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 September 30, 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 October 31, 2006 was 134,061,668 shares.

KMI Form 10-Q

KINDER MORGAN, INC. AND SUBSIDIARIES

FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 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	8-67
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	68-89
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	89-90
Item 4.	Controls and Procedures.	90
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings.	91
Item 1A.	Risk Factors.	91
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	91
Item 3.	Defaults Upon Senior Securities.	91
Item 4.	Submission of Matters to a Vote of Security Holders.	91
Item 5.	Other Information.	91
Item 6.	Exhibits.	92
SIGNATURE		93

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KMI Form 10-Q

PART I. - FINANCIAL INFORMATION

Item 1.  Financial Statements.

CONSOLIDATED BALANCE SHEETS (Unaudited)

Kinder Morgan, Inc. and Subsidiaries

	September 30, 2006		December 31, 2005
	(In millions)
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	110.2	$	116.6
Restricted Deposits		23.5		10.6
Accounts, Notes and Interest Receivable, Net:
Trade		1,017.7		489.0
Related Parties		17.8		17.2
Inventories		353.4		228.2
Gas Imbalances		19.1		16.9
Assets Held for Sale		72.8		126.7
Rate Stabilization		148.2		35.7
Other		301.8		263.2
		2,064.5		1,304.1
Notes Receivable – Related Parties		90.9		-
Investments:
Kinder Morgan Energy Partners		-		2,202.9
Other		1,109.3		649.6
		1,109.3		2,852.5
Goodwill		3,765.3		2,781.0
Other Intangibles, Net		226.6		17.7
Property, Plant and Equipment, Net		18,530.1		9,545.6
Assets Held for Sale, Non-current		411.4		-
Deferred Charges and Other Assets		1,090.0		950.7
Total Assets	$	27,288.1	$	17,451.6

The accompanying notes are an integral part of these statements.

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KMI Form 10-Q

CONSOLIDATED BALANCE SHEETS (Unaudited)

Kinder Morgan, Inc. and Subsidiaries

	September 30, 2006			December 31, 2005
	(In millions except shares)
LIABILITIES AND STOCKHOLDERS’ EQUITY:
Current Liabilities:
Current Maturities of Long-term Debt	$	301.4		$	347.4
Notes Payable		1,468.4			610.6
Cash Book Overdrafts		53.1			-
Accounts Payable:
Trade		917.0			431.2
Related Parties		4.1			-
Accrued Interest		124.2			92.0
Accrued Taxes		121.6			100.1
Gas Imbalances		21.8			16.1
Rate Stabilization		24.1			115.1
Liabilities Held for Sale		59.8			21.9
Other		1,026.2			208.2
		4,121.7			1,942.6
Other Liabilities and Deferred Credits:
Deferred Income Taxes		3,114.1			3,156.4
Liabilities Held for Sale, Non-current		45.1			-
Other		1,537.3			451.5
		4,696.5			3,607.9
Long-term Debt:
Outstanding Notes and Debentures		10,923.6			6,286.8
Deferrable Interest Debentures Issued to Subsidiary Trusts		283.6			283.6
Capital Securities		111.5			107.2
Value of Interest Rate Swaps		53.4			51.8
		11,372.1			6,729.4
Minority Interests in Equity of Subsidiaries		2,903.0			1,247.3
Stockholders’ Equity:
Common Stock-
Authorized – 300,000,000 Shares, Par Value $5 Per Share
Outstanding – 149,026,132 and 148,479,863 Shares, Respectively, Before Deducting 15,017,251 and 14,712,901 Shares Held in Treasury		745.1			742.4
Additional Paid-in Capital		3,061.7			3,056.3
Retained Earnings		1,319.2			1,175.3
Treasury Stock		(915.5	)		(885.7	)
Deferred Compensation		-			(36.9	)
Accumulated Other Comprehensive Loss		(15.7	)		(127.0	)
Total Stockholders’ Equity		4,194.8			3,924.4
Total Liabilities and Stockholders’ Equity	$	27,288.1		$	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 September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(In millions except per share amounts)
Operating Revenues:
Natural Gas Sales	$	1,736.9		$	47.6		$	5,750.4		$	107.2
Transportation and Storage		826.4			174.0			2,422.2			533.0
Oil and Product Sales		193.5			-			556.5			1.3
Other		71.9			25.1			169.5			55.0
Total Operating Revenues		2,828.7			246.7			8,898.6			696.5
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales		1,709.1			82.3			5,551.3			187.8
Operations and Maintenance		344.8			33.6			956.0			95.0
General and Administrative		97.4			14.5			298.5			44.8
Depreciation, Depletion and Amortization		164.5			26.0			471.6			76.5
Taxes, Other Than Income Taxes		51.5			7.5			163.2			23.0
Other Expenses (Income)		-			-			(15.1	)		-
Total Operating Costs and Expenses		2,367.3			163.9			7,425.5			427.1
Operating Income		461.4			82.8			1,473.1			269.4
Other Income and (Expenses):
Equity in Earnings of Kinder Morgan Energy Partners		-			169.2			-			480.4
Equity in Earnings of Other Equity Investments		23.0			3.7			80.6			10.3
Interest Expense, Net		(200.0	)		(37.0	)		(569.6	)		(106.0	)
Interest Expense – Deferrable Interest Debentures		(5.4	)		(5.4	)		(16.4	)		(16.4	)
Interest Expense – Capital Securities		(2.2	)		-			(6.6	)		-
Minority Interests		(78.7	)		(23.7	)		(265.6	)		(55.0	)
Other, Net		5.0			0.4			(5.0	)		29.6
Total Other Income and (Expenses)		(258.3	)		107.2			(782.6	)		342.9
Income from Continuing Operations Before Income Taxes		203.1			190.0			690.5			612.3
Income Taxes		60.0			77.2			203.4			249.3
Income from Continuing Operations		143.1			112.8			487.1			363.0
Income (Loss) from Discontinued Operations, Net of Tax		1.1			(3.7	)		8.0			11.4
Net Income	$	144.2		$	109.1		$	495.1		$	374.4
Basic Earnings (Loss) Per Common Share:
Continuing Operations	$	1.07		$	0.92		$	3.67		$	2.96
Discontinued Operations		0.01			(0.03	)		0.06			0.09
Total Basic Earnings Per Common Share	$	1.08		$	0.89		$	3.73		$	3.05
Number of Shares Used in Computing Basic Earnings Per Common Share		133.1			122.5			132.9			122.6
Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$	1.06		$	0.91		$	3.61		$	2.94
Discontinued Operations		0.01			(0.03	)		0.06			0.09
Total Diluted Earnings Per Common Share	$	1.07		$	0.88		$	3.67		$	3.03
Number of Shares Used in Computing Diluted Earnings Per Common Share		135.1			123.7			135.0			123.8
Dividends Per Common Share	$	0.8750		$	0.7500		$	2.6250		$	2.1500

The accompanying notes are an integral part of these statements.

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KMI Form 10-Q

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

Kinder Morgan, Inc. and Subsidiaries

Increase (Decrease) in Cash and Cash Equivalents

	Nine Months Ended September 30,
	2006			2005
	(In millions)
Cash Flows From Operating Activities:
Net Income	$	495.1		$	374.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Income from Discontinued Operations, Net of Tax		(8.0	)		(11.4	)
Depreciation, Depletion and Amortization		471.6			76.5
Deferred Income Taxes		63.3			118.4
Equity in Earnings of Kinder Morgan Energy Partners		-			(480.4	)
Distributions from Kinder Morgan Energy Partners		-			389.5
Equity in Earnings of Other Investments		(80.6	)		(10.3	)
Distributions from Other Equity Investees		60.9			5.5
Minority Interests in Income of Consolidated Subsidiaries		265.6			55.0
Changes in Rate Stabilization Accounts		18.7			-
Net Gains on Sales of Assets		(20.6	)		(27.1	)
Mark-to-Market Interest Rate Swap Loss		22.3			-
Pension Contribution in Excess of Expense		-			(24.0	)
Changes in Gas in Underground Storage		(112.8	)		(33.4	)
Changes in Working Capital Items		29.3			(248.2	)
Payment to Terminate Interest Rate Swap		-			(3.5	)
Other, Net		(55.4	)		19.5
Net Cash Flows Provided by Continuing Operations		1,149.4			200.5
Net Cash Flows Provided by Discontinued Operations		22.3			46.9
Net Cash Flows Provided by Operating Activities		1,171.7			247.4
Cash Flows From Investing Activities:
Capital Expenditures		(1,050.5	)		(79.5	)
Acquisition of Terasen		(10.2	)		-
Other Acquisitions		(366.4	)		-
Investment in Kinder Morgan Energy Partners		-			(3.2	)
Net Investments in Margin Deposits		(8.3	)		(0.5	)
Other Investments		(3.8	)		(0.4	)
Sale of Kinder Morgan Management Shares		-			92.5
Natural Gas Stored Underground and Natural Gas Liquids Line-fill		(12.9	)		-
Sales of Other Assets Net of Removal Costs		78.6			(1.9	)
Net Cash Flows (Used in) Provided by Continuing Investing Activities		(1,373.5	)		7.0
Net Cash Flows Provided by (Used in) Discontinued Investing Activities		88.5			(23.9	)
Net Cash Flows Used in Investing Activities		(1,285.0	)		(16.9	)

6

KMI Form 10-Q

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (continued)

Kinder Morgan, Inc. and Subsidiaries

Increase (Decrease) in Cash and Cash Equivalents

	Nine Months Ended September 30,
	2006			2005
	(In millions)
Cash Flows From Financing Activities:
Short-term Debt, Net		684.8			269.3
Long-term Debt Issued		353.5			250.0
Long-term Debt Retired		(494.3	)		(505.0	)
Increase in Cash Book Overdrafts		11.4			-
Common Stock Issued		30.4			55.4
Excess Tax Benefits from Share-based Payment Arrangements		7.6			-
Short-term Advances From (To) Unconsolidated Affiliates		(7.9	)		0.1
Treasury Stock Acquired		(34.3	)		(199.0	)
Cash Dividends, Common Stock		(351.2	)		(263.6	)
Minority Interests, Contributions		353.8			-
Minority Interests, Distributions		(453.8	)		(1.7	)
Debt Issuance Costs		(5.3	)		(1.5	)
Other, Net		(3.2	)		-
Net Cash Flows Provided by (Used in) Financing Activities		91.5			(396.0	)
Effect of Exchange Rate Changes on Cash		6.5			-
Effect of Accounting Change on Cash		12.1			-
Cash Balance Included in Assets Held for Sale		(3.2	)		-
Net Decrease in Cash and Cash Equivalents		(6.4	)		(165.5	)
Cash and Cash Equivalents at Beginning of Period		116.6			176.5
Cash and Cash Equivalents at End of Period	$	110.2		$	11.0

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 the accounts, balances and results of operations of Kinder Morgan Energy Partners and its consolidated subsidiaries are now presented on a consolidated basis with ours and those of our other consolidated subsidiaries for financial reporting purposes, instead of equity method accounting as prev iously 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.

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

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”), the consol idated 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”) and the interim consolidated financial statements and related notes included in Kinder Morgan Energy Partners’ quarterly report on Form 10-Q for the quarter ended September 30, 2006.

To convert September 30, 2006 balances denominated in Canadian dollars to U.S. dollars, we used the September 30, 2006 Bank of Canada closing exchange rate of 0.8947 U.S. dollars per Canadian dollar.  All dollars are U.S. dollars, except where stated otherwise. Canadian dollars are designated as C$.

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 headquartered in Burnaby, 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 A lberta to the U.S. Rocky Mountain region and Midwest. Further information regarding this acquisition is available in our 2005 Form 10-K.

On August 28, 2006, we entered into a definitive merger agreement under which investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, will acquire all of our outstanding common stock for $107.50 per share in cash. Our board of directors, on the unanimous recommendation of a special committee composed entirely of independent directors, approved the agreement and has recommended that our stockholders approve the merger. The transaction is expected to be completed in the first quarter of 2007, subject to receipt of stockholder and regulatory approvals, as well as the satisfaction of other customary closing conditions.

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

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KMI Form 10-Q

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 (“SFAS No. 123R”). This Statement amends SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”), 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.

	Effect of Applying Statement No. 123(R)
	Three Months Ended September 30, 2006				Nine Months Ended September 30, 2006
	(In millions, except per share amounts)
Income from Continuing Operations Before Income Taxes		$	(0.8	)		$	(4.5	)
Income from Continuing Operations		$	(0.5	)		$	(2.8	)
Net Income		$	(0.5	)		$	(2.8	)
Basic Earnings Per Common Share		$	(0.01	)		$	(0.02	)
Diluted Earnings Per Common Share		$	-			$	(0.02	)
Net Cash Flows Provided by Operating Activities		$	(1.8	)		$	(7.6	)
Net Cash Flows Provided by Financing Activities		$	1.8			$	7.6

For the three and nine months ended September 30, 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 September 30, 2005				Nine Months Ended September 30, 2005
	(In millions, except per share amounts)
Net Income, As Reported		$	109.1			$	374.4
Add: Stock-based Employee Compensation Expense Included in Reported Net Income, Net of Related Tax Effects			1.0				3.4
Deduct: Total Stock-based Employee Compensation Expense Determined Under the Fair Value Method for All Awards, Net of Related Tax Effects			(2.6	)			(9.0	)
Net Income, Pro Forma		$	107.5			$	368.8
Basic Earnings Per Share:
As Reported		$	0.89			$	3.05
Pro Forma		$	0.88			$	3.01
Diluted Earnings Per Share:
As Reported		$	0.88			$	3.03
Pro Forma		$	0.87			$	2.98

We have stock options issued under the following plans: The 1992 Non-Qualified Stock Option Plan for Non-Employee Directors (which plan has expired), the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which plan has expired), the Kinder Morgan, Inc. Amended and Restated 1999 Stock 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 two employee stock purchase plans, one for U.S. employees and one for Canadian employees.

Over the years, the 1999 Stock Plan has been amended to increase shares available to grant, to allow for granting of restricted shares, and effective January 18, 2006 has been amended to allow for the granting of restricted stock units to employees residing outside the United States. The company stopped granting stock options after July 2004 and has replaced option grants with grants of restricted stock and restricted stock units to fewer people and in smaller amounts. Options granted prior to 2005 generally had vesting schedules of either 25% per year with a 10-year life or 100% after three years with a seven-

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KMI Form 10-Q

year life. Our restricted stock and restricted stock unit grants generally have either a three-year or five-year cliff vesting. Our most recent grants to employees have been 10,000 restricted shares in July 2006; 224,040 restricted shares in July 2005; 167,350 restricted shares and 310,000 options in July 2004; and 575,000 restricted shares and 658,000 options in July 2003.

During the three months and nine months ended September 30, 2006, we recognized stock option compensation expense of $0.8 million and $4.5 million, respectively. At September 30, 2006, unrecognized compensation cost was approximately $1.4 million, which will be recognized over the next two years.

During the nine months ended September 30, 2006 and 2005, we made restricted common stock grants to our non-employee directors of 17,600 and 15,750 shares, respectively. These grants are valued at $1.7 million and $1.1 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 to non-employee directors in the nine months ended September 30, 2006 and 2005 vest during a six-month period. During the three and nine months ended September 30, 2006, we made restricted common stock grants to employees of 10,000 shares. These grants are valued at $1.0 million based on the closing market price of our common stock on either the date of grant or the measurement date, if different. During the three and nine months ended September 30, 2005, we made restricted common stock grants to employees of 224,040 and 227,040 shares, respectively. These grants are valued at $20.0 million and $20.2 million, respectively, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. Expense related to restricted grants is recognized on a straight-line basis over the respective vesting periods. During the three months and nine months ended September 30, 2006, we amortized $4.9 million and $11.9 million, respectively, related to restricted stock grants. During the three months and nine months ended September 30, 2005, we amortized $1.6 million and $5.5 million, respectively, related to restricted stock grants.

During the nine months ended September 30, 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 and nine months ended September 30, 2006, we amortized $0.7 million and $2.2 million, respectively, 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 September 30, 2006, and changes during the three months and nine months then ended is presented in the table below:

	Three Months Ended September 30, 2006						Nine Months Ended September 30, 2006
	Shares		Weighted Average Grant Date Fair Value (In millions)				Shares		Weighted Average Grant Date Fair Value (In millions)
Outstanding at Beginning of Period	906,773			$	61.2		880,310			$	56.6
Granted	10,000				1.0		89,400				8.7
Reinstated	50,000				2.7		50,000				2.7
Vested	(144,683	)			(8.5	)	(193,620	)			(11.3	)
Forfeited	(3,750	)			(0.3	)	(7,750	)			(0.6	)
Outstanding at End of Period	818,340			$	56.1		818,340			$	56.1
Intrinsic Value of Restricted Stock Vested During the Period				$	14.5					$	19.2

Contingent grants totaling an additional 178,000 shares of restricted common stock and 65,650 restricted stock units were granted in July 2006. These grants will only be effective if we do not execute the definitive merger agreement under which investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, will acquire all of our outstanding common stock for $107.50 per share in cash (the “Going Private” transaction). If the Going Private transaction occurs, we plan to implement a replacement plan of similar value.

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. The Long-term Incentive Plan has been terminated and therefore has no shares available for

10

KMI Form 10-Q

future grants.

Plan Name	Shares Subject to the Plan	Option Shares Granted Through September 30, 2006	Vesting Period	Expiration Period
1992 Directors’ Plan	1,025,000	621,875	0 – 6 Months	10 Years
Long-term Incentive Plan	5,700,000	4,109,595	0 – 5 Years	5 – 10 Years
1999 Plan	10,500,000	8,002,243	3 – 4 Years	7 – 10 Years
Non-Employee Directors Plan	500,000	33,350	0 – 6 Months	10 Years

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 September 30, 2006, and changes during the three months and nine months then ended is presented in the table and narrative below:

	Three Months Ended September 30, 2006					Nine Months Ended September 30, 2006
	Shares		Weighted Average Exercise Price			Shares		Weighted Average Exercise Price
Outstanding at Beginning of Period	3,088,898			$	45.40	3,421,849			$	45.21
Granted	-			$	-	-			$	-
Exercised	(202,965	)		$	45.96	(488,141	)		$	44.59
Forfeited	(103,075	)		$	57.16	(150,850	)		$	53.13
Outstanding at End of Period	2,782,858			$	45.76	2,782,858			$	45.76
Exercisable at End of Period	2,484,808			$	44.28	2,484,808			$	44.28
Aggregate Intrinsic Value of Options Exercisable at End of Period (In millions)				$	157.0				$	157.0
Intrinsic Value of Options Exercised During the Period (In millions)				$	11.1				$	26.3
Cash Received from Exercise of Options During the Period (In millions)				$	9.3				$	21.8

11

KMI Form 10-Q

The following table sets forth our common stock options outstanding at September 30, 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	418,007	$	23.81	3.01 years	418,007	$	23.81
$24.75 - $43.10	614,721	$	35.97	4.75 years	569,321	$	35.40
$49.00 - $53.20	669,168	$	50.87	4.41 years	669,168	$	50.87
$53.60 - $60.18	768,312	$	54.92	4.38 years	768,312	$	54.92
$60.79 - $61.40	312,650	$	60.91	5.28 years	60,000	$	61.40
	2,782,858	$	45.76	4.36 years	2,484,808	$	44.28

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 9,279 shares and 29,375 shares for the three months and nine months ended September 30, 2006, respectively. Employees purchased 10,791 shares and 35,857 shares for the three months and nine months ended September 30, 2005, respectively. We implemented a Foreign Subsidiary Employees Stock Purchase Plan for our employees working in Canada. This plan mirrors the Employee Stock Purchase Plan for our United States employees. Employees were eligible to participate in the program beginning April 1, 2006. Employees purchased 694 shares and 1,441 shares for the three months and nine months ending September 30, 2006, respectively.

(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. Except for 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 has no impact on our consolidated stockholders’ equity. There also is 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 has the effect of increasing our consolidated operating revenues and expenses and

12

KMI Form 10-Q

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

We provide various types of natural gas storage and transportation services to customers. 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 in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as “interruptible service”), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements.

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

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

	September 30,			December 31,
	2006			2005
	(In millions)
Gas in Underground Storage (Current)		$	308.3		$	209.6
Materials and Supplies			29.2			18.6
Petroleum Products			15.9			-
		$	353.4		$	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 January 1, 2006, we include 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

13

KMI Form 10-Q

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 nine months ended September 30, 2006 are summarized as follows:

	Balance December 31, 2005		KMP Goodwill Consolidated into KMI1		Reallocation of Equity Method Goodwill			Acquisitions		Other2			Balance September 30, 2006
	(In millions)
Kinder Morgan Energy Partners	$	859.4	$	-	$	(859.4	)	$	-	$	-		$	-
Power Segment		24.8		-		-			-		-			24.8
Kinder Morgan Canada Segment3		658.2		-		-			-		26.8			685.0
Terasen Gas Segment3		1,238.6		-		-			-		157.5			1,396.1
Products Pipelines Segment		-		263.2		695.5			-		(15.2	)		943.5
Natural Gas Pipelines Segment		-		288.4		-			-		-			288.4
CO2 Segment		-		46.1		26.9			-		(0.6	)		72.4
Terminals Segment		-		201.2		137.0			17.8		(0.9	)		355.1
Consolidated Total	$	2,781.0	$	798.9	$	-		$	17.8	$	167.6		$	3,765.3

_________________

¹

At January 1, 2006.

²

Other adjustments include the translation of goodwill denominated in foreign currencies, purchase price adjustments and a reduction of the reallocation of equity method goodwill due to a reduction in KMI’s ownership percentage of KMP.

³

Goodwill assigned to the Kinder Morgan Canada and Terasen Gas business segments is based on the purchase price allocation for our November 30, 2005 acquisition of Terasen (see Note 5). 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 September 30, 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:

	September 30, 2006				December 31, 2005
	(In millions)
Lease Value:
Gross Carrying Amount		$	6.6			$	-
Accumulated Amortization			(1.3	)			-
Net Carrying Amount			5.3				-
Contracts and Other:
Gross Carrying Amount			253.9				29.4
Accumulated Amortization			(32.6	)			(11.7	)
Net Carrying Amount			221.3				17.7
Total Other Intangibles, Net		$	226.6			$	17.7

14

KMI Form 10-Q

Amortization expense on our intangibles consisted of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(In millions)
Lease Value1	$	-	$	-	$	0.1	$	-
Contracts and Other		3.7		0.4		11.2		1.1
Total Amortizations	$	3.7	$	0.4	$	11.3	$	1.1

_______________

¹

Three months ended September 30, 2006 included expense of less than $0.1 million.

As of September 30, 2006, our weighted-average amortization period for our intangible assets was approximately 18.4 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, $13.4 million and $13.3 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.

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

	September 30,		December 31,
	2006		2005
	(In millions)
Kinder Morgan Energy Partners	$	1,579.4	$	-
Kinder Morgan Management, LLC		1,284.9		1,221.7
Triton Power		29.5		21.8
Other		9.2		3.8
	$	2,903.0	$	1,247.3

On August 14, 2006, Kinder Morgan Energy Partners paid a quarterly distribution of $0.81 per common unit for the quarterly period ended June 30, 2006, of which $115.6 million was paid to the public holders (represented in minority interests) of Kinder Morgan Energy Partners’ common units. On October 18, 2006, Kinder Morgan Energy Partners declared a quarterly distribution of $0.81 per common unit for the quarterly period ended September 30, 2006. The distribution will be paid on November 14, 2006, to unitholders of record as of October 31, 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 $1.6 million of our total asset retirement obligations as of September 30, 2006 in the caption “Current Liabilities: Other” and the remaining $49.5 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 nine months ended September 30, 2006 and 2005 is as follows:

15

KMI Form 10-Q

	Nine Months Ended September 30,
	2006			2005
	(In millions)
Balance at Beginning of Period	$	3.2		$	3.3
KMP ARO Consolidated into KMI1		43.2			-
Additions		5.0			-
Liabilities Settled		(2.2	)		(0.2	)
Accretion Expense2		1.9			-
Balance at End of Period	$	51.1		$	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 January 1, 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.

(J) Related Party Transactions

Plantation Pipe Line Company

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

In June 2006, Plantation paid to Kinder Morgan Energy Partners $1.1 million in principal amount under the note, and as of September 30, 2006, the principal amount receivable from this note was $93.1 million. We included $2.2 million of this balance within “Accounts, Notes and Interest Receivable, Net: Related Parties” on our consolidated balance sheet as of September 30, 2006, and we included the remaining $90.9 million balance as “Notes Receivable – Related Parties.”

Coyote Gas Treating, LLC

Coyote Gas Treating, LLC is a joint venture that was organized in December 1996. It is referred to as Coyote Gulch in this report.  The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. Prior to the contribution of Kinder Morgan Energy Partners’ ownership interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006, discussed below, Kinder Morgan Energy Partners was the managing partner and owned a 50% equity interest in 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 Field Services LLC (“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.

In the third quarter of 2006, the Southern Ute Indian Tribe acquired the remaining 50% ownership interest in Coyote Gulch from Enterprise. The acquisition was made effective March 1, 2006. On September 1, 2006, Kinder Morgan Energy Partners and the Southern Ute Tribe agreed to a resolution that would transfer all of the members’ equity in Coyote Gulch to the members’ equity of Red Cedar Gathering, a joint venture organized in August 1994 and referred to in this report as Red Cedar. Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in

16

KMI Form 10-Q

La Plata County, Colorado, and is owned 49% by Kinder Morgan Energy Partners and 51% by the Southern Ute Tribe. Under the terms of a five-year operating lease agreement that became effective January 1, 2002, Red Cedar also operates the gas treating facility owned by Coyote Gulch and is responsible for all operating and maintenance expenses and capital costs.

According to the provisions of the September 1, 2006 resolution, Kinder Morgan Energy Partners and the Southern Ute Tribe contributed the value of their respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a result, Coyote Gulch became a wholly owned subsidiary of Red Cedar. The value of Kinder Morgan Energy Partners’ 50% equity contribution from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7 million, and this amount remains included within “Investments: Other” in our accompanying interim Consolidated Balance Sheet as of September 30, 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

	Nine Months Ended September 30,
	2006			2005
	(In millions)
Accounts Receivable	$	458.9		$	1.4
Materials and Supplies Inventory		14.2			(0.2	)
Other Current Assets		27.7			(195.5	)
Accounts Payable		(475.5	)		(1.8	)
Excess Tax Benefits from Share-based Payment Arrangements		-			20.1
Other Current Liabilities		4.0			(72.2	)
	$	29.3		$	(248.2	)

Supplemental Disclosures of Cash Flow Information:

Cash Paid During the Period for:
Interest, Net of Amount Capitalized	$	627.1	$	153.2
Income Taxes Paid1	$	264.5	$	203.2

_____________

¹

Income taxes paid includes taxes paid related to prior periods.

As discussed in Note 1(C), due to our adoption of EITF No. 04-5, beginning January 1, 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.

As discussed in Note 1(A), we made non-cash grants of restricted shares of common stock during each of the nine months ended September 30, 2006 and 2005.

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

During the nine months ended September 30, 2006, we acquired $3.7 million of assets by the assumption of liabilities.

(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 $8.7 million and $0.3 million for the three months ended September 30, 2006 and 2005, respectively, and $25.5 million and $0.7 million for the nine months ended September 30, 2006 and 2005, respectively.

17

KMI Form 10-Q

(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 Statement of Operations) was 29.5% for the three months ended September 30, 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) a reduction in the effective tax rate applied in calculating deferred tax due to a decrease in the state effective tax rate, (ii) tax benefits resulting from our Terasen acquisition structure and (iii) taxes applicable to our Canadian operations. The effective tax rate fo r the three months ended September 30, 2005 was 40.6%, which reflects, among other factors, differences from the federal statutory rate of 35% due to increases attributable to (i) state income taxes and (ii) the minority interest associated with Kinder Morgan Management. The effective tax rate was 29.5% for the nine months ended September 30, 2006. This effective tax rate reflects differences from the federal statutory tax rate of 35% due to the same factors affecting third quarter 2006, as discussed above. The effective tax rate was 40.7% for the nine months ended September 30, 2005 which 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) gains from sales of Kinder Morgan Management shares.

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, restricted stock 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. During the past several years, 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 September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
	(In millions)
Weighted-average Common Shares Outstanding	133.1	122.5	132.9	122.6
Restricted Stock and Share Units	0.8	-	0.9	-
Dilutive Common Stock Options	1.2	1.2	1.2	1.2
Shares Used to Compute Diluted Earnings Per Common Share	135.1	123.7	135.0	123.8

3.

Comprehensive Income

Our comprehensive income is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006		2005
	(In millions)
Net Income:	$	144.2		$	109.1		$	495.1	$	374.4
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes		29.3			(59.8	)		32.2		(73.7	)
Reclassification of Change in Fair Value of Derivatives to Net Income		4.2			26.4			21.3		28.5
Equity in Other Comprehensive Loss of Equity Method Investees		-			(29.1	)		-		(176.5	)
Minority Interest in Other Comprehensive Loss of Equity Method Investees		-			22.4			-		100.1
Change in Foreign Currency Translation Adjustment		(11.5	)		-			57.8		-
Other Comprehensive Income (Loss)		22.0			(40.1	)		111.3		(121.6	)
Comprehensive Income	$	166.2		$	69.0		$	606.4	$	252.8

18

KMI Form 10-Q

The Accumulated Other Comprehensive Loss balance of $15.7 million at September 30, 2006 consisted of (i) $73.6 million representing unrecognized net losses on hedging activities, primarily at Kinder Morgan Energy Partners, and (ii) $3.3 million representing minimum pension liability, offset by $61.2 million representing foreign currency translation adjustments.

4.

Kinder Morgan Management, LLC

On August 14, 2006, Kinder Morgan Management made a distribution of 0.018860 of its shares per outstanding share (1,131,777 total shares) to shareholders of record as of July 31, 2006, based on the $0.81 per common unit distribution declared by Kinder Morgan Energy Partners. On November 14, 2006, Kinder Morgan Management will make a distribution of 0.018981 of its shares per outstanding share (1,160,520 total shares) to shareholders of record as of October 31, 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 and liabilities assumed 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 $244.6 million in cash. West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. Kinder Morgan Energy Partners contributed 66 2/3% of the consideration for this purchase, which corresponded to its percentage ownership of West2East Pipeline LLC at that time. At the time of acquisition, Sempra Energy held the remaining 33 1/3% ownership interest and contributed this same proportional amount of the total consideration.

On the acquisition date, Entegra Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that will, when fully constructed, 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 the Rockies Express Pipeline, an interstate natural gas pipeline that is currently being developed by Rockies Express Pipeline LLC. The acquired operations are included as part of the Natural Gas Pipelines business segment.

In the first quarter of 2006, EnCana Corporation completed construction of the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and interim service began on that portion of the pipeline. Under the terms of the purchase and sale agreement, Rockies Express Pipeline LLC will construct the segment that extends from the Wamsutter Hub to the Cheyenne Hub. Construction on this pipeline segment began in the second quarter of 2006, and it is anticipated that both pipeline segments will be placed into service by January 1, 2007.

With regard to Rockies Express Pipeline LLC’s acquisition of Entrega Gas Pipeline LLC, the allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price:
Cash Paid, Including Transaction Costs	$	244.6
Liabilities Assumed		-
Total Purchase Price	$	244.6
Allocation of Purchase Price:
Current Assets	$	-
Property, Plant and Equipment		244.6
Deferred Charges and Other Assets		-
	$	244.6

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 (including the lines currently being developed) will be known as the Rockies Express Pipeline. The combined 1,663-mile pipeline system will be one of the largest natural gas pipelines ever constructed in North America. The approximately $4.4 billion project will have the

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KMI Form 10-Q

capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity.

On June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline LLC). On that date, a 24% ownership interest was transferred to ConocoPhillips, and an additional 1% interest will be transferred once construction of the entire project is completed. Through its subsidiary, Kinder Morgan W2E Pipeline LLC, Kinder Morgan Energy Partners will continue to operate the project but its ownership interest decreased to 51% of the equity in the project (down from 66 2/3%). Sempra’s ownership interest in West2East Pipeline LLC decreased to 25% (down from 33 1/3%). When construction of the entire project is completed, Kinder Morgan Energy Partners’ ownership interest will be reduced to 50% at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect Kinder Morgan Energy Partners’ 50% economics in the project. We do not ant icipate any additional changes in the ownership structure of the Rockies Express Pipeline project.

West2East Pipeline LLC qualifies as a variable interest entity as defined by FASB Interpretation No. 46 (Revised December 2003) (“FIN 46R”), Consolidation of Variable Interest Entities-An Interpretation of ARB No. 51, due to the fact that the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including equity holders. As Kinder Morgan Energy Partners will receive 50% of the economics of the project on an ongoing basis, they are no longer considered the primary beneficiary of this entity as defined by FIN 46R and thus, effective June 30, 2006, West2East Pipeline LLC was deconsolidated and will subsequently be accounted for under the equity method of accounting.

Under the equity method, the costs of the investment in West2East Pipeline LLC will be recorded within the “Investments: Other” caption on our consolidated balance sheet and as changes in the net assets of West2East Pipeline LLC occur (for example, earnings and dividends), we will recognize our proportional share of that change in the “Investments: Other” account. We will also record our proportional share of any accumulated other comprehensive income or loss within the “Accumulated Other Comprehensive Loss” caption on our consolidated balance sheet.

Summary financial information as of September 30, 2006, for West2East Pipeline LLC, which is accounted for under the equity method, is as follows (in millions of dollars; amounts represent 100% of investee information):

Balance Sheet	September 30, 2006
Current Assets	$	0.9
Non-current Assets	$	594.9
Current Liabilities	$	14.1
Non-Current Liabilities	$	588.3
Accumulated Other Comprehensive Income	$	(6.5	)

In addition, Kinder Morgan Energy Partners has guaranteed its proportional share of West2East Pipeline LLC’s debt borrowings under a $2 billion credit facility entered into by Rockies Express Pipeline LLC.

April 2006 Oil and Gas Properties

On April 7, 2006, Kinder Morgan Production Company L.P., a subsidiary of Kinder Morgan Energy Partners, purchased various oil and gas properties from Journey Acquisition – I, L.P. and Journey 2000, L.P. for an aggregate consideration of approximately $63.7 million, consisting of $60.2 million in cash and $3.5 million in assumed liabilities. The acquisition was effective March 1, 2006. However, Kinder Morgan Energy Partners divested certain acquired properties that are not considered candidates for carbon dioxide enhanced oil recovery, thus reducing the total investment. As of September 30, 2006, Kinder Morgan Energy Partners received proceeds of approximately $27.0 million from the sale of these properties.

The properties are primarily located in the Permian Basin area of West Texas and New Mexico, produce approximately 425 barrels of oil equivalent per day, and include some fields with potential for enhanced oil recovery development near our current carbon dioxide operations. The acquired operations are included as part of the CO₂ business segment. Following this acquisition, and continuing through the remainder of 2006, Kinder Morgan Energy Partners 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.

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KMI Form 10-Q

As of September 30, 2006, the allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price:
Cash Paid, Including Transaction Costs	$	60.2
Liabilities Assumed		3.5
Total Purchase Price	$	63.7
Allocation of Purchase Price:
Current Assets	$	0.2
Property, Plant and Equipment		63.5
	$	63.7

April 2006 Terminal Assets

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 its existing deepwater terminal by providing customers with both rail and vessel transportation options for bulk products. Thirdly, Kinder Morgan Energy Partners acquired the entire membership interest of Lomita Rail Terminal LLC, a limited liability company that owns a high-volume rail ethanol terminal in Carson, California. The terminal serves approximately 80% of the southern Califo rnia 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 the Terminals business segment.

As of September 30, 2006, the allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price:
Cash Paid, Including Transaction Costs	$	61.6
Liabilities Assumed		0.3
Total Purchase Price	$	61.9
Allocation of Purchase Price:
Current Assets	$	0.5
Property, Plant and Equipment		43.6
Goodwill		17.8
	$	61.9

The $17.8 million of goodwill was assigned to the Terminals business segment and the entire amount is expected to be deductible for tax purposes.

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 headquartered in Burnaby, 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 Midwes t.

The acquisition was accounted for as a purchase and, accordingly, the assets acquired and liabilities assumed are recorded at their respective estimated fair market values as of the acquisition date. The calculation of the total purchase price and the

21

KMI Form 10-Q

allocation of that purchase price to the assets acquired and liabilities assumed based on their estimated fair market values is shown following. Further information regarding this acquisition is available in our 2005 Form 10-K.

The Total Purchase Price Consisted of the Following:	(In millions)
Total Market Value of Kinder Morgan, Inc. Common Shares Issued	$	1,146.8
Cash Paid – U.S. Dollar Equivalent		2,134.3
Transaction Fees		15.7
Total Purchase Price	$	3,296.8

The Allocation of the Purchase Price is as Follows:	(In millions)
Current Assets	$	812.7
Goodwill		1,973.3
Investments		504.8
Property, Plant and Equipment		3,592.7
Deferred Charges and Other Assets		602.4
Current Liabilities		(1,520.2	)
Deferred Income Taxes		(647.7	)
Other Deferred Credits		(264.5	)
Long-term Debt		(1,756.7	)
	$	3,296.8

During the first nine months of 2006, we increased the goodwill by $82.8 million, primarily related to decreases in the estimated fair value of regulated assets.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the nine months ended September 30, 2006 and 2005, assumes that all of the acquisitions we have made and joint ventures we have entered into between January 1, 2005 and September 30, 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 the beginning of the period presented or the results that will be attained in the future.

	Nine Months Ended September 30,
	2006		2005
	(In millions, except per share amounts)
Operating Revenues	$	8,910.8	$	1,705.2
Income from Continuing Operations	$	487.3	$	426.9
Net Income	$	495.3	$	440.6
Diluted Earnings Per Common Share	$	3.67	$	3.23
Common Shares Used in Computing Diluted Earnings Per Share		135.0		136.2

6.

Investments and Sales

In August 2006, Kinder Morgan Energy Partners issued 5.75 million common units in a public offering at a price of $44.80 per common unit, receiving total net proceeds (after underwriting discount) of $248.0 million. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transaction) from approximately 15.0% to approximately 14.7% and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $16.9 million and reducing our (i) equity method goodwill in Kinder Morgan Energy Partners by $18.8 million, (ii) associated accumulated deferred income taxes by $0.8 million and (iii) paid-in capital by $1.1 million. In addition, in August 2006, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $2.5 million.

Effective April 1, 2006, Kinder Morgan Energy Partners sold its Douglas natural gas gathering system and its Painter Unit fractionation facility to Momentum Energy Group, LLC for approximately $42.5 million in cash. Kinder Morgan Energy Partners’ investment in net assets, including all transaction related accruals, was approximately $24.5 million, most of which represented property, plant and equipment, and Kinder Morgan Energy Partners recognized approximately $18.0 million of

22

KMI Form 10-Q

gain on the sale of these net assets. Kinder Morgan Energy Partners used the proceeds from these asset sales to reduce the outstanding balance on its commercial paper borrowings.

The Douglas gathering system is comprised of approximately 1,500 miles of 4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet per day of natural gas from 650 active receipt points. Gathered volumes are processed at Kinder Morgan Energy Partners’ Douglas plant (which Kinder Morgan Energy Partners retained), located in Douglas, Wyoming. As part of the transaction, Kinder Morgan Energy Partners executed a long-term processing agreement with Momentum Energy Group, LLC, which dedicates volumes from the Douglas gathering system to Kinder Morgan Energy Partners’ Douglas processing plant. The Painter Unit, located near Evanston, Wyoming, consists of a natural gas processing plant and fractionator, a nitrogen rejection unit, a natural gas liquids terminal, and interconnecting pipelines with truck and rail loading facilities. Prior to the sale, Kinder Morgan Energy Partners leased the plant to BP, which operates the fractionator and the associated Millis terminal and storage facilities for its own account.

Additionally, with regard to the natural gas operating activities of Kinder Morgan Energy Partners’ Douglas gathering system, Kinder Morgan Energy Partners utilized certain derivative financial contracts to offset its exposure to fluctuating expected future cash flows caused by periodic changes in the price of natural gas and natural gas liquids. According to the provisions of current accounting principles, changes in the fair value of derivative contracts that are designated and effective as cash flow hedges of forecasted transactions are reported in other comprehensive income (not net income) and recognized directly in equity (included within accumulated other comprehensive income/(loss)). Amounts deferred in this way are reclassified to net income in the same period in which the forecast transactions are recognized in net income. However, if a hedged transaction is no longer expected to occur by the end of the originally specified time p eriod, because, for example, the asset generating the hedged transaction is disposed of prior to the occurrence of the transaction, then the net cumulative gain or loss recognized in equity should be transferred to net income in the current period.

Accordingly, upon the sale of Kinder Morgan Energy Partners’ Douglas gathering system, Kinder Morgan Energy Partners reclassified a net loss of $2.9 million on those derivative contracts that effectively hedged uncertain future cash flows associated with forecasted Douglas gathering transactions from “Accumulated Other Comprehensive Loss” into net income. We included the net amount of the gain, $15.1 million, within the caption “Operating Costs and Expenses: Other Expenses (Income)” in our accompanying consolidated statements of income for the nine months ended September 30, 2006.

During the first quarter of 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. We recognized a pre-tax gain of $1.5 million associated with this sale. The book value of the remaining surplus power generation equipment available for sale at September 30, 2006 was $17.6 million.

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

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

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

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

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KMI Form 10-Q

7.

Summarized Income Statement Information for Kinder Morgan Energy Partners

Following is summarized income statement information for the three months and nine months ended September 30, 2005 for Kinder Morgan Energy Partners. 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 September 30, 2006 and in its Annual Report on Form 10-K for the year ended December 31, 2005.

	Three Months Ended September 30, 2005			Nine Months Ended September 30, 2005
	(In millions)
Operating Revenues		$	2,631.3		$	6,729.5
Operating Expenses			2,332.7			5,886.8
Operating Income		$	298.6		$	842.7
Net Income		$	245.4		$	690.8

8.

Discontinued Operations

In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S.-based retail natural gas distribution and related operations for $710 million plus working capital. Pending regulatory approvals, we expect this transaction to close by the end of the first quarter of 2007. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented. The assets and liabilities of these operations are included in our Consolidated Balance Sheet at September 30, 2006 in the captions “Current Assets: Assets Held for Sale”, “Assets Held for Sale, Non-current”, “Current Liabilities: Liabilities Held for Sale” and “Liabilities Held for Sale, Non-current.” No such reclassification of the assets and liabilities of the U.S.-based retail natural gas distribution business has been made to the Consolidated Balance Sheet at December 31, 2005. Summarized financial results and financial position information of these operations is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(In millions)
Operating Revenues	$	52.2		$	46.4		$	254.2		$	226.2
Operating Expenses		(52.9	)		(50.0	)		(237.2	)		(196.8	)
Other Income and Expenses, Net		(2.2	)		(2.7	)		(5.6	)		(7.8	)
Earnings (Loss) Before Income Taxes		(2.9	)		(6.3	)		11.4			21.6
Income Taxes		4.1			2.6			(2.3	)		(8.8	)
Earnings (Loss) from Discontinued Operations	$	1.2		$	(3.7	)	$	9.1		$	12.8

	At September 30, 2006
	(In millions)
Current Assets		$	55.3
Property, Plant and Equipment, Net			399.1
Other Assets			12.3
Total Assets		$	466.7
Current Liabilities		$	59.8
Other Liabilities and Deferred Credits			45.1
Total Liabilities		$	104.9

Our U.S.-based retail natural gas distribution operations obtain natural gas transportation and storage services and purchase natural gas from our Natural Gas Pipelines – KMP business segment and we expect these transactions to continue to a similar extent following the close of the disposal transaction. The intercompany revenues of our ongoing operations for products and services sold to our discontinued operations that have been eliminated in our Consolidated Statements of Operations were $4.0 million and $16.3 million for the three months and nine months ended September 30, 2006, respectively. Revenues (and

24

KMI Form 10-Q

expenses) for these products and services were not eliminated in 2005 due to the fact that we did not include Kinder Morgan Energy Partners in our consolidated operating results until the implementation of EITF 04-5, effective January 1, 2006 (see Note 1(C)). In addition, following the close of the disposal transaction, we expect to receive fees from GE to provide certain administrative functions for a limited period of time and for the lease of office space. We will not have any significant continuing involvement in or retain any ownership interest in these operations and, therefore, the continuing cash flows discussed above are not considered direct cash flows of the disposal group.

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, which offers water, wastewater and utility services, primarily in Western Canada. During the second quarter of 2006, Terasen completed the sale of Terasen Water and Utility Services to a group led by CAI Capital Management Co. and including the existing management team of Terasen Water and Utility Services for approximately $118 million (C$133 million). The sale does not include CustomerWorks LP, a 30% joint venture with Enbridge Inc. No gain or loss was recognized from the sale of the water and utility segment. Incremental losses of $0.7 million (net of tax benefits of $0.4 million) were recorded in the six months ended June 30, 2006 reflecting the operating results of the water and utility business segment during 2006 until its sale.

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. For the three months ended September 30, 2006, incremental losses of approximately $0.2 million (net of tax benefits of $0.1 million) were recorded to update previously recorded liabilities. For the nine months ended September 30, 2006 and 2005, incremental losses of approximately $0.4 million (net of tax benefits of $0.2 million) and approximately $1.4 million (net of tax benefits of $0.8 million), respectively, were recorded 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 Provided by Discontinued Operations” and “Net Cash Flows Provided by (Used in) Discontinued Investing 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 has the effect, among other things, of increasing our consolidated debt beginning January 1, 2006, but has 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.

Credit Facilities

We and our consolidated subsidiaries had the following unsecured credit facilities outstanding at September 30, 2006.

Credit Facilities

Kinder Morgan, Inc.

$800 million, five-year revolver, due August 2010

Kinder Morgan Energy Partners

$1.85 billion, five-year revolver, due August 2010

Terasen

C$450 million, three-year revolver, due May 2009

Terasen Gas Inc.

C$500 million, three-year revolver, due June 2009

Terasen Pipelines (Corridor) Inc.

C$225 million, 364-day revolver, due January 2007

C$20 million, 364-day demand non-revolver, due January 2007

Terasen Gas (Vancouver Island) Inc.

C$350 million, five-year revolver, due January 2011

C$20 million, seven-year demand non-revolver, due January 2013

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

25

KMI Form 10-Q

commitment varies based on 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 following tables represent borrowings against our credit facilities, which include commercial paper and bankers’ acceptances supported by those facilities. Our commercial paper and bankers’ acceptances are comprised of unsecured short-term notes with maturities not to exceed 364 days from the date of issue.

	September 30, 2006
	Short-term Debt Outstanding		Weighted-Average Interest Rate of Short-term Debt Outstanding
	(In millions of U.S. dollars)
Kinder Morgan, Inc.
$800 million	$	112.0		5.95	%
Kinder Morgan Energy Partners
$1.85 billion	$	887.6		5.42	%
Terasen
C$450 million	$	157.5		4.99	%
Terasen Gas Inc.
C$500 million	$	185.2		4.28	%
Terasen Pipelines (Corridor) Inc.
C$225 million	$	126.2		4.22	%

	Three Months Ended September 30, 2006						Nine Months Ended September 30, 2006
	Average 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
	(In millions of U.S. dollars)
Kinder Morgan, Inc.
$800 million		$	127.7		5.72	%		$	45.7		5.72	%
Kinder Morgan Energy Partners
$1.85 billion		$	1,002.4		5.45	%		$	996.7		5.07	%
Terasen
C$450 million		$	109.0		4.99	%		$	87.6		4.65	%
Terasen Gas Inc.
C$500 million		$	190.5		4.46	%		$	170.6		3.90	%
Terasen Pipelines (Corridor) Inc.
C$225 million		$	125.2		3.04	%		$	124.0		3.44	%

Effective August 28, 2006, Kinder Morgan Energy Partners terminated its $250 million unsecured nine-month bank credit facility due November 21, 2006, and increased its existing five-year bank credit facility from $1.60 billion to $1.85 billion. The five-year unsecured bank credit facility remains due August 18, 2010; however, the bank facility can now be amended to allow for borrowings up to $2.1 billion. There were no borrowings under Kinder Morgan Energy Partners’ five-year credit facility as of September 30, 2006.

On June 21, 2006, Terasen Gas Inc. entered into a C$500 million three-year revolving credit facility, extendible annually for an additional 364 days at the option of the lenders. This facility replaces five bi-lateral facilities aggregating C$500 million and includes terms and conditions similar to the facilities it replaced.

On May 9, 2006, Terasen entered into a C$450 million three-year revolving credit facility. This facility replaces three bi-lateral facilities aggregating C$450 million and includes terms and conditions similar to the facilities it replaced.

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 supports a $2.0 billion commercial paper program that was established in May 2006, and borrowings under the commercial paper program reduce the borrowings allowed under the credit facility. Borrowings under the Rockies Express credit facility and commercial paper program will be primarily used to finance the construction of

26

KMI Form 10-Q

the Rockies Express interstate natural gas pipeline and to pay related expenses, and the borrowings will not reduce the borrowings allowed under our credit facilities described above.

Effective June 30, 2006, West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline LLC) was deconsolidated and will subsequently be accounted for under the equity method of accounting (See Note 5). All three owners have agreed to guarantee borrowings under the Rockies Express credit facility and under the Rockies Express commercial paper program in the same proportion as their percentage ownership of the member interests in Rockies Express Pipeline LLC. As of September 30, 2006, Rockies Express Pipeline LLC had $583.5 million of commercial paper outstanding, and there were no borrowings under its five-year credit facility. Accordingly, as of September 30, 2006, Kinder Morgan Energy Partners’ contingent share of Rockies Express’ debt was $297.6 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. This agreement was terminated effective August 26, 2006 when Kinder Morgan Energy Partners increased its existing 5-year bank credit facility from $1.6 billion to $1.85 billion.

On January 31, 2006, Terasen Pipelines (Corridor) Inc.’s $225 million senior unsecured revolving credit facility and the associated C$20 million non-revolving demand facility were extended under the same terms for an additional 364 days as permitted under the terms of the facilities.

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 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 governme nt 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 September 30, 2006, TGVI had outstanding 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, under the C$350 million credit facility, borrowings outstanding at September 30, 2006 of $237.3 million have been classified as long-term debt and an estimated $16.8 million as current maturities in our accompanying interim Consolidated Balance Sheet. Borrowings outstanding under the C$20 million credit facility at September 30, 2006 were $3.4 million.

Long-term Debt

On September 25, 2006, Terasen Gas Inc. issued C$120 million 5.55% Medium Term Note debentures, due September 25, 2036. Of the $106.9 million (C$119.4 million) net proceeds from this issuance after underwriting discounts and commissions,  $89.5 million (C$100 million) will be used to repay short-term commercial paper debt that was primarily incurred to pay Terasen Gas Inc.’s C$100 million 6.15% medium term note debentures that matured in July 31, 2006. The remaining proceeds will be used to repay Terasen Gas Inc.’s C$20 million 9.75% notes, which will mature on December 17, 2006.

In July 2006, we received notification of election from the holders of our 7.35% Series debentures due 2026 electing the option, as provided in the indenture governing the debentures, to require us to redeem the securities on August 1, 2006. The full $125 million of principal was elected to be redeemed and was paid, along with accrued interest of approximately $4.6 million, on August 1, 2006, utilizing incremental borrowing under our $800 million credit facility.

On July 31, 2006, Terasen Gas Inc.’s C$100 million 6.15% Medium Term Note debentures matured, and the note holders were paid utilizing a combination of cash on hand and incremental short-term borrowing.

On June 30, 2006, TGVI made a $5.6 million (C$6.2 million) payment on its government loans, of which, approximately $3.3 million (C$3.7 million) was refinanced through borrowings under its C$20 million non-revolving credit facility and the remaining amount funded with cash on hand. Additional information on the government loans can be found in Note 17(D) of the Notes to Consolidated Financial Statements in our 2005 Form 10-K.

On May 8, 2006, Terasen Inc.’s C$100 million of 4.85%, Series 2 Medium Term Notes matured and Terasen Inc. paid the holders of the notes, utilizing a combination of incremental short-term borrowing and proceeds from the sale of Terasen Water and Utility Services (see Note 8).

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KMI Form 10-Q

Common Stock

On August 14, 2006, we paid a cash dividend on our common stock of $0.875 per share to shareholders of record as of July 31, 2006. On October 18, 2006, our Board of Directors approved a cash dividend of $0.875 per common share payable on November 14, 2006 to shareholders of record as of October 31, 2006.

On August 28, 2006, we entered into a definitive merger agreement under which investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, will acquire all of our outstanding common stock for $107.50 per share in cash. Our board of directors, on the unanimous recommendation of a special committee composed entirely of independent directors, approved the agreement and will recommend that our stockholders approve the merger. The transaction is expected to be completed by early 2007, subject to receipt of stockholder and regulatory approvals, as well as the satisfaction of other customary closing conditions.

Kinder Morgan Energy Partners’ Common Units

On August 14, 2006, Kinder Morgan Energy Partners paid a quarterly distribution of $0.81 per common unit for the quarterly period ended June 30, 2006, of which $115.6 million was paid to the public holders of Kinder Morgan Energy Partners’ common units. The distributions were declared on July 19, 2006, payable to unitholders of record as of July 31, 2006. On October 18, 2006, Kinder Morgan Energy Partners declared a quarterly cash distribution of $0.81 per common unit for the quarterly period ended September 30, 2006. The distribution will be paid on November 14, 2006, to unitholders of record as of October 31, 2006. See Note 1(H) for additional information regarding our minority interests.

In an August 2006 public offering, Kinder Morgan Energy Partners issued 5,750,000 common units at a price of $44.80, less commissions and underwriting expenses. After all fees, net proceeds were $248.0 million for the issuance of these common units. The proceeds from this equity issuance were used to reduce the borrowings under Kinder Morgan Energy Partners’ commercial paper program.

10.

Common Stock Repurchase Plan

The following table summarizes our common stock repurchases during the third quarter of 2006.

Our Purchases of Our Common Stock

Period	Total Number of Shares Purchased		Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs1		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 to July 31, 2006		-		$	-		-		$	18,203,665
August 1 to August 31, 2006		-		$	-		-		$	18,203,665
September 1 to September 30, 2006		-		$	-		-		$	18,203,665
Total		-		$	-		-		$	18,203,665

¹

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 September 30, 2006, we had repurchased a total of approximately $906.8 million (14,934,300 shares) of our outstanding common stock under the program. No shares of our common stock were repurchased in the three months ended September 30, 2006. In the nine months ended September 30, 2006, we repurchased $31.5 million (339,800 shares) of our common stock. We repurchased $9.4 million (101,600 shares) and $193.1 million (2,519,900 shares) of our common stock in the three months and nine months ended September 30, 2005, respectively.

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,

28

KMI Form 10-Q

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) Power, the ownership and operation of natural gas-fired electric generation facilities; (5) 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; (6) Natural Gas Pipelines – KMP, the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (7) CO₂ – KMP, the production, tra nsportation 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 (8) 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 August 2006, we reached an agreement to sell our Kinder Morgan Retail segment. Accordingly, the activities and assets related to that segment are presented as discontinued items in the accompanying interim financial statements. 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. See Note 8 for additional information regarding discontinued opera tions.

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 State ments 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) our business segments that are also segments of Kinder Morgan Energy Partners include certain other income and expenses and income taxes in their segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on segment earnings in relation to the level of capital employed. In addition, because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depl etion 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.

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KMI Form 10-Q

BUSINESS SEGMENT INFORMATION

	Three Months Ended September 30, 2006											September 30, 2006
	Segment Earnings			Revenues From External Customers		Intersegment Revenues		Depreciation, Depletion And Amortization		Capital Expenditures		Segment Assets1
	(In millions)
NGPL	$	120.1		$	289.1	$	1.3	$	26.3	$	51.4	$	5,702.7
Terasen Gas		40.1			192.8		-		22.1		31.2		4,863.9
Kinder Morgan Canada		30.0			53.9		-		8.8		48.5		2,391.9
Power		6.9			23.3		-		0.5		-		405.0
Products Pipelines – KMP		95.3			207.7		-		20.8		30.7		4,820.5
Natural Gas Pipelines – KMP		124.7			1,646.4		4.0		16.0		18.7		3,775.4
CO2 – KMP		75.8			192.3		-		50.7		75.3		1,870.8
Terminals – KMP		79.1			223.2		-		19.3		65.4		2,407.5
Segment Totals		572.0		$	2,828.7	$	5.3	$	164.5	$	321.2		26,237.7
General and Administrative Expenses		(97.4	)
Other Income and (Expenses)2		(275.5	)					Other3					1,050.4
Income from Continuing Operations								Consolidated				$	27,288.1
Before Income Taxes4	$	199.1

	Three Months Ended September 30, 2005
	Segment Earnings			Revenues From External Customers		Intersegment Revenues		Depreciation, Depletion And Amortization		Capital Expenditures
	(In millions)
NGPL	$	88.6		$	222.8	$	-	$	25.3	$	42.7
Power		4.6			20.1		-		0.7		-
Segment Totals		93.2			242.9	$	-	$	26.0	$	42.7
Other Revenues5					3.8
Total Revenues				$	246.7
Earnings from Investment in Kinder
Morgan Energy Partners		169.2
General and Administrative Expenses		(14.5	)
Other Income and (Expenses)		(57.9	)
Income from Continuing Operations
Before Income Taxes	$	190.0

_____________

¹

Segment assets include goodwill allocated to the segments.

²

Includes (i) interest expense, (ii) minority interests and (iii) other, net.

³

Includes assets of discontinued operations, 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 $4.0 million of income tax expense that was allocated to business segments that are also business segments of Kinder Morgan Energy Partners.

⁵

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

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KMI Form 10-Q

	Nine Months Ended September 30, 2006
	Segment Earnings			Revenues From External Customers		Intersegment Revenues		Depreciation, Depletion And Amortization		Capital Expenditures
	(In millions)
NGPL	$	367.0		$	797.0	$	2.9	$	78.2	$	120.7
Terasen Gas		212.7			1,057.1		-		68.3		85.2
Kinder Morgan Canada		83.0			147.7		0.9		26.8		93.3
Power		17.0			51.5		-		1.6		-
Products Pipelines – KMP		298.0			577.3		-		61.5		151.9
Natural Gas Pipelines – KMP		387.0			5,065.9		16.3		47.9		228.3
CO2 – KMP		239.3			552.8		-		132.0		208.4
Terminals – KMP		234.7			649.3		0.5		55.3		162.7
Segment Totals		1,838.7		$	8,898.6	$	20.6	$	471.6	$	1,050.5
General and Administrative Expenses		(298.5	)
Other Income and (Expenses)1		(861.5	)
Income from Continuing Operations
Before Income Taxes2	$	678.7

	Nine Months Ended September 30, 2005
	Segment Earnings			Revenues From External Customers		Intersegment Revenues		Depreciation, Depletion And Amortization		Capital Expenditures
	(In millions)
NGPL	$	302.2		$	645.6	$	-	$	73.9	$	79.5
Power		13.4			44.6		-		2.6		-
Segment Totals		315.6			690.2	$	-	$	76.5	$	79.5
Other Revenues3					6.3
Total Revenues				$	696.5
Earnings from Investment in Kinder
Morgan Energy Partners		480.4
General and Administrative Expenses		(44.8	)
Other Income and (Expenses)		(138.9	)
Income from Continuing Operations
Before Income Taxes	$	612.3

_____________

¹

Includes (i) interest expense, (ii) minority interests, (iii) a reduction in pre-tax income of $22.3 million ($14.1 million after tax) resulting from non-cash charges to mark to market certain interest rate swaps and (iv) other, net.

²

Includes $11.8 million of income tax expense that was allocated to business segments that are also business segments of Kinder Morgan Energy Partners.

³

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

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.

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KMI Form 10-Q

Revenues from External Customers

	Three Months Ended September 30, 2006
	United States		Canada		Mexico and Other1		Total
	(In millions)
NGPL	$	289.1	$	-	$	-	$	289.1
Terasen Gas		-		192.8		-		192.8
Kinder Morgan Canada		2.8		51.1		-		53.9
Power		23.3		-		-		23.3
Products Pipelines - KMP		205.3		2.4		-		207.7
Natural Gas Pipelines - KMP		1,642.9		-		3.5		1,646.4
CO2 - KMP		192.3		-		-		192.3
Terminals - KMP		221.9		-		1.3		223.2
	$	2,577.6	$	246.3	$	4.8	$	2,828.7

	Nine Months Ended September 30, 2006
	United States		Canada		Mexico and Other1		Total
	(In millions)
NGPL	$	797.0	$	-	$	-	$	797.0
Terasen Gas		-		1,057.1		-		1,057.1
Kinder Morgan Canada		8.0		139.7		-		147.7
Power		51.5		-		-		51.5
Products Pipelines - KMP		568.5		8.8		-		577.3
Natural Gas Pipelines - KMP		5,055.4		-		10.5		5,065.9
CO2 - KMP		552.8		-		-		552.8
Terminals - KMP		645.3		-		4.0		649.3
	$	7,678.5	$	1,205.6	$	14.5	$	8,898.6

Long-lived Assets²

	At September 30, 2006
	United States		Canada		Mexico and Other1		Total
	(In millions)
NGPL	$	5,516.3	$	-	$	-	$	5,516.3
Terasen Gas		-		2,961.6		-		2,961.6
Kinder Morgan Canada		335.3		1,345.9		-		1,681.2
Power		345.0		-		-		345.0
Products Pipelines - KMP		3,691.5		47.5		-		3,739.0
Natural Gas Pipelines - KMP		2,689.8		-		84.7		2,774.5
CO2 - KMP		1,635.5		-		-		1,635.5
Terminals - KMP		1,687.7		9.0		8.4		1,705.1
Discontinued Operations		386.9		-		24.5		411.4
Other		294.5		167.6		-		462.1
	$	16,582.5	$	4,531.6	$	117.6	$	21,231.7

________________

¹

Terminals – KMP includes revenues of $1.3 million and $4.0 million for the three months and nine months ended September 30, 2006, respectively, and long-lived assets of $8.4 million at September 30, 2006 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”).

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KMI Form 10-Q

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 and nine months ended September 30, 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 a pre-tax gain of approximately $3.2 million (net of minority interest gain of $0.1 million) and a pre-tax loss of $24.6 million in the three months ended September 30, 2006 and 2005, respectively, and a pre-tax gain of approximately $4.9 million (net of minority interest loss of $0.2 million) and a pre-tax loss of $26.4 million in the nine month periods ending September 30, 2006 and 2005, respectively, as a result of ineffectiveness of these hedges, which amounts are reported within the captions “Natural Gas Sales,” “Oil and Product 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 and nine m onths ended September 30, 2006 we reclassified $4.2 million (net of minority interest of $16.6 million) and $21.3 million (net of minority interest of $49.8 million) respectively, of accumulated other comprehensive loss into earnings, as a result of hedged forecasted transactions occurring during the periods. During the three and nine months ended September 30, 2005 we reclassified $26.4 million and $28.5 million, respectively, of accumulated other comprehensive loss into earnings as a result of hedged forecasted transactions occurring during the period. During the three months ended September 30, 2006, we reclassified $2.9 million of net losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period. We expect to reclassify approximately $19.2 million (net of minority interest of $61.4 million) of accumulated other comprehensive loss as of September 30, 2006 to earning s 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 September 30, 2006, our margin requirements associated with our commodity contract positions and over-the-counter swap partners totaled $3.2 million and is reported within the caption “Current Liabilities: Other.” As of December 31, 2005, we had no cash margin deposits associated with our commodity contract positions and over-the-counter swap partners. As of September 30, 2006 and December 31, 2005, we had six outstanding letters of credit totaling $382 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. In June 2006, Kinder Morgan Energy Partners’ CO₂ business segment hedged an incremental 23 million barrels of crude oil production at its SACROC and Yates oil field units for the years 2007 through 2011 by entering into a new hedge facility with J. Aron & Company/Goldman Sachs that does not require the posting of margin.

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 caption “Current Assets: Rate Stabilization.”

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 September 30, 2006 and December 31, 2005:

	September 30, 2006		December 31, 2005
	(In millions)
Derivatives Asset (Liability)
Current Assets: Other	$	182.1		$	151.2
Deferred Charges and Other Assets		22.3			1.3
Current Liabilities: Other		797.4			78.9
Other Liabilities and Deferred Credits: Other		603.5			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.

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KMI Form 10-Q

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 $109.5 million and $54.8 million at September 30, 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 e qual 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 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 $1.9 million (C$2.2 million). The cumulative loss recognized of $2.0 million (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 September 30, 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 September 30, 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

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KMI Form 10-Q

·

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

As of September 30, 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 $1.7 million at September 30, 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.

(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 and nine months ended September 30, 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 September 30, 2006 is a liability of $175.6 million which is included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying i nterim 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. d ollar.

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KMI Form 10-Q

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 September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(In thousands)
Service Cost	$	2,829		$	2,493		$	8,487		$	7,480
Interest Cost		3,141			2,993			9,424			8,980
Expected Return on Assets		(5,329	)		(5,101	)		(15,988	)		(15,303	)
Amortization of:
Transition Asset		-			(8	)		-			(24	)
Prior Service Cost		43			44			131			133
Loss		381			179			1,141			534
Net Periodic Pension Cost	$	1,065		$	600		$	3,195		$	1,800

We previously disclosed in our 2005 Form 10-K that we expected to make no contributions to our retirement plans during 2006. As of September 30, 2006, no contributions have been made and we do not expect to make any additional contributions to the plans during 2006.

(B)    Other Postretirement Employee Benefits

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(In thousands)
Service Cost	$	96		$	110		$	290		$	330
Interest Cost		1,232			1,302			3,694			3,905
Expected Return on Assets		(1,401	)		(1,428	)		(4,200	)		(4,285	)
Amortization of:
Prior Service Cost		(393	)		(415	)		(1,179	)		(1,246	)
Loss		1,149			1,206			3,443			3,621
Net Periodic Postretirement Benefit Cost	$	683		$	775		$	2,048		$	2,325

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 September 30, 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 September 30, 2006				Nine Months Ended September 30, 2006
	(In thousands)
Service Cost		$	1,975			$	6,013
Interest Cost			3,648				11,104
Expected Return on Assets			(4,322	)			(13,158	)
Plan Amendments			93				283
Other			42				130
Net Periodic Pension Cost			1,436				4,372
Defined Contribution Cost			405				1,437
Total Pension Costs		$	1,841			$	5,809

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KMI Form 10-Q

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 September 30, 2006, contributions of approximately $5.5 million have been made. Terasen expects to make additional contributions of approximately $1.8 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 September 30, 2006				Nine Months Ended September 30, 2006
	(In thousands)
Service Cost		$	423			$	1,265
Interest Cost			904				2,698
Other			(4	)			(13	)
Net Periodic Postretirement Benefit Cost		$	1,323			$	3,950

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 September 30, 2006, contributions of approximately $1.0 million have been made. Terasen expects to make additional contributions of approximately $0.4 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 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 September 30, 2006				Nine Months Ended September 30, 2006
	(In thousands)
Service Cost		$	3			$	8
Interest Cost			68				202
Amortization of Prior Service Cost			(29	)			(88	)
Actuarial (Gain)			(114	)			(340	)
Net Periodic Benefit Cost		$	(72	)		$	(218	)

As of September 30, 2006, Kinder Morgan Energy Partners’ estimated 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 October 10, 2006, in Federal Energy Regulatory Commission (“FERC”) Docket No. CP 07-3, NGPL filed seeking approval to expand its Louisiana Line by 200,000 Dth/day. This $66 million project is supported by five-year agreements that fully subscribe the additional capacity.

On September 14, 2006, in FERC Docket No. CP06-455, Kinder Morgan Illinois Pipeline filed seeking a certificate from the FERC to acquire long-term lease capacity on NGPL and build facilities to supply transportation service for Peoples Gas Light and Coke Co., who has signed a 10-year agreement for all the capacity.  The $13.3 million project would have a capacity of 360,000 Dth/day and is expected to be operational by the 2007-08 winter heating season.

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KMI Form 10-Q

On September 8, 2006, in FERC Docket No. CP06-449, Kinder Morgan Louisiana Pipeline filed an application with the FERC requesting approval to construct and operate the Kinder Morgan Louisiana Pipeline, an interstate natural gas pipeline. The pipeline will extend approximately 135 miles from Cheniere’s Sabine Pass liquefied natural gas terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including NGPL. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. The entire approximately $500 million project is expected to be in service in the second quarter of 2009.

On July 20, 2006, the FERC accepted the Kinder Morgan interstate pipelines’ May 19, 2005 compliance filing under Order No. 2004, the order adopting standards of conduct that govern the relationships between natural gas transmission providers and all their marketing and energy affiliates.

In June 2006, the British Columbia Utilities Commission (“BCUC”) approved an application from Terasen Gas to build a 50-kilometer natural gas pipeline from Squamish to Whistler. The estimated C$37 million project, which is subject to securing acceptable construction arrangements, will replace an aging propane system and will bring natural gas to Whistler prior to the 2010 Winter Olympics. Terasen Gas hopes to begin construction on the project this year with full service available to Whistler by November 2008.

On June 2, 2006, Kinder Morgan Retail filed a general rate increase application with the Nebraska Public Service Commission seeking an additional $11.05 million of revenue per year from its Nebraska gas utility operations. A phased-in annual increase of $7.7 million went into effect subject to refund on September 1, 2006, pursuant to Nebraska law which allows interim rates, with the proposed full $11.05 million going into effect in early 2007, subject to final Commission approval, which is expected within nine months of the filing date.

On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado Gas Transmission Company (“TransColorado”) filed an application for authorization to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” Upon implementation, this project will facilitate the transportation of up to 250,000 Dth/day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing interstate pipeline for delivery to Rockies Express Pipeline LLC at an existing point of interconnection located in the Meeker Hub in Rio Blanco County, Colorado.

On May 31, 2006, in FERC Docket No. CP06-354-000, Rockies Express Pipeline LLC filed an application for authorization to construct and operate certain facilities comprising its proposed “REX-West Project.” This project is the first planned segment extension of Rockies Express Pipeline LLC’s currently certificated facilities, which include (i) a 136-mile pipeline segment currently in operation from the Meeker Hub in Colorado to the Wamsutter Hub in Wyoming, and (ii) a 191-mile segment currently under construction and expected to be in service by January 1, 2007, from the Wamsutter Hub to the Cheyenne Hub located in Weld County, Colorado. This project would extend the Rockies Express Pipeline from the Cheyenne Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The project will comprise approximately 713 miles of 42-inch diameter pipeline and is proposed to transport 1,500,000 Dth/day of n atural gas across portions of the following five states: Wyoming, Colorado, Nebraska, Kansas and Missouri. The project also will include certain improvements to existing Rockies Express Pipeline facilities located west of the Cheyenne Hub.

On September 21, 2006, the FERC issued a favorable preliminary determination on all non-environmental issues of the project, approving Rockies Express’ application (i) to construct and operate the 713 miles of new natural gas transmission facilities from the Cheyenne Hub and (ii) to lease capacity on Questar Overthrust Pipeline Company, which will extend the Rockies Express system 140 miles west from the Wamsutter Hub to the Opal Hub in Wyoming. Pending completion of the FERC environmental review and the issuance of a certificate, the project is expected to begin service on January 1, 2008.  Rockies Express Pipeline LLC will file a separate application in the future for its proposed “REX-East Project,” which will extend the pipeline from eastern Missouri to the Clarington Hub in eastern Ohio.

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. On September 20, 2006, the Wyoming Public Service Commission issued a Bench Decision approving an annual increase of $6.45 million effective October 1, 2006.

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$435 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 barrels per day (“bpd”) to 300,000 bpd by the end of 2008. The public hearing of the application was held the week of August 8, 2006. On October 26, 2006, the NEB released its favorable decision on the application.

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KMI Form 10-Q

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 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, with an effective date as of January 1, 2006. The decision resulted in increases in the deemed equity components of Terasen Gas Inc. and TGVI to 35% and 40%, respectively, and their allowed RO Es 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”). In September 2006, Kinder Morgan Canada completed the negotiation with CAPP on the final ITS agreement and on October 18, 2006, the CAPP Board of Governors approved the agreement. The agreement was filed with the NEB on October 19, 2006 and a decision is expected in December 2006. The 2006-2010 ITS determines the tolls to be charged on the Trans Mountain system over the five-year term of the agreement, to take effect as of January 1, 2006. The agreement also governs the financial arrangements for the Pump Station Expansion and Anchor Loop projects. In addition to tolling and expansion parameters, the formal agreement contains capacity allocation procedures for the Westridge Marine Terminal and enhanced service standards definit ions.

We have initiated engineering, environmental, consultation and procurement activities on the proposed Corridor pipeline expansion project, as authorized and supported by shipper resolutions and the underlying firm service agreement. The proposed C$1.6 billion expansion includes building a new 42-inch diameter diluent/bitumen (“dilbit”) pipeline, a new 20-inch diameter 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 180,000 bpd of dilbit capacity to accommodate the new bitumen production from the Muskeg River Mine. An expansion of the Corridor pipeline system has been completed in 2006 increasing the dilbit capacity to 278,000 bpd by upgrading existing pump station facilities. By 2009, the dilbit capacity of the Corridor system is expected to be approximately 460,000 bpd. An application for the Corridor pipeline expansion project was filed with the Alberta Energy Utilities Board and Alberta Environment on December 22, 2005, and approval was received in August 2006. Construction of the Corridor pipeline expansion is expected to begin in November 2006 as the shippers have received definitive approval of their Muskeg River Mine expansion. Please refer to our 2005 Form 10-K for additional information regarding Kinder Morgan Canada.

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, the FERC proposed 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 proposed 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 ad equately protected from the abuse of market power. On June 19, 2006, the FERC issued Order 678 allowing for broader market-based pricing of storage services. The rule expands the alternatives that can be considered in evaluating competition, provides that market-based pricing may be available even when market power is present (if market-based pricing is needed to stimulate development) and treats expansions of existing facilities similar to new facilities. The order became effective July 27, 2006. Several parties have filed for rehearing of this order.

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. On June 5, 2006, in Docket No. AC 06-18, the FERC ruled on NGPL’s request to capitalize pipeline rehabilitation costs. The ruling states that NGPL must expense rather than capitalize the majority of the costs. NGPL can continue to capitalize the costs of pipe replacement and coating but costs to assess the integrity of pipe must be expensed.

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. Comments were filed by numerous entities. By an order issued 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

39

KMI Form 10-Q

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. The Interstate Natural Gas Association of America, referred to in this report as INGAA, sought rehearing of the FERC’s June 30 order. On September 19, 2005, the FERC denied INGAA’s request for rehearing. On December 15, 2005, INGAA fi led 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 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. On May 10, 2006, the Court issued an order establishing a briefing schedule. Under the schedule, INGAA filed its initial brief on June 23, 2006. Both the FERC’s and INGAA’s reply briefs have been filed.

Due to the implementation of this FERC order on January 1, 2006, which caused the Kinder Morgan FERC-regulated natural gas pipelines to expense certain pipeline integrity management program costs that would have been capitalized, NGPL and Kinder Morgan Energy Partners’ Kinder Morgan Interstate Gas Transmission LLC expect increases of approximately $11.8 million and $0.9 million, respectively, in operating expenses in 2006 compared to 2005.  Also, beginning in the third quarter of 2006, Kinder Morgan Energy Partners’ Texas intrastate natural gas pipeline group and the operations included in Kinder Morgan Energy Partners’ Products Pipelines and CO₂ business segments began recognizing certain costs incurred as part of their pipeline integrity management program as operating expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six m onths of 2006. For the year 2006 compared to 2005, we expect this change to result in operating expense increases of approximately $1.8 million for the Texas intrastate gas group, $26.8 million for the Products Pipelines business segment, and $1.4 million for the CO₂ business segment. Combined, this change did not have any material effect on prior periods and is not expected to have a material impact on our financial position, results of operations, or cash flows for the 2006 annual period. In addition, due to the fact that these amounts will not be capitalized but instead charged to expense, we expect Kinder Morgan Energy Partners’ sustaining capital expenditures to be reduced by similar amounts.

15.

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 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 Kinder Morgan Energy Partners’ Pacific operations’ pipeline systems.

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

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KMI Form 10-Q

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 f or 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

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interests owned by corporate partners. By its terms, the portion of the opinion addressing SFPP only pertained to SFPP and was based on the record in that case.

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

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

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

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

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

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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 e ntity’s public utility income. The FERC expressed the intent to implement its policy in individual cases as they arise. The FERC’s decision in Docket No. PL05-5 has been appealed to the United States Court of Appeals for the District of Columbia, and final briefs were filed on September 11, 2006.

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 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 discussed further below.

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

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and Valero. SFPP moved to intervene in the review proceedings brought by the other parties. The proceedings before the court are addressed further below.

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.

Watson Station proceedings. The FERC’s June 1, 2005 Order on Remand and Rehearing initiated a separate proceeding regarding the reasonableness of the Watson Station charge. All Watson-related issues in Docket No. OR92-8, Docket No. OR96-2 and other dockets were also consolidated in that proceeding. After discovery and the filing of prepared direct testimony, the procedural schedule was suspended while the parties pursued settlement negotiations.

On May 17, 2006, the parties entered into a settlement agreement and filed an offer of settlement with the FERC. On August 2, 2006, the FERC approved the settlement without modification and directed that it be implemented. Pursuant to the settlement, SFPP filed a new tariff, which took effect September 1, 2006, lowering SFPP’s going-forward rate to $0.003 per barrel and including certain volumetric pumping rates. SFPP also paid refunds to all shippers for the period from April 1, 1999 through August 31, 2006. Those refunds were based upon the difference between the Watson Station charge as filed in SFPP’s prior tariffs and the reduced charges set forth in the agreement. On September 28, 2006, SFPP filed a refund report with the FERC, setting forth the refunds that had been paid and describing how the refund calculations were made. Two of the settling parties, BP and ExxonMobil, protested the refund report, and SFPP responded to that pr otest. The FERC has yet to act on the protest. As of September 30, 2006, SFPP had made aggregate payments, including accrued interest of $19.1 million.

For the period prior to April 1, 1999, the parties agreed to reserve for briefing issues related to whether shippers are entitled to reparations. To the extent any reparations are owed, the parties agreed on how reparations would be calculated. Initial briefs regarding the reserved legal issues are due November 15, 2006. Reply briefs are due December 21, 2006.

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.

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. The FERC has not yet ruled on the initial decision in this proceeding.

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

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

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

On March 26, 2004, the FERC issued an order on the phase one initial decision. The FERC’s phase one order reversed the initial decision by finding that SFPP’s rates for its North and Oregon Lines should remain “grandfathered” and amended the initial decision by finding that SFPP’s West Line rates (i) to Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no longer be “grandfathered” and are not just and reasonable. The FERC upheld these findings in its June 1, 2005 order, although it appears to have found substantially changed circumstances as to SFPP’s West Line rates on a somewhat different basis than in the phase one order. The FERC’s phase one order did not address prospective West Line rates and whether reparations were necessary. As discussed below, those issues have been addressed in the FERC’s December 16, 2005 order on phase two issues. The FERC’s phase one order also did not address the “grandfathered” status of the Watson Station fee, noting that it would address that issue once it was ruled on by the Court of Appeals in its review of the FERC’s Opinion No. 435 orders; as noted above, the FERC held in its June 1, 2005 order that the Watson Station fee is not grandfathered. Several of the participants in the proceeding requested rehearing of the FERC’s phase one order. The FERC denied those requests in its June 1, 2005 order. In addition, several participants, including SFPP, filed petitions with the United States Court of Appeals for the District of Columbia Circuit for review of the FERC’s phase one order. On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for review of the phase one order, which Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004, the Court of Appeals referred the FERC’s motion to the merits panel and directed the parties to address the issues in that motion on brief, thus effectively dismissing the FERC’s motion. In the same order, the Court of Appeals granted a motion to hold the petitions for review of the FERC’s phase one order in abeyance and directed the parties to file motions to govern future proceeding 30 days after FERC disposition of the pending rehearing requests. In August 2005, the FERC and SFPP jointly moved that the Court of Appeals hold the petitions for review of the March 26, 2004 and June 1, 2005 orders in abeyance due to the pendency of further action before the FERC on income tax allowance issues. In December 2005, the Court of Appeals denied this motion and placed the petitions seeking review of the two orders on the active docket. Initial briefs to the Court were filed May 30, 2006, and final briefs were filed October 19, 2006. Oral argument has been scheduled for December 12, 2006.

On July 24, 2006, the FERC filed with the Court of Appeals a motion for voluntary partial remand, requesting that the portion of the March 26, 2004 and June 1, 2005 orders in which the FERC removed grandfathering protection from SFPP’s West Line rates and affirmed such protection for the North Line and Oregon Line rates be returned to the FERC for reconsideration in light of arguments presented by SFPP and other parties in their initial briefs. In response to the FERC’s remand motion, SFPP filed on August 1, 2006 to reinstate its West Line rates at the previous, grandfathered level effective August 2, 2006, and asked for FERC approval of such reinstatement on the ground that, pending the FERC’s reconsideration of its grandfathering rulings, the prior grandfathered rate level is the lawful rate. On August 17, 2006, the Court of Appeals denied without prejudice the FERC’s motion for voluntary partial remand. In light of this denial, on August 31, 2006, the FERC issued an order rejecting SFPP’s August 1, 2006 filing seeking reinstatement of SFPP’s grandfathered West Line rates.

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 Kinder Morgan Energy Partners’ 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

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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 that the FERC’s policy statement and its decision in these cases have been 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 a t 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 July 31, 2006, the Court of Appeals held the appeals of these orders in abeyance pending further FERC action.

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). In accordance with the December 16, 2005 order, rate reductions were 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 operatio ns in the FERC Docket Nos. OR92-8, OR96-2 and IS05-230 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

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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 is expected to be approximately $15 million and the partial year impact on our 2006 earnings per share will be approximately $0.05 per share.

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

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

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

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

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

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

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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, 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. 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. On September 5, 2006, the presiding administrative law judge suspended the procedural schedule in Docket No. OR03-5 pending a decision by the United States Court of Appeals for the District of Columbia regarding various issues before the court that directly impact the Docket No. OR03-5 proceeding.

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 presiding administrative law judge issued his initial decision on September 26, 2006.

The initial decision held that SFPP should be allowed to include in its rate base all costs associated with relocating the Concord to Sacramento Segment, but to include only 14/20ths of the cost of constructing the new line; it further held that the FERC’s policy statement on income tax allowance is inconsistent with the Court’s decision in BP West Coast Products, LLC v. Federal Energy Regulatory Commission and that, therefore, SFPP should be allowed no income tax allowance. While the initial decision held that SFPP could recover its litigation costs, it otherwise made rulings generally adverse to SFPP on cost of service issues. These issues included the capital structure to be used in computing SFPP’s “starting rate base,” treatment of SFPP’s accumulated deferred income tax account, costs of debt and equity, as well as allocation of overhead. Briefs on exceptions are due on October 25, 2006. The FERC has not yet reviewed the initial decision, and it is not possible to predict the outcome of FERC and/or appellate review.

East Line rate case, IS06-283 proceeding. In April 2006, SFPP filed to increase its East Line interstate rates to reflect increased costs, principally due to the installation of replacement pipe between El Paso, Texas and Tucson, Arizona, significantly increasing the East Line’s capacity. Under FERC regulations, SFPP was required to demonstrate that there was a substantial divergence between the revenues generated by its existing East Line rates and its increased costs. SFPP’s rate increase was protested by various shippers and accepted subject to refund by the FERC. The FERC established an investigation and hearing before an administrative law judge. A procedural schedule has been established, with a hearing scheduled for February 2007.

Index Increases, IS06-356, IS05-327. On May 27, 2005, SFPP filed to increase certain rates pursuant to the FERC’s indexing methodology. Various shippers protested, and the FERC accepted and suspended all but one of the filed tariffs, subject to SFPP’s filing of a revised Page 700 of its FERC Form 6 and subject to the outcome of various proceedings involving SFPP at the FERC. BP West Coast Products and ExxonMobil Oil Corporation filed for rehearing and challenged the revised Page 700 filed by SFPP. On December 12, 2005, the FERC denied the request for rehearing; this decision is currently on appeal before the Court of Appeals. Initial briefs were filed on August 25, 2006, and final briefs are due on November 28, 2006.

On May 30, 2006, SFPP also filed to increase certain interstate rates pursuant to the FERC’s indexing methodology. This filing was protested, but the FERC determined that SFPP’s tariff filing was consistent with the FERC’s regulations. Certain shippers requested rehearing, which the FERC granted for further consideration on August 21, 2006. The FERC’s order has been appealed to the United States Court of Appeals for the District of Columbia Circuit. On August 31, 2006, the FERC filed a motion with the Court to hold the case in abeyance, and SFPP and BP West Coast subsequently intervened. The Court has not yet issued a ruling on the motions filed by the FERC, SFPP, and BP West Coast.

Calnev Pipe Line LLC

On May 22, 2006, Calnev Pipe Line LLC filed to increase its interstate rates pursuant to the FERC’s indexing methodology applicable to oil pipelines. The filing was docketed in IS06-296. Calnev’s filing was protested by ExxonMobil, claiming that Calnev was not entitled to an indexing increase in its rates based on its cost of service. Calnev answered the protest. On June 29, 2006, the FERC accepted and suspended the filing, subject to refund, permitting the increased rates to go into effect on July 1, 2006. The FERC found that Calnev’s indexed rates exceeded its change in costs to a degree that warranted

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establishing an investigation and hearing. However, the FERC initially directed the parties to attempt to reach a settlement of the dispute before a FERC settlement judge. The settlement process is proceeding.

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 at any time.

In October 2002, the CPUC issued a resolution, referred to in this report as the Power Surcharge 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 Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and Chevron P roducts 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 at any time.

With regard to the CPUC complaints and the Power Surcharge Resolution, we currently believe the complainants/protestants seek approximately $31 million in prospective annual tariff reductions. Based upon CPUC practice and procedure which precludes refunds or reparations in complaints in which the complainants challenge the reasonableness of rates previously found reasonable by the CPUC (as is the case with the two pending complaints contesting the reasonableness of SFPP’s rates) except for matters which have been expressly reserved by the CPUC for further consideration (as is the case with respect to the reasonableness of the rate charged for use of the Watson Station gathering enhancement facilities), we currently believe that complainants/protestants are seeking approximately $15 million in refunds/reparations. There is no way to quantify the potential extent to which the CPUC could determine that SFPP’s existing California rates are unreasonable.

SFPP also has various, pending ratemaking matters before the CPUC that are unrelated to the above-referenced complaints and the Power Surcharge Resolution. On November 22, 2004, SFPP filed an application with the CPUC requesting a $9 million annual 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. Because no schedule has been established by the CPUC for addressing the issues raised by the contested rate increase application nor does any record exist upon which the CPUC c ould base a decision, SFPP has no basis for estimating either the prospective rate reductions or the potential refunds at issue or for establishing a date by which the CPUC is likely to render a decision regarding the application.

On January 26, 2006, SFPP filed a request for a rate increase of approximately $5.4 million annually 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. As a consequence of the protests, the related rate increases are being collected subject to refund. Because no schedule has

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been established by the CPUC for addressing the issues raised by the contested rate increase application nor does any record exist upon which the CPUC could base a decision, SFPP has no basis for estimating either the prospective rate reductions or the potential refunds at issue or for establishing a date by which the CPUC is likely to render a decision regarding the application.

On August 25, 2006, SFPP filed an application to increase rates by approximately $0.5 million annually to recover costs incurred to comply with revised Ultra Low Sulfur Diesel regulations and to offset the revenue loss associated with reduction of the Watson Station Volume Deficiency Charge (intrastate) by increasing rates on a system-wide basis by approximately $3.1 million annually to be effective as of October 5, 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. As a consequence of the protests, the related rate increases are being collected subject to refund. Because no schedule has been established by the CPUC for addressing the issues raised by the contest ed rate increase application, nor does any record exist upon which the CPUC could base a decision, SFPP has no basis for estimating either the prospective rate reductions, or the potential refunds at issue, or for establishing a date by which the CPUC is likely to render a decision regarding the application.

All of the referenced pending matters before the CPUC have been consolidated and assigned to a single Administrative Law Judge who has indicated his intention to refer the matters to mediation under CPUC procedures applicable to alternative dispute resolution processes.

With regard to the Power Surcharge Resolution, the November 2004 rate increase application, the January 2006 rate increase application and the August 2006 rate increase application, 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 rate reductions or 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).

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. The case is currently set for trial on June 11, 2007.

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

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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 currently set for trial on June 11, 2007.

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 Sta te 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 anoth er 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 transfe r 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 Cour t denied Bailey’s petition for writ of certiorari. The Houston federal district court subsequently realigned the parties in the Bailey Houston Federal Court Action. Pursuant to the Houston federal district court’s order, Bailey and the other realigned plaintiffs have filed amended complaints in which they assert claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of contract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account. Bailey also asserted claims as a private relator under the False Claims Act and for violation of federal and Colorado antitrust laws. The realigned plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The Shell and Kinder Morgan defendants, along with Cortez Pipeline Company and ExxonMobil defendants, have filed motions for summary j udgment 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 that are virtually identical to the 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.

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, asserted claims for civil conspiracy, violation of the Colorado Organized Crime Control Act, violation of Colorado antitrust laws,

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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 sought actual damages, treble damages, forfeiture, disgorgement, and declaratory and injunctive relief. The Colorado court transferred the case to Houston federal district court, and Ptasynski subsequently sought to non-suit the case. The Houston federal district court has granted Ptasynski’s request to non-suit. Prior to non-suiting the case, Ptasynski filed an appeal in the Tenth Circuit seeking to overturn the Colorado court’s order transferring the case to Houston federal district court. That appeal is currently pending.

Kinder Morgan CO₂ Company, L.P. and Cortez Pipeline Company were 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 involved 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 claimed breaches of contractual and potential fiduciary duties owed by the defendants and also alleged 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 addit ion to actual or compensatory damages, plaintiffs sought 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. In August 2006, plaintiffs and defendants reached a settlement of all claims. Pursuant to the settlement, the case was dismissed with prejudice on September 27, 2006.

Cortez Pipeline Company and Kinder Morgan CO₂ Company, L.P., successor in interest to Shell CO₂ Company, Ltd., were among the named defendants in CO₂ Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The arbitration arose 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 arb itration 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 alleged 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 $12 million. The plaintiff also alleged 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 $0.5 million. Defendants denied that there was any breach of the settlement agreement. The arbitration panel issued various preliminary evidentiary rulings. The arbitration hearing took place in Albuquerque, New Mexico on June 26-30, 2006. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. The arbitration opinion remains subjec t to further proceedings to confirm, vacate, or modify the opinion.

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 thos e 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. Kinder Morgan appealed that ruling to the New Mexico Court of Appeals. Oral arguments took place before the New Mexico Court of Appeals on March 23, 2006, and the New Mexico Court of Appeals affirmed th e district court’s order on August 8, 2006. Kinder Morgan filed a petition for writ of certiorari in the New Mexico Supreme Court. The New Mexico Supreme Court granted the petition on October 11, 2006.

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

Commercial Litigation Matters

Union Pacific Railroad Company Easements

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

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

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

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. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and a decision from the judge is expected in the fourth quarter of 2006. In addition, 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 declarator y 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 positions, 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 greater 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 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 was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. Certain entities Kinder Morgan Energy Partners 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

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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 Kinder Morgan Energy Partners 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 L itigation, and transferred to the District of Wyoming. The multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases, referred to as valuation claims. Judge Downes denied the defendant’s motion to dismiss on May 18, 2001. The United States’ motion to dismiss most of plaintiff’s valuation claims has been granted by the court. Grynberg has appealed that dismissal to the 10^th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Subsequently, Grynberg’s appeal was dismissed for lack of appellate jurisdiction. Discovery to determine issues related to the Court’s subject matter jurisdiction arising out of the False Claims Act is complete. Briefing has been completed and oral arguments on jurisdiction were held before the Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to carbon dioxide production. Defendants have filed briefs opposing leave to amend. Neither the Court nor the Special Master has ruled on Grynberg’s Motion to Amend.

On May 13, 2005, the Special Master issued his Report and Recommendations to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. The Special Master found that there was a prior public disclosure of the mismeasurement fraud Grynberg alleged, and that Grynberg was not an original source of the allegations. As a result, the Special Master recommended dismissal of the Kinder Morgan defendants on jurisdictional grounds. On June 27, 2005, Grynberg filed a motion to modify and partially reverse the Special Master’s recommendations and the Defendants filed a motion to adopt the Special Master’s recommendations with modifications. An oral argument was held on December 9, 2005 on the motions concerning the Special Master’s recommendations.

On October 20, 2006, the United States District Court, for the District of Wyoming, issued its Order on Report and Recommendations of Special Master. In its Order, the Court upheld the dismissal of the claims against the Kinder Morgan defendants on jurisdictional grounds, finding that Grynberg’s claims are based upon public disclosures and that Grynberg does not qualify as an original source. It is probable that Grynberg will appeal this Order to the 10^th 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 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 recentl y concluded jurisdictional discovery and various defendants have filed motions arguing that the Arkansas courts lack personal jurisdiction over them. The Court has not yet ruled on these

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motions. 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.

Federal Investigation at Cora and Grand Rivers Coal Facilities

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

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

Claims asserted by residents and businesses. 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 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, referred to in this report as 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, the Kinder Morgan entities named as defendants in the case 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, 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.

In June 2006, the parties reached an agreement to partially settle the class action suit. On June 29, 2006, the plaintiffs filed an unopposed motion for conditional certification of a settlement class. The settlement provides for a fund of $2.0 million to distribute to residents within the evacuation zone (“Zone 1”) and residents immediately adjacent to the evacuation zone (“Zone 2”). Persons in Zones 1 and 2 reside within approximately one mile from the site of the incident. The court preliminarily approved the partial class action settlement on July 7, 2006. Kinder Morgan Energy Partners agreed to participate in and fund a minor percentage of the settlement. A fairness hearing occurred on August 18, 2006 for the purpose of establishing final approval of the partial settlement. The Court approved the settlement, entered a final judgment and

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certified a settlement class for Zones 1 and 2. The bar date for claims has passed and Plaintiffs’ counsel reports that they will be paying claims in the immediate future. Certain claims by other residents and businesses remain pending. Specifically, the settlement and final judgment does not apply to purported class action claims by residents in outlying geographic zones more than one mile from the site of the incident. Defendants deny liability to such other residents in outlying geographic zones and intend to vigorously defend such claims. In addition, the non-Kinder Morgan defendants have agreed to settle remaining claims asserted by businesses and will obtain a release of such claims favoring all defendants, including Kinder Morgan Energy Partners and its affiliates, subject to the retention by all defendants of their claims against each other for contribution and indemnity. Kinder Morgan Energy Partners expects that a claim will be as serted by other defendants against Kinder Morgan Energy Partners seeking contribution or indemnity for any settlements funded exclusively by other defendants, and Kinder Morgan Energy Partners expects to vigorously defend against any such claims.

Claims asserted by the city of Cincinnati. 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. 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 seeking dismissal of the remaining aspects of the city’s complaint. The issues have been thoroughly briefed, and oral argument will be heard on December 8, 2006. The parties agreed to stay discovery until after the hearing, if necessary. No trial date has been established.

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,

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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 Kinder Morgan Energy Partners. 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 Kinder Morgan Energy Partners (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 Kinder Morgan Energy Partners. 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. This motion was denied by the 9^th Circuit Court of Appeals on May 25, 2006.

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

On May 30, 2003, a separate group of plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against Kinder Morgan Energy Partners and several Kinder Morgan related entities and individuals and additional unrelated defendants. Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing “harmful substances and emissions and gases” to damage “the environment and health of human beings.” Plaintiffs claim that “Adam Jernee’s death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins.” Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. The Jernee case has been consolidated for pretrial purposes with the Sands case (see below). Plaintiffs have filed a third amended complaint and all defendants filed motions to dismiss all causes of action excluding plaintiffs’ cause of action for negligence. Defendants also filed motions to strike portions of the complaint. By order dated May 5, 2006, the Court granted defendants’ motions to dismiss as to the counts purporting to assert claims for fraud, but denied defendants’ motions to dismiss as to the remaining counts, as well as defendants’ motions to strike. Defendant Kennametal, Inc. has filed a third-party complaint naming the United States and the United States Navy (the “United States”) as additional defendants.  In response, the United States removed the case to the United States District Court for the District of Nevada and filed a motion to dismiss the third-party complaint, which motion is currently pending.  Plaintiff has also filed a motion t o dismiss the United States and/or to remand the case back to state court.  Briefing on these motions is currently underway.

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.”

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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 third amended complaint and all defendants filed motions to dismiss all causes of action excluding plaintiffs’ cause of action for negligence. Defendants also filed motions to strike portions of the complaint. By order dated May 5, 2006, the Court granted defendants’ motions to dismiss as to the counts purporting to assert claims for fraud, but denied defendants’ motions to dismiss as to the remaining counts, as well as defendants’ motions to strike. Defendant Kennametal, Inc. has filed a third-party complaint naming the United States and the United States Navy (the “United States”) as additional defendants. In response, the United States removed the case to the United States District Court for the District of Nevada and filed a motion to dismiss the third-party complaint, which motion is currently pending. Plaintiff has also filed a motion to dismiss th e United States and/or to remand the case back to state court. Briefing on these motions is currently underway.

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 and SFPP. The plaintiffs are homebuilders who constructed a subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30, 2003 pipeline rupture and accompanying release of petroleum products, soil and groundwater adjacent to, on and underlying portions of Silver Creek II became contaminated. Plaintiffs allege that they have incurred and continue to incur costs, damages and expenses associated with the delay of closings of home sales within Silver Creek II and damage to their reputation and goodwill as a result of the rupture and release. Plaintiffs’ complaint purports to assert claims for negligence, breach of contract, trespass, nuisance, strict liability, subrogation and indemnity, and negligence per se. Plaintiffs seek “no le ss 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 executed a settlement agreement and release of all claims and counterclaims in the above captioned matter. On August 14, 2006, the case was dismissed with prejudice.

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 inc ident 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

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CSFM, and SFPP has appealed the civil penalties while, at the same time, it has continued to work cooperatively with CalOSHA and the CSFM to resolve these matters. 

As a result of the accident, fifteen separate lawsuits have been filed. Each of these lawsuits is currently coordinated in Contra Costa County Superior Court. There are also several cross-complaints for indemnity between the co-defendants in the coordinated lawsuits. The majority of the cases 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 the Kinder Morgan defendants failed to properly field mark the area where the accident occurred. All of these plaintiffs seek compensatory and punitive damages. These complaints also allege that the general contractor who struck the pipeline, Mountain Cascade, Inc. (“MCI”), and EBMUD were at fault for negligently failing to locate the pipeline. Some of these complaints also name various engineers on the project for negligently failing to draw up adequate plans indicating the bend in the pipeline. A number of these actions also name Comforce Technical Services as a defendant. Comforce supplied SFPP with temporary employees/independent contractors who performed line marking and inspections of the pipeline on behalf of SFPP. Some of these complaints also named various governmental entities—such as the City of Walnut Creek, Contra Costa Count y, and the Contra Costa Flood Control and Water Conservation District—as defendants.

Two of the 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 their pipeline, causing damage to these plaintiffs. The Chabot and USAA plaintiffs allege property damage, while MCI and Matamoros Welding allege damage to their business as a result of the Kinder Morgan defendants’ alleged failures, as well as indemnity and other common law and statutory tort theories of recovery.

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. The parties are currently engaged in discovery and court ordered mediation.

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 u ntil 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.

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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 which 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. 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. Kinder M organ 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. The released product did not ignite and there were no deaths or injuries. Plantation estimates the amount of product released to be approximately 553 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. Repairs to the pipeline were completed on April 19, 2006 with the approval of the United States Department of Transportation, Pipeline and Hazardous Materi als 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 while the cause is investigated and a remediation plan is proposed and approved by PHMSA. The cause of the release is related to an original pipe manufacturing seam defect.

Dublin, California

In June 2006, near Dublin, California, the SFPP pipeline, which transports refined petroleum products to San Jose, California, experienced a failure resulting in a release of product that affected a limited area along a recreation path known as the Iron Horse Trail. Product impacts were primarily limited to backfill of utilities crossing the pipeline. The release was located on land administered by Alameda County, California. Remediation and monitoring activities are ongoing under the supervision of The State of California Department of Fish & Game. The cause of the release was outside force damage. We are currently investigating potential recovery against third parties.

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Soda Springs, California

In August 2006, the SFPP pipeline, which transports refined petroleum products to Reno, Nevada, experienced a failure near Soda Springs, California, resulting in a release of product that affected a limited area along Interstate 80. Product impacts were primarily limited to soil in an area between the pipeline and Interstate 80.  The release was located on land administered by Nevada County, California.  Remediation and monitoring activities are ongoing under the supervision of The State of California Department of Fish & Game and Nevada County. 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 Pipeline and Hazardous Materials Safety Administration (PHMSA) 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. PHMSA sought to have Kinder Morgan Energy Partners implement a number of changes to its integrity management program and also sought to impose a proposed civil penalty of approximately $0.3 million. An administrative hearing was held on April 11 and 12, 2005, and a final order was issued on June 26, 2006. Kinder Morgan Energy Partners has already addressed most of the concerns identified by PHMSA and continues to work with them to ensure that its integrity management program satisfies all applicable regulations. However, Kinder Morgan Energy Partners is seeking clarification for portions of this order and has received an extension of time to allow for discussions. Along with the extension, Kinder Morgan Energy Partners reserved its right to seek reconsideration if needed. We have established a reserve for the $0.3 million proposed civil penalty, and this matter is not expected to have a material impact 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 ac tivities to remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is still remediating the site and has not been removed as a responsible party from the state’s cleanup order; however, ExxonMobil claims that the remediation continues because of GATX Terminals’ storage of a fuel additive, MTBE, at the terminal during GATX Terminals’ ownership of the terminal. When GATX Terminals sold the terminal to ST Services, the parties indemnified one another for certain environmental matters. When GATX Terminals was sold to Kinder Morgan Energy Partners, GATX Terminals’ indemnification obligations, if any, to ST Services may have passed to Kinder Morgan Energy Partners. Consequently, at issue is any indemnification obligation Kinder Morgan Energy Partners may owe to ST Services for environmental remediation of MTBE at the terminal. The complaint seeks any and all damages related to remediating MTBE at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit for remediating MTBE at the terminal. The parties have completed limited discovery. In October 2004, the judge assigned to the case 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.

The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC; Continental Oil Company; Chevron Corporation, California Superior Court, County of Los Angeles, Case No. NC041463.

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Kinder Morgan Energy Partners and some of its subsidiaries are defendants in a lawsuit filed in 2005 captioned The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC; Continental Oil Company; Chevron Corporation, California Superior Court, County of Los Angeles, Case No. NC041463. This suit involves claims for environmental cleanup costs and rent at the former Los Angeles Marine Terminal in the Port of Los Angeles. Plaintiff alleges that terminal cleanup costs could approach $18 million; however, we believe that the cleanup costs should be substantially less, and that cleanup costs must be apportioned among all the parties to the litigation. Plaintiff also alleges that it is owed approximately $2.8 million in past rent and an unspecified amount for future rent; however, we believe that previously paid rents will offset some of the Plaintiff’s rent claim and that we have certain defenses to the payment of rent allegedly owed. The lawsuit is set for trial in October 2007. We will vigorously defend these matters and believe that the outcome will not have a material adverse effect on us.

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 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 law s, 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 September 30, 2006, we have accrued an environmental reserve of $82.0 million.

Assessment of Additional Sales Tax

Terasen Gas received a Notice of Assessment dated July 31, 2006 from the British Columbia Social Service Tax authority for C$37.1 million of additional provincial sales tax and interest on the Southern Crossing Pipeline, which was completed in 2000. We are appealing this assessment and we believe this assessment is without merit and will not have a material adverse impact on our business, financial position, results of operations or cash flows.

Retroactive Quebec Tax Amendments

In June 2006, two Terasen entities received notices of reassessment from Revenue Quebec for a total of C$10.9 million for the 2004 taxation year. These reassessments were made pursuant to new, retroactive legislation passed in Quebec in June

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2006 for the express purpose of challenging certain inter-provincial Canadian tax structures. In October, we received assessments totaling C$8.4 million for the 2005 tax year. Terasen has filed Notices of Objection for the 2004 reassessments, and intends to file Notices of Objection for the 2005 assessments to preserve its legal rights to challenge any assessments/reassessments arising from this retroactive legislation and to vigorously defend against all such assessments/reassessments. The reassessment plus any accrued interest to November 30, 2005 has been accounted for as a purchase price adjustment for the Terasen acquisition and any interest subsequent to the date of the acquisition has been included in interest expense in the accompanying Consolidated Statements of Operations for the periods ended September 30, 2006.

Litigation Relating to Proposed Kinder Morgan, Inc. “Going Private” Transaction

On May 28, 2006, Richard D. Kinder, our Chairman and Chief Executive Officer, together with other members of Kinder Morgan, Inc.’s management, co-founder Bill Morgan, current board members Fayez Sarofim and Mike Morgan, and investment partners Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group and Riverstone Holdings LLC, submitted a proposal to our Board of Directors to acquire all of our outstanding common stock at a price of $100 per share in cash. On August 28, 2006, Kinder Morgan, Inc. entered into a definitive merger agreement with Knight Holdco LLC and Knight Acquisition Co. to effectuate the transaction at a price of $107.50 per share in cash.

Beginning on May 29, 2006, and in the days following, eight putative Class Action lawsuits were filed in Harris County (Houston), Texas and seven putative Class Action lawsuits were filed in Shawnee County (Topeka), Kansas against, among others, Kinder Morgan, Inc., its Board of Directors, and several corporate officers.

These cases are as follows:

Harris County, Texas

Cause No. 2006-33011; Mary Crescente v. Kinder Morgan, Inc., Richard D. Kinder, Edward H. Austin, Charles W. Battey, Stewart A. Bliss, Ted A. Gardner, William J. Hybl, Michael C. Morgan, Edward Randall III, Fayez S. Sarofim, H.A. True III, Douglas W.G. Whitehead, and James M. Stanford; in the 164th Judicial District Court, Harris County, Texas

Cause No. 2006-39364; CWA/ITU Negotiated Pension Plan, individually and on behalf of others similarly situated v. Kinder Morgan, Inc., Richard D. Kinder, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battery, H.A. True, III, Fayez Sarofim, James M. Stanford, Michael C. Morgan, Stewart A. Bliss, Edward Randall, III, and Douglas W.G. Whitehead; in the 129^th Judicial District Court, Harris County, Texas

Cause No. 2006-33015; Robert Kemp, on behalf of himself and all other similarly situated v. Richard D. Kinder, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True, III, Fayez Sarofim, James Stanford, Michael C. Morgan, Stewart A. Bliss, Edward Randall III, Douglas W. G. Whitehead, Kinder Morgan, Inc., GS Capital Partners V Fund, L.P., AIG Global Asset Management Holdings Corp., Carlyle Partners IV, L.P., and Carlyle/Riverstone Energy Partners III, L.P.; in the 113^th Judicial District Court, Harris County, Texas

Cause No. 2006-34594; Dean Drulias v. Kinder Morgan, Inc., Richard D. Kinder, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True III, Fayez S. Sarofim, James Stanford, Michael C. Morgan, Stewart A. Bliss, Edward Randall III, Douglas W.G. Whitehead, Goldman Sachs, American International Group, Inc., the Carlyle Group, and Riverstone Holdings, LLC; in the 333^rd Judicial District Court, Harris County, Texas

Cause No. 2006-40027; J. Robert Wilson, On Behalf of Himself and All Others Similarly Situated v. Kinder Morgan, Inc., Richard D. Kinder, Michael C. Morgan, Fayez Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True, III, James M. Stanford, Stewart A. Bliss, Edward Randall, III, Douglas W.G. Whitehead, Bill Morgan, Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group, Riverstone Holdings, L.L.C., C. Park Shaper, Steven J. Kean, Scott E. Parker, and Tim Bradley; in the 270^th Judicial District Court, Harris County, Texas

Cause No. 2006-33042; Sandra Donnelly, On Behalf of Herself and All Others Similarly Situated v. Kinder Morgan, Inc., Richard D. Kinder, Michael C. Morgan, Fayez S. Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True III, James M. Stanford, Stewart A. Bliss, Edward Randall III, and Douglas W.G. Whitehead; in the 61st Judicial District Court, Harris County, Texas

Cause No. 2006-34520; David Zeitz, On Behalf of Himself and All Others Similarly Situated v. Richard D. Kinder; in the 234^th Judicial District Court, Harris County, Texas

Cause No. 2006-36184; Robert L. Dunn, Trustee for the Dunn Marital Trust, and the Police & Fire Retirement System of the City of Detroit v. Richard D. Kinder, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True,

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III, Fayez Sarofim, James M. Stanford, Michael C. Morgan, Stewart A. Bliss, Edward Randall III, and Douglas W.G. Whitehead; in the 127^th Judicial District Court, Harris County, Texas

By order of the Court dated June 26, 2006, each of the above-listed cases have been consolidated into the Crescente v. Kinder Morgan, Inc. et al case; in the 164th Judicial District Court, Harris County, Texas, which challenges the proposed transaction as inadequate and unfair to Kinder Morgan’s public stockholders. Seven of the eight original petitions consolidated into this lawsuit raised virtually identical allegations. One of the eight original petitions (Zeitz) challenges the proposal as unfair to holders of the common units of Kinder Morgan Energy Partners and/or listed shares of Kinder Morgan Management. On September 8, 2006, interim class counsel filed their Consolidated Petition for Breach of Fiduciary Duty and Aiding and Abetting in which they alleged that Kinder Morgan’s board of directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They seek, among other things, to enjoin the merger, rescission of the merger agreement, disg orgement of any improper profits received by the defendants, and attorneys’ fees.

Shawnee County, Kansas Cases

Cause No. 06C 801; Michael Morter v. Richard D. Kinder, Edward H. Austin, Jr., Charles W. Battey, Stewart A. Bliss, Ted A. Gardner, William J. Hybl, Michael C. Morgan, Edward Randall, III, Fayez S. Sarofim, H.A. True, III, and Kinder Morgan, Inc.; in the District Court of Shawnee County, Kansas, Division 12

Cause No. 06C 841; Teamsters Joint Counsel No. 53 Pension Fund v. Richard D. Kinder, Edward H. Austin, Charles W. Battey, Stewart A. Bliss, Ted A. Gardner, William J. Hybl, Michael C. Morgan, Edward Randall, III, Fayez S. Sarofim, H.A. True, III, and Kinder Morgan, Inc.; in the District Court of Shawnee County, Kansas, Division 12

Cause No. 06C 813; Ronald Hodge, Individually And On Behalf Of All Others Similarly Situated v. Kinder Morgan, Inc., Richard D. Kinder, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battery, H.A. True III, Fayez S. Sarofim, James M. Stanford, Michael C. Morgan, Stewart A. Bliss, Edward Randall, III, and Douglas W.G. Whitehead; in the District Court of Shawnee County, Kansas, Division 6

Cause No. 06C-864; Robert Cohen, Individually And On Behalf Of All Others Similarly Situated v. Kinder Morgan, Inc., Richard D. Kinder, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battery, H.A. True, III, Fayez Sarofim, James M. Stanford, Michael C. Morgan, Stewart A. Bliss, Edward Randall, III, and Douglas W.G. Whitehead; in the District Court of Shawnee County, Kansas, Division 6

Cause No. 06C-853; Robert P. Land, individually, and on behalf of all others similarly situated v. Edward H. Austin, Jr., Charles W. Battey, Stewart A. Bliss, Ted A. Gardner, William J. Hybl, Edward Randall, III, James M. Stanford, Fayez Sarofim, H.A. True, III, Douglas W.G. Whitehead, Richard D. Kinder, Michael C. Morgan, AIG Global Asset Management Holdings Corp., GS Capital Partners V Fund, LP, The Carlyle Group LP, Riverstone Holdings LLC, Bill Morgan and Kinder Morgan, Inc.; in the District Court of Shawnee County, Kansas, Division 6

Cause No. 06C-854; Dr. Douglas Geiger, individually, and on behalf of all others similarly situated v. Edward H. Austin, Jr., Charles W. Battey, Stewart A. Bliss, Ted A. Gardner, William J. Hybl, Edward Randall, III, James M. Stanford, Fayez Sarofim, H.A. True, III, Douglas W.G. Whitehead, Richard D. Kinder, Michael C. Morgan, AIG Global Asset Management Holding Corp., GS Capital Partners V Fund, LP, The Carlyle Group LP, Riverstone Holdings LLC, Bill Morgan and Kinder Morgan, Inc.; in the District Court of Shawnee County, Kansas, Division 6

Cause No. 06C-837; John Bolton, On Behalf of Himself and All Others Similarly Situated v. Kinder Morgan, Inc., Richard D. Kinder, Michael C. Morgan, Fayez Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True, III, James M. Stanford, Stewart A. Bliss, Edward Randall, III, Douglas W.G. Whitehead, William V. Morgan, Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group, Riverstone Holdings LLC, C. Park Shaper, Steven J. Kean, Scott E. Parker and Tim Bradley; in the District Court of Shawnee County, Kansas, Division 6

By order of the Court dated June 26, 2006, each of the above-listed Kansas cases have been consolidated into the Consol. Case No. 06 C 801; In Re Kinder Morgan, Inc. Shareholder Litigation; in the District Court of Shawnee County, Kansas, Division 12. On August 1, 2006, the Court selected lead plaintiffs’ counsel in the Kansas State Court proceedings. On August 28, 2006, the plaintiffs filed their Consolidated and Amended Class Action Petition in which they alleged that Kinder Morgan’s board of directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They seek, among other things, to enjoin the stockholder vote on the merger agreement and any action taken to effect the acquisition of Kinder Morgan and its assets by the buyout group, damages, disgorgement of any improper profits received by the defendants, and attorney’s fees.

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On October 12, 2006, the District Court of Shawnee County, Kansas entered a Memorandum Decision and Order in which it ordered the parties in both the Crescente v. Kinder Morgan, Inc. et al case pending in Harris County Texas and the In Re Kinder Morgan, Inc. Shareholder Litigation case pending in Shawnee County Kansas to confer and to submit to the court recommendations for the “appointment of a Special Master or a Panel of Special Masters to control all of the pretrial proceedings in both the Kansas and Texas Class Actions arising out of the proposed private offer to purchase the stock of the public shareholders of Kinder Morgan, Inc.”  The parties are currently conferring and anticipate the appointment of a Special Master or panel of Special Masters in accordance with such order.  In addition, the parties are engaging in discovery.

In addition to the above-described consolidated putative Class Action cases, Kinder Morgan, Inc. is aware of two additional lawsuits that challenge either the proposal or the merger agreement.

On July 25, 2006 a civil action entitled David Dicrease, individually and on behalf of all others similarly situated v. Joseph Listengart, Edward H. Austin, Jr., Charles W. Battey, Stewart A. Bliss, Ted A. Gardner, William J. Hybl, Michael C. Morgan, Edward Randall, III, Fayez Sarofim, James M. Stanford, H.A. True, III, Douglas W.G. Whitehead, Richard D. Kinder, Kinder Morgan, Inc., Kinder Morgan Fiduciary Committee, John Does 1-30; Case 4:06-cv-02447, was filed in the United States District Court for the Southern District of Texas. This suit purports to be brought on behalf of the Kinder Morgan, Inc. Savings Plan (the “Plan”) and a class comprised of all participants and beneficiaries of the Plan, for alleged breaches of fiduciary duties allegedly owed to the Plan and its participants by the defendants, in violation of the Employee Retirement Income Security Act (“ERISA”). More specifically, the suit asserts that defendants failed to prudently manage the Plan’s assets (Count I); failed to appropriately monitor the F iduciary Committee and provide it with accurate information (Count II); failed to provide complete and accurate information to the Plan’s participants and beneficiaries (Count III); failed to avoid conflicts of interest (Count IV) and violated ERISA by engaging in a prohibited transaction (Count V). The relief requested seeks to enjoin the proposed transaction, damages allegedly incurred by the Plan and the participants, recovery of any “unjust enrichment” obtained by the defendants, and attorneys’ fees and costs.

On August 24, 2006, a civil action entitled City of Inkster Policeman and Fireman Retirement System, Derivatively on Behalf of Kinder Morgan, Inc., Plaintiffs v. Richard D. Kinder, Michael C. Morgan, William v. Morgan, Fayez Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True, III, James M. Stanford, Stewart A. Bliss, Edward Randall, III, Douglas W.G. Whitehead, Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group, Riverstone Holdings LLC, C. Park Shaper, Steven J. Kean, Scott E. Parker and R. Tim Bradley, Defendants and Kinder Morgan, Inc., Nominal Defendant; Case 2006-52653, was filed in the 270^th Judicial District Court, Harris County, Texas.  This putative derivative lawsuit was brought against certain of Kinder Morgan’s senior officers and directors, alleging that the proposal constituted a breach of fiduciary duties owed to Kinder Morgan, Inc. Plaintiff also contends that the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty. Plaintiff seeks, among other things, to enjoin the defendants from consummating the proposal, a declaration that the proposal is unlawful and unenforceable, the imposition of a constructive trust upon any benefits improperly received by the defendants, and attorney’s fees.

Defendants believe that the claims asserted in the lawsuits are legally and factually without merit and intend to vigorously defend against them.

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.

16.

Recent Accounting Pronouncements

On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This Statement defines fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles and, as a result, there is now a common definition of fair value to be used throughout generally accepted accounting principles.

This Statement applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements; however, for some entities the application of this Statement will change current practice. The changes to current practice resulting from the application of this Statement relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 (January 1, 2008 for us), and interim periods within those fiscal years. This Statement is to be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, with certain exceptions. The disclosure requirements of this

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Statement are to be applied in the first interim period of the fiscal year in which this Statement is initially applied. We are currently reviewing the effects of this Statement.

On September 29, 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R). This Statement requires an employer to:

·

recognize the overfunded or underfunded status of a defined benefit pension plan or postretirement benefit plan (other than a multiemployer plan) as an asset or liability in its statement of financial position;

·

measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and to disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations; and

·

recognize changes in the funded status of a plan in the year in which the changes occur through comprehensive income.

Past accounting standards only required an employer to disclose the complete funded status of its plans in the notes to the financial statements. Recognizing the funded status of a company’s benefit plans as a net liability or asset on its balance sheet will require an offsetting adjustment to “Accumulated other comprehensive income/loss” in shareholders’ equity. SFAS No. 158 does not change how pensions and other postretirement benefits are accounted for and reported in the income statement—companies will continue to follow the existing guidance in previous accounting standards. Accordingly, the amounts to be recognized in “Accumulated other comprehensive income/loss” representing unrecognized gains/losses, prior service costs/credits, and transition assets/obligations will continue to be amortized under the existing guidance. Those amortized amounts will continue to be reported as net periodic benefit cost in the income statement. Prior to SFAS No. 158, those unrecognized amounts were only disclosed in the notes to the financial statements.

According to the provisions of this Statement, an employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit pension plan or postretirement benefit plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006 (December 31, 2006 for us). In the year that the recognition provisions of this Statement are initially applied, an employer is required to disclose, in the notes to the annual financial statements, the incremental effect of applying this Statement on individual line items in the year-end statement of financial position. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008 (December 31, 2008 for us). In the year that the measurement date provisions of this Statement are initial ly applied, a business entity is required to disclose the separate adjustments of retained earnings and “Accumulated other comprehensive income/loss” from applying this Statement. While earlier application of the recognition of measurement date provisions is allowed, we have opted not to adopt this part of the Statement early.

We will apply the guidance of SFAS No. 158 prospectively; retrospective application of this Statement is not permitted. We are currently reviewing the effects of this Statement, but we do not expect the adoption of this Statement to have a material effect on our statement of financial position as of December 31, 2006.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin (“SAB”) No. 108. This Bulletin requires a “dual approach” for quantifications of errors using both a method that focuses on the income statement impact, including the cumulative effect of prior years’ misstatements, and a method that focuses on the period-end balance sheet. SAB No. 108 will be effective for us as of January 1, 2007. The adoption of this Bulletin is not expected to have a material impact on our consolidated financial statements.

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This Interpretation is effective for fiscal years beginning after December 15, 2006 (January 1, 2007 for us). We are currently reviewing the effects of this Interpretation.

In June 2006, the FASB ratified the consensuses reached by the Emerging Issues Task Force on EITF 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation). According to the provisions of EITF 06-3:

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·

taxes assessed by a governmental authority that are directly imposed on a revenue-producing transaction between a seller and a customer may include, but are not limited to, sales, use, value added, and some excise taxes; and

·

that the presentation of such taxes on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed pursuant to Accounting Principles Board Opinion No. 22 (as amended), Disclosure of Accounting Policies. In addition, for any such taxes that are reported on a gross basis, a company should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The disclosure of those taxes can be done on an aggregate basis.

EITF 06-3 should be applied to financial reports for interim and annual reporting periods beginning after December 15, 2006 (January 1, 2007 for us). Because the provisions of EITF 06-3 require only the presentation of additional disclosures, we do not expect the adoption of EITF 06-3 to have an effect on our consolidated financial statements.

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KMI Form 10-Q

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 are 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. In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S. retail natural gas distribution and related operations for $710 million plus working capital. In prior periods, we referred to these operations as the Kinder Morgan Retail business segment. In accordance with Statement of Financial Accounting Standards (“SFAS”) N o. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented. Refer to the heading “Discontinued Operations” included elsewhere in management’s discussion and analysis for additional information regarding discontinued operations.

To convert September 30, 2006 balances denominated in Canadian dollars to U.S. dollars, we used the September 30, 2006 Bank of Canada closing exchange rate of 0.8947 U.S. dollars per Canadian dollar.

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 and (iii) Kinder Morgan Energy Partners’ Annual Report on Form 10-K for the year ended December 31, 2005 and Quarterly Report on Form 10-Q for the quarter ended September 30, 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 September 30, 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 oth er 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 ch anges in these policies and estimates during the first nine months of 2006.

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Consolidated Financial Results

	Three Months Ended September 30,						Earnings Increase
	20061, 2			2005			(Decrease)
	(In millions except per share amounts)
Equity in Earnings of Kinder Morgan Energy Partners2, 3	$	-		$	169.2		$	(169.2	)
Segment Earnings:4
NGPL5		120.1			88.6			31.5
Terasen Gas		40.1			-			40.1
Kinder Morgan Canada		30.0			-			30.0
Power		6.9			4.6			2.3
Products Pipelines – KMP		95.3			-			95.3
Natural Gas Pipelines – KMP		124.7			-			124.7
CO2 – KMP		75.8			-			75.8
Terminals – KMP		79.1			-			79.1
Total Segment Earnings		572.0			262.4			309.6
Interest and Corporate Expenses, Net6, 7		(372.9	)		(72.4	)		(300.5	)
Income From Continuing Operations Before Income Taxes4		199.1			190.0			9.1
Income Taxes4, 8		(56.0	)		(77.2	)		21.2
Income From Continuing Operations		143.1			112.8			30.3
Income (Loss) From Discontinued Operations, Net of Tax		1.1			(3.7	)		4.8
Net Income	$	144.2		$	109.1		$	35.1
Diluted Earnings (Loss) Per Common Share:
Income From Continuing Operations	$	1.06		$	0.91		$	0.15
Income (Loss) From Discontinued Operations		0.01			(0.03	)		0.04
Total Diluted Earnings Per Common Share	$	1.07		$	0.88		$	0.19
Number of Shares Used in Computing Diluted Earnings Per Common Share		135.1			123.7			11.4

__________________

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, effective January 1, 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 September 30, 2005 includes a reduction in pre-tax earnings of approximately $1.8 million ($1.1 million after tax) resulting from the effects of certain items of Kinder Morgan Energy Partners on our earnings.

⁴

Segment earnings includes operating income before corporate costs plus earnings from equity method investments plus gains and losses on incidental sales of assets. In 2006, for our business segments that are also segments of Kinder Morgan Energy Partners, also includes interest income, other, net and an aggregate of $4.0 million of income taxes allocated to the segments.

⁵

Results for the three months ended September 30, 2005 include a pre-tax loss of $24.6 million ($15.6 million after tax) for hedge ineffectiveness.

⁶

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

⁷

Results for the three months ended September 30, 2005 include a decrease in after-tax minority interest expense in Kinder Morgan Management of $0.6 million.

⁸

Results for the three months ended September 30, 2006 include a reduction in the income tax provision of $5.8 million resulting from the adjustment of deferred tax liability amounts.

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KMI Form 10-Q

	Nine Months Ended September 30,						Earnings Increase
	20061, 2			2005			(Decrease)
	(In millions except per share amounts)
Equity in Earnings of Kinder Morgan Energy Partners2, 3	$	-		$	480.4		$	(480.4	)
Segment Earnings:4
NGPL5		367.0			302.2			64.8
Terasen Gas		212.7			-			212.7
Kinder Morgan Canada		83.0			-			83.0
Power		17.0			13.4			3.6
Products Pipelines – KMP		298.0			-			298.0
Natural Gas Pipelines – KMP		387.0			-			387.0
CO2 – KMP		239.3			-			239.3
Terminals – KMP		234.7			-			234.7
Total Segment Earnings		1,838.7			796.0			1,042.7
Interest and Corporate Expenses, Net6, 7, 8		(1,160.0	)		(183.7	)		(976.3	)
Income From Continuing Operations Before Income Taxes4		678.7			612.3			66.4
Income Taxes4, 9		(191.6	)		(249.3	)		57.7
Income From Continuing Operations10		487.1			363.0			124.1
Income From Discontinued Operations, Net of Tax		8.0			11.4			(3.4	)
Net Income	$	495.1		$	374.4		$	120.7
Diluted Earnings Per Common Share:
Income From Continuing Operations	$	3.61		$	2.94		$	0.67
Income From Discontinued Operations		0.06			0.09			(0.03	)
Total Diluted Earnings Per Common Share	$	3.67		$	3.03		$	0.64
Number of Shares Used in Computing Diluted Earnings Per Common Share		135.0			123.8			11.2

__________________

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, effective January 1, 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 nine months ended September 30, 2005 includes a reduction in pre-tax earnings of approximately $13.2 million ($8.4 million after tax) resulting principally 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. In 2006, for our business segments that are also segments of Kinder Morgan Energy Partners, also includes interest income, other, net and an aggregate of $11.8 million of income taxes allocated to the segments.

⁵

Results for the nine months ended September 30, 2005 include a pre-tax loss of $24.6 million ($15.6 million after tax) incurred during the third quarter for hedge ineffectiveness.

⁶

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

⁷

Results for the nine months ended September 30, 2005 include (i) a pre-tax gain of $22.0 million ($8.1 million after tax) from the sale of Kinder Morgan Management shares that we owned and (ii) a decrease in after-tax minority interest expense in Kinder Morgan Management of $0.9 million.

⁸

Results for the nine months ended September 30, 2006 include (i) a reduction in pre-tax income of $22.3 million ($14.1 million after tax) resulting from non-cash charges to mark to market certain interest rate swaps and (ii) miscellaneous other items totaling a net decrease of $0.7 million in pre-tax income ($0.4 million after tax).

⁹

Results for the nine months ended September 30, 2006 include a reduction in the income tax provision of $24.7 million resulting from the adjustment of deferred tax liability amounts.

¹⁰

Our income from continuing operations for the nine months ended September 30, 2006 includes the effects of certain items

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KMI Form 10-Q

of Kinder Morgan Energy Partners on our income totaling a net increase in pre-tax earnings of $1.1 million ($0.4 million after tax).

Our income from continuing operations increased from $112.8 million in the third quarter of 2005 to $143.1 million in the third quarter of 2006, an increase of $30.3 million (27%). Our net income increased from $109.1 million in the third quarter of 2005 to $144.2 million in the third quarter of 2006, an increase of $35.1 million (32%). The items discussed in footnotes 3, 4, 5, 7 and 8 of the table above for the three months ended September 30, 2006 and 2005, had the effect of increasing earnings by $21.9 million. The remaining $8.4 million increase in our income from continuing operations for the third quarter of 2006, relative to 2005, principally resulted from (i) increased earnings from Kinder Morgan Energy Partners, net of associated minority interests and (ii) increased earnings from our Natural Gas Pipeline Company of America (“NGPL”) and Power business segments. These positive impacts were partially offset by increased interest expense, including interest associated with financing the Terasen acquisition. 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.

Our income from continuing operations increased from $363.0 million in the first nine months of 2005 to $487.1 million in the first nine months of 2006, an increase of $124.1 million (34%). Our net income increased from $374.4 million in the first nine months of 2005 to $495.1 million in the first nine months of 2006, an increase of $120.7 million (32%). The items discussed in footnotes 3, 4, 5, 7, 8, 9 and 10 of the table above for the nine months ended September 30, 2006 and 2005, had the effect of increasing earnings by $25.6 million. The remaining $98.5 million increase in our income from continuing operations for the first nine months 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 NGPL and Power business segments. These positive impacts were partiall y offset by increased interest costs due, in part, to the effect of higher interest rates on our floating-rate debt.

Diluted earnings per common share from continuing operations increased from $0.91 in the third quarter of 2005 to $1.06 in the third quarter of 2006, an increase of $0.15 (16%). This increase reflected, in addition to the financial and operating impacts discussed preceding, an increase of 11.4 million (9%) 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 $0.88 in the third quarter of 2005 to $1.07 in the third quarter of 2006, an increase of $0.19 (22%).

Diluted earnings per common share from continuing operations increased from $2.94 in the first nine months of 2005 to $3.61 in the first nine months of 2006, an increase of $0.67 (23%). This increase reflected, in addition to the financial and operating impacts discussed preceding, an increase of 11.2 million (9%) in average shares outstanding. The increase in average shares outstanding for the first nine months of 2006, relative to 2005, resulted principally from the same factors affecting the third quarter, as discussed above. Total diluted earnings per common share increased from $3.03 in the first nine months of 2005 to $3.67 in the first nine months of 2006, an increase of $0.64 (21%).

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.

In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S. retail natural gas distribution and related operations for $710 million plus working capital. In prior periods, we referred to these operations as the Kinder Morgan Retail business segment. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented. Refer to the heading “Discontinued Operations” included elsewhere in management’s discussion and analysis for additional information regarding discontinued operations.

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

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

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KMI Form 10-Q

Energy Partners’ Form 10-Q for the third 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.

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
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 Form 10-K, except that (i) certain items below the “Operating Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners, are included. These equity method earnings are included in “Other Income and (Expenses)” in the accompanying interim Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not considered by management in its evaluation of business segment performance and (ii) gains and l osses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment

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KMI Form 10-Q

performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

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 September 30,
	2006		2005			Increase
	(In millions except system throughput)
Total Operating Revenues	$	290.4	$	222.8		$	67.6
Gas Purchases and Other Costs of Sales	$	103.7	$	80.9		$	22.8
Segment Earnings	$	120.1	$	88.6	1	$	31.5
System Throughput (Trillion Btus)		403.8		379.6			24.2

	Nine Months Ended September 30,
	2006		2005			Increase
	(In millions except system throughput)
Total Operating Revenues	$	799.9	$	645.6		$	154.3
Gas Purchases and Other Costs of Sales	$	242.7	$	184.1		$	58.6
Segment Earnings	$	367.0	$	302.2	2	$	64.8
System Throughput (Trillion Btus)		1,239.7		1,202.1			37.6
1 Includes a pre-tax loss of $24.6 million for hedge ineffectiveness. 2 Includes a pre-tax loss of $26.4 million for hedge ineffectiveness.

NGPL’s segment earnings for the third quarter and first nine months of 2005 include pre-tax losses of $24.6 million and $26.4 million, respectively, due to hedge ineffectiveness, which was recorded as a reduction to operating revenues. The third quarter 2005 loss was largely the result of significant changes in the values of various natural gas price indices relative to the value of the Henry Hub index used by the NYMEX in the valuation of derivative instruments, caused by hurricane-related supply disruptions in the Gulf of Mexico area. The remaining $6.9 million increase in NGPL’s segment earnings in the third quarter of 2006, relative to 2005 resulted from (i) increased transportation and storage margins in 2006 due principally to successful re-contracting of transportation and storage services, favorable basis differentials and recent storage system expansions and (ii) increased operational gas sales prices. These positive impacts w ere partially offset by (i) $12.0 million of expense for a stress corrosion cracking rehabilitation project (as discussed below) and pipeline integrity management programs, (ii) an increase of $0.8 million in electric compression costs and (iii) a $1.1 million increase in depreciation and amortization expense. NGPL’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs. Total system throughput volumes increased by 24.2 trillion Btus in the third quarter of 2006, relative to 2005 due, in part, to shippers moving significant volumes of natural gas within Texas on NGPL’s Gulf Coast Pipeline. The increase in system throughput in the third 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 “firm” contracts in which shippers pay a “demand” fee to reserve a set amount of system capacity for their use.

NGPL’s segment earnings increased from $302.2 million in the first nine months of 2005 to $367.0 million in the first nine months of 2006, an increase of $64.8 million (21%). Segment earnings for the first nine months of 2006 were positively impacted, relative to 2005, principally by the same factors positively affecting third quarter results, as discussed above. These positive impacts were partially offset by (i) $22.5 million of expense for a stress corrosion cracking rehabilitation project and

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KMI Form 10-Q

pipeline integrity management programs, (ii) an increase of $3.3 million in electric compression costs and (iii) a $4.4 million increase in depreciation and amortization expense.

On October 10, 2006, in FERC Docket No. CP 07-3, NGPL filed seeking approval to expand its Louisiana Line by 200,000 dekatherms per day (Dth/day). This $66 million project is supported by five-year agreements that fully subscribe the additional capacity.

In a letter filed on December 8, 2005, NGPL requested that the Office of the Chief Accountant of the Federal Energy Regulatory Commission (“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. On June 5, 2006, in Docket No. AC 06-18, the FERC ruled on NGPL’s request to capitalize pipeline rehabilitation costs. The ruling states that NGPL must expense rather than capitalize the majority of the costs. NGPL can continue to capitalize the costs of pipe replacement and coating but costs to assess the integrity of pipe must be expensed.

During the second quarter of 2006, NGPL commenced operation of the following projects: the $21 million Amarillo cross-haul line expansion, which adds 51,000 Dth/day of capacity and is fully subscribed under long-term contracts; the $38 million Sayre storage field expansion in Oklahoma that added 10 billion cubic feet (Bcf) of capacity, which is contracted for under long-term agreements; and a $4 million, 2 Bcf expansion of no-notice delivered storage service.

In the first quarter of 2006, NGPL received certificate approval from the 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. Please refer to our 2005 Form 10-K for additional information regarding NGPL.

Terasen Gas

	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
	(In millions, except system throughput)
Operating Revenues		$	192.8		$	1,057.1
Gas Purchases and Other Costs of Sales		$	96.7		$	671.5
Segment Earnings		$	40.1		$	212.7
System Throughput (Trillion Btus)			31.1			137.0

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”).

In June 2006, the BCUC approved an application from Terasen Gas to build a 50-kilometer natural gas pipeline from Squamish to Whistler. The estimated C$37 million project, which is subject to securing acceptable construction arrangements, will replace an aging propane system and will bring natural gas to Whistler prior to the 2010 Winter Olympics. Terasen Gas hopes to begin construction on the project this year with full service available to Whistler by November 2008.

Terasen Gas Inc.’s allowed return on equity (“ROE”) is determined annually based on a formula that applies a risk premium to a forecast of long-term Government of Canada bond yields. For 2005, the application of the ROE formula set Terasen Gas Inc.’s allowed ROE at 9.03%, down from 9.15% in 2004. On March 2, 2006, a decision was issued by the BCUC, with an effective date of January 1, 2006, 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.

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KMI Form 10-Q

Kinder Morgan Canada

	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
	(In millions, except system throughput)
Operating Revenues		$	53.9		$	148.6
Segment Earnings		$	30.0		$	83.0
System Throughput (MMBbl)			44.7			125.9

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”). In September 2006, Kinder Morgan Canada completed the negotiation with CAPP of the final ITS agreement and on October 18, 2006, the CAPP Board of Governors approved the agreement. The agreement was filed for approval with the NEB on October 19, 2006 and a decision is expected in December 2006. The 2006-2010 ITS determines the tolls to be charged on the Trans Mountain system over the five-year term of the agreement, to take effect as of January 1, 2006. The agreement also governs the financial arrangements for the Pump Station Expansion and Anchor Loop projects. In addition to tolling and expansion parameters, the formal agreement contains capacity allocation procedures for the Westridge Marine Terminal and enhanced service stan dards 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 barrels per day (“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 began in the summer of 2006 and the expansion is expected to be in service by April 2007.

Kinder Morgan Canada filed a comprehensive environmental report with the Canadian Environmental Assessment Agency on November 15, 2005, and filed a complete NEB application for the Anchor Loop Project on February 17, 2006. The C$435 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 public hearing of the application was held the week of August 8, 2006. On October 26, 2006, the NEB released its favorable decision on the application.

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 closed on July 17, 2006 without full subscription for the expanded pipeline. Discussions with shippers are ongoing and we remain confident that shippers will ultimately support the expansion. 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: (i) 252 kilometers of 36-inch diameter pipe in Alberta between Edmonton and Edson, and (ii) 243 kilometers of 30- and 36-inch diameter pipe in British Columbia betwee n Rearguard and Darfield, north of Kamloops. The proposed loops will generally follow the existing 24-inch diameter Trans Mountain pipeline. New pump stations and storage tank facilities will also be required for the TMX-2 project.

We have initiated engineering, environmental, consultation and procurement activities on the proposed Corridor pipeline expansion project, as authorized and supported by shipper resolutions and the underlying firm service agreement. The proposed C$1.6 billion expansion includes building a new 42-inch diameter diluent/bitumen (“dilbit”) pipeline, a new 20-inch diameter 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 180,000 bpd of dilbit capacity to accommodate the new bitumen production from the Muskeg River Mine. An expansion of the Corridor pipeline system has been completed in 2006 increasing the dilbit capacity to 278,000 bpd by upgrading existing pump station facilities. By 2009, the dilbit capacity of the Corridor system is expected to be approximately 460,000 bpd. An application for the Corridor pipeline expansion project was filed with the Alberta Energy Utilities Board and Alberta Environment on December 22, 2005, and approval was received in August 2006. Construction of the Corridor pipeline

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expansion is expected to begin in November 2006 as the shippers have received definitive approval of their Muskeg River Mine expansion. Please refer to our 2005 Form 10-K for additional information regarding Kinder Morgan Canada.

Power

	Three Months Ended September 30,
	2006		2005		Increase
	(In millions)
Total Operating Revenues	$	23.3	$	20.1	$	3.2
Gas Purchases and Other Costs of Sales	$	2.7	$	1.4	$	1.3
Segment Earnings	$	6.9	$	4.6	$	2.3

	Nine Months Ended September 30,
	2006		2005		Increase
	(In millions)
Total Operating Revenues	$	51.5	$	44.6	$	6.9
Gas Purchases and Other Costs of Sales	$	6.3	$	3.8	$	2.5
Segment Earnings	$	17.0	$	13.4	$	3.6

Power’s segment earnings increased from $4.6 million in the third quarter of 2005 to $6.9 million in the third quarter of 2006, an increase of $2.3 million (50%). Segment results were positively impacted in the third quarter of 2006, relative to 2005, by (i) the recognition of $1.5 million of gains from surplus equipment sales, (ii) an increase of $0.4 million in earnings from Thermo Cogeneration Partnership and (iii) a reduction in amortization expense resulting from prior period asset write-downs.

Power’s segment earnings increased from $13.4 million in the first nine months of 2005 to $17.0 million in the first nine months of 2006, an increase of $3.6 million (27%). Segment results were positively impacted in the first nine months of 2006, relative to 2005, by (i) the recognition of $1.5 million of gains from surplus equipment sales, (ii) approximately $0.9 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 and (iii) a reduction in amortization expense. These positive impacts were offset by a $0.3 million reduction in earnings from Thermo Cogeneration Partnership due, in part, to the fact that 2005 results included proceeds from the resolution of the Enron bankruptcy proceeding. Please refer to our 2005 Form 10-K for additional information regarding Power.

Products Pipelines – KMP

	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
	(In millions)
Operating Revenues		$	207.7		$	577.3
Gas Purchases and Other Costs of Sales		$	15.3		$	29.6
Segment Earnings		$	95.3		$	298.0

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 January 1, 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 62 to 67 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, which is incorporated herein by reference.

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Natural Gas Pipelines - KMP

	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
	(In millions)
Operating Revenues		$	1,650.4		$	5,082.2
Gas Purchases and Other Costs of Sales		$	1,488.6		$	4,598.4
Segment Earnings		$	124.7		$	387.0

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 January 1, 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 67 to 70 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, which is incorporated herein by reference.

CO2 – KMP

	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
	(In millions)
Operating Revenues		$	192.3		$	552.8
Gas Purchases and Other Costs of Sales		$	1.4		$	4.1
Segment Earnings		$	75.8		$	239.3

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 January 1, 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 70 to 73 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, which is incorporated herein by reference.

Terminals – KMP

	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
	(In millions)
Operating Revenues		$	223.2		$	649.8
Gas Purchases and Other Costs of Sales		$	5.9		$	17.8
Segment Earnings		$	79.1		$	234.7

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 January 1, 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 74 to 78 of Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, which is incorporated herein by reference.

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KMI Form 10-Q

Interest and Corporate Expenses, Net

	Three Months Ended September 30,						Earnings Increase
	2006			2005			(Decrease)
	(In millions)
General and Administrative Expense	$	(97.4	)	$	(14.5	)	$	(82.9	)
Interest Expense, Net		(200.0	)		(37.0	)		(163.0	)
Interest Expense – Deferrable Interest Debentures		(5.4	)		(5.4	)		-
Interest Expense – Capital Securities		(2.2	)		-			(2.2	)
Minority Interests		(78.7	)		(23.7	)		(55.0	)
Other, Net		10.8			8.2			2.6
	$	(372.9	)	$	(72.4	)	$	(300.5	)

	Nine Months Ended September 30,						Earnings Increase
	2006			2005			(Decrease)
	(In millions)
General and Administrative Expense	$	(298.5	)	$	(44.8	)	$	(253.7	)
Interest Expense, Net		(569.6	)		(106.0	)		(463.6	)
Interest Expense – Deferrable Interest Debentures		(16.4	)		(16.4	)		-
Interest Expense – Capital Securities		(6.6	)		-			(6.6	)
Minority Interests		(265.6	)		(55.0	)		(210.6	)
Loss on Mark-to-market Interest Rate Swaps		(22.3	)		-			(22.3	)
Gain on Sale of Kinder Morgan Management Shares		-			26.5			(26.5	)
Other, Net		19.0			12.0			7.0
	$	(1,160.0	)	$	(183.7	)	$	(976.3	)

“Interest and Corporate Expenses, Net” was an expense of $372.9 million in the third quarter of 2006, compared to an expense of $72.4 million in the third quarter of 2005. “Interest and Corporate Expenses, Net” was an expense of $1,160.0 million in the first nine months of 2006, compared to an expense of $183.7 million in the first nine months of 2005. The increases in net expenses for the third quarter and first nine months of 2006, relative to 2005, were 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 $82.9 million increase in general and administrative expense in the third quarter of 2006, relative to 2005, was due to (i) $59.7 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 and (ii) $27.4 million of general and administrative expense of Terasen, partially offset by a $4.2 million decrease in other general and administrative expense.

The $253.7 million increase in general and administrative expense in the first nine months of 2006, relative to 2005, was due to (i) $183.9 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) $70.3 million of general and administrative expense of Terasen and (iii) a $0.5 million decrease in other general and administrative expense.

The $165.2 million increase in total interest expense in the third quarter of 2006, relative to 2005, was due to (i) $88.4 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) $71.1 million of interest expense resulting from (1) interest on Terasen’s existing debt, including debt issued during 2006 and (2) interest on incremental debt issued during the fourth quarter of 2005 to acquire Terasen and (iii) a $5.7 million increase in other interest expense resulting from higher effective interest rates, partially offset by lower debt balances.

The $470.2 million increase in total interest expense in the first nine months of 2006, relative to 2005, was due to (i) $246.4 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) $209.2 million of interest expense resulting from (1) interest on Terasen’s existing debt, including debt issued during 2006 and (2) interest on incremental debt issued during the fourth quarter of 2005 to acquire Terasen and (iii) a $14.6 million increase in other interest expense resulting from higher effective interest rates, partially offset by lower debt balances.

The $55.0 million increase in minority interests in the third quarter of 2006, relative to 2005, was due to (i) $57.7 million of

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KMI Form 10-Q

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 decrease in minority interests of Kinder Morgan Management and (iii) a $0.2 million increase in other minority interests, principally Triton Power.

The $210.6 million increase in minority interests in the first nine months of 2006, relative to 2005, was due to (i) $209.3 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, (ii) a $0.1 million decrease in minority interests of Kinder Morgan Management and (iii) a $1.4 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, 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 and second quarters of 2005, we sold a total of 2.1 million Kinder Morgan Management shares that we owned, receiving net proceeds of $92.5 million. In conjunction with these sales, we recorded pre-tax gains of $26.5 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 three months and nine months ended September 30, 2005, when we accounted for Kinder Morgan Energy Partners under the equity method, was as follows:

	Three Months Ended September 30, 2005				Nine Months Ended September 30, 2005
	(In millions)
General Partner Interest, Including Minority Interest in the Operating Limited Partnerships		$	125.3			$	358.8
Limited Partner Units (Kinder Morgan Energy Partners)			11.3				31.7
Limited Partner i-units (Kinder Morgan Management)			32.6				89.9
			169.2				480.4
Pre-tax Minority Interest in Kinder Morgan Management			(25.0	)			(72.7	)
Pre-tax Earnings from Investment in Kinder Morgan Energy Partners		$	144.2			$	407.7

As discussed in Note 1(C) of the accompanying Notes to Consolidated Financial Statements, due to our adoption of EITF
No. 04-5, beginning January 1, 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. The net impact on pre-tax earnings of our investment in Kinder Morgan Energy Partners was $148.1 million and $444.4 million for the three months and nine months ended September 30, 2006, respectively.

Income Taxes – Continuing Operations

The income tax provision decreased from $77.2 million in the third quarter of 2005 to $60.0 million in the third quarter of 2006, a decrease of $17.2 million (22%) due principally to a reduction in the effective tax rate applied in calculating deferred tax due to a decrease in the state effective tax rate, tax benefits associated with our Terasen acquisition structure and tax benefits applicable to our Canadian operations, partially offset by taxes on corporate equity and subsidiary earnings of Kinder Morgan Energy Partners.

The income tax provision decreased from $249.3 million for the nine months ended September 30, 2005 to $203.4 million for the nine months ended September 30, 2006, a decrease of $45.9 million (18%) due principally to a reduction in the effective

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KMI Form 10-Q

tax rate applied in calculating deferred tax due to a decrease in the state effective tax rate, tax benefits associated with our Terasen acquisition structure and the fact that Kinder Morgan Management shares were sold in 2005 but not in 2006, partially offset by taxes on corporate equity and subsidiary earnings of Kinder Morgan Energy Partners.

Discontinued Operations

In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S. retail natural gas distribution and related operations for $710 million plus working capital. Pending regulatory approvals, we expect this transaction to close by the end of the first quarter of 2007. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented. For the three months ended September 30, 2006 and 2005, we recorded $1.2 million of income (net of tax benefits of $4.1 million) and $3.7 million of loss (net of tax benefits of $2.6 million), respectively, from these operations. For the nine months ended September 30, 2006 and 2005, we recorded $9.1 million of income (net of tax of $2.3 million) and $12.8 million of income (net of tax of $8.8 million), respectively, from these 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. During the second quarter of 2006, our wholly owned subsidiary, Terasen Inc., completed the sale of Terasen Water and Utility Services to a group led by CAI Capital Management Co. and including the existing management team of Terasen Water and Utility Services for approximately $118 million (C$133 million). The sale does not include CustomerWorks LP, a 30% joint venture with Enbridge Inc. No gain or loss was recognized from the sale of the water and utility segment. Incremental losses of $0.7 million (net of tax benefits of $0.4 million) were recorded in the six months ended June 30, 2006 reflecting the operating resul ts of the water and utility business segment during 2006 until its sale.

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. For the three months ended September 30, 2006, incremental losses of approximately $0.2 million (net of tax benefits of $0.1 million) were recorded to update previously recorded liabilities. For the nine months ended September 30, 2006 and 2005, incremental losses of approximately $0.4 million (net of tax benefits of $0.2 million) and approximately $1.4 million (net of tax benefits of $0.8 million), respectively, were recorded 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 long-term notes or additional shares of common stock. In addition, Kinder Morgan Energy Partners and Terasen could meet their respective cash requirements with cash from operations and through borrowings under t heir 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 six months of 2006 due to our adoption of EITF No. 04-5, which resulted in the inclusion of the accounts, balances and results of operations of Kinder Morgan Energy Partners in our consolidated financial statements beginning January 1, 2006. 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 a result of the acquisition of Terasen.

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

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KMI Form 10-Q

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.

	September 30,			December 31,
	2006			2005			2004			2003
	(Dollars in millions)
Long-term Debt:
Outstanding Notes and Debentures	$	10,923.6		$	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		111.5			107.2			-			-
Value of Interest Rate Swaps1		53.4			51.8			88.2			88.2
		11,372.1			6,729.4			2,629.8			3,209.3
Minority Interests		2,903.0			1,247.3			1,105.4			1,010.1
Common Equity, Excluding Accumulated Other Comprehensive Loss		4,210.5			4,051.4			2,919.5			2,691.8
		18,485.6			12,028.1			6,654.7			6,911.2
Value of Interest Rate Swaps		(53.4	)		(51.8	)		(88.2	)		(88.2	)
Capitalization		18,432.2			11,976.3			6,566.5			6,823.0
Short-term Debt, Less Cash and Cash Equivalents2		1,659.6			841.4			328.5			121.8
Invested Capital	$	20,091.8		$	12,817.7		$	6,895.0		$	6,944.8
Capitalization:
Outstanding Notes and Debentures		59.3%			52.5%			34.4%			41.6%
Minority Interests		15.8%			10.4%			16.8%			14.8%
Common Equity		22.8%			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		62.6%			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		37.4%			44.4%			62.5%			57.4%

¹

See “Significant Financing Transactions” following.

²

Cash and cash equivalents netted against short-term debt were $110.2 million, $116.6 million, $176.5 million and $11.1 million for September 30, 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 September 30, 2006, not including the effects of consolidating Kinder Morgan Energy Partners, was 54.4%.

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, amounts outstanding and available borrowing capacity under the facilities after applicable letters of credit.

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KMI Form 10-Q

	At September 30, 2006				At October 31, 2006
	Short-term Debt Outstanding		Available Borrowing Capacity		Short-term Debt Outstanding			Available Borrowing Capacity
	(U.S. Dollars in millions)
Kinder Morgan, Inc.
$800 million, five-year revolver, due August 20101	$	112.0	$	618.1		$	185.0		$	545.1
Kinder Morgan Energy Partners
$1.85 billion, five-year revolver, due August 2010		887.6		524.3			834.1			652.8
Terasen
C$450 million, three-year revolver, due May 2009		157.5		179.8			111.3			224.5
Terasen Gas Inc.
C$500 million, three-year revolver, due June 2009		185.2		223.1			150.5			256.0
Terasen Pipelines (Corridor) Inc.
C$225 million, 364-day revolver, due January 2007		126.2		75.2			154.9			45.4

¹

As discussed in Note 9 of the accompanying Notes to Consolidated Financial Statements, on August 28, 2006, we entered into a definitive merger agreement under which investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, will acquire all of our outstanding common stock for $107.50 per share in cash (the “Going Private” transaction). Credit rating agencies have indicated that our debt rating would be downgraded if the proposed Going Private transaction is approved by our stockholders. This factor combined with the uncertainty that the Going Private transaction or any other proposals or extraordinary transaction will be approved or completed has limited our access to the commercial paper market. As a result, we are currently utilizing our $800 million credit facility for Kinder Morgan, Inc.’s short-term borrowing needs.

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 September 30, 2006 and October 31, 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 $301.4 million at September 30, 2006 represents (i) $5.0 million of current maturities of our 6.50% Series Debentures due September 1, 2013, (ii) $248.8 million, net of discounts, of Kinder Morgan Energy Partners’ 5.35 % Senior Notes due August 18, 2007, (iii) $5.8 million of current maturities under Kinder Morgan Texas Pipeline, L.P.’s 5.23% Series Notes due January 2, 2014, (iv) $5.0 million of current maturities under Central Florida Pipe Line LLC’s 7.84% Series Notes due July 23, 2007, (v) $2.1 million of current maturities under Terasen Gas Inc.’s capital lease obligations, (vi) $17.9 million of Terasen Gas Inc.’s 9.75% Series D Notes due December 17, 2006 and (vii) $16.8 million of estimated current maturities relating to TGVI’s C$350 million credit facility which, as discussed following, has been classified as long-term in our Consolidated Balance Sheet at September 30, 2006. Current maturities of Terasen and its subsidiaries are denominated in Canadian dollars but are reported here in U.S. dollars converted at the September 30, 2006 Bank of Canada closing rate of 0.8947 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 $287.4 million at September 30, 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 September 30, 2006, we had repurchased a total of approximately $906.8 million (14,934,300 shares) of our outstanding common stock under the program. No shares of our common stock were repurchased in the three months ended September 30, 2006. In the nine months ended September 30, 2006, we repurchased $31.5 million (339,800 shares) of our common stock. We have ceased additional share repurchases in 2006 in order to fund capital projects, primarily in Canada.

On September 25, 2006, Terasen Gas Inc. issued C$120 million 5.55% medium term note debentures, due September 25, 2036. Of the $106.9 million (C$119.4 million) net proceeds from this issuance after underwriting discounts and commissions, $89.5 million (C$100 million) was used to repay short-term commercial paper debt that was primarily incurred to pay Terasen Gas Inc.’s C$100 million 6.15% medium term note debentures that matured on July 31, 2006. The remaining proceeds will be used to repay Terasen Gas Inc.’s C$20 million 9.75% notes, which will mature on December 17, 2006.

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Effective August 28, 2006, Kinder Morgan Energy Partners terminated its $250 million unsecured nine-month bank credit facility due November 21, 2006, and increased its existing five-year bank credit facility from $1.60 billion to $1.85 billion. The five-year unsecured bank credit facility remains due August 18, 2010; however, the bank facility can now be amended to allow for borrowings up to $2.1 billion.  There were no borrowings under Kinder Morgan Energy Partners’ five-year credit facility as of September 30, 2006.

In an August 2006 public offering, Kinder Morgan Energy Partners issued 5,750,000 common units at a price of $44.80, less commissions and underwriting expenses. After all fees, net proceeds were $248.0 million for the issuance of these common units. The proceeds from this equity issuance were used to reduce the borrowings under Kinder Morgan Energy Partners’ commercial paper program.

In July 2006, we received notification of election from the holders of our 7.35% Series debentures due 2026 electing the option, as provided in the indenture governing the debentures, to require us to redeem the securities on August 1, 2006. The full $125 million of principal was elected to be redeemed and was paid, along with accrued interest of approximately $4.6 million, on August 1, 2006, utilizing incremental borrowing under our $800 million credit facility.

On July 31, 2006, Terasen Gas Inc.’s C$100 million 6.15% medium term note debentures matured, and the note holders were paid utilizing a combination of cash on hand and incremental short-term borrowing.

On June 30, 2006, TGVI made a $5.6 million (C$6.2 million) payment on its government loans, of which approximately $3.3 million (C$3.7 million) was refinanced through borrowings under its C$20 million non-revolving credit facility and the remaining amount funded with cash on hand. Additional information on the government loans can be found in Note 17(D) of the Notes to Consolidated Financial Statements in Kinder Morgan Inc.’s 2005 Form 10-K.

On June 21, 2006, Terasen Gas Inc. entered into a C$500 million three-year revolving credit facility, extendible annually for an additional 364 days at the option of the lenders. This facility replaces five bi-lateral facilities aggregating C$500 million and includes terms and conditions similar to the facilities it replaced.

On May 9, 2006, Terasen entered into a C$450 million three-year revolving credit facility. This facility replaces three bi-lateral facilities aggregating C$450 million and includes terms and conditions similar to the facilities it replaced.

On May 8, 2006, Terasen Inc.’s C$100 million of 4.85%, Series 2 Medium Term Notes matured and Terasen Inc. paid the holders of the notes, utilizing a combination of incremental short-term borrowing and proceeds from the sale of Terasen Water and Utility Services as previously discussed under “Discontinued Operations.”

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 supports a $2.0 billion commercial paper program that was established in May 2006, and borrowings under the commercial paper program reduce the borrowings allowed under the credit facility. Borrowings under the Rockies Express credit facility and commercial paper program will be primarily used to finance the construction of the Rockies Express interstate natural gas pipeline and to pay related expenses, and the borrowings will not reduce the borrowings allowed under our credit facilities described above.

Effective June 30, 2006, West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline, LLC) was deconsolidated and will subsequently be accounted for under the equity method of accounting (See Note 5). All three owners have agreed to guarantee borrowings under the Rockies Express credit facility and under the Rockies Express commercial paper program in the same proportion as their percentage ownership of the member interests in Rockies Express Pipeline LLC. As of September 30, 2006, Rockies Express Pipeline LLC had $583.5 million of commercial paper outstanding, and there were no borrowings under its five-year credit facility. Accordingly, as of September 30, 2006, Kinder Morgan Energy Partners’ contingent share of Rockies Express’ debt was $297.6 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. This agreement was terminated concurrent with Kinder Morgan Energy Partners’ increase of its 5-year credit facility from $1.6 billion to $1.85 billion.

On January 31, 2006, Terasen Pipelines (Corridor) Inc.’s $225 million senior unsecured revolving credit facility and the associated C$20 million non-revolving demand facility were extended under the same terms for an additional 364 days as permitted under the terms of the facilities.

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 bankers’ acceptances under this facility to completely refinance TGVI’s former term facility

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and intercompany advances from Terasen. The bankers’ acceptances have terms not to exceed 180 days at the end of which time they are replaced by new bankers’ acceptances. The facility can also be utilized to finance working capital requirements and for general corporate purposes. The terms and conditions are similar to those of the previous facility and common for such term credit facilities. Concurrently with executing this facility, TGVI entered into a C$20 million seven-year unsecured committed non-revolving credit facility with one bank. This facility will be utilized for purposes of refinancing any annual prepayments that TGVI may be required to make on non-interest bearing government contributions. The terms and conditions are primarily the same as the aforementioned TGVI facility except this facility ranks junior to repayment of TGVI’s Class B subordinated debt, which is held by its parent company, Terasen. At September 30, 2006, TGVI had outstanding 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, under the C$350 million credit facility, borrowings outstanding at September 30, 2006 of $237.3 million have been classified as long-term debt and an estimated $16.8 million as current maturities in our accompanying interim Consolidated Balance Sheet at a weighted-average interest rate of 5.11%. For the three months ended September 30, 2006, average borrowings were $252.4 million at a weighted-average rate of 5.12%. For the nine months ended September 30, 2006, average borrowings were $254.5 million at a weighted-average rate of 4.70%. Borrowings outstanding under the $20 million credit facility at September 30, 2006 were $3.4 million.

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 $1.9 million (C$2.2 million). The cumulative loss recognized of $2.0 million (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 September 30, 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;

·

$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;

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·

$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 September 30, 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 are ultimately recoverable or payable to customers or shippers.

(i)

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

(ii)

TGVI has floating-to-fixed interest rate swap agreements, with a notional principal amount of C$65 million, which effectively convert its floating rate long-term bank debt to fixed rates in order to stabilize interest costs in the cost of service model approved by the regulatory authorities. The interest swaps mature in October and November of 2008.

(iii)

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

In February 2006, we entered into a series of transactions to effectively terminate our receive-fixed-rate, pay-variable-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with a combined notional value of C$1,254 million and entered into a series of receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements with a combined notional value of C$1,254 million. The new derivative instruments have been designated as hedges of our net investment in Canadian operations in accordance with SFAS No. 133. We recognized a one time non-cash, after-tax loss of approximately $14 million in the first quarter of 2006 from changes in the fair value of our receive-fixed-rate, pay-variable rate U.S. dollar to Canadian dollar cross-currency interest rate swaps from January 1, 2006 to the termination of the agreements to reflect the strengthening of the Canadian dollar versus the U.S. dollar.

Interest in Kinder Morgan Energy Partners

At September 30, 2006, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management we owned, approximately 29.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 14.4 million common units, 5.3 million Class B units and 10.1 million i-units, represent approximately 13.0% of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 14.7% of Kinder Morgan Energy Partners’ total equity interests at September 30, 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 January 1, 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.

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 January 1, 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 79 to 86 of Kinder

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KMI Form 10-Q

Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, which is incorporated herein by reference.

Net Cash Flows from Operating Activities

“Net Cash Flows Provided by Operating Activities” increased from $247.4 million for the nine months ended September 30, 2005 to $1,171.7 million for the nine months ended September 30, 2006, an increase of $924.3 million. This positive variance is principally due to (i) an increase of $1,113.6 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 ($951.6 million and $101.9 million of this $1,113.6 million increase are attributable to Kinder Morgan Energy Partners and Terasen, respectively), (ii) a $277.5 million increase in cash relative to net changes in working capital items, of which Kinder Morgan Energy Partners contributed a decrease of $64.0 m illion and Terasen contributed an increase of $60.3 million, (iii) the fact that 2005 included a $25.0 million pension payment and (iv) an $18.7 million source of cash attributable to Terasen rate stabilization accounts. These positive impacts are partially offset by (i) a $334.1 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 $387.6 million, (ii) a net increased use of cash of $79.4 million for gas in underground storage, of which Kinder Morgan Energy Partners and Terasen contributed $26.1 million and $48.4 million, respectively, (iii) a $15.4 million increase of payments made for natural gas liquids inventory entirely attributable to Kinder Morgan Energy Partners, (iv) $19.1 million of payments made to certain shippers on Kinder Morgan Energy Partners’ Pacific operations’ pipelines as a result of a settle ment agreement reached in May 2006 regarding delivery tariffs and gathering enhancement fees at its Watson Station (see Note 15 of the accompanying Notes to Consolidated Financial Statements), (v) the fact that 2005 included a $26.4 million non-cash debit to income for hedging ineffectiveness and (vi) a decrease of $24.6 million in 2006 cash attributable to discontinued operations (see Note 8 of the accompanying Notes to Consolidated Financial Statements.) 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 Investing Activities” increased from $16.9 million for the nine months ended September 30, 2005 to $1,285.0 million for the nine months ended September 30, 2006, an increase of $1,268.1 million. This increased use of cash is principally due to (i) $366.4 million of cash used to acquire Entrega Pipeline LLC and various other assets (See Note 5 of the accompanying Notes to Consolidated Financial Statements), (ii) an additional $10.2 million attributable to the acquisition of Terasen (See Note 5 of the accompanying Notes to Consolidated Financial Statements), (iii) a $971.0 million increased use of cash for capital expenditures, of which $751.3 million and $178.5 million are attributable to Kinder Morgan Energy Partners and Terasen, respectively, (iv) the fact that 2005 included $92.5 million of proceeds from the sale of Kinder Morgan Management, LLC shares (see Note 6 of the accompanying Notes to Consolidated Fina ncial Statements), (v) $12.9 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 and (vi) a $7.8 million net increase during 2006 of investments in margin deposits associated with hedging activities utilizing energy derivative instruments, of which proceeds of $1.4 million is attributable to Kinder Morgan Energy Partners. Partially offsetting these negative impacts are (i) an $80.5 million increase in proceeds from sales of other assets net of removal costs, of which $71.6 million is attributable to Kinder Morgan Energy Partners and (ii) $113.3 million of proceeds received for the sale of Terasen’s discontinued Water and Utility Services.

Net Cash Flows from Financing Activities

“Net Cash Flows Provided by (Used in) Financing Activities” increased from a use of $396.0 million for the nine months ended September 30, 2005 to a source of $91.5 million for the nine months ended September 30, 2006, an increase of $487.5 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) $249.5 million of proceeds received in 2006 from the issuance of TGVI’s Floating Rate Syndicated Credit Facility, (iii) $103.5 million of proceeds, net of issuance costs, received in 2006 from the issuance of Terasen Gas Inc.’s 5.55% Medium Term Note Debentures due September 25, 2036 (see Note 9 of the accompanying Notes to Consolidated Financial Statements), (iv) a $164.7 million decrease in cash paid during 2006 to repurchase our common shares, (v) a $415.5 million increase in short-term debt, of which $733.9 million of additional borr owing is attributable to Kinder Morgan Energy Partners and a $136.1 million reduction in short-term debt is attributable to Terasen, (vi) $353.8 million of contributions from minority interest owners, primarily Kinder Morgan Energy Partners’ issuance of 5.75 million common units receiving net proceeds (after underwriting discount) of $248.0 million and Sempra Energy’s $104.2 million contribution for its 33 1/3% share of the purchase price of Entrega Pipeline LLC and (vii) an $11.4 million increase from net changes in cash book overdrafts—which represent checks issued but not yet endorsed. Partially offsetting these factors are (i) $125 million of cash used to retire our 7.35% Series  debentures which were elected by the holders to be redeemed on August 1, 2006 as provided in the indenture governing the debentures (ii) the fact that 2005 included $248.5 million of proceeds, net

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of issuance costs, from the issuance of our 5.15% Senior Notes due March 1, 2015, (iii) $181.6 million of cash used to retire TGVI’s Syndicated Credit Facility, $86.7 million of cash used to retire Terasen’s 4.85% Series 2 Medium Term Notes and $86.7 million of cash used to retire Terasen Gas Inc.’s 6.15% Series 16 Medium Term Notes (see Note 9 of the accompanying Notes to Consolidated Financial Statements), (iv) an increase of $452.1 million of minority interest distributions, principally consisting of Kinder Morgan Energy Partners’ $345.5 million distribution to common unit owners and $105.2 million paid from Kinder Morgan Energy Partners’ Rockies Express Pipeline LLC subsidiary to Sempra Energy, (v) an $87.6 million increase in cash paid for dividends in 2006, principally due to the increased dividends declared per share, (vi)  a decrease of $25.0 million for issuance of our common stock, principally due to a red uction of employee stock option exercises and (vii) an $7.9 million use of cash during 2006 for short-term advances to unconsolidated affiliates versus a $0.1 million source of cash during 2005 for short-term advances from unconsolidated affiliates, principally Kinder Morgan Energy Partners, during 2005.

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

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

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

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

Available cash for each quarter is distributed:

·

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

·

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

·

third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% 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 July 19, 2006, Kinder Morgan Energy Partners declared a quarterly distribution of $0.81 per unit for the quarterly period ended June 30, 2006, of which $115.6 million was paid on August 14, 2006 to the public holders (included in minority interests) of Kinder Morgan Energy Partners’ common units.

On October 18, 2006, Kinder Morgan Energy Partners declared a quarterly distribution of $0.81 per unit for the quarterly period ended September 30, 2006. The distribution will be paid on November 14, 2006, to unitholders of record as of October 31, 2006.

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KMI Form 10-Q

Recent Accounting Pronouncements

Refer to Note 16 of the accompanying Notes to Consolidated Financial Statements for information regarding recent accounting pronouncements.

Information Regarding Forward-looking Statements

This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to pay dividends or 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 that could cause actual results to differ from those in the forward-looking statements include:

·

the occurrence of any event, change or other circumstance that could give rise to the termination of the merger agreement in connection with the Going Private transaction;

·

the inability to complete the Going Private transaction due to the failure to obtain stockholder approval or the failure to satisfy other conditions required to consummate the merger;

·

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;

·

crude oil and natural gas production from exploration and production areas that we serve, such as the Permian Basin area of 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, and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;

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KMI Form 10-Q

·

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 significant levels of self-retention of risk;

·

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

·

capital markets conditions;

·

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

·

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

·

our ability to achieve cost savings and revenue growth;

·

inflation;

·

interest rates;

·

the pace of deregulation of retail natural gas and electricity;

·

foreign exchange fluctuations;

·

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

·

the extent of Kinder Morgan Energy Partners’ 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;

·

engineering and mechanical or technological difficulties that Kinder Morgan Energy Partners may experience with operational equipment, in well completions and workovers, and in drilling new wells;

·

the uncertainty inherent in estimating future oil and natural gas production or reserves that Kinder Morgan Energy Partners may experience;

·

the timing and success of Kinder Morgan Energy Partners’ and our 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, and Part II, Item 1A “Risk Factors” of this report for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Other than as required by applicable law , we disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

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 September 30, 2006, which nets the change in our financial derivatives against the change in our physical commodities, was not material.

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

89

KMI Form 10-Q

that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio during the year. In addition, as discussed preceding, we enter into these derivatives solely for the purpose of mitigating the risks that accompany our normal business activities and, therefore, the change in the market value of our portfolio of derivatives is, with the exception of hedging inefficiency, offset by changes in the value of the underlying physical transactions.

Item 4.

Controls and Procedures.

As of September 30, 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 f ile and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

90

KMI Form 10-Q

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.

Other than as described below, 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.

Failure to complete the Going Private transaction would likely have an adverse effect on us. There can be no assurance that our stockholders will approve the merger agreement or that the other conditions to the completion of the Going Private transaction will be satisfied. In connection with the Going Private transaction, we are subject to several risks, including the following:

·

On May 26, 2006, the last trading day prior to the announcement of management’s proposal of the merger, our common stock closed at $84.41 per share. After that announcement, the stock price rose to trade close to the $100 per share proposal price. Since the merger agreement was signed on August 28, 2006, our common stock has traded generally between $104 and $106 per share. The current price of our common stock may reflect a market assumption that the merger will close. If the merger is not consummated, the stock price would likely retreat from its current trading range.

·

Certain costs relating to the merger, including legal, accounting and financial advisory fees, are payable by us whether or not the merger is completed.

·

Under circumstances set out in the merger agreement, if the Going Private transaction is not completed we may be required to pay the acquiring company a termination fee of $215 million and reimburse up to $45 million of the acquiring company’s expenses, which will be credited against the termination fee if it becomes payable.

·

Our management’s and our employees’ attention will have been diverted from our day-to-day operations, we may experience unusually high employee attrition and our business and customer relationships may be disrupted.

Consummation of the Going Private transaction would result in substantially more debt to us, which could have an adverse effect on us, such as a downgrade of the ratings of our debt securities, and that downgrade could be significant. In response to the May 29, 2006 announcement of the proposal to acquire all of our outstanding common stock, Moody’s Investor Services placed both our long-term and short-term debt ratings under review for possible downgrade. Standard & Poor’s put our long-term and short-term debt ratings on credit watch with negative implications. There can be no assurance that any definitive offer will be made, that any agreement will be executed, or that the management proposal or any other transaction will be approved or consummated. If the Going Private transaction is consummated, we will incur substantially more debt, which could have an adverse effect on us, such as a downgrade in the ratings of our debt securities, which could be significant. Additionally, consummation of the Going Private transaction could have other adverse effects on us.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

During the quarter ended September 30, 2006, we did not sell any equity securities that were not registered under the Securities Act of 1933, as amended. See also 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.

91

KMI Form 10-Q

Item 6.

Exhibits.

2.1

Agreement and Plan of Merger, dated as of August 28, 2006, among Kinder Morgan, Inc., Knight Holdco LLC and Knight Acquisition Co. (filed as Exhibit 2.1 to Kinder Morgan, Inc.’s Current Report on Form
8-K, filed on August 28, 2006, and incorporated herein by reference).

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.

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 September 30, 2006

_______________________________________

*Filed herewith

92

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)
November 8, 2006	/s/ Kimberly A. Dang
	Kimberly A. Dang Vice President and Chief Financial Officer

93

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:  November 8, 2006
	/s/ Richard D. Kinder
	Richard D. Kinder Chairman and Chief Executive Officer

EX-31.1

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:  November 8, 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 September 30, 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:  November 8, 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 September 30, 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:  November 8, 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 September 30, 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 162,779,676 common units outstanding as of October 31,

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 and Nine

           Months Ended September 30, 2006 and 2005.....................  3

           Consolidated Balance Sheets - September 30, 2006 and

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

           Consolidated Statements of Cash Flows - Nine Months

           Ended September 30, 2006 and 2005............................  5

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

Item 2:  Management's Discussion and Analysis of Financial

           Condition and Results of Operations.......................... 60

           Critical Accounting Policies and Estimates................... 60

           Results of Operations........................................ 61

           Financial Condition.......................................... 79

           Information Regarding Forward-Looking Statements............. 86

Item 3:  Quantitative and Qualitative Disclosures About Market Risk..... 88

Item 4:  Controls and Procedures........................................ 88

                           PART II. OTHER INFORMATION

Item 1:  Legal Proceedings.............................................. 90

Item 1A: Risk Factors................................................... 90

Item 2:  Unregistered Sales of Equity Securities and Use of Proceeds.... 90

Item 3:  Defaults Upon Senior Securities................................ 90

Item 4:  Submission of Matters to a Vote of Security Holders............ 90

Item 5:  Other Information.............................................. 90

Item 6:  Exhibits....................................................... 90

         Signature...................................................... 92

                                       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)

<TABLE>

<CAPTION>

                                                          Three Months Ended         Nine Months Ended

                                                            September 30,              September 30,

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

                                                          2006          2005         2006         2005

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

Revenues

<S>                                                    <C>          <C>          <C>          <C>       

  Natural gas sales................................... $1,516,874   $1,975,583   $4,679,236   $4,820,732

  Services............................................    532,392      470,469    1,554,052    1,369,496

  Product sales and other.............................    224,167      185,202      628,234      539,313

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

                                                        2,273,433    2,631,254    6,861,522    6,729,541

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

Costs, Expenses and Other

  Gas purchases and other costs of sales..............  1,511,217    1,970,579    4,649,851    4,795,923

  Operations and maintenance..........................    208,816      156,486      575,352      448,621

  Fuel and power......................................     56,644       44,951      160,621      132,329

  Depreciation, depletion and amortization............    106,830       85,356      296,780      258,644

  General and administrative..........................     59,694       47,073      183,913      171,058

  Taxes, other than income taxes......................     28,005       28,198       90,859       80,249

  Other expense (income)..............................         --           --      (15,114)          --

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

                                                        1,971,206    2,332,643    5,942,262    5,886,824

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

Operating Income......................................    302,227      298,611      919,260      842,717

Other Income (Expense)

  Earnings from equity investments....................     14,032       20,512       57,203       69,422

  Amortization of excess cost of equity investments...     (1,416)      (1,407)      (4,244)      (4,233)

  Interest, net.......................................    (88,301)     (68,348)    (246,109)    (192,387)

  Other, net..........................................      3,339        2,880       11,179        2,208

Minority Interest.....................................     (2,018)      (1,806)      (7,881)      (6,648)

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

Income Before Income Taxes............................    227,863      250,442      729,408      711,079

Income Taxes..........................................     (4,045)      (5,055)     (11,820)     (20,245)

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

Net Income............................................ $  223,818   $  245,387   $  717,588   $  690,834

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

General Partner's interest in Net Income.............. $  133,881   $  122,744   $  393,565   $  351,724

Limited Partners' interest in Net Income..............     89,937      122,643      324,023      339,110

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

Net Income............................................ $  223,818   $  245,387   $  717,588   $  690,834

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

Basic Limited Partners' Net Income per Unit........... $     0.40   $     0.58   $     1.45   $     1.61

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

Diluted Limited Partners' Net Income per Unit......... $     0.40   $     0.57   $     1.45   $     1.61

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

Weighted average number of units used in computation

of Limited Partners' Net Income per unit:

Basic.................................................    225,809      213,192      222,810      210,001

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

Diluted...............................................    226,155      213,496      223,144      210,199

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

Per unit cash distribution declared................... $     0.81   $     0.79   $     2.43   $     2.33

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

</TABLE>

              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)

                                                   September 30,   December 31,

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

                                                       2006           2005

                                                       ----           ----

                      ASSETS

Current Assets

  Cash and cash equivalents.....................  $    23,953     $    12,108

  Accounts, notes and interest receivable, net

     Trade......................................      811,897       1,011,716

     Related parties............................        7,230           2,543

  Inventories

     Products...................................       15,924          18,820

     Materials and supplies.....................       12,909          13,292

  Gas imbalances

     Trade......................................        9,464          18,220

     Related parties............................        5,241               -

  Gas in underground storage....................       26,036           7,074

  Other current assets..........................      129,643         131,451

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

                                                    1,042,297       1,215,224

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

Property, Plant and Equipment, net..............    9,222,800       8,864,584

Investments.....................................      429,924         419,313

Notes receivable

  Trade.........................................        1,241           1,468

  Related parties...............................       90,854         109,006

Goodwill........................................      818,800         798,959

Other intangibles, net..........................      210,074         217,020

Deferred charges and other assets...............      207,042         297,888

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

Total Assets....................................

                                                  $12,023,032     $11,923,462

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

        LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities

  Accounts payable

     Cash book overdrafts.......................  $    43,220     $    30,408

     Trade......................................      677,652         996,174

     Related parties............................          739          16,676

  Current portion of long-term debt.............    1,147,213               -

  Accrued interest..............................       45,384          74,886

  Accrued taxes.................................       70,903          23,536

  Deferred revenues.............................       15,699          10,523

  Gas imbalances

     Trade......................................        9,780          22,948

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

  Accrued other current liabilities.............      689,840         632,088

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

                                                    2,700,430       1,808,885

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

Long-Term Liabilities and Deferred Credits

  Long-term debt

     Outstanding................................    4,386,706       5,220,887

     Market value of interest rate swaps........       44,806          98,469

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

                                                    4,431,512       5,319,356

  Deferred revenues.............................       23,494           6,735

  Deferred income taxes.........................       71,225          70,343

  Asset retirement obligations..................       46,873          42,417

  Other long-term liabilities and deferred credits    849,271       1,019,655

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

                                                    5,422,375       6,458,506

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

Commitments and Contingencies (Note 3)

Minority Interest...............................       44,666          42,331

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

Partners' Capital

  Common Units..................................    2,778,382       2,680,352

  Class B Units.................................      104,487         109,594

  i-Units.......................................    1,870,072       1,783,570

  General Partner...............................      125,113         119,898

  Accumulated other comprehensive loss..........   (1,022,493)     (1,079,674)

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

                                                    3,855,561       3,613,740

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

Total Liabilities and Partners' Capital.........  $12,023,032     $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)

<TABLE>

<CAPTION>

                                                                                     Nine Months Ended

                                                                                       September 30,

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

                                                                                    2006           2005

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

Cash Flows From Operating Activities

<S>                                                                             <C>            <C>       

  Net income.................................................................   $  717,588     $  690,834

  Adjustments to reconcile net income to net cash provided

  by operating activities:

    Depreciation, depletion and amortization.................................      296,780        258,644

    Amortization of excess cost of equity investments........................        4,244          4,233

    Gains and other non-cash income from the sale of property,

    plant and equipment......................................................      (15,716)          (635)

    Earnings from equity investments.........................................      (57,203)       (69,422)

  Distributions from equity investments......................................       56,281         51,552

  Changes in components of working capital:

    Accounts receivable......................................................      216,850       (249,056)

    Other current assets.....................................................       (3,775)          (394)

    Inventories..............................................................        6,083         (7,172)

    Accounts payable.........................................................     (334,434)       222,739

    Accrued interest.........................................................      (29,503)       (17,057)

    Accrued liabilities......................................................       (2,269)        (1,218)

    Accrued taxes............................................................       47,759         40,722

    FERC rate reparations and refunds........................................      (19,079)            --

  Other, net.................................................................       (4,879)       (22,170)

Net Cash Provided by Operating Activities....................................      878,727        901,600

Cash Flows From Investing Activities

  Acquisitions of assets.....................................................     (367,292)      (289,751)

  Additions to property, plant and equip. for expansion

  and maintenance projects...................................................     (751,346)      (597,186)

  Sale of property, plant and equipment, and other net

  assets net of removal costs................................................       71,532          2,987

  Net proceeds from margin deposits..........................................        1,390             --

  Contributions to equity investments........................................         (106)        (1,202)

  Natural gas stored underground and natural gas liquids line-fill...........      (12,863)       (20,208)

  Other......................................................................       (3,401)          (211)

Net Cash Used in Investing Activities........................................   (1,062,086)      (905,571)

Cash Flows From Financing Activities

  Issuance of debt...........................................................    3,730,016      3,812,933

  Payment of debt............................................................   (3,005,384)    (3,401,190)

  Repayments from loans to related party.....................................        1,097             --

  Debt issue costs...........................................................       (1,554)        (5,723)

  Increase in cash book overdrafts...........................................       12,812          6,782

  Proceeds from issuance of common units.....................................      248,376        285,407

  Contributions from minority interest.......................................      109,294          4,509

  Distributions to partners:

    Common units.............................................................     (380,245)      (337,994)

    Class B units............................................................      (12,858)       (12,115)

    General Partner..........................................................     (388,350)      (337,633)

    Minority interest........................................................     (115,424)        (8,754)

  Other, net.................................................................       (2,693)        (2,063)

Net Cash Provided by Financing Activities....................................      195,087          4,159

Effect of exchange rate changes on cash and cash equivalents.................          117           (188)

Increase in Cash and Cash Equivalents........................................       11,845             --

Cash and Cash Equivalents, beginning of period...............................       12,108             --

Cash and Cash Equivalents, end of period.....................................   $   23,953     $       --

Noncash Investing and Financing Activities:

  Contribution of net assets to partnership investments......................   $   17,003     $       --

  Assets acquired by the issuance of units...................................           --         49,635

  Assets acquired by the assumption of liabilities...........................        3,725         68,045

</TABLE>

              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. Certain

amounts from prior periods have been reclassified to conform to the current

presentation.

     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, Joint Ventures and Divestitures

     Acquisitions and Joint Ventures

     During the first nine months of 2006, we completed or made adjustments for

the following acquisitions. Each of the acquisitions was accounted for under the

purchase method and the assets acquired and liabilities assumed 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.

     Kinder Morgan River Terminals LLC

     Effective October 6, 2004, we acquired Global Materials Services LLC and

its consolidated subsidiaries from Mid-South Terminal Company, L.P. for

approximately $87.9 million, consisting of $31.8 million in cash and $56.1

million of assumed liabilities, including debt of $33.7 million. In the third

quarter of 2006, we made certain immaterial purchase price adjustments based on

a further evaluation of acquired income tax assets and liabilities. Global

Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC,

operates a network of 21 river terminals and two rail transloading facilities

primarily located along the Mississippi River system. The network provides

loading, storage and unloading points for various bulk commodity imports and

exports. The acquisition further expanded and diversified our customer base and

complemented our existing terminal facilities located along the

lower-Mississippi River system. The acquired terminals are included in our

Terminals business segment.

     Our allocation of the purchase price to assets acquired and liabilities

assumed after giving effect to the above adjustments is as follows (in

thousands):

                Purchase price:

                  Cash paid, including transaction costs......  $31,819

                  Debt assumed................................   33,677

                  Liabilities assumed (excluding debt)........   22,371

                                                                 ------

                  Total purchase price........................  $87,867

                                                                 ======

                Allocation of purchase price:

                  Current assets..............................   $9,855

                  Property, plant and equipment...............   43,191

                  Goodwill....................................   20,218

                  Other intangibles, net......................   12,400

                  Deferred charges and other assets...........    2,203

                                                                 ------

                                                                $87,867

                                                                 ======

     The $20.2 million of goodwill was assigned to our Terminals business

segment, and the entire amount is expected to be deductible for tax purposes. We

believe this acquisition resulted in the recognition of goodwill primarily due

to the fact that certain advantageous factors and conditions existed that

contributed to the fair value of acquired identifiable net assets and

liabilities exceeding our acquisition price--in the aggregate, these factors

represented goodwill. The $12.4 million of other intangibles in the table above

includes $11.9 million representing the fair value of intangible customer

relationships, which encompass both the contractual life of customer contracts

plus any future customer relationship value beyond the contract life.

     General Stevedores, L.P.

     Effective July 31, 2005, we acquired all of the partnership interests in

General Stevedores, L.P. for an aggregate consideration of approximately $8.9

million, consisting of $2.0 million in cash, $3.4 million in common units, and

$3.5 million in assumed liabilities, including debt of $3.0 million. In August

2005, we paid the $3.0 million outstanding debt balance. General Stevedores,

L.P. owns, operates and leases barge unloading facilities located along the

Houston, Texas ship channel. Its operations primarily consist of receiving,

storing and transferring semi-finished steel products, including coils, pipe and

billets. The acquisition complemented and further expanded our existing Texas

Gulf Coast terminal facilities, and its operations are included as part of our

Terminals business segment. In the second quarter of 2006, we made our final

purchase price adjustments and the final allocation of our purchase price to

assets acquired and liabilities assumed. The adjustments included minor

revisions to acquired working capital items, and, pursuant to an

                                       7

<PAGE>

appraisal of acquired fixed asset and land values, an adjustment of $2.9 million

from property, plant and equipment to goodwill.

     Our allocation of the purchase price to assets acquired and liabilities

assumed was as follows (in thousands):

                Purchase price:

                  Cash paid, including transaction costs......  $1,995

                  Common units issued.........................   3,385

                  Debt assumed................................   3,009

                  Liabilities assumed (excluding debt)........     479

                                                                 -----

                  Total purchase price........................  $8,868

                                                                 =====

                Allocation of purchase price:

                  Current assets..............................  $  601

                  Property, plant and equipment...............   5,197

                  Goodwill....................................   2,870

                  Other intangibles, net .....................     200

                                                                 -----

                                                                $8,868

                                                                 =====

     The $2.9 million of goodwill was assigned to our Terminals business segment

and the entire amount is expected to be deductible for tax purposes.

     Entrega Gas Pipeline LLC

     Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega

Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East

Pipeline LLC is a limited liability company and is the sole owner of Rockies

Express Pipeline LLC. We contributed 66 2/3% of the consideration for this

purchase, which corresponded to our percentage ownership of West2East Pipeline

LLC at that time. At the time of acquisition, Sempra Energy held the remaining

33 1/3% ownership interest and contributed this same proportional amount of the

total consideration.

     On the acquisition date, Entegra Gas Pipeline LLC owned the Entrega

Pipeline, an interstate natural gas pipeline that will, when fully constructed,

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 the Rockies Express Pipeline, an

interstate natural gas pipeline that is currently being developed by Rockies

Express Pipeline LLC. The acquired operations are included as part of our

Natural Gas Pipelines business segment.

     In the first quarter of 2006, EnCana Corporation completed construction of

the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and

interim service began on that portion of the pipeline. Under the terms of the

purchase and sale agreement, Rockies Express Pipeline LLC will construct the

segment that extends from the Wamsutter Hub to the Cheyenne Hub. Construction on

this pipeline segment began in the second quarter of 2006, and it is anticipated

that both pipeline segments will be placed into service by January 1, 2007.

     With regard to Rockies Express Pipeline LLC's acquisition of Entrega Gas

Pipeline LLC, the allocation of the purchase price to assets acquired and

liabilities assumed was as follows (in thousands):

                Purchase price:

                  Cash paid, including transaction costs......  $244,572

                  Liabilities assumed.........................         -

                                                                 -------

                  Total purchase price........................  $244,572

                                                                 =======

                Allocation of purchase price:

                  Current assets..............................  $      -

                  Property, plant and equipment...............   244,572

                  Deferred charges and other assets ..........         -

                                                                 -------

                                                                $244,572

                                                                 =======

     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 (including the lines currently

being developed) will be known as the Rockies Express Pipeline. The combined

1,663-mile pipeline system

                                       8

<PAGE>

will be one of the largest natural gas pipelines ever constructed in North

America. The approximately $4.4 billion project will have the capability to

transport 1.8 billion cubic feet per day of natural gas, and binding firm

commitments have been secured for virtually all of the pipeline capacity.

     On June 30, 2006, ConocoPhillips exercised its option to acquire a 25%

ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express

Pipeline LLC). On that date, a 24% ownership interest was transferred to

ConocoPhillips, and an additional 1% interest will be transferred once

construction of the entire project is completed. Through our subsidiary Kinder

Morgan W2E Pipeline LLC, we will continue to operate the project but our

ownership interest decreased to 51% of the equity in the project (down from 66

2/3%). Sempra's ownership interest in West2East Pipeline LLC decreased to 25%

(down from 33 1/3%). When construction of the entire project is completed, our

ownership interest will be reduced to 50% at which time the capital accounts of

West2East Pipeline LLC will be trued up to reflect our 50% economics in the

project. We do not anticipate any additional changes in the ownership structure

of the Rockies Express Pipeline project.

     West2East Pipeline LLC qualifies as a variable interest entity as defined

by Financial Accounting Standards Board Interpretation No. 46 (Revised December

2003) (FIN 46R), "Consolidation of Variable Interest Entities-An Interpretation

of ARB No. 51," due to the fact that the total equity at risk is not sufficient

to permit the entity to finance its activities without additional subordinated

financial support provided by any parties, including equity holders.

Furthermore, following ConocoPhillips' acquisition of its ownership interest in

West2East Pipeline LLC on June 30, 2006, we receive 50% of the economics of the

Rockies Express project on an ongoing basis, and thus, effective June 30, 2006,

we were no longer considered the primary beneficiary of this entity as defined

by FIN 46R. Accordingly, on that date, we made the change in accounting for our

investment in West2East Pipeline LLC from full consolidation to the equity

method following the decrease in our ownership percentage.

     Under the equity method, we record the costs of our investment within the

"Investments" line on our consolidated balance sheet and as changes in the net

assets of West2East Pipeline LLC occur (for example, earnings and dividends), we

recognize our proportional share of that change in the "Investment" account. We

also record our proportional share of any accumulated other comprehensive income

or loss within the "Accumulated other comprehensive loss" line on our

consolidated balance sheet.

     Summary financial information as of September 30, 2006, for West2East

Pipeline LLC, which is accounted for under the equity method, is as follows (in

thousands; amounts represent 100% of investee information):

                                                          September 30,

                        Balance Sheet                          2006

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

                Current assets............................  $    935

                Non-current assets........................   594,947

                Current liabilities.......................    14,098

                Non-current liabilities...................   588,296

                Accumulated other comprehensive income....  $ (6,512)

     In addition, we have guaranteed our proportional share of West2East

Pipeline LLC's debt borrowings under a $2 billion credit facility entered into

by Rockies Express Pipeline LLC. For more information on our contingent debt,

see Note 7.

     April 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.

for an aggregate consideration of approximately $63.7 million, consisting of

$60.2 million in cash and $3.5 million in assumed liabilities. The acquisition

was effective March 1, 2006. However, we divested certain acquired properties

that are not considered candidates for carbon dioxide enhanced oil recovery,

thus reducing our total investment. As of September 30, 2006, we received

proceeds of approximately $27.0 million from the sale of these properties.

     The properties are primarily located in the Permian Basin area of West

Texas and New Mexico, produce approximately 425 barrels of oil equivalent per

day, and include some fields with potential for enhanced oil recovery

                                       9

<PAGE>

development near our current carbon dioxide operations. The acquired operations

are included as part of our CO2 business segment. Following our acquisition, and

continuing through the remainder of 2006, 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.

     As of September 30, 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......  $60,188

                  Long-term liabilities assumed...............    3,548

                                                                 ------

                  Total purchase price........................  $63,736

                                                                 ======

                Allocation of purchase price:

                  Current assets..............................  $   229

                  Property, plant and equipment...............   63,507

                                                                 ------

                                                                $63,736

                                                                 ======

     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.

     Our allocation of the purchase price to assets acquired and liabilities

assumed was as follows (in thousands):

                Purchase price:

                  Cash paid, including transaction costs......  $61,614

                  Long-term liabilities assumed...............      253

                                                                 ------

                  Total purchase price........................  $61,867

                                                                 ======

                Allocation of purchase price:

                  Current assets..............................  $   509

                  Property, plant and equipment...............   43,595

                  Goodwill....................................   17,763

                                                                 ------

                                                                $61,867

                                                                 ======

     The $17.8 million of goodwill was assigned to our Terminals business

segment and the entire amount is expected to be deductible for tax purposes.

     Pro Forma Information

     Pro forma information regarding consolidated income statement information

that assumes all of the acquisitions we have made and joint ventures we have

entered into since January 1, 2005, including the ones listed above, had

occurred as of January 1, 2005, is not materially different from the information

presented in our accompanying consolidated statements of income.

                                       10

<PAGE>

     Divestitures

     Effective April 1, 2006, we sold our Douglas natural gas gathering system

and our Painter Unit fractionation facility to Momentum Energy Group, LLC for

approximately $42.5 million in cash. Our investment in net assets, including all

transaction related accruals, was approximately $24.5 million, most of which

represented property, plant and equipment, and we recognized approximately $18.0

million of gain on the sale of these net assets. We used the proceeds from these

asset sales to reduce the outstanding balance on our commercial paper

borrowings.

     The Douglas gathering system is comprised of approximately 1,500 miles of

4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet

per day of natural gas from 650 active receipt points. Gathered volumes are

processed at our Douglas plant (which we retained), located in Douglas, Wyoming.

As part of the transaction, we executed a long-term processing agreement with

Momentum Energy Group, LLC which dedicates volumes from the Douglas gathering

system to our Douglas processing plant. The Painter Unit, located near Evanston,

Wyoming, consists of a natural gas processing plant and fractionator, a nitrogen

rejection unit, a natural gas liquids terminal, and interconnecting pipelines

with truck and rail loading facilities. Prior to the sale, we leased the plant

to BP, which operates the fractionator and the associated Millis terminal and

storage facilities for its own account.

     Additionally, with regard to the natural gas operating activities of our

Douglas gathering system, we utilized certain derivative financial contracts to

offset our exposure to fluctuating expected future cash flows caused by periodic

changes in the price of natural gas and natural gas liquids. According to the

provisions of current accounting principles, changes in the fair value of

derivative contracts that are designated and effective as cash flow hedges of

forecasted transactions are reported in other comprehensive income (not net

income) and recognized directly in equity (included within accumulated other

comprehensive income/(loss)). Amounts deferred in this way are reclassified to

net income in the same period in which the forecast transactions are recognized

in net income. However, if a hedged transaction is no longer expected to occur

by the end of the originally specified time period, because, for example, the

asset generating the hedged transaction is disposed of prior to the occurrence

of the transaction, then the net cumulative gain or loss recognized in equity

should be transferred to net income in the current period.

     Accordingly, upon the sale of our Douglas gathering system, we reclassified

a net loss of $2.9 million from "Accumulated other comprehensive loss" into net

income on those derivative contracts that effectively hedged uncertain future

cash flows associated with forecasted Douglas gathering transactions. We

included the net amount of the gain, $15.1 million, within the caption "Other

expense (income)" in our accompanying consolidated statement of income for the

nine months ended September 30, 2006. For more information on our accounting for

derivative contracts, see Note 10.

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 and

protests regarding interstate rates on our Pacific operations' pipeline systems.

     OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a

consolidated proceeding that began in September 1992 and includes a number of

shipper complaints against certain rates and practices on SFPP's East Line (from

El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California

to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson

Station in Carson, California. The complainants in the case are El Paso

Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,

Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products

Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing

Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),

Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco

Corporation (now part of ConocoPhillips Company). The FERC has ruled that the

complainants have the burden of proof in this proceeding.

                                       11

<PAGE>

     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.

     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

                                       12

<PAGE>

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.

     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

                                       13

<PAGE>

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.

The FERC's decision in Docket No. PL05-5 has been appealed to the United States

Court of Appeals for the District of Columbia, and final briefs were filed on

September 11, 2006.

     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 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

                                       14

<PAGE>

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 discussed further below.

     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 moved to intervene in the review proceedings brought

by the other parties. The proceedings before the Court are addressed further

below.

     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.

     Watson Station proceedings. The FERC's June 1, 2005 Order on Remand and

Rehearing initiated a separate proceeding regarding the reasonableness of the

Watson Station charge. All Watson-related issues in Docket No. OR92-8, Docket

No. OR96-2 and other dockets were also consolidated in that proceeding. After

discovery and the filing of prepared direct testimony, the procedural schedule

was suspended while the parties pursued settlement negotiations.

     On May 17, 2006, the parties entered into a settlement agreement and filed

an offer of settlement with the FERC. On August 2, 2006, the FERC approved the

settlement without modification and directed that it be implemented. Pursuant to

the settlement, SFPP filed a new tariff, which took effect September 1, 2006,

lowering SFPP's going-forward rate to $0.003 per barrel and including certain

volumetric pumping rates. SFPP also paid refunds to all shippers for the period

since April 1, 1999 through August 31, 2006. Those refunds were based upon the

difference between the Watson Station charge as filed in SFPP's prior tariffs

and the reduced charges set forth in the agreement. On September 28, 2006, SFPP

filed a refund report with the FERC, setting forth the refunds that had

                                       15

<PAGE>

been paid and describing how the refund calculations were made. Two of the

settling parties, BP and ExxonMobil, protested the refund report, and SFPP

responded to that protest. The FERC has yet to act on the protest. As of

September 30, 2006, SFPP had made aggregate payments, including accrued

interest, of $19.1 million.

     For the period prior to April 1, 1999, the parties agreed to reserve for

briefing issues related to whether shippers are entitled to reparations. To the

extent any reparations are owed, the parties agreed on how reparations would be

calculated. Initial briefs regarding the reserved legal issues are due November

15, 2006. Reply briefs are due December 21, 2006.

     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.

     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. The FERC has not

yet ruled on the initial decision in this proceeding.

     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

                                       16

<PAGE>

proceeding in Docket No. OR96-2, et al.

     A hearing in this consolidated proceeding was held from October 2001 to

March 2002. A FERC administrative law judge issued his initial decision in June

2003. The initial decision found that, for the years at issue, the complainants

had shown substantially changed circumstances for rates on SFPP's West, North

and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson

Station and thus found that those rates should not be "grandfathered" under the

Energy Policy Act of 1992. The initial decision also found that most of SFPP's

rates at issue were unjust and unreasonable.

     On March 26, 2004, the FERC issued an order on the phase one initial

decision. The FERC's phase one order reversed the initial decision by finding

that SFPP's rates for its North and Oregon Lines should remain "grandfathered"

and amended the initial decision by finding that SFPP's West Line rates (i) to

Yuma, Tucson and Calnev, as of 1995, and (ii) to Phoenix, as of 1997, should no

longer be "grandfathered" and are not just and reasonable. The FERC upheld these

findings in its June 1, 2005 order, although it appears to have found

substantially changed circumstances as to SFPP's West Line rates on a somewhat

different basis than in the phase one order. The FERC's phase one order did not

address prospective West Line rates and whether reparations were necessary. As

discussed below, those issues have been addressed in the FERC's December 16,

2005 order on phase two issues. The FERC's phase one order also did not address

the "grandfathered" status of the Watson Station fee, noting that it would

address that issue once it was ruled on by the Court of Appeals in its review of

the FERC's Opinion No. 435 orders; as noted above, the FERC held in its June 1,

2005 order that the Watson Station fee is not grandfathered. Several of the

participants in the proceeding requested rehearing of the FERC's phase one

order. The FERC denied those requests in its June 1, 2005 order. In addition,

several participants, including SFPP, filed petitions with the United States

Court of Appeals for the District of Columbia Circuit for review of the FERC's

phase one order. On August 13, 2004, the FERC filed a motion to dismiss the

pending petitions for review of the phase one order, which Petitioners,

including SFPP, answered on August 30, 2004. On December 20, 2004, the Court of

Appeals referred the FERC's motion to the merits panel and directed the parties

to address the issues in that motion on brief, thus effectively dismissing the

FERC's motion. In the same order, the Court of Appeals granted a motion to hold

the petitions for review of the FERC's phase one order in abeyance and directed

the parties to file motions to govern future proceeding 30 days after FERC

disposition of the pending rehearing requests. In August 2005, the FERC and SFPP

jointly moved that the Court of Appeals hold the petitions for review of the

March 26, 2004 and June 1, 2005 orders in abeyance due to the pendency of

further action before the FERC on income tax allowance issues. In December 2005,

the Court of Appeals denied this motion and placed the petitions seeking review

of the two orders on the active docket. Initial briefs to the Court were filed

May 30, 2006, and final briefs were filed October 19, 2006. Oral argument has

been scheduled for December 12, 2006.

     On July 24, 2006, the FERC filed with the Court of Appeals a motion for

voluntary partial remand, requesting that the portion of the March 26, 2004 and

June 1, 2005 orders in which the FERC removed grandfathering protection from

SFPP's West Line rates and affirmed such protection for the North Line and

Oregon Line rates be returned to the FERC for reconsideration in light of

arguments presented by SFPP and other parties in their initial briefs. In

response to the FERC's remand motion, SFPP filed on August 1, 2006 to reinstate

its West Line rates at the previous, grandfathered level effective August 2,

2006, and asked for FERC approval of such reinstatement on the ground that,

pending the FERC's reconsideration of its grandfathering rulings, the prior

grandfathered rate level is the lawful rate. On August 17, 2006, the Court of

Appeals denied without prejudice the FERC's motion for voluntary partial remand.

In light of this denial, on August 31, 2006, the FERC issued an order rejecting

SFPP's August 1, 2006 filing seeking reinstatement of SFPP's grandfathered West

Line rates.

     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.

                                       17

<PAGE>

     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 that the FERC's policy

statement and its decision in these cases have been 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 July 31, 2006,

the court of appeals held the appeals of these orders in abeyance pending

further FERC action.

     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). In accordance

with the December 16, 2005 order, rate reductions were 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, OR96-2, and IS05-230 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.

                                       18

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     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 is expected to be

approximately $15 million.

     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 United States Court of Appeals

for the District of Columbia Circuit.

     On June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) -

substantially similar to its previous complaint - and moved to consolidate the

complaint with the Docket No. OR96-2, et al. proceeding. Chevron requested that

this new complaint be treated as if it were an amendment to its complaint in

Docket No. OR02-4, which was previously dismissed by the FERC. By this request,

Chevron sought to, in effect, back-date its complaint, and claim for

reparations, to February 2002. SFPP answered Chevron's complaint on July 22,

2003, opposing Chevron's requests. On October 28, 2003, the FERC accepted

Chevron's complaint, but held it in abeyance pending the outcome of the Docket

No. OR96-2, et al. proceeding. The FERC denied Chevron's request for

consolidation and for back-dating. On November 21, 2003, Chevron filed a

petition for review of the FERC's October 28, 2003 order at the Court of Appeals

for the District of Columbia Circuit.

     On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for

review in OR02-4 on the basis that Chevron lacks standing to bring its appeal

and that the case is not ripe for review. Chevron answered on September 10,

2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,

granted Chevron's motion to hold the case in abeyance pending the outcome of the

appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the

Court of Appeals granted Chevron's motion to have its appeal of the FERC's

decision in OR03-5 consolidated with Chevron's appeal of the FERC's decision in

the OR02-4 proceeding. Following motions to dismiss by the FERC and SFPP, on

December 10, 2004, the Court dismissed Chevron's petition for review in Docket

No. OR03-5 and set Chevron's appeal of the FERC's orders in OR02-4 for briefing.

On January 4, 2005, the Court granted Chevron's request to hold such briefing in

abeyance until after final disposition of the OR96-2 proceeding. Chevron

continues to participate in the Docket No. OR96-2 et al. proceeding as an

intervenor.

     Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines,

Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental

Airlines, Inc. (collectively, the "Airlines") filed a complaint against SFPP at

the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and

SFPP's charge for its gathering enhancement service at Watson Station are not

just and reasonable. The Airlines seek rate reductions and reparations for two

years prior to the filing of their complaint. BP West Coast Products LLC and

ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company,

L.P., and ChevronTexaco Products Company all filed timely motions to intervene

in this proceeding. Valero Marketing and Supply Company filed a motion to

intervene one day after the deadline. SFPP answered the Airlines' complaint on

October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's

answer and on November 12, 2004, SFPP replied to the Airlines' response. In

March and June 2005, the Airlines filed motions seeking expedited action on

their complaint, and in July 2005, the Airlines filed a motion seeking to sever

issues related to the Watson Station gathering enhancement fee from the OR04-3

proceeding and consolidate them in the proceeding regarding the justness and

reasonableness of that fee that the FERC docketed as part of the June 1, 2005

order. In August 2005, the FERC granted the Airlines' motion to sever and

consolidate the Watson Station fee issues.

     OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products

LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC,

which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate

rates are not just and reasonable, that certain rates found grandfathered by the

FERC are not entitled to such status, and, if so entitled, that "substantially

changed circumstances" have occurred, removing such protection. The complainants

seek rate reductions and reparations for two years prior to the filing of their

complaint and ask that the complaint be consolidated with the Airlines'

complaint in the OR04-3 proceeding.

                                       19

<PAGE>

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, 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. 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. On

September 5, 2006, the presiding administrative law judge suspended the

procedural schedule in Docket No. OR03-5 pending a decision by the United States

Court of Appeals for the District of Columbia regarding various issues before

the court that directly impact the Docket No. OR03-5 proceeding.

     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 presiding administrative law judge issued

his initial decision on September 26, 2006.

     The initial decision held that SFPP should be allowed to include in its

rate base all costs associated with relocating the Concord to Sacramento

Segment, but to include only 14/20ths of the cost of constructing the new line;

it further held that the FERC's policy statement on income tax allowance is

inconsistent with the Court's decision in BP West Coast Products, LLC v. Federal

Energy Regulatory Commission and that, therefore, SFPP should be allowed no

income tax allowance. While the initial decision held that SFPP could recover

its litigation costs, it otherwise made rulings generally adverse to SFPP on

cost of service issues. These issues included the capital structure to be used

in computing SFPP's "starting rate base," treatment of SFPP's accumulated

deferred income tax account, costs of debt and equity, as well as allocation of

overhead. Briefs on exceptions are due on October 25, 2006. The FERC has not yet

reviewed the initial decision, and it is not possible to predict the outcome of

FERC and/or appellate review.

     East Line rate case, IS06-283 proceeding. In April 2006, SFPP filed to

increase its East Line interstate rates to reflect increased costs, principally

due to the installation of replacement pipe between El Paso, Texas and Tucson,

Arizona, significantly increasing the East Line's capacity. Under FERC

regulations, SFPP was required to demonstrate that there was a substantial

divergence between the revenues generated by its existing East Line rates and

its increased costs. SFPP's rate increase was protested by various shippers and

accepted subject to refund by the FERC. FERC established an investigation and

hearing before an administrative law judge. A procedural schedule has been

established, with a hearing scheduled for February 2007.

     Index Increases, IS06-356, IS05-327. On May 27, 2005, SFPP filed to

increase certain rates pursuant to the FERC's indexing methodology. Various

shippers protested, and the FERC accepted and suspended all but one of

                                       20

<PAGE>

the filed tariffs, subject to SFPP's filing of a revised Page 700 of its FERC

Form 6 and subject to the outcome of various proceedings involving SFPP at the

FERC. BP West Coast Products and ExxonMobil Oil Corporation filed for rehearing

and challenged the revised Page 700 filed by SFPP. On December 12, 2005, the

FERC denied the request for rehearing; this decision is currently on appeal

before the Court of Appeals. Initial briefs were filed on August 25, 2006, and

final briefs are due on November 28, 2006.

     On May 30, 2006, SFPP also filed to increase certain interstate rates

pursuant to the FERC's indexing methodology. This filing was protested, but the

FERC determined that SFPP's tariff filing was consistent with the FERC's

regulations. Certain shippers requested rehearing, which the FERC granted for

further consideration on August 21, 2006. The FERC's order has been appealed to

the United States Court of Appeals for the District of Columbia Circuit. On

August 31, 2006, the FERC filed a motion with the Court to hold the case in

abeyance, and SFPP and BP West Coast subsequently intervened. The Court has not

yet issued a ruling on the motions filed by the FERC, SFPP, and BP West Coast.

     Calnev Pipe Line LLC

     On May 22, 2006, Calnev Pipe Line LLC filed to increase its interstate

rates pursuant to the FERC's indexing methodology applicable to oil pipelines.

The filing was docketed in IS06-296. Calnev's filing was protested by

ExxonMobil, claiming that Calnev was not entitled to an indexing increase in its

rates based on its cost of service. Calnev answered the protest. On June 29,

2006, the FERC accepted and suspended the filing, subject to refund, permitting

the increased rates to go into effect on July 1, 2006. The FERC found that

Calnev's indexed rates exceeded its change in costs to a degree that warranted

establishing an investigation and hearing. However, the FERC initially directed

the parties to attempt to reach a settlement of the dispute before a FERC

settlement judge. The settlement process is proceeding.

     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 at any time.

     In October, 2002, the CPUC issued a resolution, referred to in this report

as the Power Surcharge 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

                                       21

<PAGE>

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 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 at any time.

     With regard to the CPUC complaints and the Power Surcharge Resolution, we

currently believe the complainants/protestants seek approximately $31 million in

prospective annual tariff reductions. Based upon CPUC practice and procedure

which precludes refunds or reparations in complaints in which the complainants

challenge the reasonableness of rates previously found reasonable by the CPUC

(as is the case with the two pending complaints contesting the reasonableness of

SFPP's rates) except for matters which have been expressly reserved by the CPUC

for further consideration (as is the case with respect to the reasonableness of

the rate charged for use of the Watson Station gathering enhancement

facilities), we currently believe that complainants/protestants are seeking

approximately $15 million in refunds/reparations. There is no way to quantify

the potential extent to which the CPUC could determine that SFPP's existing

California rates are unreasonable.

     SFPP also has various, pending ratemaking matters before the CPUC that are

unrelated to the above-referenced complaints and the Power Surcharge Resolution.

On November 22, 2004, SFPP filed an application with the CPUC requesting a $9

million annual 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. Because no

schedule has been established by the CPUC for addressing the issues raised by

the contested rate increase application nor does any record exist upon which the

CPUC could base a decision, SFPP has no basis for estimating either the

prospective rate reductions or the potential refunds at issue or for

establishing a date by which the CPUC is likely to render a decision regarding

the application.

     On January 26, 2006, SFPP filed a request for a rate increase of

approximately $5.4 million annually 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. As a consequence of the protests, the related rate

increases are being collected subject to refund. Because no schedule has been

established by the CPUC for addressing the issues raised by the contested rate

increase application nor does any record exist upon which the CPUC could base a

decision, SFPP has no basis for estimating either the prospective rate

reductions or the potential refunds at issue or for establishing a date by which

the CPUC is likely to render a decision regarding the application.

     On August 25, 2006, SFPP filed an application to increase rates by

approximately $0.5 million annually to recovers costs incurred to comply with

revised Ultra Low Sulfur Diesel regulations and to offset the revenue loss

associated with reduction of the Watson Station Volume Deficiency Charge

(intrastate) by increasing rates on a system-wide basis by approximately $3.1

million annually to be effective as of October 5, 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. As a

consequence of the protests, the related rate increases are being collected

subject to refund. Because no schedule has been established by the CPUC for

addressing the issues raised by the contested rate increase application, nor

does any record exist upon which the CPUC could base a decision, SFPP has no

basis for estimating either the prospective rate reductions, or the potential

refunds at issue, or for establishing a date by which the CPUC is likely to

render a decision regarding the application.

                                       22

<PAGE>

     All of the referenced pending matters before the CPUC have been

consolidated and assigned to a single Administrative Law Judge who has indicated

his intention to refer the matters to mediation under CPUC procedures applicable

to alternative dispute resolution processes.

     With regard to the Power Surcharge Resolution, the November 2004 rate

increase application, the January 2006 rate increase application, and the August

2006 rate increase application, 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 rate

reductions or 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).

     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. The case is currently set for trial on June 11, 2007.

     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 case is currently set for trial on June 11,

2007.

     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

                                       23

<PAGE>

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

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 denied Bailey's petition for writ of certiorari. The Houston

federal district court subsequently realigned the parties in the Bailey Houston

Federal Court Action. Pursuant to the Houston federal district court's order,

Bailey and the other realigned plaintiffs have filed amended complaints in which

they assert claims for fraud/fraudulent inducement, real estate fraud, negligent

misrepresentation, breach of fiduciary and agency duties, breach of contract and

covenants, violation of the Colorado Unfair Practices Act, civil theft under

Colorado law, conspiracy, unjust enrichment, and open account. Bailey also

asserted claims as a private relator under the False Claims Act and for

violation of federal and Colorado antitrust laws. The realigned plaintiffs seek

actual damages, treble damages, punitive damages, a constructive trust and

accounting, and declaratory relief. The Shell and Kinder Morgan defendants,

along with Cortez Pipeline Company and ExxonMobil defendants, have filed motions

for summary judgment on all claims. No current trial date is set.

     On March 1, 2004, Bridwell Oil Company, one of the named

defendants/realigned plaintiffs in the Bailey actions, filed a new matter in

which it asserts claims that are virtually identical to the 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, asserted 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,

                                       24

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breach of contract and implied duties to market and good faith and fair dealing,

and civil theft and conversion. Ptasynski sought actual damages, treble damages,

forfeiture, disgorgement, and declaratory and injunctive relief. The Colorado

court transferred the case to Houston federal district court, and Ptasynski

subsequently sought to non-suit the case. The Houston federal district court

granted Ptasynski's request to non-suit. Prior to non-suiting the case,

Ptasynski filed an appeal in the Tenth Circuit seeking to overturn the Colorado

court's order transferring the case to Houston federal district court. That

appeal is currently pending.

     Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company were 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

involved 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 claimed breaches of contractual and potential fiduciary

duties owed by the defendants and also alleged 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 sought 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. In August

2006, plaintiffs and defendants reached a settlement of all claims. Pursuant to

the settlement, the case was dismissed with prejudice on September 27, 2006.

     Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in

interest to Shell CO2 Company, Ltd., were among the named defendants in CO2

Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November

28, 2005. The arbitration arose 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 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 alleged 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 $12 million. The plaintiff also alleged 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 $0.5 million. Defendants denied that there was any breach of the

settlement agreement. The arbitration panel issued various preliminary

evidentiary rulings. The arbitration hearing took place in Albuquerque, New

Mexico on June 26-30, 2006. On August 7, 2006, the arbitration panel issued its

opinion finding that defendants did not breach the settlement agreement. The

arbitration opinion remains subject to further proceedings to confirm, vacate,

or modify the opinion.

     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

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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 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. Kinder Morgan appealed that ruling to the

New Mexico Court of Appeals. Oral arguments took place before the New Mexico

Court of Appeals on March 23, 2006, and the New Mexico Court of Appeals affirmed

the district court's order on August 8, 2006. Kinder Morgan filed a petition for

writ of certiorari in the New Mexico Supreme Court. The New Mexico Supreme Court

granted the petition on October 11, 2006.

     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.

     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 sought appellate review of

the interest award. In July 2006, the Court of Appeals disallowed the award of

interest.

     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. In July

2006, a trial before a judge regarding the circumstances under which we must pay

for relocations concluded, and a decision from the judge is expected in the

fourth quarter of 2006. In addition,

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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 positions, 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 greater 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 filed briefs opposing

leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's

Motion to Amend.

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     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.

     On October 20, 2006, the United States District Court, for the District of

Wyoming, issued its Order on Report and Recommendations of Special Master. In

its Order, the Court upheld the dismissal of the claims against the Kinder

Morgan defendants on jurisdictional grounds, finding that the Grynberg's claims

are based upon public disclosures and that Grynberg does not qualify as an

original source. It is probable that Grynberg will appeal this Order 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 various defendants have filed motions

arguing that the Arkansas courts lack personal jurisdiction over them. The Court

has not yet ruled on these motions. 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.

     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. In September 2005 and subsequent thereto, we

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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 believe that the federal authorities are also investigating coal

inventory practices at one or more of our other terminals. While we have no

indication of the direction of this additional investigation, our records do not

reflect any sales of excess coal from our other terminals, and we are not aware

of any wrongdoing or improper activities at our terminals. We are cooperating

fully with federal law enforcement authorities in this investigation, and expect

several of our officers and employees to be interviewed formally by federal

authorities. 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

     Claims asserted by residents and businesses. 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 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, referred to in this report as 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.

     In June, 2006, the parties reached an agreement to partially settle the

class action suit. On June 29, 2006, the plaintiffs filed an unopposed motion

for conditional certification of a settlement class. The settlement provides for

a fund of $2.0 million to distribute to residents within the evacuation zone

("Zone 1") and residents immediately adjacent to the evacuation zone ("Zone 2").

Persons in Zones 1 and 2 reside within approximately one mile from the site of

the incident. The court preliminarily approved the partial class action

settlement on July 7, 2006. Kinder Morgan Energy Partners agreed to participate

in and fund a minor percentage of the settlement. A fairness hearing occurred on

August 18, 2006 for the purpose of establishing final approval of the partial

settlement. The Court approved the settlement, entered a final judgment, and

certified a settlement class for Zones 1 and 2. The bar date for claims has

passed and Plaintiffs' counsel reports that they will be paying claims in the

immediate future. Certain claims by other residents and businesses remain

pending. Specifically, the settlement and final judgment does not apply to

purported class action claims by residents in outlying geographic zones more

than one mile from the site of the incident. Defendants deny liability to such

other residents in outlying geographic zones and intend to vigorously defend

such claims. In addition, the non-Kinder Morgan defendants have agreed to settle

remaining claims asserted by businesses and will obtain a release of such claims

favoring all defendants, including Kinder Morgan and its affiliates, subject to

the retention by all defendants of their claims against each other for

contribution and indemnity. Kinder Morgan expects that a claim will be asserted

by other defendants against Kinder Morgan seeking contribution or indemnity for

any settlements funded exclusively by other defendants, and Kinder Morgan

expects to vigorously defend against any such claims.

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     Claims asserted by the city of Cincinnati. 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. 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, the Kinder Morgan defendants filed a motion for

summary judgment seeking dismissal of the remaining aspects of the city's

complaint. The issues have been thoroughly briefed, and oral argument will be

heard on December 8, 2006. The parties agreed to stay discovery until after the

hearing, if necessary. No trial date has been established.

     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 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.

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     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. This motion was denied by the 9th Circuit Court of

Appeals on May 25, 2006.

     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

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 filed motions to dismiss

all causes of action excluding plaintiffs' cause of action for negligence.

Defendants also filed motions to strike portions of the complaint. By order

dated May 5, 2006, the Court granted defendants' motions to dismiss as to the

counts purporting to assert claims for fraud, but denied defendants' motions to

dismiss as to the remaining counts, as well as defendants' motions to strike.

Defendant Kennametal, Inc. has filed a third-party complaint naming the United

States and the United States Navy (the "United States") as additional

defendants. In response, the United States removed the case to the United States

District Court for the District of Nevada and filed a motion to dismiss the

third-party complaint, which motion is currently pending. Plaintiff has also

filed a motion to dismiss the United States and/or to remand the case back to

state court. Briefing on these motions is currently underway.

                                       31

<PAGE>

     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 third amended complaint and all defendants filed

motions to dismiss all causes of action excluding plaintiffs' cause of action

for negligence. Defendants also filed motions to strike portions of the

complaint. By order dated May 5, 2006, the Court granted defendants' motions to

dismiss as to the counts purporting to assert claims for fraud, but denied

defendants' motions to dismiss as to the remaining counts, as well as

defendants' motions to strike. Defendant Kennametal, Inc. has filed a

third-party complaint naming the United States and the United States Navy (the

"United States") as additional defendants. In response, the United States

removed the case to the United States District Court for the District of Nevada

and filed a motion to dismiss the third-party complaint, which motion is

currently pending. Plaintiff has also filed a motion to dismiss the United

States and/or to remand the case back to state court. Briefing on these motions

is currently underway.

     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 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 executed a

settlement agreement and release of all claims and counterclaims in the above

captioned matter. On August 14, 2006, the case was dismissed with prejudice.

     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

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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.

Each of these lawsuits are currently coordinated in Contra Costa County Superior

Court. There are also several cross-complaints for indemnity between the

co-defendants in the coordinated lawsuits. The majority of the cases 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 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 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.

     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. The parties are currently engaged in

discovery and court ordered mediation.

     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

                                       33

<PAGE>

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 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. The released product

did not ignite and there were no deaths or injuries. Plantation

                                       34

<PAGE>

estimates the amount of product released to be approximately 553 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. 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 while the cause is

investigated and a remediation plan is proposed and approved by PHMSA. The cause

of the release is related to an original pipe manufacturing seam defect.

     Dublin, California

     In June 2006, near Dublin, California, our SFPP pipeline, which transports

refined petroleum products to San Jose, California, experienced a failure,

resulting in a release of product that affected a limited area along a

recreation path known as the Iron Horse Trail. Product impacts were primarily

limited to backfill of utilities crossing the pipeline. The release was located

on land administered by Alameda County, California. Remediation and monitoring

activities are ongoing under the supervision of The State of California

Department of Fish & Game. The cause of the release was outside force damage. We

are currently investigating potential recovery against third parties.

     Soda Springs, California

     In August 2006, our SFPP pipeline, which transports refined petroleum

products to Reno, Nevada, experienced a failure near Soda Springs, California,

resulting in a release of product that affected a limited area along Interstate

Highway 80. Product impacts were primarily limited to soil in an area between

the pipeline and Interstate Highway 80. The release was located on land

administered by Nevada County, California. Remediation and monitoring activities

are ongoing under the supervision of The State of California Department of Fish

& Game and Nevada County. 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 Pipeline and

Hazardous Materials Safety Administration (PHMSA) 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. PHMSA sought to have us implement a number of

changes to our integrity management program and also to impose a proposed civil

penalty of approximately $0.3 million. An administrative hearing was held on

April 11 and 12, 2005, and a final order was issued on June 26, 2006. We have

already addressed most of the concerns identified by PHMSA and continue to work

with them to ensure that our integrity management program satisfies all

applicable regulations. However, we are seeking clarification for portions of

this order and have received an extension of time to allow for discussions.

Along with the extension, we reserved our right to seek reconsideration if

needed. We have established a reserve for the $0.3 million proposed civil

penalty, and this matter is not expected to have a material impact 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.

                                       35

<PAGE>

     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.

     The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder

Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC;

Continental Oil Company; Chevron Corporation, California Superior Court, County

of Los Angeles, Case No. NC041463.

     We are and some of our subsidiaries are defendants in a lawsuit filed in

2005 captioned The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.;

Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC;

Continental Oil Company; Chevron Corporation, California Superior Court, County

of Los Angeles, Case No. NC041463. The suit involves claims for environmental

cleanup costs and rent at the former Los Angeles Marine Terminal in the Port of

Los Angeles. Plaintiff alleges that terminal cleanup costs could approach $18

million; however, Kinder Morgan believes that the clean up costs should be

substantially less and that cleanup costs must be apportioned among all the

parties to the litigation. Plaintiff also alleges that it is owed approximately

$2.8 million in past rent and an unspecified amount for future rent; however, we

believe that previously paid rents paid will offset some of the Plaintiff's rent

claim and that we have certain defenses to the payment of rent allegedly owed.

The lawsuit is set for trial in October 2007. We will vigorously defend these

matters and believe that the outcome will not have a material adverse effect on

us

     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.

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     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 September 30,

2006, we have accrued an environmental reserve of $65.2 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.

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.

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     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 September 30, 2006, we have recognized asset

retirement obligations in the aggregate amount of $46.6 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 September 30, 2006, we have recognized

asset retirement obligations in the aggregate amount of $1.7 million relating to

the businesses within our Natural Gas Pipelines business segment.

     We have included $1.4 million of our total asset retirement obligations as

of September 30, 2006 with "Accrued other current liabilities" in our

accompanying consolidated balance sheet. The remaining $46.9 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 nine months ended September 30,

2006 and 2005 is as follows (in thousands):

                                              Nine Months Ended September 30,

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

                                                    2006            2005

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

        Balance at beginning of period.........  $ 43,227       $  38,274

          Liabilities incurred.................     4,950             521

          Liabilities settled..................    (1,762)         (1,497)

          Accretion expense....................     1,853             807

          Revisions in estimated cash flows....        --            (522)

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

        Balance at end of period...............  $ 48,268       $  37,583

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

5. Distributions

     On August 14, 2006, we paid a cash distribution of $0.81 per unit to our

common unitholders and our Class B unitholders for the quarterly period ended

June 30, 2006. KMR, our sole i-unitholder, received 1,131,777 additional i-units

based on the $0.81 cash distribution per common unit. The distributions were

declared on July 19, 2006, payable to unitholders of record as of July 31, 2006.

     On October 18, 2006, we declared a cash distribution of $0.81 per unit for

the quarterly period ended September 30, 2006. The distribution will be paid on

November 14, 2006, to unitholders of record as of October 31, 2006. Our common

unitholders and Class B unitholders will receive cash. KMR will receive a

distribution in the form of additional i-units based on the $0.81 distribution

per common unit. The number of i-units distributed will be 1,160,520. For each

outstanding i-unit that KMR holds, a fraction of an i-unit (0.018981) will be

issued. The fraction was determined by dividing:

     o    $0.81, the cash amount distributed per common unit

     by

     o    $42.675, the average of KMR's shares' closing market prices from

          October 13-26, 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.

                                       38

<PAGE>

6. Intangibles

     Goodwill

     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. Goodwill is not subject to

amortization but must be tested for impairment at least annually. Following is

information related to our goodwill (in thousands):

                                                September 30,     December 31,

                                                    2006              2005

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

                Goodwill

                  Gross carrying amount.......   $ 832,942          $813,101

                  Accumulated amortization....     (14,142)          (14,142)

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

                  Net carrying amount.........     818,800           798,959

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

     Changes in the carrying amount of our goodwill for the nine months ended

September 30, 2006 are summarized as follows (in thousands):

<TABLE>

<CAPTION>

                                       Products    Natural Gas

                                       Pipeline     Pipelines      CO2       Terminals      Total

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

<S>                    <C> <C>         <C>          <C>          <C>         <C>          <C>     

Balance as of December 31, 2005......  $263,182     $288,435     $46,101     $201,241     $798,959

  Acquisitions.......................         -            -           -       17,763       17,763

  Purchase price adjustments.........         -            -           -        2,078        2,078

  Impairments........................         -            -           -            -            -

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

Balance as of September 30, 2006.....  $263,182     $288,435     $46,101     $221,082     $818,800

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

</TABLE>

     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.

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 September 30, 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. The caption "Investments" in our

accompanying consolidated balance sheets includes excess fair value of net

assets over book value costs of $178.6 million as of September 30, 2006 and

$181.7 million as of December 31, 2005.

     Other Intangibles

     Excluding goodwill, our other intangible assets 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 our accompanying consolidated balance sheets. Following is information

related to our intangible assets subject to amortization (in thousands):

                                       39

<PAGE>

                                             September 30,   December 31,

                                                 2006            2005

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

          Lease value

            Gross carrying amount.........   $   6,592       $   6,592

            Accumulated amortization......      (1,274)         (1,168)

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

            Net carrying amount...........       5,318           5,424

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

          Contracts and other

            Gross carrying amount.........     224,550         221,250

            Accumulated amortization......     (19,794)         (9,654)

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

            Net carrying amount...........     204,756         211,596

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

          Total Other intangibles, net....   $ 210,074       $ 217,020

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

     Amortization expense on our intangiblesconsisted of the following (in

     thousands):

<TABLE>

<CAPTION>

                        Three Months Ended September 30,        Nine Months Ended September 30,

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

                             2006              2005                  2006              2005

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

<S>                        <C>               <C>                  <C>                <C>    

Lease value............    $    35           $    35              $    106           $   106

Contracts and other....      3,372             3,487                10,140             4,318

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

Total amortization.....    $ 3,407           $ 3,522              $ 10,246           $ 4,424

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

</TABLE>

     As of September 30, 2006, our weighted average amortization period for our

intangible assets was approximately 18.9 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, $11.9 million and $11.8 million,

respectively.

7. Debt

     Our outstanding short-term debt as of September 30, 2006 was $1,147.2

million. The balance consisted of:

     o    $887.6 million of commercial paper borrowings;

     o    $250.0 million in principal amount of 5.35% senior notes due August

          15, 2007;

     o    a $5.8 million portion of 5.23% senior notes (our subsidiary, Kinder

          Morgan Texas Pipeline, L.P., is the obligor on the notes);

     o    a $5.0 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).

     The weighted average interest rate on all of our borrowings was

approximately 6.44% during the third quarter of 2006 and 5.40% during the third

quarter of 2005.

     Credit Facility

     Effective August 28, 2006, we terminated our $250 million unsecured

nine-month bank credit facility due November 21, 2006, and we increased our

existing five-year bank credit facility from $1.60 billion to $1.85 billion. The

five-year unsecured bank credit facility remains due August 18, 2010; however,

the bank facility can now be amended to allow for borrowings up to $2.1 billion.

There were no borrowings under our five-year credit facility as of December 31,

2005 or as of September 30, 2006.

     Our five-year credit facility is with a syndicate of financial

institutions, and Wachovia Bank, National Association is the administrative

agent. The amount available for borrowing under our credit facility as of

September 30, 2006 was reduced by:

                                       40

<PAGE>

     o    our outstanding commercial paper borrowings ($887.6 million as of

          September 30, 2006);

     o    a combined $353 million in five letters of credit that support our

          hedging of commodity price risks associated with the sale of natural

          gas, natural gas liquids and crude oil;

     o    a combined $49 million in two letters of credit that support

          tax-exempt bonds;

     o    a $19.9 million letter of credit that supports the construction of our

          Kinder Morgan Louisiana Pipeline (a natural gas pipeline); and

     o    a combined $16.2 million in 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. Borrowings under our commercial paper program reduce the

borrowings allowed under our credit facility. As of September 30, 2006, we had

$887.6 million of commercial paper outstanding with an average interest rate of

5.42%.

     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.

     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 ownership 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 will be 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.

                                       41

<PAGE>

     As of September 30, 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 September 30, 2006, Cortez Capital Corporation had $76.2 million of

commercial paper outstanding with an average interest rate of 5.31%, 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 September 30, 2006, $39.3 million in principal amount

of Senior 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 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 September 30,

2006, this letter of credit had an outstanding balance under our credit facility

of $24.9 million.

     Rockies Express Pipeline LLC Debt

     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 supports a $2.0 billion commercial paper program that was established

in May 2006, and borrowings under the commercial paper program reduce the

borrowings allowed under the credit facility; this facility can be amended to

allow for borrowings up to $2.5 billion. Borrowings under the Rockies Express

credit facility and commercial paper program will be primarily used to finance

the construction of the Rockies Express interstate natural gas pipeline and to

pay related expenses, and the borrowings will not reduce the borrowings allowed

under our credit facility described above in "--Credit Facility."

     In addition, pursuant to certain guaranty agreements, all three member

owners of West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline,

LLC) have agreed to guarantee borrowings under the Rockies Express credit

facility and under the Rockies Express commercial paper program severally in the

same proportion as their percentage ownership of the member interests in Rockies

Express Pipeline LLC. The three member owners and their respective ownership

interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline

LLC - 51%, Sempra Energy - 25%, and ConocoPhillips - 24%. As of September 30,

2006, Rockies Express Pipeline LLC had $583.5 million of commercial paper

outstanding, and there were no borrowings under its five-year credit

                                       42

<PAGE>

facility. Accordingly, as of September 30, 2006, our contingent share of Rockies

Express' debt was $297.6 million (51% of total commercial paper borrowings).

     Certain Relationships and Related Transactions

     In conjunction with our acquisition of Natural Gas Pipelines assets from

KMI on December 31, 1999 and 2000, KMI agreed to indemnify us and our general

partner with respect to 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 agreed to indemnify us and our general partner with respect to

approximately $210.8 million of our debt. Thus, as of September 30, 2006, KMI

has agreed to indemnify us and our general partner with respect to a total of

approximately $733.5 million of our debt. KMI would be obligated to perform

under this indemnity only if our assets were insufficient 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 September 30, 2006 and December 31, 2005, our partners' capital

consisted of the following limited partner units:

                                             September 30,    December 31,

                                                  2006            2005

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

        Common units.......................   162,779,676      157,005,326

        Class B units......................     5,313,400        5,313,400

        i-units............................    61,141,156       57,918,373

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

          Total limited partner units......   229,234,232      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 September 30, 2006, our common unit totals consisted of 148,423,941

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 August 15, 2006, we issued, in a public offering, 5,000,000 of our

common units at a price of $44.80 per unit, less commissions and underwriting

expenses. At the time of the offering, we granted the underwriters a 30-day

option to purchase up to an additional 750,000 common units from us on the same

terms and conditions, and we issued the additional 750,000 common units on

August 23, 2006 upon the underwriters' exercise of this option. After

commissions and underwriting expenses, we received net proceeds of approximately

$248.0 million for the issuance of these 5,750,000 common units, and we used the

proceeds to reduce the borrowings under our commercial paper program.

     On both September 30, 2006 and December 31, 2005, all of our 5,313,400

Class B units were held entirely by a wholly-owned subsidiary of KMI. The Class

B units are similar to our common units except that they are not eligible for

trading on the New York Stock Exchange. All of our Class B units were issued to

a wholly-owned subsidiary of KMI in December 2000.

     On both September 30, 2006 and December 31, 2005, all of our i-units were

held entirely by KMR. Our i-units are a separate class of limited partner

interests in us 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 to 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

                                       43

<PAGE>

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 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 1,131,777 i-units from us on August

14, 2006. These additional i-units distributed were based on the $0.81 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 $0.81 per unit paid on August 14, 2006 for

the second quarter of 2006 required an incentive distribution to our general

partner of $129.0 million. Our distribution of $0.78 per unit paid on August 12,

2005 for the second quarter of 2005 required an incentive distribution to our

general partner of $115.7 million. The increased incentive distribution to our

general partner paid for the second quarter of 2006 over the distribution paid

for the second quarter of 2005 reflects the increase in the amount distributed

per unit as well as the issuance of additional units.

     Our declared distribution for the third quarter of 2006 of $0.81 per unit

will result in an incentive distribution to our general partner of approximately

$133.0 million. This compares to our distribution of $0.79 per unit and

incentive distribution to our general partner of approximately $121.5 million

for the third 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 and

nine month periods ended September 30, 2006, and September 30, 2005, the

difference between our net income and our comprehensive income resulted from

unrealized gains or losses on derivative contracts utilized for hedging purposes

and from foreign currency translation adjustments. For more information on our

hedging activities, see Note 10. Our total comprehensive income was as follows

(in thousands):

<TABLE>

<CAPTION>

                                                Three Months Ended          Nine Months Ended

                                                   September 30,              September 30,

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

                                                2006          2005           2006        2005

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

<S>                                           <C>           <C>            <C>        <C>      

Net income................................... $223,818      $245,387       $717,588   $ 690,834

Foreign currency translation adjustments.....       72             8            456        (596)

Change in fair value of derivatives

used for hedging purposes....................  203,572      (259,826)      (281,295) (1,016,695)

Reclassification of change in fair

value of derivatives to net income...........  118,868       141,361        338,020     287,032

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

  Total other comprehensive

income/(loss)................................  322,512      (118,457)        57,181    (730,259)

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

Comprehensive income/(loss).................. $546,330      $126,930       $774,769   $ (39,425)

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

</TABLE>

                                       44

<PAGE>

10. Risk Management

     Certain of our business activities expose us to risks associated with

unfavorable changes in the market price of natural gas, natural gas liquids and

crude oil. We also have exposure to interest rate risk as a result of the

issuance of our fixed rate debt obligations. Pursuant to our management's

approved risk management policy, we use derivative contracts to hedge or reduce

our exposure to these risks, and we account for these hedging transactions

according to the provisions of SFAS No. 133, "Accounting for Derivative

Instruments and Hedging Activities" and associated amendments, collectively,

SFAS No. 133.

     Energy Commodity Price Risk Management

     We are exposed to risks associated with unfavorable 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. Such changes are often caused by

shifts in the supply and demand for these commodities, as well as their

locations. Our energy commodity derivative contracts act as a hedging (offset)

mechanism against the volatility of energy commodity prices by allowing us to

transfer this price risk to counterparties who are able and willing to bear it.

     Hedging effectiveness and ineffectiveness

     These contracts are used to offset the risk associated with an anticipated

future cash flow of a transaction that is expected to occur but whose value is

uncertain, therefore the resulting hedges are designated and qualified as cash

flow hedges in accordance with SFAS No. 133. For cash flow hedges, the portion

of the change in the value of derivative contracts that is effective in

offsetting undesired changes in expected cash flows (the effective portion) is

reported as a component of other comprehensive income (outside current earnings,

net income), but only to the extent that they can later offset the undesired

changes in expected cash flows during the period in which the hedged cash flows

affect earnings. Other comprehensive income consists of those financial items

that are included in "accumulated other comprehensive income/loss" on the

balance sheet but not included within net income on the statement of income.

Thus, in highly effective cash flow hedges, where there is no ineffectiveness,

other comprehensive income changes by exactly as much as the change in the value

of the derivative contacts and there is no impact on earnings.

     To the contrary, the portion of the change in the value of derivative

contracts that is not effective in offsetting undesired changes in expected cash

flows (the ineffective portion), as well as any component excluded from the

computation of the effectiveness of the derivative contracts, is required to be

recognized currently in earnings. Accordingly, as a result of ineffective

hedges, we recognized a gain of $0.5 million and a loss of $1.3 million,

respectively, during the three and nine month periods ended September 30, 2006,

and losses of $1.9 million and $2.3 million, respectively, during the three and

nine month periods ended September 30, 2005. All of the gains and losses we

recognized as a result of ineffective hedges are reported within the captions

"Natural gas sales," "Gas purchases and other costs of sales," and "Product

sales and other" in our accompanying consolidated statements of income. For each

of the three and nine months ended September 30, 2006 and 2005, we did not

exclude any component of the derivative contracts' gain or loss from the

assessment of hedge effectiveness.

     When the hedged sales and purchases take place and we record them into

earnings, or when a determination is made that a forecasted transaction will no

longer occur by the end of the originally specified time period or within an

additional two-month period of time thereafter, the gains and losses from the

effective portion of the change in the value of the derivative contracts are

removed from "accumulated other comprehensive income/loss" on the balance sheet

and reclassified into earnings. During the three and nine month periods ended

September 30, 2006, we reclassified $118.9 million and $338.0 million,

respectively, of "Accumulated other comprehensive loss" into earnings, and

during the three and nine month periods ended September 30, 2005, we

reclassified $141.3 million and $287.0 million, respectively, of "Accumulated

other comprehensive loss" into earnings.

     With the exception of the $2.9 million loss resulting from the

discontinuance of cash flow hedges related to the sale of our Douglas gathering

assets (described in Note 2), none of the reclassification of Accumulated other

comprehensive loss into earnings during the first nine months of 2006 or 2005

resulted from the discontinuance of

                                       45

<PAGE>

cash flow hedges due to a determination that the forecasted transactions would

no longer occur by the end of the originally specified time period or within an

additional two-month period of time thereafter, but rather resulted from the

hedged forecasted transactions actually affecting earnings (for example, when

the forecasted sales and purchases actually occurred). Approximately $437.4

million of our "Accumulated other comprehensive loss" balance of $1,022.5

million as of September 30, 2006 is expected to be reclassified into earnings

during the next twelve months.

     Fair Value of Energy Commodity Derivative Contracts

     Derivative contracts represent rights or obligations that meet the

definitions of assets or liabilities and should be reported in financial

statements. Furthermore, SFAS No. 133 requires derivative contracts 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 energy

commodity derivative contracts reflect the estimated amounts that we would

receive or pay to terminate the contracts at the reporting date, thereby taking

into account the current unrealized gains or losses on open contracts. We have

available market quotes for substantially all of the energy commodity derivative

contracts that we use, including: commodity futures and options contracts, fixed

price swaps, and basis swaps.

     The fair values of our energy commodity derivative contracts are included

in our accompanying consolidated balance sheets within "Other current assets,"

"Deferred charges and other assets," "Accrued other current liabilities," "Other

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 commodity derivative contracts associated with our

commodity price risk management activities and included on our accompanying

consolidated balance sheets as of September 30, 2006 and December 31, 2005 (in

thousands):

                                                 September 30,     December 31,

                                                      2006             2005

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

Derivatives-net asset/(liability)

  Other current assets......................      $  115,347       $  109,437

  Deferred charges and other assets.........          17,977           47,682

  Accounts payable-Related parties..........              --          (16,057)

  Accrued other current liabilities.........        (553,330)        (507,306)

  Other long-term liabilities and

  deferred credits..........................      $ (602,900)      $ (727,929)

     Our over-the-counter swaps and options are contracts 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 September 30, 2006. We both owe money

and are owed money under these derivative contracts. 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 contracts 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 derivative

contracts or when the market value of our derivative contracts 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 September 30, 2006, we had five outstanding

letters of credit totaling $353 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 September 30, 2006, we had no cash margin deposits associated with

our commodity contract positions and over-the-counter swap partners; however,

our counterparties associated with our commodity contract positions and

over-the-counter swap agreements had margin deposits with us totaling $1.4

million, and we reported this amount within "Accrued other liabilities" in our

accompanying consolidated balance sheet as of September 30,

                                       46

<PAGE>

2006. As of December 31, 2005, we had no cash margin deposits associated with

our commodity contract positions and over-the-counter swap partners.

     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 September 30, 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.

     As of September 30, 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 September

30, 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.

     Hedging effectiveness and ineffectiveness

     Our interest rate swaps have been designated as fair value hedges as

defined by SFAS No. 133. According to the provisions of SFAS No. 133, when

derivative contracts are used 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

                                       47

<PAGE>

contract is appropriate, 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.

     Fair Value of Interest Rate Swap Agreements

     The differences between the fair value and the original carrying value

associated with our interest rate swap agreements, that is, the derivative

contracts' 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.

     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 September 30,

2006 and December 31, 2005 (in thousands):

                                                     September 30,  December 31,

                                                          2006          2005

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

Derivatives-net asset/(liability)

  Deferred charges and other assets.................  $  67,444      $ 112,386

  Other long-term liabilities and deferred credits..    (22,638)       (13,917)

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

    Market value of interest rate swaps.............  $  44,806      $  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 contracts 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 September 30, 2006, all

of our interest rate swap agreements were with counterparties with investment

grade credit ratings.

     Other

     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.

11. Reportable Segments

     We divide our operations into four reportable business segments:

     o    Products Pipelines;

     o    Natural Gas Pipelines;

     o    CO2; and

                                       48

<PAGE>

     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, the transportation and marketing of carbon

dioxide used as a flooding medium for recovering crude oil from mature oil

fields, and the production and sale of natural gas and natural gas liquids. 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):

<TABLE>

<CAPTION>

                                                    Three Months Ended             Nine Months Ended

                                                       September 30,                 September 30,

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

                                                   2006            2005           2006           2005

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

Revenues(a)

<S>     <C>    <C>    <C>    <C>    <C>    <C>

   Products Pipelines

      Revenues from external customers.......  $   207,726     $   181,903    $   577,273    $   527,818

      Intersegment revenues..................            -               -              -              -

   Natural Gas Pipelines

      Revenues from external customers.......    1,650,427       2,108,788      5,082,183      5,198,337

      Intersegment revenues..................            -               -              -              -

   CO2

      Revenues from external customers.......      192,303         163,079        552,783        488,271

      Intersegment revenues..................            -               -              -              -

   Terminals

      Revenues from external customers.......      222,977         177,484        649,283        515,115

      Intersegment revenues..................          174               -            539              -

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

   Total segment revenues....................    2,273,607       2,631,254      6,862,061      6,729,541

   Less: Total intersegment revenues.........         (174)              -           (539)             -

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

     Total consolidated revenues.............  $ 2,273,433     $ 2,631,254    $ 6,861,522    $ 6,729,541

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

Operating expenses(b)

   Products Pipelines........................  $    94,609     $    60,613    $   234,149    $   169,739

   Natural Gas Pipelines.....................    1,519,129       1,996,737      4,693,969      4,863,524

   CO2.......................................       68,888          48,546        194,212        152,389

   Terminals.................................      122,230          94,318        354,892        271,470

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

     Total consolidated operating expenses...  $ 1,804,856     $ 2,200,214    $ 5,477,222    $ 5,457,122

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

Other expense (income)(c)

   Products Pipelines........................  $         -     $         -    $         -    $         -

   Natural Gas Pipelines.....................            -               -        (15,114)             -

   CO2.......................................            -               -              -              -

   Terminals.................................            -               -              -              -

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

     Total consolidated other

     expense (income)........................  $         -     $         -    $   (15,114)   $         -

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

Depreciation, depletion and amortization

   Products Pipelines........................  $    20,820     $    19,849    $    61,541    $    59,071

   Natural Gas Pipelines.....................       15,959          15,205         47,938         45,779

   CO2.......................................       50,731          34,658        132,021        111,822

   Terminals.................................       19,320          15,644         55,280         41,972

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

     Total consol. depreciation, depletion

     and amortization........................  $   106,830     $    85,356    $   296,780    $   258,644

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

</TABLE>

                                       49

<PAGE>

<TABLE>

<CAPTION>

                                                    Three Months Ended             Nine Months Ended

                                                       September 30,                 September 30,

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

                                                   2006            2005           2006           2005

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

Earnings from equity investments(d)

<S>                                             <C>             <C>            <C>            <C>       

   Products Pipelines........................   $     514       $   6,256      $   11,067     $   21,706

   Natural Gas Pipelines.....................      10,062           8,705          31,833         25,733

   CO2.......................................       3,380           5,533          14,113         21,932

   Terminals.................................          76              18             190             51

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

     Total consolidated equity earnings......   $  14,032       $  20,512      $   57,203     $   69,422

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

Amortization of excess cost of equity

investments

   Products Pipelines........................   $     841       $     832      $    2,521     $    2,512

   Natural Gas Pipelines.....................          71              70             210            208

   CO2.......................................         504             505           1,513          1,513

   Terminals.................................           -               -               -              -

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

     Total consol. amortization of excess

     cost of investments.....................   $   1,416       $   1,407      $    4,244     $    4,233

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

Interest income

   Products Pipelines........................   $   1,123       $   1,147      $    3,358     $    3,445

   Natural Gas Pipelines.....................           -             193             150            530

   CO2.......................................           -               -               -              -

   Terminals.................................           -               -               -              -

     Total segment interest income...........       1,123           1,340           3,508          3,975

   Unallocated interest income...............         238             109           1,599            374

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

     Total consolidated interest income......   $   1,361       $   1,449      $    5,107     $    4,349

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

Other, net - income (expense)(e)

   Products Pipelines........................   $   1,583       $     633      $    7,783     $      998

   Natural Gas Pipelines.....................         376           1,367             725          1,509

   CO2.......................................         324              (6)            336             (6)

   Terminals.................................       1,056             886           2,335           (293)

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

     Total consolidated other, net - income

     (expense)...............................   $   3,339       $   2,880      $   11,179     $    2,208

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

Income tax benefit (expense)(f)

   Products Pipelines........................   $     584       $  (2,171)     $   (3,288)    $   (8,209)

   Natural Gas Pipelines.....................        (973)           (361)           (900)        (1,899)

   CO2.......................................         (57)           (151)           (181)          (263)

   Terminals.................................      (3,599)         (2,372)         (7,451)        (9,874)

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

     Total consolidated income tax benefit

     (expense)...............................   $  (4,045)      $  (5,055)     $  (11,820)    $  (20,245)

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

Segment earnings

   Products Pipelines........................   $  95,260       $ 106,474      $  297,982     $  314,436

   Natural Gas Pipelines.....................     124,733         106,680         386,988        314,699

   CO2.......................................      75,827          84,746         239,305        244,210

   Terminals.................................      79,134          66,054         234,724        191,557

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

     Total segment earnings(g)...............     374,954         363,954       1,158,999      1,064,902

   Interest and corporate administrative

   expenses(h)...............................    (151,136)       (118,567)       (441,411)      (374,068)

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

     Total consolidated net income...........   $ 223,818       $ 245,387      $  717,588     $  690,834

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

Segment earnings before depreciation,

  depletion, amortization and amortization

  of excess cost of equity investments(i)

   Products Pipelines........................   $ 116,921       $ 127,155      $  362,044     $  376,019

   Natural Gas Pipelines.....................     140,763         121,955         435,136        360,686

   CO2.......................................     127,062         119,909         372,839        357,545

   Terminals.................................      98,454          81,698         290,004        233,529

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

     Total segment earnings before DD&A......     483,200         450,717       1,460,023      1,327,779

   Total consol. depreciation, depletion and

   amortization..............................    (106,830)        (85,356)       (296,780)      (258,644)

   Total consol. amortization of excess cost

   of investments............................      (1,416)         (1,407)         (4,244)        (4,233)

   Interest and corporate administrative

   expenses..................................    (151,136)       (118,567)       (441,411)      (374,068)

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

     Total consolidated net income ..........   $ 223,818       $ 245,387      $  717,588     $  690,834

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

</TABLE>

                                       50

<PAGE>

<TABLE>

<CAPTION>

                                                    Three Months Ended             Nine Months Ended

                                                       September 30,                 September 30,

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

                                                   2006            2005           2006           2005

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

Capital expenditures(j)

<S>                                             <C>             <C>            <C>            <C>       

   Products Pipelines.........................  $   30,685      $   82,592     $  151,927     $  180,309

   Natural Gas Pipelines......................      18,725          31,707        228,294         64,854

   CO2........................................      75,304          92,603        208,396        219,545

   Terminals..................................      65,392          48,675        162,729        132,478

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

     Total consolidated capital expenditures..  $  190,106      $  255,577     $  751,346     $  597,186

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

</TABLE>

                                                  September 30,     December 31,

                                                      2006             2005

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

                Assets

                  Products Pipelines............  $  3,895,385     $  3,873,939

                  Natural Gas Pipelines.........     3,896,528        4,139,969

                  CO2...........................     1,859,407        1,772,756

                  Terminals.....................     2,243,150        2,052,457

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

                  Total segment assets..........    11,894,470       11,839,121

                  Corporate assets(k)...........       128,562           84,341

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

                  Total consolidated assets.....  $ 12,023,032     $ 11,923,462

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

--------

(a)  Nine month 2006 amounts include a reduction of $1,819 to our CO2 business

     segment from a loss on derivative contracts used to hedge forecasted crude

     oil sales.

(b)  Includes natural gas purchases and other costs of sales, operations and

     maintenance expenses, fuel and power expenses and taxes, other than income

     taxes. Nine month 2006 amounts include expenses of $13,458 to our Products

     Pipelines business segment and $1,500 to our Natural Gas Pipelines business

     segment associated with environmental liability adjustments, and a $6,244

     reduction in expense to our Natural Gas Pipelines business segment due to

     the release of a reserve related to a natural gas purchase/sales contract.

     Three and nine month 2005 amounts include a $5,000 increase in expense to

     our Products Pipelines business segment associated with a North System

     liquids inventory reconciliation adjustment.

(c)  Nine month 2006 amount represents a $15,114 gain to our Natural Gas

     Pipelines business segment from the combined sale of our Douglas natural

     gas gathering system and our Painter Unit fractionation facility.

(d)  Nine month 2006 amounts include a $4,861 increase in expense to our

     Products Pipelines business segment associated with environmental liability

     adjustments on Plantation Pipe Line Company.

(e)  Nine month 2006 amounts include a $5,700 increase in income to our Products

     Pipelines business segment from the settlement of transmix processing

     contracts.

(f)  Nine month 2006 amounts include a $1,871 decrease in expense to our

     Products Pipelines business segment associated with the tax effect on

     expenses from environmental liability adjustments made by Plantation Pipe

     Line Company and described in footnote (d).

(g)  Includes revenues, earnings from equity investments, income taxes,

     allocable interest income and other, net, less operating expenses, other

     expense (income), depreciation, depletion and amortization, and

     amortization of excess cost of equity investments.

(h)  Includes unallocated interest income, interest and debt expense, general

     and administrative expenses and minority interest expense.

(i)  Includes revenues, earnings from equity investments, income taxes,

     allocable interest income and other, net, less operating expenses and other

     expense (income).

(j)  Includes sustaining capital expenditures of $15,576 and $42,845 for the

     three months ended September 30, 2006 and 2005, respectively, and includes

     sustaining capital expenditures of $76,229 and $95,801 for the nine months

     ended September 30, 2006 and 2005, respectively. Sustaining capital

     expenditures are defined as capital expenditures which do not increase the

     capacity of an asset.

(k)  Includes cash, cash equivalents, margin and restricted deposits, certain

     unallocable deferred charges, and risk management assets related to the

     market value of interest rate swaps.

                                       51

<PAGE>

     We do not attribute interest and debt expense to any of our reportable

business segments. For the three months ended September 30, 2006 and 2005, we

reported (in thousands) total consolidated interest expense of $89,662 and

$69,797, respectively. For the nine months ended September 30, 2006 and 2005, we

reported (in thousands) total consolidated interest expense of $251,216 and

$196,736, 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 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):

<TABLE>

<CAPTION>

                                                           Other Post-retirement Benefits

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

                                        Three Months Ended September 30,     Nine Months Ended September 30,

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

                                             2006              2005               2006             2005

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

Net periodic benefit cost

<S>                                         <C>               <C>                <C>              <C>   

Service cost...........................     $    3            $    2             $    8           $    6

Interest cost..........................         68                77                202              231

Amortization of prior service cost.....        (29)              (29)               (88)             (87)

Actuarial (gain).......................       (114)             (127)              (340)            (381)

Net periodic benefit cost..............     $  (72)           $  (77)            $ (218)          $ (231)

</TABLE>

     Our net periodic benefit cost for the third quarter and the first nine

months of 2006 were credits of $72,000 and $218,000, respectively, 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 were 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 September 30, 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

                                       52

<PAGE>

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 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."

     In June 2006, Plantation paid to us $1.1 million in principal amount under

the note, and as of September 30, 2006, the principal amount receivable from

this note was $93.1 million. We included $2.2 million of this balance within

"Accounts, notes and interest receivable, net-Related parties" on our

consolidated balance sheet as of September 30, 2006, and we included the

remaining $90.9 million balance as "Notes receivable-Related parties."

     Coyote Gas Treating, LLC

     Coyote Gas Treating, LLC is a joint venture that was organized in December

1996. It is referred to as Coyote Gulch in this report. The sole asset owned by

Coyote Gulch is a 250 million cubic feet per day natural gas treating facility

located in La Plata County, Colorado. Prior to the contribution of our ownership

interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006, discussed

below, we were the managing partner and owned a 50% equity interest in 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 corresponded 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, the owners of Coyote Gulch agreed to a resolution that would

transfer Coyote Gulch's notes payable 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.

     In the third quarter of 2006, the Southern Ute Indian Tribe acquired the

remaining 50% ownership interest in Coyote Gulch from Enterprise Field Services

LLC. The acquisition was made effective March 1, 2006. On September 1, 2006, we

and the Southern Ute Tribe agreed to a resolution that would transfer all of the

members' equity in Coyote Gulch to the members' equity of Red Cedar Gathering, a

joint venture organized in August 1994 and referred to in this report as Red

Cedar. Red Cedar owns and operates natural gas gathering, compression and

treating facilities in the Ignacio Blanco Field in La Plata County, Colorado,

and is owned 49% by us and 51% by the Southern Ute Tribe. Under the terms of a

five-year operating lease agreement that became effective January 1, 2002, Red

Cedar also operates the gas treating facility owned by Coyote Gulch and is

responsible for all operating and maintenance expenses and capital costs.

     According to the provisions of the September 1, 2006 resolution, we and the

Southern Ute Tribe contributed the value of our respective 50% ownership

interests in Coyote Gulch to Red Cedar, and as a result, Coyote Gulch became a

wholly owned subsidiary of Red Cedar. The value of our 50% equity contribution

from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7 million, and this

amount remains included within "Investments" on our consolidated balance sheet

as of September 30, 2006.

                                       53

<PAGE>

14. Regulatory Matters

     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

     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, referred to in this

report as INGAA, 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. On May 10, 2006,

the court issued an order establishing a briefing schedule. Under the schedule,

INGAA filed its initial brief on June 23, 2006. Both the FERC's and INGAA's

reply briefs have been filed.

     Due to the implementation of this FERC order on January 1, 2006, which

caused our FERC-regulated natural gas pipelines to expense certain pipeline

integrity management program costs that would have been capitalized, our Kinder

Morgan Interstate Gas Transmission system, referred to in this report as KMIGT,

expects an increase of approximately $0.9 million in operating expenses in 2006

compared to 2005. Also, beginning in the third quarter of 2006, our Texas

intrastate natural gas pipeline group and the operations included in our

Products Pipelines and CO2 business segments began recognizing certain costs

incurred as part of their pipeline integrity management program as operating

expense in the period incurred, and in addition, recorded an expense for costs

previously capitalized during the first six months of 2006. For the year 2006

compared to 2005, we expect this change to result in operating expense increases

of approximately $1.8 million for our Texas intrastate gas group, $26.8 million

for our Products Pipelines business segment, and $1.4 million for our CO2

business segment. Combined, this change did not have any material effect to

prior periods and is not expected to have a material impact on our financial

position, results of operations, or cash flows for the 2006 annual period. In

addition, due to the fact that these amounts will not be capitalized but instead

charged to expense, we expect our 2006 sustaining capital expenditures to be

reduced by similar amounts.  

     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

                                       54

<PAGE>

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.

     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, the FERC proposed 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 proposed 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.

     On June 19, 2006, FERC issued Order No. 678 allowing for broader

market-based pricing of storage services. The rule expands the alternatives that

can be considered in evaluating competition, provides that market-based pricing

may be available even when market power is present (if market-based pricing is

needed to stimulate development), and treats expansions of existing storage

facilities similar to new storage facilities. The order became effective July

27, 2006. Several parties have filed for rehearing of this Order.

     Natural Gas Pipeline Expansion Filings

     Rockies Express Pipeline

     On May 31, 2006, in FERC Docket No. CP06-354-000, Rockies Express Pipeline

LLC filed an application for authorization to construct and operate certain

facilities comprising its proposed "Rockies Express-West Project." This project

is the first planned segment extension of the Rockies Express' currently

certificated facilities, which includes (i) a 136-mile pipeline segment

currently in operation from the Meeker Hub in Colorado to the Wamsutter Hub in

Wyoming, and (ii) a 191-mile segment currently under construction and expected

to be in service by January 1, 2007, from Wamsutter to the Cheyenne Hub located

in Weld County, Colorado. The Rockies Express-West Project will be comprised of

approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne

Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain

County, Missouri. The segment extension proposes to transport approximately 1.5

billion cubic feet per day of natural gas across the following five states:

Wyoming, Colorado, Nebraska, Kansas and Missouri. The project will also include

certain improvements to existing Rockies Express facilities located to the west

of the Cheyenne Hub.

     On September 21, 2006, the FERC issued a favorable preliminary

determination on all non-environmental issues of the project, approving Rockies

Express' application (i) to construct and operate the 713 miles of new natural

gas transmission facilities from the Cheyenne Hub and (ii) to lease capacity on

Questar Overthrust Pipeline Company, which will extend the Rockies Express

system 140 miles west from Wamsutter to the Opal Hub in Wyoming. Pending

completion of the FERC environmental review and the issuance of a certificate,

the project is expected to begin service on January 1, 2008. Rockies Express

will file a separate application in the future for its proposed "Rockies

Express-East Project," which will extend the pipeline from eastern Missouri to

the Clarington Hub in eastern Ohio.

                                       55

<PAGE>

     TransColorado Pipeline

     On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado Gas

Transmission Company filed an application for authorization to construct and

operate certain facilities comprising its proposed "Blanco-Meeker Expansion

Project." Upon implementation, this project will facilitate the transportation

of up to approximately 250 million cubic feet per day of natural gas from the

Blanco Hub area in San Juan County, New Mexico through TransColorado's existing

interstate pipeline for delivery to the Rockies Express Pipeline at an existing

point of interconnection located in the Meeker Hub in Rio Blanco County,

Colorado.

     Kinder Morgan Louisiana Pipeline

          On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an

application with the FERC requesting approval to construct and operate our

Kinder Morgan Louisiana Pipeline. The pipeline will extend approximately 135

miles from Cheniere's Sabine Pass liquefied natural gas terminal in Cameron

Parish, Louisiana, to various delivery points in Louisiana and will provide

interconnects with many other natural gas pipelines, including KMI's Natural Gas

Pipeline Company of America. The project is supported by fully subscribed

capacity and long-term customer commitments with Chevron and Total. The entire

approximately $500 million project is expected to be in service in the second

quarter of 2009.

     FERC Order No. 2004

     On July 20, 2006, the FERC accepted our interstate pipelines' May 19, 2005

compliance filing under Order No. 2004, the order adopting standards of conduct

that govern the relationships between natural gas transmission providers and all

their marketing and energy affiliates.

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.

                                       56

<PAGE>

     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.

     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 from 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

                                       57

<PAGE>

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).

Adoption of this Statement should not have any immediate effect on our

consolidated financial statements, and we will apply this guidance

prospectively.

     EITF 06-3

     On June 28, the FASB ratified the consensuses reached by the Emerging

Issues Task Force on EITF 06-3, "How Taxes Collected from Customers and Remitted

to Governmental Authorities Should Be Presented in the Income Statement (That

is, Gross versus Net Presentation)." According to the provisions of EITF 06-3:

     o    taxes assessed by a governmental authority that are directly imposed

          on a revenue-producing transaction between a seller and a customer may

          include, but are not limited to, sales, use, value added, and some

          excise taxes; and

     o    that the presentation of such taxes on either a gross (included in

          revenues and costs) or a net (excluded from revenues) basis is an

          accounting policy decision that should be disclosed pursuant to

          Accounting Principles Board Opinion No. 22 (as amended) "Disclosure of

          Accounting Policies." In addition, for any such taxes that are

          reported on a gross basis, a company should disclose the amounts of

          those taxes in interim and annual financial statements for each period

          for which an income statement is presented if those amounts are

          significant. The disclosure of those taxes can be done on an aggregate

          basis.

     EITF 06-3 should be applied to financial reports for interim and annual

reporting periods beginning after December 15, 2006 (January 1, 2007 for us).

Because the provisions of EITF 06-3 require only the presentation of additional

disclosures, we do not expect the adoption of EITF 06-3 to have an effect on our

consolidated financial statements.

     FIN 48

     In June 2006, the FASB issued Interpretation (FIN) No. 48, "Accounting for

Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109." This

interpretation clarifies the accounting for uncertainty in income taxes

recognized in an enterprise's financial statements in accordance with SFAS No.

109, "Accounting for Income Taxes." This Interpretation prescribes a recognition

threshold and measurement attribute for the financial statement recognition and

measurement of a tax position taken or expected to be taken in a tax return. It

also provides guidance on derecognition, classification, interest and penalties,

accounting in interim periods, disclosure, and transition. This Interpretation

is effective for fiscal years beginning after December 15, 2006 (January 1, 2007

for us). We are currently reviewing the effects of this Interpretation.

     SAB 108

     In September 2006, the Securities and Exchange Commission issued Staff

Accounting Bulletin No. 108. This Bulletin requires a "dual approach" for

quantifications of errors using both a method that focuses on the income

statement impact, including the cumulative effect of prior years' misstatements,

and a method that focuses on the period-end balance sheet. SAB No. 108 will be

effective for us as of January 1, 2007. The adoption of this Bulletin is not

expected to have a material impact on our consolidated financial statements.

     SFAS No. 157

     On September 15, 2006, the FASB issued SFAS No. 157, "Fair Value

Measurements." This Statement defines fair value in generally accepted

accounting principles, and expands disclosures about fair value measurements. It

addresses how companies should measure fair value when they are required to use

a fair value measure for

                                       58

<PAGE>

recognition or disclosure purposes under generally accepted accounting

principles and, as a result, there is now a common definition of fair value to

be used throughout generally accepted accounting principles.

     This Statement applies to other accounting pronouncements that require or

permit fair value measurements; the Board having previously concluded in those

accounting pronouncements that fair value is the relevant measurement attribute.

Accordingly, this Statement does not require any new fair value measurements;

however, for some entities the application of this Statement will change current

practice. The changes to current practice resulting from the application of this

Statement relate to the definition of fair value, the methods used to measure

fair value, and the expanded disclosures about fair value measurements.

     This Statement is effective for financial statements issued for fiscal

years beginning after November 15, 2007 (January 1, 2008 for us), and interim

periods within those fiscal years. This Statement is to be applied prospectively

as of the beginning of the fiscal year in which this Statement is initially

applied, with certain exceptions. The disclosure requirements of this Statement

are to be applied in the first interim period of the fiscal year in which this

Statement is initially applied. We are currently reviewing the effects of this

Statement.

     SFAS No. 158

     On September 29, 2006, the FASB issued SFAS No. 158, "Employers' Accounting

for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB

Statement Nos. 87, 88, 106 and 132(R)." This Statement requires an employer to:

     o    recognize the overfunded or underfunded status of a defined benefit

          pension plan or postretirement benefit plan (other than a

          multiemployer plan) as an asset or liability in its statement of

          financial position;

     o    measure a plan's assets and its obligations that determine its funded

          status as of the end of the employer's fiscal year (with limited

          exceptions), and to disclose in the notes to financial statements

          additional information about certain effects on net periodic benefit

          cost for the next fiscal year that arise from delayed recognition of

          the gains or losses, prior service costs or credits, and transition

          assets or obligations; and

     o    recognize changes in the funded status of a plan in the year in which

          the changes occur through comprehensive income.

     Past accounting standards only required an employer to disclose the

complete funded status of its plans in the notes to the financial statements.

Recognizing the funded status of a company's benefit plans as a net liability or

asset on its balance sheet will require an offsetting adjustment to "Accumulated

other comprehensive income/loss" in shareholders' equity ("Partners' Capital"

for us). SFAS No. 158 does not change how pensions and other postretirement

benefits are accounted for and reported in the income statement--companies will

continue to follow the existing guidance in previous accounting standards.

Accordingly, the amounts to be recognized in "Accumulated other comprehensive

income/loss" representing unrecognized gains/losses, prior service

costs/credits, and transition assets/obligations will continue to be amortized

under the existing guidance. Those amortized amounts will continue to be

reported as net periodic benefit cost in the income statement. Prior to SFAS No.

158, those unrecognized amounts were only disclosed in the notes to the

financial statements.

     According to the provisions of this Statement, an employer with publicly

traded equity securities is required to initially recognize the funded status of

a defined benefit pension plan or postretirement benefit plan and to provide the

required disclosures as of the end of the fiscal year ending after December 15,

2006 (December 31, 2006 for us). In the year that the recognition provisions of

this Statement are initially applied, an employer is required to disclose, in

the notes to the annual financial statements, the incremental effect of applying

this Statement on individual line items in the year-end statement of financial

position. The requirement to measure plan assets and benefit obligations as of

the date of the employer's fiscal year-end statement of financial position is

effective for fiscal years ending after December 15, 2008 (December 31, 2008 for

us). In the year that the measurement date provisions of this Statement are

initially applied, a business entity is required to disclose the separate

adjustments of retained earnings ("Partners' Capital" for us) and "Accumulated

other comprehensive income/loss" from applying this Statement. While earlier

application of the recognition of measurement date provisions is allowed, we

have opted not to adopt this part of the Statement early.

                                       59

<PAGE>

     We will apply the guidance of SFAS No. 158 prospectively; retrospective

application of this Statement is not permitted. We are currently reviewing the

effects of this Statement, but we do not expect the adoption of this Statement

to have a material effect on our statement of financial position as of December

31, 2006. Currently, based on the most recent measurement of our benefit plan

assets and obligations, we expect the incremental impact on our December 31,

2006 statement of financial position from adopting the recognition provisions of

this Statement to be as follows (amounts are approximations): a $6.1 million

decrease in total liabilities, and a $6.1 million increase in partners' capital

("Accumulated other comprehensive income/loss.")

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. You should read the following discussion and analysis 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

     Accounting standards require information in financial statements about the

risks and uncertainties inherent in significant estimates, and the application

of generally accepted accounting principles involves the exercise of varying

degrees of judgment. 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 our assets and

liabilities, our revenues and expenses during the reporting period, 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,

examples of certain areas that require more judgment relative to others include

our use of estimates in determining:

     o    the economic useful lives of our assets;

     o    the fair values used to determine possible asset impairment charges;

     o    reserves for environmental claims, legal fees, transportation rate

          cases and other litigation liabilities;

     o    provisions for uncollectible accounts receivables;

     o    exposures under contractual indemnifications; and

     o    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

                                       60

<PAGE>

not been any significant changes in these policies and estimates during the

three and nine months ended September 30, 2006.

Results of Operations

     Consolidated

<TABLE>

<CAPTION>

                                                                        Three Months Ended              Nine Months Ended

                                                                           September 30,                  September 30,

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

                                                                       2006            2005            2006           2005

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

                                                                                          (In thousands)

Earnings before depreciation, depletion and amortization

  expense and amortization of excess cost of equity investments

<S>                                                                 <C>             <C>            <C>            <C>       

    Products Pipelines...........................................   $ 116,921       $ 127,155      $  362,044     $  376,019

    Natural Gas Pipelines........................................     140,763         121,955         435,136        360,686

    CO2..........................................................     127,062         119,909         372,839        357,545

    Terminals....................................................      98,454          81,698         290,004        233,529

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

Segment earnings before depreciation, depletion and

  amortization expense and amortization of excess cost of

  equity investments(a)..........................................     483,200         450,717       1,460,023      1,327,779

    Depreciation, depletion and amortization expense.............    (106,830)        (85,356)       (296,780)      (258,644)

    Amortization of excess cost of equity investments............      (1,416)         (1,407)         (4,244)        (4,233)

    Interest and corporate administrative expenses(b)............    (151,136)       (118,567)       (441,411)      (374,068)

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

Net income.......................................................   $ 223,818       $ 245,387      $  717,588     $  690,834

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

</TABLE>

-----------

(a)  Includes revenues, earnings from equity investments, income taxes,

     allocable interest income and other, net, less operating expenses and other

     expense (income). Operating expenses include natural gas purchases and

     other costs of sales, operations and maintenance expenses, fuel and power

     expenses and taxes, other than income taxes.

(b)  Includes unallocated interest income, interest and debt expense, general

     and administrative expenses (including unallocated litigation and

     environmental expenses) and minority interest expense.

          Our consolidated net income for the quarterly period ended September

30, 2006 was $223.8 million ($0.40 per diluted unit), compared to $245.4 million

($0.57 per diluted unit) for the quarterly period ended September 30, 2005. Our

consolidated net income was negatively impacted in the third quarter of 2006 by

(i) an $18.1 million decrease in net income from our Products Pipelines business

segment, consisting of an approximate $11.6 million decrease related to a change

that transferred certain pipeline integrity management costs from sustaining

capital expenditures to expense and an approximate $6.5 million decrease related

to pipeline integrity costs expensed in the third quarter of 2006 and (ii) a

$16.1 million decrease in net income from our CO2 business segment, related to

higher depreciation expenses that were largely caused by a higher

unit-of-production depreciation rate as a result of a reduction in reserves at

our SACROC oil field unit. However, due to the fact that we deduct our

sustaining capital expenditures from our net income to determine distributable

cash flow, and that depreciation, depletion and amortization expenses do not

affect cash and are therefore added to our net income to determine distributable

cash flow, these two items negatively impacted our overall distributable cash

flow for the third quarter of 2006 by only $3.5 million. The difference

primarily relates to our share of Plantation Pipe Line's third quarter 2006

pipeline integrity expenses, which were included in our net income under the

equity method of accounting but excluded from our consolidated sustaining

capital expenditures.

     Net income for the nine months ended September 30, 2006 was $717.6 million

($1.45 per diluted unit), compared to $690.8 million ($1.61 per diluted unit)

for the first nine months of 2005. We earned total revenues of $2,273.4 million

and $2,631.3 million, respectively, in the three month periods ended September

30, 2006 and 2005, and revenues of $6,861.5 million and $6,729.5 million,

respectively, in the nine month periods ended September 30, 2006 and 2005.

     We declared a cash distribution of $0.81 per unit for the third quarter of

2006 (an annualized rate of $3.24). This distribution is almost 3% higher than

the $0.79 per unit distribution we made for the third quarter of 2005. 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.

                                       61

<PAGE>

     Our annual published budget calls for cash distributions of $3.28 per unit

for 2006; however, no assurance can be given that we will be able to achieve

this level of distribution. Our budget does not take into account any

transportation rate reductions or capital costs associated with financing the

payment of reparations sought by shippers on our Pacific operations' interstate

pipelines, which we now estimate will be approximately $15 million in 2006. We

currently expect to distribute between $3.24 and $3.28 per unit for 2006. For

more information on our Pacific operations' regulatory proceedings, see Note 3

to our consolidated financial statements included elsewhere in this report.

Segment earnings before depreciation, depletion and amortization expenses

     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 (segment

earnings before depreciation, depletion and amortization expenses) internally

for evaluating segment performance and deciding how to allocate resources to our

four reportable business segments. For the third quarters of 2006 and 2005, our

total segment earnings before depreciation, depletion and amortization totaled

$483.2 million and $450.7 million, respectively, and for the first nine months

of 2006 and 2005, our total segment earnings before depreciation, depletion and

amortization totaled $1,460.0 million and $1,327.8 million, respectively. As

discussed below in "--Products Pipelines," our total segment earnings before

depreciation, depletion and amortization expenses in both the third quarter and

first nine months of 2006 were negatively impacted by $18.1 million due to a

change related to the expensing of pipeline integrity costs.

     On a consolidated basis, throughout the first nine months of 2006, we

increased our segment earnings before depreciation, depletion and amortization

expenses in 2006, relative to 2005, by capitalizing on:

     o    improved sales margins on renewal and incremental natural gas sale

          contracts and higher earnings from natural gas storage and processing

          activities, largely from our Texas intrastate natural gas pipeline

          group;

     o    strong natural gas gathering operations from the Red Cedar Gathering

          Company, our 49%-owned equity investee;

     o    the sales of carbon dioxide, crude oil and natural gas plant liquids

          products at higher average prices, and transporting higher volumes of

          carbon dioxide for use in enhanced oil recovery operations; and

     o    incremental contributions from bulk and liquids terminal operations

          acquired since the third quarter of 2005.

     Products Pipelines

<TABLE>

<CAPTION>

                                                                    Three Months Ended             Nine Months Ended

                                                                       September 30,                  September 30,

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

                                                                   2006            2005           2006           2005

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

                                                                       (In thousands, except operating statistics)

<S>                                                            <C>             <C>             <C>            <C>      

Revenues...................................................    $ 207,726       $ 181,903       $ 577,273      $ 527,818

Operating expenses(a)......................................      (94,609)        (60,613)       (234,149)      (169,739)

Earnings from equity investments(b)........................          514           6,256          11,067         21,706

Interest income and Other, net-income (expense)(c).........        2,706           1,780          11,141          4,443

Income taxes(d)............................................          584          (2,171)         (3,288)        (8,209)

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

  Earnings before depreciation, depletion and

  amortization Expense and amortization of excess

  cost of equity investments...............................      116,921         127,155         362,044        376,019

Depreciation, depletion and amortization expense...........      (20,820)        (19,849)        (61,541)       (59,071)

Amortization of excess cost of equity investments..........         (841)           (832)         (2,521)        (2,512)

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

  Segment earnings.........................................    $  95,260       $ 106,474       $ 297,982      $ 314,436

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

</TABLE>

                                       62

<PAGE>

<TABLE>

<CAPTION>

                                                                    Three Months Ended             Nine Months Ended

                                                                       September 30,                 September 30,

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

                                                                    2006           2005           2006           2005

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

<S>                                                                 <C>            <C>            <C>            <C>  

Gasoline (MMBbl)...........................................         117.1          117.5          344.1          344.4

Diesel fuel (MMBbl)........................................          42.2           41.7          120.2          122.8

Jet fuel (MMBbl)...........................................          30.0           29.3           89.4           88.1

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

  Total refined products volumes (MMBbl)...................         189.3          188.5          553.7          555.3

Natural gas liquids (MMBbl)................................           9.3            8.4           28.0           26.1

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

  Total delivery volumes (MMBbl)(e)........................         198.6          196.9          581.7          581.4

</TABLE>

----------

(a)  Nine month 2006 amount includes a $13,458 increase in expense associated

     with environmental liability adjustments. Third quarter and nine month 2005

     amounts include a $5,000 increase in expense associated with a North System

     liquids inventory reconciliation adjustment.

(b)  Nine month 2006 amount includes a $4,861 increase in expense associated

     with environmental liability adjustments on Plantation Pipe Line Company.

(c)  Nine month 2006 amount includes a $5,700 increase in income from the

     settlement of transmix processing contracts.

(d)  Nine month 2006 amount includes a $1,871 decrease in expense associated

     with the tax effect on our share of environmental expenses incurred by

     Plantation Pipe Line Company and described in footnote (b).

(e)  Includes Pacific, Plantation, North System, CALNEV, Central Florida,

     Cypress and Heartland pipeline volumes.

     Our Products Pipelines segment reported earnings before depreciation,

depletion and amortization of $116.9 million on revenues of $207.7 million in

the third quarter of 2006. This compares to earnings before depreciation,

depletion and amortization of $127.2 million on revenues of $181.9 million in

the third quarter of 2005. For the comparable nine month periods, the segment

reported earnings before depreciation, depletion and amortization of $362.0

million on revenues of $577.3 million in 2006, and earnings before depreciation,

depletion and amortization of $376.0 million on revenues of $527.8 million in

2005.

     Segment Earnings before Depreciation, Depletion and Amortization

     The segment's $10.3 million (8%) decrease in earnings before depreciation,

depletion and amortization expenses in the third quarter of 2006 compared with

the third quarter of 2005, and its $14.0 million (4%) decrease in earnings

before depreciation, depletion and amortization in the first nine months of 2006

compared with the first nine months of 2005 were largely related to incremental

pipeline maintenance expenses recognized in the third quarter of 2006, related

to a change that both recognized and transferred a portion of the segment's

pipeline integrity costs from sustaining capital expenditures (within "Property,

plant and equipment, net" on our accompanying consolidated balance sheets) to

maintenance expense (within "Operations and maintenance" in our accompanying

consolidated statements of income).

     Pipeline integrity costs encompass those costs incurred as part of an

overall pipeline integrity management program, which is a process for assessing

and mitigating pipeline risks in order to reduce both the likelihood and

consequences of incidents. An effective pipeline integrity program is a

systematic, comprehensive process that entails pipeline assessment services,

maintenance and repair services, and regulatory compliance. Our pipeline

integrity program is designed to provide our management the information needed

to effectively allocate resources for appropriate prevention, detection and

mitigation activities.

     Beginning in the third quarter of 2006, the refined petroleum products

pipelines and associated terminal operations included within our Products

Pipelines segment (including Plantation Pipe Line Company, our 51%-owned equity

investee) began recognizing certain costs incurred as part of its pipeline

integrity management program as maintenance expense in the period incurred, and

in addition, recorded an expense for costs previously capitalized during the

first six months of 2006. Combined, this change reduced the segment's earnings

before depreciation, depletion and amortization expenses by $18.1

million--increasing maintenance expenses by $14.9 million, decreasing earnings

from equity investments by $5.2 million, and decreasing income tax expenses by

$2.0 million.

                                       63

<PAGE>

     In addition, as noted in the table above, the segment's earnings before

depreciation, depletion and amortization expenses for the first nine months of

2006 included environmental expenses of $16.4 million, net of taxes, from the

adjustment of environmental liabilities, and other income of $5.7 million from

the settlement of transmix processing contracts. Both of these items occurred in

the second quarter of 2006. Also, the segment's earnings before depreciation,

depletion and amortization expenses for the third quarter and first nine months

of 2005 included a loss of $5.0 million, recognized in September 2005, to

account for differences between physical and book natural gas liquids inventory

on our North System natural gas liquids pipeline.

     The overall decreases of $10.3 million (8%) and $14.0 million (4%),

respectively, in the three and nine month segment earnings before depreciation,

depletion and amortization expenses in 2006, relative to 2005, were primarily

due to the following:

     o    increases of $5.9 million (480%) and $7.5 million (94%) respectively,

          from our North System--due primarily to the $5.0 million inventory

          reconciliation reserve taken in the third quarter of 2005, as

          discussed above, and to higher throughput revenues in both the third

          quarter and first nine months of 2006. The overall increases were

          partly offset by a $1.0 million increase in pipeline maintenance

          expenses due to the expensing of pipeline integrity costs;

     o    increases of $1.1 million (22%) and $6.0 million (37%), respectively,

          from our petroleum pipeline transmix processing operations--due

          primarily to incremental earnings before depreciation, depletion and

          amortization from the inclusion of our recently constructed

          Greensboro, North Carolina transmix facility and (for the comparable

          nine month periods) to an increase of $5.7 million related to

          favorable settlements of transmix contract agreements.

          In the second quarter of 2006, we completed construction and placed

          into service the approximately $11 million Greensboro facility, which

          is capable of processing 6,000 barrels of transmix per day for

          Plantation and other interested parties. In the three and nine months

          ended September 30, 2006, the Greensboro facility accounted for

          incremental earnings before depreciation, depletion and amortization

          of $1.3 million and $1.5 million, respectively. The increase from

          contract settlements consisted of two separate settlements in the

          second quarter of 2006. First, we recorded income of $6.2 million from

          fees received for the early termination of a long-term transmix

          processing agreement at our Colton, California processing facility.

          Secondly, we recorded an expense of $0.5 million related to payments

          we made to Motiva Enterprises LLC in June 2006 to settle claims for

          prior period transmix purchase costs at our Richmond, Virginia

          processing facility;

     o    an increase of $1.1 million (15%) and a decrease of $0.2 million (1%),

          respectively, from our Central Florida Pipeline--the quarterly

          increase was driven by higher operating revenues, due to higher

          average tariff rates, and the nine month decrease resulted from higher

          operating expenses, which included $0.4 million of pipeline integrity

          expenses and which more than offset a year-over-year increase in

          revenues;

     o    a decrease of $1.8 million (9%) and an increase of $1.3 million (2%),

          respectively, from the combined operations of our West Coast and

          Southeast refined products terminal operations--the quarterly decrease

          included a $1.6 million (17%) drop in earnings before depreciation,

          depletion and amortization from our West Coast terminals, due

          primarily to incremental environmental expenses in the third quarter

          of 2006. The nine month increase in earnings was driven by higher

          earnings from our Southeast terminals, due to higher 2006 throughput

          volumes at higher rates, relative to 2005;

     o    decreases of $3.4 million (43%) and $6.9 million (24%), respectively,

          from our approximate 51% ownership interest in Plantation Pipe Line

          Company--primarily due to lower equity earnings from Plantation, net

          of income taxes. The overall quarterly decrease in earnings before

          depreciation, depletion and amortization was primarily due to a $3.2

          million decrease, representing our proportionate share of Plantation's

          pipeline integrity expenses, net of income taxes that were recognized

          in the third quarter of 2006. The decrease across the comparable nine

          month periods includes the $3.2 million decrease due to pipeline

          integrity expenses and a $3.5 million decrease, representing our

          proportionate share of additional environmental expense recognized by

          Plantation Pipe Line Company in the second quarter of 2006. The

          expense was related to environmental

                                       64

<PAGE>

          and clean-up liability adjustments associated with an April 17, 2006

          pipeline release of turbine fuel from Plantation's 12-inch petroleum

          products pipeline located in Henrico County, Virginia;

     o    decreases of $5.1 million (127%) and $5.4 million (34%), respectively,

          from our 49.8% ownership interest in the Cochin pipeline system--due

          mainly to incremental pipeline integrity expenses of $5.4 million

          recognized in the third quarter of 2006; and

     o    decreases of $7.8 million (9%) and $16.1 million (7%), respectively,

          from our combined Pacific and CALNEV Pipeline operations--the

          quarterly decrease was largely due to higher pipeline maintenance

          expenses, resulting from incremental pipeline integrity expenses of

          $7.5 million in the third quarter of 2006, and the nine month decrease

          was primarily due to higher environmental expenses associated with

          environmental liability adjustments, the expensing of pipeline

          integrity expenses in the third quarter of 2006, and higher

          year-over-year fuel and power costs as a result of higher electricity

          usage and higher utility rates.

     Segment Details

     Revenues for the segment increased $25.8 million (14%) in the third quarter

of 2006, compared to the third quarter of 2005. For the comparable nine month

periods, revenues increased $49.5 million (9%) in 2006 versus 2005. The

period-to-period increases in segment revenues for the comparable three and nine

month periods of 2006 and 2005, respectively, were principally due to the

following:

     o    increases of $12.2 million (80%) and $21.4 million (50%),

          respectively, from our Southeast terminals--largely attributable to

          higher ethanol blending and sales revenues and higher liquids

          inventory sales (offset by higher costs of sales, as described below);

     o    increases of $5.3 million (6%) and $10.5 million (4%), respectively,

          from our Pacific operations--the quarter-to-quarter increase consisted

          of a $3.3 million (5%) increase in refined products delivery revenues

          and a $2.0 million (9%) increase in refined products terminal revenues

          in the third quarter of 2006, compared to the third quarter of 2005.

          The increase from refined products delivery revenues was due to a 3%

          increase in mainline delivery volumes and an almost 2% increase in

          mainline average tariff rates, reflecting the impact of both rate

          reductions that went into effect on May 1, 2006 according to

          settlements reached in connection with our Pacific operations' rate

          litigation, and rate increases that went into effect July 1, 2006

          according to the FERC annual index rate increase (a producer price

          index-finished goods adjustment).

          For the comparable nine month periods, the overall increase in

          revenues consisted of a $5.8 million (3%) increase from mainline

          delivery revenues and a $4.7 million (7%) increase in product terminal

          revenues. The increase from product delivery revenues was due to a 2%

          increase in mainline delivery volumes and a slight (almost 1%)

          increase in mainline average tariff rates. The increase from terminal

          revenues was due to the higher transportation barrels and to

          incremental service revenues, including diesel lubricity-improving

          injection services that we began offering in May 2005;

     o    increases of $2.3 million (29%) and $3.5 million (13%), respectively,

          from our North System--due to higher natural gas liquids delivery

          revenues in 2006 versus 2005. The period-to-period increases in

          delivery revenues were driven by increases of 18% and 6%,

          respectively, in system throughput volumes, due largely to additional

          refinery demand, and by increases of 10% and 7%, respectively, in

          average tariff rates. The tariff increases resulted from a combination

          of annual indexed tariff increases approved by the FERC (effective

          July 1, 2005 and 2006), and from increases in the proportion of

          volumes shipped at higher versus lower tariffs;

     o    increases of $2.2 million (15%) and $5.7 million (13%), respectively,

          from our West Coast terminals--related to rent escalations, higher

          throughput barrels and rates at various locations, and additional tank

          capacity at our Carson/Los Angeles Harbor system terminals;

     o    increases of $1.6 million (10%) and $4.9 million (11%), respectively,

          from our CALNEV Pipeline--due mainly to higher refined products

          deliveries, higher terminal revenues as a result of additional

          transportation barrels delivered at our Barstow, California and Las

          Vegas, Nevada terminals, and higher diesel lubricity

                                       65

<PAGE>

          additive injection service revenues. Revenues from refined products

          deliveries increased $1.3 million (11%) and $4.0 million (12%),

          respectively, in the three and nine months ended September 30, 2006,

          when compared to the same periods last year. The quarter-to-quarter

          increase from refined products deliveries was due to a 3% increase in

          delivery volumes and a 7% increase in average tariff rates (including

          a FERC tariff index increase in July 2006). The nine month increase

          was due to a 6% increase in delivery volumes and a 5% increase in

          average tariff rates (including FERC annual index rate increases

          effective July 1, 2005 and July 1, 2006); and

     o    increases of $0.9 million (9%) and $2.6 million (9%), respectively,

          from our Central Florida Pipeline--driven by increases of 13% and 10%,

          respectively, in average tariff rates for the three and nine month

          periods of 2006 compared to 2005. The increased rates reflect

          reductions in zone-based credits in 2006 versus 2005.

     Combining all of the segment's operations, total delivery volumes of

refined petroleum products increased a slight 0.4% in the third quarter of 2006,

compared to the third quarter of 2005, but transport volumes increased by 10.5%

in the Arizona market during the third quarter of 2006, as our Pacific

operations' East Line expansion was in service for the entire quarter. The

expansion project substantially increased pipeline capacity from El Paso, Texas

to Tucson and Phoenix, Arizona. Excluding volumes delivered by Plantation Pipe

Line, combined deliveries of refined petroleum products were up 2% for the third

quarter of 2006 compared to the third quarter of 2005. In the third quarter of

2006, Plantation realized a 3.9% decrease in delivery volumes compared to the

third quarter of 2005, primarily due to alternative pipeline service into

Southeast markets and to changes in supply from Louisiana and Mississippi

refineries related to new ultra low sulfur diesel and ethanol blended gasoline

requirements. Compared to the third quarter of 2005, total deliveries of natural

gas liquids increased almost 11% in the third quarter of 2006.

     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 $34.0 million (56%) and

$64.4 million (38%), respectively, in the third quarter and first nine months of

2006, compared to the same year-ago periods. The overall increases in operating

expenses for the comparable three and nine month periods were mainly due to the

following:

     o    increases of $12.4 million (228%) and $18.5 million (105%),

          respectively, from our Southeast terminals--largely attributable to

          higher costs of sales related to higher ethanol blending and purchases

          (offset by higher ethanol revenues) and higher liquids purchases;

     o    increases of $10.4 million (51%) and $23.9 million (38%),

          respectively, from our Pacific operations--due primarily to higher

          overall major maintenance expenses, including $5.8 million of pipeline

          integrity expenses in the third quarter of 2006, lower capitalized

          expenses primarily due to the September 2006 reclassification of

          pipeline integrity management costs from capital to expense, and to

          higher period-to-period fuel and power expenses, due to both higher

          refined products delivery volumes and overall higher utility rates.

          The nine month increase was also due to higher environmental expenses

          in 2006 versus 2005, due to environmental liability adjustments, and

          higher electricity expenses resulting from a utility rebate credit

          received in the first quarter of 2005;

     o    increases of $5.2 million (140%) and $4.9 million (42%), respectively,

          from our proportionate interest in the Cochin Pipeline--due

          principally to an incremental $5.4 million of pipeline integrity

          expenses in the third quarter of 2006. The incremental pipeline

          integrity expenses were partly offset by lower pipeline operating

          expenses, in the first nine months of 2006, related to the decrease in

          transportation volumes in 2006 compared to 2005. The decrease in

          delivery volumes was primarily due to pipeline operating pressure

          restrictions;

     o    increases of $4.9 million (93%) and $8.1 million (55%), respectively,

          from our West Coast terminals--primarily related to incremental

          environmental expenses, higher materials and supplies expense as a

          result of lower capitalized overhead, and incremental pipeline

          integrity expenses;

     o    increases of $4.0 million (114%) and $7.7 million (71%), respectively,

          from our CALNEV Pipeline--due primarily to higher period-to-period

          environmental expense accruals, higher overall major maintenance

          expenses, including $1.7 million of pipeline integrity expenses in the

          third quarter of 2006, and to higher power expenses, related to

          increases in product delivery volumes and average utility rates;

                                       66

<PAGE>

     o    a decrease of $0.1 million (4%) and an increase of $2.9 million (42%),

          respectively, from our Central Florida Pipeline operations--the slight

          quarterly decrease reflects incremental pipeline integrity expenses of

          $0.4 million in 2006, offset by lower maintenance expenses due to

          additional expense accruals related to a pipeline release occurring in

          September 2005. The nine month increase was chiefly due to incremental

          environmental expenses, in 2006, resulting from quarterly

          environmental liability adjustments; and

     o    decreases of $3.6 million (37%) and $3.4 million (17%), respectively,

          from our North System--due primarily to the $5.0 million inventory

          reconciliation reserve taken in the third quarter of 2005, as

          discussed above, partly offset by both incremental pipeline integrity

          expenses of $1.0 million in the third quarter of 2006, and higher

          property tax expenses related to an expense true-up recognized in the

          third quarter of 2006.

     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. Earnings from

these investments decreased $5.7 million (92%) in the third quarter of 2006 and

$10.6 million (49%) in the first nine months of 2006, when compared to the same

periods last year. Both decreases primarily related to the lower earnings from

Plantation, as described above.

     Income from both allocable interest income and other income and expense

items increased $0.9 million (52%) and $6.7 million (151%), respectively, in the

comparable three and nine month periods. The quarterly increase was due to

higher administrative overhead collected by our West Coast terminals from a

reimbursable project, and the nine month increase was primarily due to the $5.7

million other income item from the settlement of transmix processing contracts

in the second quarter of 2006.

     For the comparable three and nine month periods, the segment's income tax

expenses decreased $2.8 million (127%) and $4.9 million (60%), respectively.

Both decreases related to the lower pre-tax earnings from Plantation and Cochin,

as described above.

     Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of equity investments, increased $1.0 million (5%)

in the third quarter of 2006 and $2.5 million (4%) in the first nine months of

2006, when compared to the same prior year periods. The period-to-period

increases were primarily due to higher depreciation expenses from our Pacific

and Southeast terminal operations. The increase from our Pacific operations

related to higher depreciable costs as a result of the capital spending we have

made for both pipeline and storage expansion since the end of the third quarter

of 2005. The increase from our Southeast terminal operations related to

incremental depreciation charges resulting from final purchase price

allocations, 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.

     Natural Gas Pipelines

<TABLE>

<CAPTION>

                                                                     Three Months Ended              Nine Months Ended

                                                                        September 30,                   September 30,

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

                                                                    2006            2005            2006           2005

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

                                                                        (In thousands, except operating statistics)

<S>                                                             <C>             <C>            <C>            <C>        

Revenues...................................................     $ 1,650,427     $ 2,108,788    $ 5,082,183    $ 5,198,337

Operating expenses and Other expense(a)....................      (1,519,129)     (1,996,737)    (4,678,855)    (4,863,524)

Earnings from equity investments...........................          10,062           8,705         31,833         25,733

Interest income and Other, net-income (expense)............             376           1,560            875          2,039

Income taxes...............................................            (973)           (361)          (900)        (1,899)

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

  Earnings before depreciation, depletion and amortization

    expense and amortization of excess cost of equity               140,763         121,955        435,136        360,686

investments................................................

Depreciation, depletion and amortization expense...........         (15,959)        (15,205)       (47,938)       (45,779)

Amortization of excess cost of equity investments..........             (71)            (70)          (210)          (208)

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

  Segment earnings.........................................     $   124,733     $   106,680    $   386,988    $   314,699

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

Natural gas transport volumes (Trillion Btus)(b)...........           384.9           353.1        1,067.4          998.1

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

Natural gas sales volumes (Trillion Btus)(c)...............           243.5           239.3          690.0          688.6

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

</TABLE>

---------

                                       67

<PAGE>

(a)  Nine month 2006 amount includes a $1,500 increase in expense associated

     with environmental liability adjustments, a $6,244 reduction in expense due

     to the release of a reserve related to a natural gas pipeline contract

     obligation, and a $15,114 gain from the combined sale of our Douglas

     natural gas gathering system and Painter Unit fractionation facility.

(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.

     Our Natural Gas Pipelines business segment reported earnings before

depreciation, depletion and amortization of $140.8 million on revenues of

$1,650.4 million in the third quarter of 2006. This compares to earnings before

depreciation, depletion and amortization of $122.0 million on revenues of

$2,108.8 million in the third quarter of 2005. For the comparable nine month

periods, the segment reported earnings before depreciation, depletion and

amortization of $435.1 million on revenues of $5,082.2 million in 2006, and

earnings before depreciation, depletion and amortization of $360.7 million on

revenues of $5,198.3 million in 2005.

     As noted in the table above, the segment's earnings before depreciation,

depletion and amortization expenses for the first nine months of 2006 included

an increase in expense of $1.5 million from the adjustment of environmental

liabilities, a reduction in expense of $6.2 million due to the release of a

reserve related to a natural gas purchase/sales contract, and a gain of $15.1

million from the combined sale of our Douglas natural gas gathering system and

Painter Unit fractionation facility. All three items occurred in the second

quarter of 2006.

     Segment Earnings before Depreciation, Depletion and Amortization

     The segment's $18.8 million (15%) increase in earnings before depreciation,

depletion and amortization expenses in the third quarter of 2006 compared with

the third quarter of 2005, and its $74.4 million (21%) increase in earnings in

the first nine months of 2006 compared with the first nine months of 2005 were

primarily due to the following:

     o    increases of $9.9 million (44%) and $6.9 million (9%), respectively,

          from our Kinder Morgan Interstate Gas Transmission system--due largely

          to higher operational sales of natural gas and incremental natural gas

          park and loan service revenues earned in the third quarter of 2006.

          The year-over-year increase in earnings in 2006 relative to 2005 was

          partially offset by favorable imbalance valuation adjustments

          recognized in the second quarter of 2005;

     o    increases of $6.3 million (9%) and $41.5 million (23%), respectively,

          from our Texas intrastate natural gas pipeline group--due primarily to

          improved margins resulting from the negotiation of profitable gas

          purchase and sales contracts, and higher value from storage and

          processing activities. With regard to our natural gas sales

          activities, 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. Our Texas

          intrastate group's margins can vary depending upon, among other

          things, the price volatility of natural gas produced in and delivered

          from the Gulf Coast region and Texas, the availability of

          transportation systems with adequate capacity, the availability of

          pipeline and/or underground system storage, and any changes or trends

          in the terms or conditions in which natural gas sale and purchase

          prices are contractually indexed.

          The increase in earnings in the first nine months of 2006 versus the

          first nine months of 2005 includes the $6.2 million increase resulting

          from the release of a previously established reserve related to a

          natural gas purchase/sales contract. The contract is associated with

          the operations of our West Clear Lake natural gas storage facility

          located in Harris County, Texas. We acquired this storage facility as

          part of our acquisition of Kinder Morgan Tejas on January 31, 2002,

          and upon acquisition, we established a reserve for a contract

          liability;

     o    an increase of $2.0 million (18%) and a decrease of $0.4 million (1%),

          respectively, from our Trailblazer Pipeline--due to timing differences

          on the settlements of pipeline transportation imbalances in 2006,

          relative to 2005. These pipeline imbalances were due to differences

          between the volumes nominated and volumes delivered at an

          inter-connecting point by the pipeline;

                                       68

<PAGE>

     o    increases of $1.3 million (18%) and $6.2 million (28%), respectively,

          from our 49% equity investment in Red Cedar Gathering Company--due

          largely to higher natural gas gathering revenues and to higher prices

          on incremental sales of excess fuel gas;

     o    increases of $0.2 million (2%) and $3.9 million (14%), respectively,

          from our TransColorado Pipeline--the quarter-to-quarter increase was

          largely due to a favorable property tax liability adjustment

          recognized in the third quarter of 2006, and the nine month increase

          was largely due to higher gas transmission revenues earned in 2006

          compared to 2005. The revenue increase related to higher natural gas

          delivery volumes resulting from system improvements 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; and

     o    a decrease of $0.9 million (34%) and an increase of $16.5 million

          (196%), respectively, from the combined operations of our Casper

          Douglas and Painter natural gas gathering and processing operations.

          The quarter-to-quarter decrease was primarily due to decreased

          revenues in 2006 compared to 2005, mainly due to lower natural gas

          sales and partly due to the sale of our Douglas natural gas gathering

          system and our Painter Unit fractionation facility in April 2006.

          Effective April 1, 2006, we sold our Douglas natural gas gathering

          system and our Painter Unit fractionation facility to a third party

          for approximately $42.5 million in cash, and we included a net gain of

          $15.1 million within "Other expense (income)" in our accompanying

          consolidated statements of income for the three and nine months ended

          September 30, 2006. For more information on this gain, see Note 2 to

          our consolidated financial statements included elsewhere in this

          report.

          The nine month increase in earnings in 2006 versus 2005 was mainly due

          to the $15.1 million gain discussed above, a $3.2 million increase in

          revenues due mainly to increased natural gas sales, favorable gas

          imbalance gains and higher commodity prices, and a $1.5 million

          decrease related to incremental environmental expenses in the second

          quarter of 2006.

     Segment Details

     Compared to the same two periods in 2005, total segment operating revenues,

including revenues from natural gas sales, decreased $458.4 million (22%) in the

third quarter of 2006, and decreased $116.1 million (2%) in the first nine

months of 2006. Similarly, combined operating expenses, including natural gas

purchase costs, decreased $477.6 million (24%) in the third quarter of 2006, and

decreased $184.7 million (4%) in the first nine months of 2006, when compared to

the same periods of 2005.

          The period-to-period changes in segment revenues and operating

expenses reflect changes in average natural gas prices and changes in natural

gas volumes purchased and sold, which affect both natural gas sales revenues and

natural gas purchase expenses; however, we increased earnings by realizing

higher margins from our Texas intrastate natural gas pipeline group's purchasing

and sales activities, and from its natural gas storage and processing

activities. For the comparable three and nine month periods, the Texas

intrastate groups' natural gas sales margin increased $7.4 million (20%) and

$47.4 million (53%), respectively, in 2006 versus 2005. The variations in

natural gas sales margin for both the three and nine months ended September 30,

2006, compared with the same periods last year, were driven by changes in

natural gas prices and sales volumes--the $7.4 million quarterly margin increase

consisted of a $10.5 million increase from favorable changes in average sales

versus average purchase prices (favorable price variance) and a $3.1 million

decrease from lower volumes (unfavorable volume variance)--the $47.4 million

nine month margin increase consisted of a $50.8 million increase from favorable

changes in average sales prices versus average purchase prices and a $3.4

million decrease from lower volumes. Also, the intrastate groups' margins from

natural gas processing activities increased $6.2 million (111%) and $8.4 million

(47%), respectively, in the comparable three and nine month periods of 2006

versus 2005.

     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. Combined earnings from these three investees increased

$1.4 million (16%) and $6.1 million (24%), respectively, in the third quarter

and first nine months of 2006, when compared to the same periods last year. The

increases were chiefly due to higher net income earned by Red Cedar during 2006,

as described above.

                                       69

<PAGE>

     On September 1, 2006, we and the Southern Ute Indian Tribe agreed to a

resolution that would transfer all of the members' equity in Coyote Gas

Treating, LLC to the members' equity of Red Cedar Gathering Company. According

to the provisions of this resolution, we and the Southern Ute Tribe contributed

the value of our respective 50% ownership interests in Coyote Gas Treating, LLC

to Red Cedar, and as a result, Coyote Gas Treating, LLC became a wholly owned

subsidiary of Red Cedar. For more information on this contribution, see Note 13

to our consolidated financial statements included elsewhere in this report.

     The segment's combined interest income and earnings from other income items

(Other, net) decreased $1.2 million in both the three and nine month periods of

2006, when compared to the same prior year periods. The decrease was chiefly due

to a gain from a property disposal by our Kinder Morgan Tejas Pipeline in the

third quarter of 2005. Income tax expenses increased $0.6 million in the third

quarter of 2006, but decreased $1.0 million in the first nine months of 2006,

when compared to the same periods in 2005. The changes primarily related to tax

accrual adjustments related to the operations of our Mier-Monterrey Mexico

Pipeline.

     Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased a slight $0.8 million (5%)

in the third quarter of 2006 versus the third quarter of 2005; for the nine

month periods, depreciation related expenses increased $2.2 million (5%) in 2006

versus 2005. The increases were largely due to incremental capital spending

since last year's third quarter, and to additional depreciation charges on our

Kinder Morgan Texas system due to the acquisition of our North Dayton, Texas

natural gas storage facility in August 2005.

     CO2

<TABLE>

<CAPTION>

                                                                        Three Months Ended             Nine Months Ended

                                                                            September 30,                  September 30,

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

                                                                        2006            2005           2006           2005

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

                                                                            (In thousands, except operating statistics)

<S>                                                                  <C>             <C>            <C>            <C>      

Revenues(a).......................................................   $ 192,303       $ 163,079      $ 552,783      $ 488,271

Operating expenses................................................     (68,888)        (48,546)      (194,212)      (152,389)

Earnings from equity investments..................................       3,380           5,533         14,113         21,932

Other, net-income (expense).......................................         324              (6)           336             (6)

Income taxes......................................................         (57)           (151)          (181)          (263)

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

  Earnings before depreciation, depletion and amortization

  expense and amortization of excess cost of equity investments...     127,062         119,909        372,839        357,545

Depreciation, depletion and amortization expense(b)...............     (50,731)        (34,658)      (132,021)      (111,822)

Amortization of excess cost of equity investments.................        (504)           (505)        (1,513)        (1,513)

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

  Segment earnings................................................   $  75,827       $  84,746      $ 239,305      $ 244,210

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

Carbon dioxide delivery volumes (Bcf)(c)..........................       164.3           153.6          503.4          479.0

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

SACROC oil production (gross) (MBbl/d)(d).........................        30.3            30.8           30.8           32.4

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

SACROC oil production (net) (MBbl/d)(e)...........................        25.3            25.6           25.7           26.9

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

Yates oil production (gross) (MBbl/d)(d)..........................        26.3            24.1           25.9           24.0

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

Yates oil production (net) (MBbl/d)(e)............................        11.7            10.7           11.5           10.7

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

Natural gas liquids sales volumes (net) (MBbl/d)(e)...............         8.4             9.4            8.9            9.5

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

Realized weighted average oil price per Bbl(f)(g).................    $  32.49       $   26.12      $   31.42      $   27.46

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

Realized weighted average natural gas liquids

  price per Bbl(g)(h).............................................    $  47.68       $   41.89      $   44.82      $   37.09

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

</TABLE>

----------

(a)  Nine month 2006 amount includes a $1,819 loss on derivative contracts used

     to hedge forecasted crude oil sales.

(b)  Includes depreciation, depletion and amortization expense associated with

     oil and gas producing and gas processing activities in the amount of

     $45,704 for the third quarter of 2006, $30,336 for the third quarter of

     2005, $117,628 for the first nine months of 2006, and $98,628 for the first

     nine months of 2005. Includes depreciation, depletion and amortization

     expense associated with sales and transportation services activities in the

     amount of $5,027 for the third quarter of 2006, $4,322 for the third

     quarter of 2005, $14,393 for the first nine months of 2006, and $13,194 for

     the first nine months 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.

                                       70

<PAGE>

(f)  Includes all Kinder Morgan crude oil production properties.

(g)  Hedge gains/losses for crude 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.

     Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its

consolidated affiliates. The segment's primary businesses involve the

production, marketing and transportation of both carbon dioxide (commonly called

CO2) and crude oil, and the production and marketing of natural gas and natural

gas liquids. For the third quarter of 2006, the segment reported earnings before

depreciation, depletion and amortization of $127.1 million on revenues of $192.3

million. These amounts compare to earnings before depreciation, depletion and

amortization of $119.9 million on revenues of $163.1 million in the same quarter

last year. For the comparable nine month periods, the segment reported earnings

before depreciation, depletion and amortization of $372.8 million on revenues of

$552.8 million in 2006, and earnings before depreciation, depletion and

amortization of $357.5 million on revenues of $488.3 million in 2005.

     Segment Earnings before Depreciation, Depletion and Amortization

     Sales and Transportation Activities

     For our CO2 segment, both the $7.2 million (6%) increase in earnings before

depreciation, depletion and amortization in the third quarter of 2006 over the

third quarter of 2005, and the $15.3 million (4%) increase in the first nine

months of 2006 over the first nine months of 2005 were driven by higher earnings

from the segment's carbon dioxide sales and transportation activities. Earnings

before depreciation, depletion and amortization from these activities increased

$7.6 million (18%) and $20.6 million (17%), respectively, in the third quarter

and first nine months of 2006, when compared to the same prior year periods. The

increases in earnings were driven by higher revenues--from both carbon dioxide

sales and deliveries, and from crude oil pipeline transportation. The overall

increases were partly offset by lower equity earnings from the segment's 50%

ownership interest in the Cortez Pipeline Company.

     The period-to-period increases in carbon dioxide sales revenues were due to

both higher average prices and higher sales volumes. The increases in volumes

were largely attributable to the continued strong demand for carbon dioxide from

tertiary oil recovery projects in the Permian Basin area since the end of the

third quarter last year, and to increased carbon dioxide production from the

McElmo Dome source field. We operate and own a 45% interest in McElmo Dome,

which supplies carbon dioxide to oil recovery fields in the Permian Basin of

southeastern New Mexico and West Texas. It is the largest known carbon dioxide

deposit in the world--covering approximately 203,000 acres from south of McElmo

Canyon into Delores County, Colorado.

     Correlating closely with the increase in crude oil prices since the end of

the third quarter of 2005, average carbon dioxide sales prices increased 19% and

26%, respectively, for the three and nine month periods of 2006, when compared

to the same periods a year ago. In addition, during both nine month periods, we

did not use derivative contracts to hedge or help manage the financial impacts

associated with the increases in carbon dioxide prices, and as always, we did

not recognize profits on carbon dioxide sales to ourselves.

     Oil and Gas Producing Activities

     The remaining changes in period-to-period segment earnings before

depreciation, depletion and amortization--a decrease of $0.4 million (1%) in the

comparable three month periods and a decrease of $5.3 million (2%) in the

comparable nine month periods, were attributable to the segment's crude oil and

natural gas producing activities, which also include its natural gas processing

activities. The decreases in period-to-period earnings were largely due to

higher combined operating expenses and partly due to lower crude oil production

at the SACROC oil field unit. The higher operating expenses included higher

field operating and maintenance expenses, higher property and severance taxes,

and higher fuel and power expenses. The increases in expenses more than offset

higher overall crude oil and natural gas plant product sales revenues.

                                       71

<PAGE>

     In addition, increased crude oil production at the Yates oil field unit was

offset by a previously announced decline in crude oil production at the SACROC

unit. On a gross basis (meaning total quantity produced), average crude oil

production increased 9% quarter-over-quarter at Yates, but decreased 2% at the

SACROC unit, where the decline in production is mostly due to one section of the

field that is underperforming. As originally disclosed in our report on Form

10-Q filed for the quarter ended March 31, 2006, we now expect our CO2 segment

to fall short of its annual published budget of segment earnings before

depreciation, depletion and amortization expenses by approximately $45 million,

or 8%. However, we continue to expect strong annual carbon dioxide production

volumes and earnings at the McElmo Dome unit in 2006, and we expect the crude

oil production and earnings from the Yates field unit to exceed their annual

budgeted amounts.

     Segment Details

     Our CO2 segment's revenues increased $29.2 million (18%) in the third

quarter of 2006 compared to the third quarter of 2005, and including a $1.8

million hedge ineffectiveness loss in June 2006, revenues increased $64.5

million (13%) in the first nine months of 2006 versus 2005. The respective third

quarter and nine month increases were primarily due to the following:

     o    increases of $24.0 million (27%) and $39.2 million (14%),

          respectively, from crude oil sales--attributable to increases of 24%

          and 14%, respectively, in our realized weighted average price of crude

          oil and a 2% increase in quarter-to-quarter sales volumes. For the

          comparable nine month periods, crude oil sales volumes were

          essentially flat;

     o    increases of $3.9 million (26%) and $14.3 million (41%), respectively,

          from carbon dioxide sales--due mainly to higher average sales prices,

          discussed above, and to increases of 12% and 8%, respectively, in

          period-to-period sales volumes;

     o    increases of $2.9 million (19%) and $7.2 million (17%), respectively,

          from carbon dioxide and crude oil pipeline transportation

          revenues--due largely to increases of 7% and 5%, respectively, in

          system-wide carbon dioxide delivery volumes. The improvements in

          carbon dioxide throughput volumes were driven by higher contract

          demand, and the higher crude oil pipeline transportation revenues

          reflect higher crude oil throughputs from our Kinder Morgan Wink

          Pipeline;

     o    increases of $0.5 million (2%) and $12.8 million (13%), respectively,

          from natural gas liquids sales--attributable to higher average sales

          prices, partially offset by decreases in volumes primarily related to

          the lower production at SACROC; and

     o    decreases of $0.9 million (70%) and $9.1 million (73%), respectively,

          from natural gas sales--mainly attributable to lower volumes of gas

          available for sale in the third quarter and first nine months of 2006

          versus the same periods last year, 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. We constructed the SACROC power plant in

          order to reduce our purchases of electricity from third-parties, but

          it reduces our sales of natural gas because some natural gas volumes

          are consumed by the plant. The power plant now provides approximately

          half of SACROC's current electricity needs. KMI operates and maintains

          the power plant under a five-year contract expiring in June 2010, and

          we reimburse KMI for its operating and maintenance costs.

     We mitigate commodity price risk through a long-term hedging strategy

that uses derivative contracts to reduce the impact of unpredictable changes in

crude oil and natural gas liquids sales prices. Our goal is to use derivative

contracts in order to prevent or reduce the possibility of future losses, and

our strategy is intended to generate more stable realized prices. Had we not

used energy derivative contracts to transfer commodity price risk, our crude oil

sales prices would have averaged $68.20 per barrel in the third quarter of 2006,

and $61.17 per barrel in the third quarter of 2005. 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.

                                       72

<PAGE>

     Compared to the same periods of 2005, the segment's operating expenses

increased $20.3 million (42%) in the third quarter of 2006 and $41.8 million

(27%) in the first nine months of 2006. The increases consisted of the

following:

     o    increases of $12.3 million (58%) and $25.0 million (36%),

          respectively, from combined cost of sales and field operating and

          maintenance expenses-- largely due to higher well workover and

          completion expenses related to infrastructure expansions at the SACROC

          and Yates oil field units since the third quarter last year. Workover

          expenses, including labor, relate to incremental operating and

          maintenance charges incurred on producing wells in order to restore or

          increase production, and are often performed in order to stimulate

          production, add pumping equipment, remove fill from the wellbore, or

          mechanically repair the well.

          Our oil and gas operations, coupled with carbon dioxide flooding,

          often require a high level of investment, including ongoing expenses

          for facility upgrades, wellwork and drilling. We continue to

          aggressively pursue opportunities to drill new wells and/or expand

          existing wells for both carbon dioxide and crude oil in order to

          benefit from robust demand for energy commodities in and around the

          Permian Basin area;

     o    increases of $6.6 million (40%) and $9.6 million (18%), respectively,

          from fuel and power expenses-- 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, however, by the benefits provided from the power plant

          we constructed at the SACROC oil field unit, described above; and

     o    increases of $1.4 million (13%) and $7.2 million (23%), respectively,

          from taxes, other than income taxes--attributable mainly to higher

          property and production (severance) taxes. The higher property taxes

          related to both increased asset infrastructure and higher assessed

          property values since the end of the third quarter of 2005. The higher

          severance taxes, which are primarily based on the gross wellhead

          production value of crude oil and natural gas, were driven by the

          higher period-to-period crude oil revenues.

     Earnings from equity investments, representing equity earnings from our 50%

ownership interest in the Cortez Pipeline Company, decreased $2.2 million (39%)

and $7.8 million (36%), respectively, in the third quarter and first nine months

of 2006, versus the same periods in 2005. The decreases reflect lower overall

net income earned by Cortez in 2006 relative to 2005. The decreases were

expected because the 2005 periods benefited from higher tariffs, due to making

up under-collected revenues in prior years. The decrease in revenues from lower

tariffs more than offset incremental revenues realized as a result of higher

carbon dioxide delivery volumes.

     Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased $16.1 million (46%) in

the third quarter and $20.2 million (18%) in first nine months of 2006, when

compared to the same prior year periods.  The increases were largely due to a

higher unit-of-production depletion rate used in third quarter of 2006,

related to our interest in the SACROC oil field unit, and to higher

depreciable costs, related to incremental capital spending since the end of

the third quarter last year.  In addition, we recognized incremental

depreciation charges of $0.8 million and $2.2 million, respectively,

attributable to the various oil and gas properties we acquired in April 2006

from Journey Acquisition - I, L.P. and Journey 2000, L.P.

                                       73

<PAGE>

     Terminals

<TABLE>

<CAPTION>

                                                                    Three Months Ended             Nine Months Ended

                                                                       September 30,                 September 30,

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

                                                                    2006           2005           2006           2005

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

                                                                       (In thousands, except operating statistics)

<S>                                                             <C>             <C>            <C>            <C>      

Revenues...................................................     $  223,151      $ 177,484      $ 649,822      $ 515,115

Operating expenses.........................................       (122,230)       (94,318)      (354,892)      (271,470)

Earnings from equity investments...........................             76             18            190             51

Other, net-income (expense)................................          1,056            886          2,335           (293)

Income taxes...............................................         (3,599)        (2,372)        (7,451)        (9,874)

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

  Earnings before depreciation, depletion and amortization

    expense and amortization of excess cost of equity               98,454         81,698        290,004        233,529

investments................................................

Depreciation, depletion and amortization expense...........        (19,320)       (15,644)       (55,280)       (41,972)

Amortization of excess cost of equity investments..........              -              -              -              -

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

  Segment earnings.........................................     $   79,134      $  66,054      $ 234,724      $ 191,557

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

Bulk transload tonnage (MMtons)(a).........................           23.2           20.4           67.9           65.8

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

Liquids leaseable capacity (MMBbl).........................           43.5           40.3           43.5           40.3

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

Liquids utilization %......................................           97.8%          96.5%          97.8%          96.5%

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

</TABLE>

----------

(a)  Volumes for acquired terminals are included for all periods.

     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. In

the third quarter of 2006, our Terminals segment reported earnings before

depreciation, depletion and amortization of $98.5 million on revenues of $223.2

million. This compares to earnings before depreciation, depletion and

amortization of $81.7 million on revenues of $177.5 million in the third quarter

last year. For the first nine months of 2006, our Terminals segment reported

earnings before depreciation, depletion and amortization of $290.0 million on

revenues of $649.8 million, while in the same prior-year period, the segment

reported earnings before depreciation, depletion and amortization of $233.5

million on revenues of $515.1 million.

     Segment Earnings before Depreciation, Depletion and Amortization

     The segment's $16.8 million (21%) increase in earnings before depreciation,

depletion and amortization expenses in the third quarter of 2006 compared with

the third quarter of 2005, and the $56.5 million (24%) increase in earnings in

the first nine months of 2006 compared with the first nine months of 2005 were

driven by a combination of internal expansions, incremental volumes, and

acquisitions.

     Our terminal acquisitions since the beginning of 2005 primarily included

the following:

     o    our Texas Petcoke terminals, located in and around the Ports of

          Houston and Beaumont, Texas, acquired effective April 29, 2005;

     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;

     o    our Kinder Morgan Blackhawk terminal located in Black Hawk County,

          Iowa, acquired in August 2005;

     o    a terminal-related repair shop located in Jefferson County, Texas,

          acquired in September 2005; and

                                       74

<PAGE>

     o    three terminal operations acquired separately in April 2006: terminal

          equipment and infrastructure located on the Houston Ship Channel, a

          rail terminal located at the Port of Houston, and a rail ethanol

          terminal located in Carson, California.

     Combined, these terminal operations acquired since the beginning of 2005

accounted for incremental amounts of earnings before depreciation, depletion and

amortization of $4.0 million, revenues of $9.2 million and operating expenses of

$5.2 million, respectively, in the third quarter of 2006, and incremental

amounts of earnings before depreciation, depletion and amortization of $29.4

million, revenues of $58.8 million and operating expenses of $29.4 million,

respectively, in the first nine months of 2006, when compared to the same

periods a year ago. The incremental amounts above relate to the acquired

terminals' operations during the additional months of ownership in the third

quarter and first nine months of 2006, as compared to 2005, and do not include

increases or decreases during the same months we owned the assets in both years.

     For the comparable three months, most of the period-to-period increases in

operating results from terminal acquisitions were attributable to the terminal

assets and operations we acquired from A&L Trucking, L.P. and U.S. Development

Group in April 2006 for an aggregate consideration of approximately $61.9

million. Combined, these assets accounted for incremental amounts of earnings

before depreciation, depletion and amortization of $3.8 million, revenues of

$8.7 million and operating expenses of $4.9 million, respectively, in the third

quarter of 2006.

     For the comparable nine month periods, most of the period-to-period

increases in operating results from terminal acquisitions were attributable to

the inclusion of our Texas petroleum coke terminals and repair shop assets,

which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an

aggregate consideration of approximately $247.2 million. The primary assets

acquired included facilities and railway equipment located at the Port of

Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the

Houston Ship Channel. Combined, these assets accounted for incremental amounts

of earnings before depreciation, depletion and amortization of $16.8 million,

revenues of $31.0 million and operating expenses of $14.2 million, respectively,

during the first four months of 2006.

     For all other terminal operations (those owned during identical periods in

both 2005 and 2006), earnings before depreciation, depletion and amortization

increased $12.8 million (16%) in the third quarter of 2006 versus the third

quarter of 2005, and increased $27.1 million (12%) in the first nine months of

2006 versus the first nine months of 2005. The respective third quarter and nine

month year-to-date increases in earnings from terminal operations owned during

both years were primarily due to the following:

     o    increases of $5.1 million (25%) and $9.6 million (17%), respectively,

          from our Gulf Coast region. The increases were primarily due to higher

          earnings from our Pasadena and Galena Park, Texas liquids facilities.

          The period-to-period increases were driven by higher revenues from new

          and incremental customer agreements, additional liquids tank capacity

          from capital expansions at our Pasadena terminal since the third

          quarter of 2005, higher truck loading rack service fees, and

          incremental revenues from customer deficiency charges in the third

          quarter of 2006;

     o    increases of $3.5 million (47%) and $7.9 million (32%), respectively,

          from our Mid-Atlantic region. The quarterly increase was driven by a

          $1.8 million increase from our Chesapeake Bay, Maryland bulk terminal

          and a $1.4 million increase from our Shipyard River terminal, located

          in Charleston, South Carolina. The increase at Chesapeake was due to

          higher revenues earned from transferring higher volumes of petroleum

          coke, coal, and pig iron; the increase at Shipyard was due to higher

          revenues from increased coal volumes, tank rentals and ancillary

          terminal services.

          The nine month increase was driven by a $3.6 million increase from our

          Shipyard River terminal, a $2.9 million increase from our Fairless

          Hills, Pennsylvania bulk terminal, and a $1.3 million increase from

          our Philadelphia, Pennsylvania liquids terminal. The increase from

          Shipyard reflects higher revenues from liquids warehousing and coal

          and cement handling, the increase at Fairless Hills was due to higher

          volumes of steel imports and heavier shipping activity on the Delaware

          River, and the increase at Philadelphia was due to higher revenues

          from an increase in fuel grade ethanol volumes, and annual rate

          escalations on certain customer contracts;

                                       75

<PAGE>

     o    increases of $2.0 million (49%) and $1.7 million (9%), respectively,

          from terminals included in our Lower Mississippi (Louisiana) region.

          The quarterly increase was primarily due to higher earnings 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.

          The nine month increase was primarily due to higher earnings from IMT

          and our DeLisle, Mississippi terminal, both negatively impacted by

          hurricane damage in 2005, incremental income related to a favorable

          settlement associated with the purchase of our Kinder Morgan St.

          Gabriel terminal in September 2002, and to incremental earnings from

          our Amory, Mississippi bulk terminal, which began operations in July

          2005;

     o    increases of $1.9 million (17%) and $2.1 million (6%), respectively,

          from terminals included in our Northeast region. The increases were

          primarily due to higher earnings from our liquids terminals located in

          Carteret, New Jersey and Staten Island, New York. The quarterly

          increase was largely due to higher revenues from new and renegotiated

          customer contracts at Carteret, and to additional tankage and transmix

          sales at our Kinder Morgan Staten Island terminal. The nine month

          increase was due to the same factors that affected third quarter

          results, and to an overall increase in petroleum imports to New York

          Harbor, resulting in an 11% increase in total liquids throughput at

          Carteret; and

     o    increases of $0.4 million (4%) and $3.9 million (26%), respectively,

          from our Texas Petcoke region. The increases were due to higher

          revenues from petroleum coke transfers, which more than offset higher

          sales costs and operating expenses.

     Segment Details

     Segment revenues for all terminals owned during identical periods of both

years increased $36.5 million (21%) in the third quarter of 2006, and $75.9

million (15%) in the first nine months of 2006, when compared to the same

prior-year periods. The overall changes in three and nine month revenues from

terminals owned during identical periods of both years included the following:

     o    increases of $9.6 million (52%) and $19.9 million (32%), respectively,

          from our Mid-Atlantic region, due primarily to higher revenues from

          our Fairless Hills, Chesapeake Bay, and Shipyard River terminals, as

          discussed above;

     o    increases of $6.5 million (24%) and $12.6 million (16%), respectively,

          from our Gulf Coast liquids facilities, due primarily to higher

          revenues from Pasadena and Galena Park, as discussed above;

     o    increases of $5.3 million (21%) and $5.8 million (7%), respectively,

          from terminals included in our Lower Mississippi (Louisiana) region.

          The increases were largely due to higher tonnage, dockage and

          insurance revenues at our IMT facility, higher bulk transfer revenues

          from our DeLisle and Amory, Mississippi terminals, and higher revenues

          from ship and cargo brokerage;

     o    increases of $5.0 million (29%) and $15.4 million (57%), respectively,

          from our Texas Petcoke terminal region, due to higher petroleum coke

          transfer volumes;

     o    increases of $3.6 million (102%) and $10.3 million (101%),

          respectively, from engineering and terminal design services, due to

          both incremental revenues from new clients and from existing clients

          starting new projects due to economic growth, and to increased

          revenues from material sales;

     o    increases of $2.6 million (9%) and $3.8 million (4%), respectively,

          from terminals included in our Midwest region, due largely to

          increased liquids throughput and storage activities from our two

          Chicago liquids terminals, increases of 34% and 10%, respectively, in

          coal transfer volumes from the combined operations of our Cora,

          Illinois and Grand Rivers, Kentucky coal terminals, and higher marine

          oil fuel and asphalt sales from our Dravosburg, Pennsylvania bulk

          terminal; and

                                       76

<PAGE>

     o    increases of $2.2 million (10%) and $2.8 million (4%), respectively,

          from our Northeast terminals, largely to increases at our Carteret and

          Kinder Morgan Staten Island terminals, as discussed above.

     Operating expenses for all terminals owned during both periods increased

$22.7 million (24%) in the third quarter of 2006, and $54.0 million (20%) in the

first nine months of 2006, when compared to the same periods last year. The

respective third quarter and nine month year-to-date increases in operating

expenses from terminal operations owned during identical periods of both years

were primarily due to the following:

     o    increases of $6.1 million (55%) and $11.3 million (30%), respectively,

          from our Mid-Atlantic terminals, largely due to higher operating and

          maintenance expenses at our Fairless Hills, Shipyard River, and Pier

          IX terminals. The increases at Fairless Hills were largely due to

          higher wharfage, trucking and general maintenance expenses related to

          the increase in steel products handled, the increases at Shipyard were

          due to higher labor, equipment rentals, and general maintenance

          expenses, all associated with increased tonnage, and the increases at

          Pier IX, located in Newport News, Virginia, related to major

          maintenance repairs and to higher expenses related to a fire that

          occurred at the terminal in June 2006;

     o    increases of $4.8 million (61%) and $11.7 million (99%), respectively,

          from our Texas Petcoke terminal region, due largely to higher labor

          expenses, rail service and railcar maintenance expenses, and harbor

          and barge expenses, all related to higher petroleum coke volumes;

     o    increases of $4.4 million (139%) and $11.8 million (124%),

          respectively, 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    increases of $2.4 million (13%) and $8.1 million (14%), respectively,

          from our Louisiana terminals, largely due to property damage,

          demurrage and other expenses, which in large part related to the

          effects of hurricanes Katrina and Rita, both of which impacted the

          Gulf Coast since the third quarter of 2005. Increases also resulted

          from higher stevedoring, dockage, and demurrage expenses related to

          increased shipping activities;

     o    increases of $1.9 million (12%) and $3.3 million (7%), respectively,

          from our Midwest region terminals, due primarily to higher marine fuel

          costs of sales at our Dravosburg terminal, higher maintenance and

          outside service expenses associated with increases in coal transfer

          volumes, and additional labor and equipment rental expenses from the

          combined operations of our Argo and Chicago, Illinois liquids

          terminals due to increased ethanol throughput and incremental liquids

          storage and handling business;

     o    increases of $1.5 million (33%) and $2.8 million (19%), respectively,

          from terminals in our Ferro alloys region, due primarily to higher

          labor and higher equipment maintenance and rentals related to

          increased ores and metals handling at our Chicago and Industry,

          Pennsylvania terminals; and

     o    increases of $1.4 million (19%) and $3.1 million (15%), respectively,

          from our Gulf Coast liquids terminals, due primarily to incremental

          labor expenses, tank cleaning and maintenance, power expenses and

          permitting fees.

     The segment's earnings from equity investments remained essentially flat

across both comparable periods, and income from other items increased $0.2

million and $2.6 million, respectively, in the comparable three and nine periods

of 2006, compared to 2005. The three month increase was largely due to gains

realized from the sale of our Kinder Morgan River Terminals' Fort Smith,

Arkansas warehouse operating assets in the third quarter of 2006. The nine month

increase included a $1.8 million income item recognized in the first quarter of

2006 and described above, related to a favorable settlement associated with the

purchase of our Kinder Morgan St. Gabriel terminal, and a $1.2 million increase

related to a disposal loss recognized in the first quarter of 2005 on warehouse

property at our Elizabeth River bulk terminal, located in Chesapeake, Virginia.

     Income tax expenses increased $1.2 million (52%) and decreased $2.4 million

(25%) in the third quarter and first nine months of 2006, respectively, compared

to the same periods a year ago. The quarter-to-quarter increase was primarily

due to higher taxable earnings from all combined tax-paying terminal entities.

The decrease in the comparable nine month periods was largely impacted by a $1.8

million reduction in expense associated with a June

                                       77

<PAGE>

2006 adjustment to the accrued federal income tax liability account of Kinder

Morgan Bulk Terminals, Inc., the tax-paying entity that owns many of our bulk

terminal businesses.

     Compared to the same periods in 2005, non-cash depreciation, depletion and

amortization charges increased $3.7 million (23%) in the third quarter of 2006,

and $13.3 million (32%) in the first nine months of 2006. The year-over-year

increases in depreciation expenses resulted from the capital expenditures and

terminal acquisitions we have made since the beginning of 2005. Since the

beginning of last year, we completed numerous improvement projects and acquired

various terminal operations in order to expand and enhance our terminalling

services. Collectively, the terminal assets we acquired since the beginning of

2005 and listed above accounted for incremental depreciation expenses of $1.1

million and $7.8 million, respectively, in the third quarter and first nine

months of 2006.

     Other

<TABLE>

<CAPTION>

                                                                    Three Months Ended             Nine Months Ended

                                                                       September 30,                 September 30,

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

                                                                   2006            2005           2006           2005

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

                                                                             (In thousands-income/(expense))

<S>                                                            <C>             <C>            <C>            <C>        

General and administrative expenses........................    $  (59,694)     $  (47,073)    $ (183,913)    $ (171,058)

Unallocable interest, net..................................       (89,424)        (69,688)      (249,617)      (196,362)

Minority interest..........................................        (2,018)         (1,806)        (7,881)        (6,648)

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

  Interest and corporate administrative expenses...........    $ (151,136)     $ (118,567)    $ (441,411)    $ (374,068)

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

</TABLE>

     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.

     Our total general and administrative expenses increased $12.6 million (27%)

in the third quarter of 2006, when compared to the third quarter of 2005. The

increase was primarily due to a $4.8 million drop in capitalized overhead costs

in the third quarter of 2006 compared to the third quarter of 2005, reflecting

both a lower capitalization rate and lower spending on capital projects. In

addition, we accrued incremental insurance expenses and realized higher employee

benefit expenses in the third quarter of 2006 compared to the third quarter of

2005. The increase in insurance expenses reflect higher period-to-period rates

and the increase in employee benefit expenses reflect higher wage and benefit

costs influenced by changes in compensation levels and health-related expenses.

     For the first nine months of 2006, general and administrative expenses

increased $12.9 million (8%) when compared to the same 2005 period. The

year-over-year increase was partly due to lower capitalized overhead costs

(described above), higher corporate service charges, insurance, and employee

benefit expenses in the first nine months of 2006, and partly due to increased

costs associated with new acquisitions made since the third quarter of 2005. The

overall increase was partly offset by lower unallocated litigation and

environmental settlement expenses in 2006--in the first nine months of 2005, we

recognized unallocated litigation and environmental settlement expenses of $33.4

million, consisting of a $25.0 million expense for a settlement reached between

us and a former joint venture partner on our Kinder Morgan Tejas natural gas

pipeline system and a cumulative $8.4 million expense related to settlements of

environmental matters at certain of our operating sites located in the State of

California.

     Unallocable interest expense, net of interest income, increased $19.7

million (28%) and $53.3 million (27%), respectively, in the third quarter and

first nine months of 2006, compared to the same year-earlier periods. The

increases were due to both higher average debt levels and higher effective

interest rates. Average borrowings for the three and nine month periods ending

September 30, 2006, increased 8% and 9%, respectively, versus the same periods

last year. The increases were mainly due to higher capital spending and to the

acquisition of external assets and businesses since the end of the third quarter

of 2005. Generally, we fund both our capital spending (including payments for

pipeline project construction costs) and our acquisition outlays from borrowings

under our commercial paper program.

     In addition, for the comparable nine month periods, average borrowings

increased in 2006 versus 2005 due to a net increase of $300 million in principal

amount of long-term senior notes. On March 15, 2005, we both closed a

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<PAGE>

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 weighted average interest rate on all of our borrowings increased 19%

and 17%, respectively, in the third quarter and first nine months of 2006,

compared to the same prior year periods. The increases in our average borrowing

rates reflect a general rise in variable interest rates since the end of the

third 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.

     Minority interest, representing the deduction in our consolidated net

income attributable to all outstanding ownership interests in our five operating

limited partnerships and their consolidated subsidiaries that are not held by

us, was essentially flat across both quarterly periods, but increased $1.2

million (19%) in the first nine months of 2006, compared to the same period last

year. The increase was primarily due to incremental interest income and expense

allocated to the minority interest in West2East Pipeline LLC, the sole owner of

Rockies Express Pipeline LLC. Prior to ConocoPhillips' acquisition of a 24%

ownership interest in West2East Pipeline LLC on June 30, 2006, we fully

consolidated West2East Pipeline LLC and we reported the 33 1/3% interest we did

not own as minority interest.

Financial Condition

     Capital Structure

     We attempt to maintain a conservative overall capital structure, with a

long-term target mix of approximately 50% equity and 50% debt. In addition to

our results of operations, our debt and capital balances are affected by our

financing activities, as discussed below in "--Financing Activities." The

following table illustrates the sources of our invested capital (dollars in

thousands):

<TABLE>

<CAPTION>

                                                                      September 30,    December 31,

                                                                          2006              2005

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

<S>                                                                  <C>               <C>        

Long-term debt, excluding market value of interest rate swaps......  $  4,386,706      $ 5,220,887

Minority interest..................................................        44,666           42,331

Partners' capital, excluding accumulated other

comprehensive loss.................................................     4,878,054        4,693,414

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

  Total capitalization.............................................     9,309,426        9,956,632

Short-term debt, less cash and cash equivalents....................     1,123,260          (12,108)

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

  Total invested capital...........................................  $ 10,432,686      $ 9,944,524

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

Capitalization:

  Long-term debt, excluding market value of interest rate swaps....          47.1%            52.4%

  Minority interest................................................           0.5%             0.4%

  Partners' capital, excluding accumulated other

  comprehensive loss...............................................          52.4%            47.2%

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

                                                                            100.0%           100.0%

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

Invested Capital:

  Total debt, less cash and cash equivalents and excluding

       market value of interest rate swaps.....................              52.8%            52.4%

  Partners' capital and minority interest, excluding accumulated

       other comprehensive loss ...............................              47.2%            47.6%

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

                                                                            100.0%           100.0%

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

</TABLE>

     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

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<PAGE>

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.

     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 proceeds from purchases of additional i-units by 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. Our debt credit

ratings are currently rated BBB+ by Standard & Poor's Rating Services, and Baa1

by Moody's Investors Service. On May 30, 2006, S&P and Moody's each placed our

ratings on credit watch pending resolution of a management buyout proposal for

all of the outstanding shares of KMI. We are not able to predict with certainty

the final outcome of the pending buyout proposal; however, even if the buyout

proposal is consummated, we expect to maintain an investment grade credit

rating.

     Short-term Liquidity

     Our principal sources of short-term liquidity are:

     o    our $1.85 billion five-year senior unsecured revolving credit facility

          that matures August 18, 2010;

     o    our $1.85 billion short-term commercial paper program (which is

          supported by our bank credit facility, with the amount available for

          borrowing under our credit facility being reduced by our outstanding

          commercial paper borrowings); and

     o    cash from operations (discussed following).

     Borrowings under our credit facility can be used for general corporate

purposes and as a backup for our commercial paper program. There were no

borrowings under our credit facility as of December 31, 2005, or as of September

30, 2006. As of September 30, 2006, we had $887.6 million of commercial paper

outstanding.

     We provide 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 facility was $524.3 million as of September 30, 2006. As

of September 30, 2006, our outstanding short-term debt was $1,147.2 million.

Currently, we believe our liquidity to be adequate.

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<PAGE>

     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 and debt markets for our

limited partner units and long-term notes, and there can be no assurance we will

be able or willing to access the public or private markets for our limited

partner units and/or long-term notes 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. Our ability to access the public and private debt markets is

affected by our credit ratings. See "--Capital Structure" above for a discussion

of our credit ratings.

     All of our long-term debt securities issued to date, other than those

issued under our long-term revolving credit facility 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 September 30, 2006, our total liability balance due on the various

series of our senior notes was $4,490.4 million, and the total liability balance

due on the various borrowings of our operating partnerships and subsidiaries was

$155.9 million. For additional information regarding our debt securities and

credit facility, 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 $878.7 million for the nine

months ended September 30, 2006, versus $901.6 million in the comparable period

of 2005. The period-to-period decrease of $22.9 million (3%) in cash flow from

operations consisted of:

     o    an $87.8 million decrease in cash inflows relative to net changes in

          working capital items, mainly due to timing differences that resulted

          in higher net cash payments of $91.3 million with regard to the

          collection and payment of both trade and related party receivables and

          payables;

     o    a $19.1 million decrease in cash related to payments made in June 2006

          to certain shippers on our Pacific operations' pipelines. The payment

          related to a settlement agreement reached in May 2006 that resolved

          certain challenges by complainants with regard to delivery tariffs and

          gathering enhancement fees at our Pacific operations' Watson Station,

          located in Carson, California. The agreement called for estimated

          refunds to be paid into an escrow account pending final approval by

          the FERC, which was made in the third quarter of 2006;

     o    a $62.0 million increase in cash from overall higher partnership

          income--net of non-cash items including depreciation charges,

          undistributed earnings from equity investments, and gains from the

          sale of assets. The higher partnership income reflects an increase in

          cash earnings from our four reportable business segments in

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<PAGE>

          the first nine months of 2006, as discussed above in "-Results of

          Operations." The non-cash items include the $15.1 million gain from

          the combined sale of our Douglas natural gas gathering system and

          Painter Unit fractionation facility in the second quarter of 2006;

     o    a $17.3 million increase in cash inflows relative to net changes in

          non-current assets and liabilities, which represent offsetting changes

          in cash from various long-term asset and liability accounts. On a net

          basis, the increase in cash inflows from non-current items reflects,

          among other things, higher environmental expense accruals in the first

          nine months of 2006, higher spending on deferred project study costs

          in the first nine months of 2005, and incremental property tax refunds

          received in the second quarter of 2006, pursuant to successful

          litigation between our Pacific operations and various Arizona taxing

          authorities concerning differences over the assessed value of property

          owned by our Pacific operations for the tax years 2000 through 2002;

          and

     o    a $4.7 million increase related to higher distributions received from

          equity investments--chiefly due to higher distributions received from

          Red Cedar Gathering Company in the first nine months of 2006. The

          increase in distributions received resulted from Red Cedar's higher

          year-over-year net income in the first nine months of 2006 versus the

          first nine months of 2005, and also from the fact that Red Cedar had

          higher capital expansion spending in 2005, and funded a large portion

          of the expenditures with retained cash.

     Investing Activities

     Net cash used in investing activities was $1,062.1 million for the nine

month period ended September 30, 2006, compared to $905.6 million in the

comparable 2005 period. The $156.5 million (17%) increase in cash used in

investing activities was primarily attributable to:

     o    a $154.1 million (26%) increase in capital expenditures--driven by a

          $163.4 million increase in capital spending from our Natural Gas

          Pipelines business segment, largely due to increased investment in

          natural gas pipeline and natural gas storage expansion projects.

          Including expansion and maintenance projects, our capital expenditures

          were $751.3 million in the first nine months of 2006, compared to

          $597.2 million in the same prior-year period.

          Our sustaining capital expenditures were $76.2 million for the first

          nine months of 2006, compared to $95.8 million for the first nine

          months of 2005. Sustaining capital expenditures are defined as capital

          expenditures which do not increase the capacity of an asset. Beginning

          in the third quarter of 2006, our Products Pipelines business segment

          began recognizing certain costs incurred as part of its pipeline

          integrity management program as maintenance expense in the period

          incurred, and in addition, recorded an expense for costs previously

          capitalized as sustaining capital expenditures during the first six

          months of 2006. Combined, this change reduced the segment's earnings

          before depreciation, depletion and amortization expenses by $18.1

          million and its sustaining capital expenditures by $14.6 million.

          Our forecasted expenditures for the fourth quarter of 2006 for

          sustaining capital expenditures are approximately $45.9 million. This

          amount has been forecasted primarily for the purchase of plant and

          equipment. All of our capital expenditures, with the exception of

          sustaining capital expenditures, are discretionary;

     o    a $77.5 million (27%) increase due to higher expenditures made for

          strategic business acquisitions--in the first nine months of 2006, our

          acquisition outlays totaled $367.3 million, which consisted of $244.6

          million for the acquisition of Entrega Gas Pipeline LLC, $62.5 million

          for the acquisition of bulk terminal operations and related assets,

          and $60.2 million for the purchase of additional oil and gas

          properties. In the first nine months of 2005, we spent $289.8 million,

          which primarily included $188.6 million for the acquisition of Texas

          Petcoke terminal assets from Trans-Global Solutions, Inc., $50.9

          million for our North Dayton, Texas natural gas storage facility, and

          $23.9 million for the acquisition of our Kinder Morgan Staten Island

          terminal, a petroleum products liquids terminal located in the New

          York Harbor area on Staten Island, New York;

     o    a $68.5 million decrease in cash used due to higher net proceeds

          received from the sales of property, plant and equipment and other net

          assets, net of salvage and removal costs. The increase in sale

          proceeds was driven

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<PAGE>

          by (i) the $42.5 million we received in the second quarter of 2006

          from Momentum Energy Group, LLC for the combined sale of our Douglas

          natural gas gathering system and Painter Unit fractionation facility

          and (ii) the $27.0 million we received in the first half of 2006 from

          the sale of certain oil and gas properties from Journey Acquisition-I,

          L.P. and Journey 2000, L.P.; and

     o    a $7.3 million decrease due to lower payments for natural gas stored

          underground and natural gas liquids pipeline line-fill--largely

          related to lower investments in underground natural gas storage

          volumes in the first nine months of this year relative to the first

          nine months of last year.

     In addition, we recently made the following announcements related to our

investing activities:

     o    On September 11, 2006, we announced major expansions at certain of our

          Texas liquids terminal facilities that will provide additional

          infrastructure to help meet the growing need for refined petroleum

          products storage capacity along the Gulf Coast. The investment of

          approximately $195 million will include the construction of:

     o    new storage tanks at our Pasadena and Galena Park terminals on the

          Houston Ship Channel;

     o    an additional cross-channel pipeline to increase the connectivity

          between the two terminals;

     o    a new ship dock at Galena Park; and

     o    an additional loading bay at our fully automated truck loading rack

          located at our Pasadena terminal.

          The expansions are supported by long-term customer commitments and

          will result in approximately 3.4 million barrels of additional tank

          storage capacity at the Pasadena and Galena Park terminals.

          Construction began in October 2006 and all of the projects are

          expected to be completed by the spring of 2008; and

     o    On October 19, 2006, we announced plans to invest approximately $388

          million to further expand our 550-mile CALNEV Pipeline. CALNEV

          currently transports refined petroleum products from the Los Angeles,

          California area to the Las Vegas, Nevada market through parallel

          14-inch and 8-inch diameter pipelines. The proposed expansion would

          include construction of a new 16-inch diameter pipeline and would

          increase system capacity to approximately 200,000 barrels per day upon

          completion. Capacity could be increased as necessary to over 300,000

          barrels per day with the addition of pump stations.

          Environmental permitting and right-of-way acquisition is expected to

          take between 24 to 30 months, and construction is anticipated to be

          competed within nine months thereafter. The expansion is subject to

          environmental permitting, right-of-way acquisition and the receipt of

          approvals from the FERC authorizing rates that are economic to CALNEV.

          Start-up of the new pipeline is scheduled for late 2009 or early 2010.

     Financing Activities

     Net cash provided by financing activities amounted to $195.1 million for

the nine months ended September 30, 2006. For the same nine month period last

year, our financing activities provided net cash of $4.2 million. The $190.9

million increase from the comparable 2005 period was primarily due to:

     o    a $318.2 million increase from overall debt financing

          activities--which include our issuances and payments of debt and our

          debt issuance costs. The overall increase was primarily due to a

          $612.1 million increase from higher net commercial paper borrowings in

          the first nine months of 2006, partially offset by a $294.4 million

          decrease due to both issuances and payments of senior notes during

          2005. The increase in commercial paper debt includes net borrowings of

          $412.5 million under the commercial paper program of Rockies Express

          Pipeline LLC. We held a 66 2/3% ownership interest in Rockies Express

          Pipeline LLC until June 30, 2006, and according to the provisions of

          generally accepted accounting principles, we included its cash inflows

          and outflows in our consolidated statement of cash flows for the six

          months ended June 30, 2006.

          On June 30, 2006, following ConocoPhillips' acquisition of a 24%

          ownership interest in West2East Pipeline LLC (and its subsidiary

          Rockies Express Pipeline LLC), we deconsolidated West2East Pipeline

          LLC and we have subsequently accounted for our investment under the

          equity method of accounting. Following the

                                       83

<PAGE>

          change to the equity method on June 30, 2006, Rockies Express' debt

          balances were no longer included in our consolidated balance sheet and

          its cash inflows and outflows for all periods subsequent to June 2006

          were not included in our consolidated statement of cash flows.

          The decrease in cash inflows from changes in our senior notes related

          to debt activities occurring on March 15, 2005. On that date, we both

          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 $104.8 million increase from contributions from minority

          interests--principally due to contributions of $104.2 million received

          from Sempra Energy with regard to its ownership interest in Rockies

          Express Pipeline LLC. The contribution from Sempra includes an amount

          of $80 million, contributed in the first quarter of 2006, for Sempra's

          original 33 1/3% share of the purchase price of Entrega Pipeline LLC.

          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;

     o    a $6.0 million increase from net changes in cash book

          overdrafts--which represent checks issued but not yet endorsed;

     o    a $200.4 million decrease from higher partnership

          distributions--distributions to all partners, consisting of our common

          and Class B unitholders, our general partner and minority interests,

          totaled $896.9 million in the first nine months of 2006, compared to

          $696.5 million in the comparable 2005 period. The overall increase in

          period-to-period distributions included minority interest

          distributions of $105.2 million paid from our Rockies Express Pipeline

          LLC subsidiary to Sempra Energy in the first half of 2006.

          The distributions to Sempra (and distributions to us for our

          proportional ownership interest) were made in conjunction with Rockies

          Express' establishment of and subsequent borrowings under its

          commercial paper program during the second quarter of 2006, as

          discussed above. During the second quarter of 2006, Rockies Express

          both issued a net amount of $412.5 million of commercial paper and

          distributed $315.5 million to its member owners. Prior to the

          establishment of its commercial paper program (supported by its

          five-year unsecured revolving credit agreement), Rockies Express

          funded its acquisition of Entrega Gas Pipeline LLC and its Rockies

          Express Pipeline construction costs with contributions from both us

          and Sempra.

          Excluding the minority interest distributions to Sempra, overall

          distributions increased $95.2 million. The increase primarily resulted

          from higher distributions in 2006 of "Available Cash," as described

          below in "--Partnership Distributions." The increase in "Available

          Cash" distributions in 2006 versus 2005 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;

          and

     o    a $37.0 million decrease in cash inflows from equity

          issuances--primarily related to the incremental cash we received for

          our third quarter 2005 common unit issuance compared to our third

          quarter 2006 common unit issuance. In the third quarter of 2005, we

          issued, in a public offering, 5,750,000 of our common units at a price

          of $51.25 per unit. After commissions and underwriting expenses, we

          received net proceeds of $283.6 million for the issuance of these

          units. Similarly, in an August 2006 public offering, we issued an

          additional 5,750,000 of our common units at a price of $44.80, less

          commissions and underwriting expenses. After all fees, we received net

          proceeds of $248.0 million for the issuance of these common units. We

          used the proceeds from each of these two equity issuances to reduce

          the borrowings under our commercial paper program.

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     Partnership Distributions

     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;

     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.

     On August 14, 2006, we paid a quarterly distribution of $0.81 per unit for

the second quarter of 2006. This distribution was 4% greater than the $0.78

distribution per unit we paid in August 2005 for the second 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 $0.81 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

that we paid on August 14, 2006 to our general partner (for the second quarter

of 2006) was $129.0 million. Our general partner's incentive distribution that

we paid in August 2005 to our general partner (for the second quarter of 2005)

was $115.7 million. Our general partner's incentive distribution for the

distribution that we declared for the third

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quarter of 2006 was $133.0 million. Our general partner's incentive distribution

for the distribution that we paid for the third quarter of 2005 was $121.5

million.

     Litigation and Environmental

     As of September 30, 2006, we have recorded a total reserve for

environmental claims, without discounting and without regard to anticipated

insurance recoveries, in the amount of $65.2 million. In addition, we have

recorded a receivable of $27.1 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 or accidental spills or releases at facilities that

we own. 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.

     Additionally, as of September 30, 2006, we have recorded a total reserve

for legal fees, transportation rate cases and other litigation liabilities in

the amount of $112.7 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.

     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 our contractual obligations that

would affect the disclosures presented as of December 31, 2005 in our 2005 Form

10-K report.

     Off Balance Sheet Arrangements

     Except as set forth under "--Rockies Express Pipeline LLC Debt" in Note 7

to our consolidated financial statements included elsewhere in this report,

there have been no material changes in our obligations with respect to other

entities that are not consolidated in our financial statements that would affect

the disclosures presented as of December 31, 2005 in our 2005 Form 10-K.

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,

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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;

     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;

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     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 3 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 and Part II, Item 1A "Risk Factors" of this report, 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 report and

this report. The risk factors could cause our actual results to differ

materially from those contained in any forward-looking statement. Other than as

required by applicable law, we disclaim any obligation to update the above list

or to announce publicly the result of any revisions to any of the

forward-looking statements to reflect future events or 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 September 30, 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,

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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 September 30,

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.

     Except as set forth below, 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.

     The consummation of a transaction to acquire all of the outstanding common

stock of KMI that results in substantially more debt at KMI could have an

adverse effect on us, such as a downgrade in the ratings of our debt securities.

On August 28, 2006, KMI entered into an agreement and plan of merger whereby

investors led by Richard D. Kinder, Chairman and CEO of KMI, would acquire all

of the outstanding shares of KMI for $107.50 per share in cash. The investors

include members of senior management of KMI, most of whom are also senior

officers of our general partner and of KMR. As a result, prior to the closing of

this transaction, our senior management's attention may be diverted from the

management of our daily operations. In response to this proposed transaction,

Moody's Investor Services placed both our long-term and short-term debt ratings

under review for possible downgrade and Standard & Poor's put our long-term debt

rating on credit watch with negative implications. In connection with the

merger, KMI will incur substantially more debt, which could have an adverse

effect on us, such as a downgrade in the ratings of our debt securities, which

could be significant.

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

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        to furnish supplementally to the Securities and Exchange Commission a

        copy of each such instrument upon request.

10.1 -- First Amendment, dated October 28, 2005, to Five-Year Credit Agreement

        dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P.,

        the lenders party thereto and Wachovia Bank, National Association as

        Administrative Agent.

10.2 -- Second Amendment, dated April 13, 2006, to Five-Year Credit Agreement

        dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P.,

        the lenders party thereto and Wachovia Bank, National Association as

        Administrative Agent.

10.3 -- Third Amendment, dated October 6, 2006, to Five-Year Credit Agreement

        dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P.,

        the lenders party thereto and Wachovia Bank, National Association as

        Administrative Agent.

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.

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.

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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:  November 7, 2006

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