrease in general and administrative expenses included a decrease of

$27.4 million related to unallocated litigation and environmental settlement

expenses that we recognized in the first quarter of 2005--consisting of a $25

million expense for a settlement reached between us and a joint venture partner

on our Kinder Morgan Tejas natural gas pipeline system, a $5.4 million expense

related to settlements of environmental matters at certain of our operating

sites located in the State of California, and a $3.0 million decrease in expense

related to favorable settlements of obligations that Enron Corp. had to us in

conjunction with derivatives we were accounting for as hedges under Statement of

Financial Accounting Standards No. 133, "Accounting for Derivative Instruments

and Hedging Activities."

     Offsetting the decrease related to unallocated litigation and environmental

settlement expenses were higher general and administrative expenses, in the

first quarter of 2006, in the amount of $14.4 million, primarily due to higher

period-to-period corporate services--due in part to acquisitions made since the

first quarter of 2005, and to higher employee benefit costs, payroll taxes, and

corporate insurance expenses. Currently and prospectively, we

                                       64

<PAGE>

face the challenge of rising general and administrative expenses due to

increasing employee health care costs and business insurance costs; however, we

continue to manage aggressively our infrastructure expense and we remain focused

on maintaining affordable expense levels and eliminating unnecessary overhead

expenses.

     Unallocable interest expense, net of interest income, increased $16.9

million (28%) in the first quarter of 2006, compared to the same year-earlier

period. The increase was due to both higher quarter-to-quarter average debt

levels and higher effective interest rates. The increase in our average

borrowings was due to higher capital spending--related to internal expansions

and improvements, external assets and businesses acquired since the end of the

first quarter of 2005, and a net increase of $300 million in principal amount of

long-term senior notes since the beginning of 2005. On March 15, 2005, we both

closed a public offering of $500 million in principal amount of senior notes and

retired a principal amount of $200 million. We issue senior notes in order to

refinance commercial paper borrowings used for both internal capital spending

and acquisition expenditures.

     The increase in our average borrowing rates reflects a general rise in

variable interest rates since the end of the first quarter of 2005. The weighted

average interest rate on all of our borrowings increased 13% in the first

quarter of 2006, compared to the first quarter of 2005. We use interest rate

swap agreements to help manage our interest rate risk. The swaps are contractual

agreements we enter into in order to transform a portion of the underlying cash

flows related to our long-term fixed rate debt securities into variable rate

debt in order to achieve our desired mix of fixed and variable rate debt.

However, in a period of rising interest rates, these swaps will result in

period-to-period increases in our interest expense. For more information on our

interest rate swaps, see Note 10 to our consolidated financial statements,

included elsewhere in this report.

     Financial Condition

     Capital Structure

     We attempt to maintain a conservative overall capital structure, with a

long-term target mix of approximately 60% equity and 40% debt. The following

table illustrates the sources of our invested capital (dollars in thousands). In

addition to our results of operations, these balances are affected by our

financing activities as discussed below:

                                                       March 31,    December 31,

                                                         2006          2005

                                                     -----------   -----------

Long-term debt, excluding market value of

interest rate swaps................................  $ 5,704,920   $ 5,220,887

Minority interest..................................      131,087        42,331

Partners' capital, excluding accumulated other

comprehensive loss.................................    4,682,849     4,693,414

                                                     -----------   -----------

  Total capitalization.............................   10,518,856     9,956,632

Short-term debt, less cash and cash equivalents....      (32,636)      (12,108)

                                                     -----------   -----------

  Total invested capital...........................  $10,486,220   $ 9,944,524

                                                     ===========   ===========

Capitalization:

  Long-term debt, excluding market value of

  interest rate swaps..............................         54.2%         52.4%

  Minority interest................................          1.3%          0.4%

   Partners' capital, excluding accumulated

   other comprehensive loss........................         44.5%         47.2%

                                                     -----------   -----------

                                                           100.0%        100.0%

                                                     ===========   ===========

Invested Capital:

  Total debt, less cash and cash equivalents and

    excluding Market value of interest rate swaps..         54.1%         52.4%

  Partners' capital and minority interest,

  excluding accumulated other comprehensive loss...         45.9%         47.6%

                                                      -----------  -----------

                                                           100.0%        100.0%

                                                      ===========  ===========

     Our primary cash requirements, in addition to normal operating expenses,

are debt service, sustaining capital expenditures, expansion capital

expenditures and quarterly distributions to our common unitholders, Class B

unitholders and general partner. In addition to utilizing cash generated from

operations, we could meet our cash requirements (other than distributions to our

common unitholders, Class B unitholders and general partner) through borrowings

under our credit facility, issuing short-term commercial paper, long-term notes

or additional common units or the proceeds from purchases of additional i-units

by KMR with the proceeds from issuances of KMR shares.

                                       65

<PAGE>

     In general, we expect to fund:

     o    cash distributions and sustaining capital expenditures with existing

          cash and cash flows from operating activities;

     o    expansion capital expenditures and working capital deficits with

          retained cash (resulting from including i-units in the determination

          of cash distributions per unit but paying quarterly distributions on

          i-units in additional i-units rather than cash), additional

          borrowings, the issuance of additional common units or the proceeds

          from purchases of additional i-units by KMR;

     o    interest payments with cash flows from operating activities; and

     o    debt principal payments with additional borrowings, as such debt

          principal payments become due, or by the issuance of additional common

          units or the issuance of additional i-units to KMR.

     As a publicly traded limited partnership, our common units are attractive

primarily to individual investors, although such investors represent a small

segment of the total equity capital market. We believe that some institutional

investors prefer shares of KMR over our common units due to tax and other

regulatory considerations. We are able to access this segment of the capital

market through KMR's purchases of i-units issued by us with the proceeds from

the sale of KMR shares to institutional investors.

     As part of our financial strategy, we try to maintain an investment-grade

credit rating, which involves, among other things, the issuance of additional

limited partner units in connection with our acquisitions and internal growth

activities in order to maintain acceptable financial ratios, including total

debt to total capital. On August 2, 2005, following KMI's announcement of its

proposed acquisition of Terasen Inc., Standard & Poor's Rating Services placed

our debt credit ratings, as well as KMI's ratings, on CreditWatch with negative

implications. On December 5, 2005, S&P affirmed our debt credit ratings, as well

as KMI's ratings, with a negative outlook and removed them from CreditWatch. On

February 23, 2006, Moody's Investors Service, which also publishes credit

ratings on commercial entities, affirmed our debt credit ratings and changed its

rating outlook from negative to stable.

     Short-term Liquidity

     Our principal sources of short-term liquidity are:

     o    our $1.6 billion five-year senior unsecured revolving credit facility

          that matures August 18, 2010;

     o    our $250 million nine-month unsecured revolving credit facility that

          matures November 21, 2006;

     o    our $1.85 billion short-term commercial paper program (which was

          increased from $1.6 billion to $1.85 billion in April 2006, and which

          is supported by our bank credit facilities, with the amount available

          for borrowing under our credit facilities being reduced by our

          outstanding commercial paper borrowings); and

     o    cash from operations (discussed following).

     Borrowings under our two credit facilities can be used for general

corporate purposes and as a backup for our commercial paper program. There were

no borrowings under our five-year credit facility as of December 31, 2005; there

were no borrowings under either credit facility as of March 31, 2006.

     We provided for additional liquidity by maintaining a sizable amount of

excess borrowing capacity related to our commercial paper program and long-term

revolving credit facility. After inclusion of our outstanding commercial paper

borrowings and letters of credit, the remaining available borrowing capacity

under our bank credit facilities was $339.5 million as of March 31, 2006.

                                       66

<PAGE>

     As of March 31, 2006, our outstanding short-term debt was $1,060.8 million.

We intended and had the ability to refinance all of our short-term debt on a

long-term basis under our unsecured long-term credit facility. Accordingly, such

amounts have been classified as long-term debt in our accompanying consolidated

balance sheet. Currently, we believe our liquidity to be adequate.

     Some of our customers are experiencing, or may experience in the future,

severe financial problems that have had or may have a significant impact on

their creditworthiness. We are working to implement, to the extent allowable

under applicable contracts, tariffs and regulations, prepayments and other

security requirements, such as letters of credit, to enhance our credit position

relating to amounts owed from these customers. We cannot provide assurance that

one or more of our financially distressed customers will not default on their

obligations to us or that such a default or defaults will not have a material

adverse effect on our business, financial position, future results of

operations, or future cash flows.

     Long-term Financing

     In addition to our principal sources of short-term liquidity listed above,

we could meet our cash requirements (other than distributions to our common

unitholders, Class B unitholders and general partner) through issuing long-term

notes or additional common units, or the proceeds from purchases of additional

i-units by KMR with the proceeds from issuances of KMR shares.

     We are subject, however, to changes in the equity markets for our limited

partner units, and there can be no assurance we will be able or willing to

access the public or private markets for our limited partner units in the

future. If we were unable or unwilling to issue additional limited partner

units, we would be required to either restrict potential future acquisitions or

pursue other debt financing alternatives, some of which could involve higher

costs or negatively affect our credit ratings.

     All of our long-term debt securities issued to date, other than those

issued under our revolving credit facilities or those issued by our subsidiaries

and operating partnerships, generally have the same terms except for interest

rates, maturity dates and prepayment premiums. All of our outstanding debt

securities are unsecured obligations that rank equally with all of our other

senior debt obligations; however, a modest amount of secured debt has been

incurred by some of our operating partnerships and subsidiaries. Our fixed rate

notes provide that we may redeem the notes at any time at a price equal to 100%

of the principal amount of the notes plus accrued interest to the redemption

date plus a make-whole premium.

     As of March 31, 2006, our total liability balance due on the various series

of our senior notes was $4,489.8 million, and the total liability balance due on

the borrowings of our operating partnerships and subsidiaries was $163.8

million. For additional information regarding our debt and credit facilities,

see Note 9 to our consolidated financial statements included in our Form 10-K

for the year ended December 31, 2005.

     Operating Activities

     Net cash provided by operating activities was $176.0 million for the three

months ended March 31, 2006, versus $259.5 million in the comparable period of

2005. The period-to-period decrease of $83.5 million (32%) in cash flow from

operations consisted of:

     o    an $81.2 million decrease in cash inflows relative to net changes in

          working capital items--mainly due to timing differences that resulted

          in higher cash outflows with regard to our net accounts payables and

          receivables, and to additional payments for natural gas imbalance

          settlements and accrued interest;

     o    a $16.6 million decrease in cash inflows relative to net changes in

          non-current assets and liabilities--related to, among other things,

          higher payments made in the first quarter of 2006 for pipeline project

          costs, studies and business development charges, largely related to

          our Rockies Express pipeline, and for higher payments made for natural

          gas liquids inventory on our North System. In the second quarter of

          2006, we will transfer accumulated project costs related to our

          Rockies Express pipeline to within "Property, plant and equipment,

          net" on our consolidated balance sheet;

                                       67

<PAGE>

     o    a $9.0 million increase related to higher distributions received from

          equity investments--chiefly due to higher distributions received from

          Red Cedar Gathering Company in the first three months of 2006,

          partially offset by lower distributions from Cortez Pipeline Company.

          The change reflects higher and lower year-over-year net income in the

          first quarter of 2006 versus the first quarter of 2005 for Red Cedar

          and Cortez, respectively; and

     o    a $5.3 million increase in cash from overall higher partnership

          income, net of non-cash items including depreciation charges,

          undistributed earnings from equity investments, and litigation and

          environmental expenses that impacted earnings but not cash. The higher

          partnership income reflects the increase in cash earnings from our

          four reportable business segments in the first three months of 2006,

          as discussed above in "-Results of Operations."

     Investing Activities

     Net cash used in investing activities was $479.9 million for the three

month period ended March 31, 2006, compared to $168.0 million in the comparable

2005 period. The $311.9 million increase in cash used in investing activities

was primarily attributable to:

     o    a $233.5 million increase due to higher expenditures made for

          strategic business acquisitions. In the first quarter of 2006, we

          spent $240.0 million to acquire Entrega Gas Pipeline LLC, and in the

          first quarter last year, we spent $6.5 million, which primarily

          related to our acquisition of a 64.5% gross working interest in the

          Claytonville oil field unit located in West Texas;

     o    a $49.9 million (35%) increase in capital expenditures;

     o    a $15.0 million increase in margin deposits--associated with hedging

          activities utilizing energy derivative instruments; and

     o    a $7.9 million increase related to additional investments in

          underground natural gas storage volumes and to higher payments made

          for natural gas liquids line-fill on our North System.

     Including expansion and maintenance projects, our capital expenditures were

$193.7 million in the first quarter of 2006, compared to $143.8 million in the

same prior-year period. Our sustaining capital expenditures were $25.7 million

for the first three months of 2006, compared to $24.2 million for the first

three months of 2005. Sustaining capital expenditures are defined as capital

expenditures which do not increase the capacity of an asset. Based on our 2006

sustaining capital expenditure forecast, our forecasted expenditures for the

remaining nine months of 2006 for sustaining capital expenditures were

approximately $144.3 million. This amount has been committed primarily for the

purchase of plant and equipment. All of our capital expenditures, with the

exception of sustaining capital expenditures, are discretionary.

     Since the beginning of 2006, we made the following announcements related to

our investing activities:

     o    On March 9, 2006, we announced that we have entered into a long-term

          agreement with Drummond Coal Sales, Inc. that will support a $70

          million expansion of our Pier IX bulk terminal located in Newport

          News, Virginia. The agreement has a term that can be extended for up

          to 30 years. The project includes the construction of a new ship dock

          and the installation of additional equipment; it is expected to

          increase throughput at the terminal by approximately 30% and will

          allow the terminal to begin receiving shipments of imported coal. The

          expansion is expected to be completed in the first quarter of 2008.

          Upon completion, the terminal will have an import capacity of up to 9

          million tons annually. Currently, our Pier IX terminal can store

          approximately 1.4 million tons of coal and 30,000 tons of cement on

          its 30-acre storage site; and

     o    On April 6, 2006, we announced the second of two investments in our

          CALNEV refined petroleum products pipeline system. Combined, the $25

          million in capital improvements will upgrade and expand pipeline

          capacity and help provide sufficient fuel supply to the Las Vegas,

          Nevada market for the next several years. The first project, estimated

          to cost approximately $10 million, involves pipeline expansions that

          will increase current transportation capacity by 3,200 barrels per day

          (2.2%), as well as the construction of two new 80,000

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          barrel storage tanks at our Las Vegas terminal. The second project,

          expected to cost approximately $15 million, includes the installation

          of new and upgraded pumping equipment and piping at our Colton,

          California terminal, a new booster station with two pumps at Cajon,

          California, and piping upgrades at our Las Vegas terminal. In

          addition, we are currently exploring a $300 to $400 million future

          expansion that would increase capacity on the pipeline to

          approximately 220,000 barrels per day by 2010. Currently, our CALNEV

          Pipeline can transport approximately 140,000 barrels of refined

          products per day;

     o    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 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. 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 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.

     o    On April 19, 2006, our general partner's and KMR's board of directors

          approved a $75 million expansion of our Texas intrastate natural gas

          pipeline group's natural gas storage capabilities. The expansion will

          include the development of a third natural gas storage cavern at our

          North Dayton, Texas storage facility, which we acquired in August

          2005. The expansion will more than double working capacity to over 9

          billion cubic feet and is expected to be in service by April 1, 2009;

     o    On April 19, 2006, we announced that the pipeline portion of our $210

          million Pacific operations' East Line expansion project, initially

          proposed in October 2002, had been completed and the new breakout tank

          farm near El Paso, Texas was scheduled to be in service around June 1,

          2006. This expansion project will significantly increase pipeline

          transportation capacity for refined petroleum products between El Paso

          and Phoenix, Arizona; and

     o    On April 19, 2006, we and our partner Sempra Energy announced that we

          are moving forward on the approximate $4.4 billion Rockies Express

          Pipeline project after obtaining binding commitments from creditworthy

          shippers for all 1.8 billion cubic feet of transportation capacity on

          the 1,323-mile pipeline that will move natural gas from the Rocky

          Mountain Region to the eastern United States. Service on the 710-mile

          segment of the Rockies Express Pipeline that extends from Cheyenne to

          eastern Missouri is expected to commence on January 1, 2008, and the

          entire project is expected to be completed by June 2009, subject to

          regulatory approvals.

          In addition, interim service has begun on the western portion of the

          Entrega Pipeline (that extends from Meeker, Colorado to Wamsutter,

          Wyoming). The construction of the remainder of Entrega (that extends

          from Wamsutter to Cheyenne, Wyoming) is scheduled to begin this

          summer, and the entire system is expected to be in service by January

          1, 2007. In April 2006, Rockies Express Pipeline LLC merged with and

          into Entrega Gas Pipeline LLC, and the remaining entity was renamed

          Rockies Express Pipeline LLC. Going forward, the entire pipeline

          system will be known as the Rockies Express Pipeline. We have ordered

          substantially all of the piping required for the Rockies Express and

          the $500 million Kinder Morgan Louisiana Pipeline projects at fixed

          prices consistent with project budgets.

     Financing Activities

     Net cash provided by financing activities amounted to $324.4 million for

the three months ended March 31, 2006; for the same quarter last year, we used

$91.5 million in financing activities. The $415.9 million overall increase in

cash inflows provided by our financing activities was primarily due to:

     o    a $343.0 million increase from overall debt financing activities,

          which include our issuances and payments of debt and our debt issuance

          costs. The increase was primarily due to a $638.6 million increase due

          to higher net commercial paper borrowings in the first quarter of

          2006, partly offset by a $294.4 million decrease due to

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          net changes in the principal amount of senior notes. On March 15,

          2005, we closed a public offering of $500 million in principal amount

          of 5.80% senior notes and repaid $200 million of 8.0% senior notes

          that matured on that date. The 5.80% senior notes are due March 15,

          2035. We received proceeds from the issuance of the notes, after

          underwriting discounts and commissions, of approximately $494.4

          million, and we used the proceeds to repay the 8.0% senior notes and

          to reduce our commercial paper debt;

     o    a $90.6 million increase from contributions from minority interests,

          principally due to Sempra Energy's $80.0 million contribution for its

          33 1/3% share of the purchase price of Entrega Pipeline LLC, discussed

          above in "--Investing Activities";

     o    a $20.3 million increase from net changes in cash book overdrafts,

          which represent checks issued but not yet endorsed; and

     o    a $37.5 million decrease from higher partnership distributions. The

          increase was due to an increase in the per unit cash distributions

          paid, an increase in the number of units outstanding and an increase

          in our general partner incentive distributions. The increase in our

          general partner incentive distributions resulted from both increased

          cash distributions per unit and an increase in the number of common

          units and i-units outstanding.

     Partnership Distributions

     Distributions to all partners, consisting of our common and Class B

unitholders, our general partner and minority interests, totaled $261.0 million

in the first quarter 2006, compared to $223.5 million in the first quarter of

2005. Our partnership agreement requires that we distribute 100% of "Available

Cash," as defined in our partnership agreement, to our 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 our cash

receipts, including cash received by our 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, L.P. in respect of

its remaining 0.5% interest in SFPP.

     Our general partner is granted discretion by our partnership agreement,

which discretion has been delegated to KMR, subject to the approval of our

general partner in certain cases, 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 KMR determines our quarterly distributions, it

considers current and expected reserve needs along with current and expected

cash flows to identify the appropriate sustainable distribution level.

     Our general partner and owners of our common units and Class B units

receive distributions in cash, while KMR, the sole owner of our i-units,

receives distributions in additional i-units. We do not distribute cash to

i-unit owners but retain the cash for use in our business. However, the cash

equivalent of distributions of i-units is treated as if it had actually been

distributed for purposes of determining the distributions to our general

partner. Each time we make a distribution, the number of i-units owned by KMR

and the percentage of our total units owned by KMR increase automatically under

the provisions of our partnership agreement.

     Available cash is initially distributed 98% to our limited partners and 2%

to our general partner. These distribution percentages are modified to provide

for incentive distributions to be paid to our general partner in the event that

quarterly distributions to unitholders exceed certain specified targets.

     Available cash for each quarter is distributed:

     o    first, 98% to the owners of all classes of units pro rata and 2% to

          our general partner 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;

     o    second, 85% of any available cash then remaining to the owners of all

          classes of units pro rata and 15% to our general partner 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;

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     o    third, 75% of any available cash then remaining to the owners of all

          classes of units pro rata and 25% to our general partner 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

     o    fourth, 50% of any available cash then remaining to the owners of all

          classes of units pro rata, to owners of common units and Class B units

          in cash and to owners of i-units in the equivalent number of i-units,

          and 50% to our general partner.

     Incentive distributions are generally defined as all cash distributions

paid to our general partner that are in excess of 2% of the aggregate value of

cash and i-units being distributed. Our general partner's incentive distribution

that we declared for 2005 was $473.9 million, while the incentive distribution

paid to our general partner during 2005 was $454.3 million. The difference

between declared and paid distributions is due to the fact that our

distributions for the fourth quarter of each year are declared and paid in the

first quarter of the following year.

     On February 14, 2006, we paid a quarterly distribution of $0.80 per unit

for the fourth quarter of 2005. This distribution was 8% greater than the $0.74

distribution per unit we paid for the fourth quarter of 2004 and 5% greater than

the $0.76 distribution per unit we paid for the first quarter of 2005. We paid

this distribution in cash to our common unitholders and to our Class B

unitholders. KMR, our sole i-unitholder, received additional i-units based on

the $0.80 cash distribution per common unit. We believe that future operating

results will continue to support similar levels of quarterly cash and i-unit

distributions; however, no assurance can be given that future distributions will

continue at such levels.

     Incentive distributions are generally defined as all cash distributions

paid to our general partner that are in excess of 2% of the aggregate value of

cash and i-units being distributed. Our general partner's incentive distribution

for the distribution that we declared for the first quarter of 2006 was $128.3

million. Our general partner's incentive distribution for the distribution that

we declared for the first quarter of 2005 was $111.1 million. Our general

partner's incentive distribution that we paid during the first quarter of 2006

to our general partner (for the fourth quarter of 2005) was $125.6 million. Our

general partner's incentive distribution that we paid during the first quarter

of 2005 to our general partner (for the fourth quarter of 2004) was $106.0

million.

     We believe that future operating results will continue to support similar

levels of quarterly cash and i-unit distributions; however, no assurance can be

given that future distributions will continue at such levels.

     Litigation and Environmental

     As of March 31, 2006, we have recorded a total reserve for environmental

claims, without discounting and without regard to anticipated insurance

recoveries, in the amount of $50.1 million. In addition, we have recorded a

receivable of $27.6 million for expected cost recoveries that have been deemed

probable. The reserve is primarily established to address and clean up soil and

ground water impacts from former releases to the environment at facilities we

have acquired. Reserves for each project are generally established by reviewing

existing documents, conducting interviews and performing site inspections to

determine the overall size and impact to the environment. Reviews are made on a

quarterly basis to determine the status of the cleanup and the costs associated

with the effort. In assessing environmental risks in conjunction with proposed

acquisitions, we review records relating to environmental issues, conduct site

inspections, interview employees, and, if appropriate, collect soil and

groundwater samples.

     As of March 31, 2006, we have recorded a total reserve for legal fees,

transportation rate cases and other litigation liabilities in the amount of

$135.6 million. The reserve is primarily related to various claims from lawsuits

arising from our Pacific operations' pipeline transportation rates, and the

contingent amount is based on both the circumstances of probability and

reasonability of dollar estimates. We regularly assess the likelihood of adverse

outcomes resulting from these claims in order to determine the adequacy of our

liability provision. We believe we have established adequate environmental and

legal reserves such that the resolution of pending environmental matters and

litigation will not have a material adverse impact on our business, cash flows,

financial position or results of operations. However, changing circumstances

could cause these matters to have a material adverse impact.

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     Pursuant to our continuing commitment to operational excellence and our

focus on safe, reliable operations, we have implemented, and intend to implement

in the future, enhancements to certain of our operational practices in order to

strengthen our environmental and asset integrity performance. These enhancements

have resulted and may result in higher operating costs and sustaining capital

expenditures; however, we believe these enhancements will provide us the greater

long term benefits of improved environmental and asset integrity performance.

     Please refer to Notes 3 and 14, respectively, to our consolidated financial

statements included elsewhere in this report for additional information

regarding pending litigation, environmental and asset integrity matters.

     Certain Contractual Obligations

     There have been no material changes in either certain contractual

obligations or our obligations with respect to other entities which are not

consolidated in our financial statements that would affect the disclosures

presented as of December 31, 2005 in our 2005 Form 10-K report.

Information Regarding Forward-Looking Statements

     This filing includes forward-looking statements. These forward-looking

statements are identified as any statement that does not relate strictly to

historical or current facts. They use words such as "anticipate," "believe,"

"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"

"estimate," "expect," "may," or the negative of those terms or other variations

of them or comparable terminology. In particular, statements, express or

implied, concerning future actions, conditions or events, future operating

results or the ability to generate sales, income or cash flow or to make

distributions 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:

     o    price trends and overall demand for natural gas liquids, refined

          petroleum products, oil, carbon dioxide, natural gas, coal and other

          bulk materials and chemicals in North America;

     o    economic activity, weather, alternative energy sources, conservation

          and technological advances that may affect price trends and demand;

     o    changes in our tariff rates implemented by the Federal Energy

          Regulatory Commission or the California Public Utilities Commission;

     o    our ability to acquire new businesses and assets and integrate those

          operations into our existing operations, as well as our ability to

          make expansions to our facilities;

     o    difficulties or delays experienced by railroads, barges, trucks, ships

          or pipelines in delivering products to or from our terminals or

          pipelines;

     o    our ability to successfully identify and close acquisitions and make

          cost-saving changes in operations;

     o    shut-downs or cutbacks at major refineries, petrochemical or chemical

          plants, ports, utilities, military bases or other businesses that use

          our services or provide services or products to us;

     o    crude oil and natural gas production from exploration and production

          areas that we serve, including, among others, the Permian Basin area

          of West Texas;

     o    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;

     o    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;

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     o    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;

     o    our indebtedness could make us vulnerable to general adverse economic

          and industry conditions, limit our ability to borrow additional funds,

          and/or place us at competitive disadvantages compared to our

          competitors that have less debt or have other adverse consequences;

     o    interruptions of electric power supply to our facilities due to

          natural disasters, power shortages, strikes, riots, terrorism, war or

          other causes;

     o    our ability to obtain insurance coverage without significant levels of

          self-retention of risk;

     o    acts of nature, sabotage, terrorism or other similar acts causing

          damage greater than our insurance coverage limits;

     o    capital markets conditions;

     o    the political and economic stability of the oil producing nations of

          the world;

     o    national, international, regional and local economic, competitive and

          regulatory conditions and developments;

     o    the ability to achieve cost savings and revenue growth;

     o    inflation;

     o    interest rates;

     o    the pace of deregulation of retail natural gas and electricity;

     o    foreign exchange fluctuations;

     o    the timing and extent of changes in commodity prices for oil, natural

          gas, electricity and certain agricultural products;

     o    the extent of our success in discovering, developing and producing oil

          and gas reserves, including the risks inherent in exploration and

          development drilling, well completion and other development

          activities;

     o    engineering and mechanical or technological difficulties with

          operational equipment, in well completions and workovers, and in

          drilling new wells;

     o    the uncertainty inherent in estimating future oil and natural gas

          production or reserves;

     o    the timing and success of business development efforts; and

     o    unfavorable results of litigation and the fruition of contingencies

          referred to in Note 16 to our consolidated financial statements

          included elsewhere in this report.

     There is no assurance that any of the actions, events or results of the

forward-looking statements will occur, or if any of them do, what impact they

will have on our results of operations or financial condition. Because of these

uncertainties, you should not put undue reliance on any forward-looking

statements.

     See Item 1A "Risk Factors" of our Annual Report on Form 10-K 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 our 2005 Form 10-K

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report. 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.

     There have been no material changes in market risk exposures that would

affect the quantitative and qualitative disclosures presented as of December 31,

2005, in Item 7A of our 2005 Form 10-K report. For more information on our risk

management activities, see Note 10 to our consolidated financial statements

included elsewhere in this report.

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 Chief Financial Officer, as appropriate, to allow timely decisions

regarding required disclosure. There has been no change in our internal control

over financial reporting during the quarter ended March 31, 2006 that has

materially affected, or is reasonably likely to materially affect, our internal

control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

     See Part I, Item 1, Note 3 to our consolidated financial statements

entitled "Litigation, Environmental and Other Contingencies," which is

incorporated in this item by reference.

Item 1A.  Risk Factors.

     There have been no material changes to the risk factors disclosed in Item

1A "Risk Factors" in our Annual Report on Form 10-K for the year ended December

31, 2005.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

     None.

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 long-term debt of Kinder Morgan

     Energy Partners, L.P. and its consolidated subsidiaries which relate to

     debt that does not exceed 10% of the total assets of Kinder Morgan Energy

     Partners, L.P. 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 Energy Partners, L.P. 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).

11   -- Statement re: computation of per share earnings.

12   -- Statement re: computation of ratio of earnings to fixed charges.

31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities

     Exchange Act of 1934, as adopted pursuant to Section 302 of the

     Sarbanes-Oxley Act of 2002.

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31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities

     Exchange Act of 1934, as adopted pursuant to Section 302 of the

     Sarbanes-Oxley Act of 2002.

32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted

     pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted

     pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

----------

*    Asterisk indicates exhibits incorporated by reference as indicated; all

     other exhibits are filed herewith, except as noted otherwise.

                                       76

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                                    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 ENERGY PARTNERS, L.P.

                                (A Delaware limited partnership)

                                By: KINDER MORGAN G.P., INC.,

                                    its sole General Partner

                                By: KINDER MORGAN MANAGEMENT, LLC,

                                    the Delegate of Kinder Morgan G.P., Inc.

                                    /s/ Kimberly A. Dang

                                    ------------------------------

                                    Kimberly A. Dang

                                    Vice President and Chief Financial Officer

                                    Date:  May 9, 2006