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. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Securities Exchange Act of 1934. Large accelerated filer x 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 Securities Exchange Act of 1934). Yes o No x

	PART I. FINANCIAL INFORMATION

Item 1:	Financial Statements	3
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2007 and 2006	3
	Consolidated Balance Sheets – September 30, 2007 and December 31, 2006	4
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2007 and 2006	5
	Notes to Consolidated Financial Statements	6

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
	Critical Accounting Policies and Estimates	55
	Results of Operations	56
	Financial Condition	70
	Information Regarding Forward-Looking Statements	76

Item 3:	Quantitative and Qualitative Disclosures About Market Risk	78

Item 4:	Controls and Procedures	78



	PART II. OTHER INFORMATION

Item 1:	Legal Proceedings	79

Item 1A:	Risk Factors	79

Item 2:	Unregistered Sales of Equity Securities and Use of Proceeds	80

Item 3:	Defaults Upon Senior Securities	80

Item 4:	Submission of Matters to a Vote of Security Holders	81

Item 5:	Other Information	81

Item 6:	Exhibits	81

	Signature	82

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Revenues
Natural gas sales	$	1,365.7		$	1,516.8		$	4,314.6		$	4,679.2
Services		624.1			555.6			1,776.8			1,618.9
Product sales and other		241.0			224.4			677.5			628.1
		2,230.8			2,296.8			6,768.9			6,926.2
Costs, Expenses and Other
Gas purchases and other costs of sales		1,371.7			1,511.2			4,296.0			4,649.8
Operations and maintenance		206.4			210.9			606.2			581.8
Fuel and power		60.7			58.9			171.3			165.2
Depreciation, depletion and amortization		138.0			109.1			401.8			304.5
General and administrative		106.2			63.5			265.9			195.1
Taxes, other than income taxes		38.9			31.8			112.0			102.7
Goodwill impairment expense		—			—			377.1			—
Other expense (income)		(2.5	)		—			(11.9	)		(16.0	)
		1,919.4			1,985.4			6,218.4			5,983.1

Operating Income		311.4			311.4			550.5			943.1

Other Income (Expense)
Earnings from equity investments		15.8			13.6			51.4			55.5
Amortization of excess cost of equity investments		(1.4	)		(1.4	)		(4.3	)		(4.2	)
Interest, net		(102.4	)		(90.1	)		(290.3	)		(251.3	)
Other, net		5.0			3.9			9.4			13.1
Minority Interest		(2.4	)		(2.1	)		(4.4	)		(8.1	)

Income from Continuing Operations Before Income Taxes		226.0			235.3			312.3			748.1

Income Taxes		(20.8	)		(8.2	)		(36.4	)		(20.1	)

Income from Continuing Operations		205.2			227.1			275.9			728.0

Income from Discontinued Operations (Note 2)		8.6			2.4			21.1			8.8

Net Income	$	213.8		$	229.5		$	297.0		$	736.8

Calculation of Limited Partners’ interest in Net Income:
Income from Continuing Operations	$	205.2		$	227.1		$	275.9		$	728.0
Less: General Partner’s interest		(155.7	)		(134.0	)		(439.9	)		(393.7	)
Limited Partners’ interest		49.5			93.1			(164.0	)		334.3
Add: Limited Partners’ interest in Discontinued Operations		8.5			2.4			20.9			8.7
Limited Partners’ interest in Net Income	$	58.0		$	95.5		$	(143.1	)	$	343.0

Basic and Diluted Limited Partners’ Net Income (loss) per Unit:
Income from Continuing Operations	$	0.21		$	0.41		$	(0.70	)	$	1.50
Income from Discontinued Operations		0.03			0.01			0.09			0.04
Net Income	$	0.24		$	0.42		$	(0.61	)	$	1.54

Weighted average number of units used in computation of
Limited Partners’ Net Income per unit:
Basic		239.0			225.8			235.0			222.8

Diluted		239.0			226.2			235.1			223.1

Per unit cash distribution declared	$	0.88		$	0.81		$	2.56		$	2.43

The accompanying notes are an integral part of these consolidated financial statements.

	September 30,			December 31,
	2007			2006
ASSETS
Current Assets
Cash and cash equivalents	$	58.4		$	6.7
Restricted deposits		38.0			—
Accounts, notes and interest receivable, net
Trade		842.1			854.7
Related parties		5.2			7.9
Inventories
Products		15.0			20.4
Materials and supplies		19.3			16.6
Gas imbalances
Trade		16.3			7.8
Related parties		—			11.6
Gas in underground storage		5.2			8.4
Assets held for sale		11.7			—
Other current assets		45.7			102.7
		1,056.9			1,036.8
Property, Plant and Equipment, net		11,079.0			10,106.1
Investments		439.9			426.3
Notes receivable
Trade		0.7			1.2
Related parties		90.1			96.2
Goodwill		1,076.0			1,421.0
Other intangibles, net		242.5			213.2
Assets held for sale, non-current		149.5			—
Deferred charges and other assets		253.4			241.4
Total Assets	$	14,388.0		$	13,542.2

LIABILITIES AND PARTNERS’ CAPITAL

Current Liabilities
Accounts payable
Cash book overdrafts	$	36.9		$	46.2
Trade		788.0			784.1
Related parties		33.2			203.3
Current portion of long-term debt		597.0			1,359.1
Accrued interest		67.0			83.7
Accrued taxes		90.7			35.4
Deferred revenues		16.9			20.0
Gas imbalances
Trade		13.3			15.9
Related parties		5.1			—
Liabilities held for sale		4.6			—
Accrued other current liabilities		598.2			589.6
		2,250.9			3,137.3
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding		6,456.8			4,384.3
Value of interest rate swaps		45.2			42.6
		6,502.0			4,426.9
Deferred revenues		10.9			18.8
Deferred income taxes		202.0			185.2
Asset retirement obligations		50.5			48.9
Liabilities held for sale, non-current		2.3			—
Other long-term liabilities and deferred credits		754.6			716.6
		7,522.3			5,396.4
Commitments and Contingencies (Note 3)
Minority Interest		55.5			60.2
Partners’ Capital
Common Units		2,767.0			3,414.9
Class B Units		103.9			126.1
i-Units		2,364.3			2,154.2
General Partner		146.9			119.2
Accumulated other comprehensive loss		(822.8	)		(866.1	)
		4,559.3			4,948.3
Total Liabilities and Partners’ Capital	$	14,388.0		$	13,542.2

The accompanying notes are an integral part of these consolidated financial statements.

	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities
Net income	$	297.0		$	736.8
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of goodwill		377.1			—
Depreciation, depletion and amortization		408.8			311.1
Amortization of excess cost of equity investments		4.3			4.2
Gains from property casualty indemnifications		(1.8	)		—
Gains and other non-cash income from the sale of property, plant and equipment		(10.4	)		(16.6	)
Earnings from equity investments		(53.2	)		(57.2	)
Distributions from equity investments		87.9			56.3
Proceeds from termination of interest rate swap agreement		15.0			—
Changes in components of working capital:
Accounts receivable		210.6			70.6
Other current assets		4.0			(4.0	)
Inventories		1.8			6.3
Accounts payable		(136.6	)		(183.4	)
Accrued interest		(17.0	)		(29.0	)
Accrued liabilities		(11.6	)		(1.5	)
Accrued taxes		57.6			53.4
FERC rate reparations, refunds and reserve adjustments		—			(19.1	)
Other, net		21.2			(11.4	)
Net Cash Provided by Operating Activities		1,254.7			916.5

Cash Flows From Investing Activities
Acquisitions of assets		(152.2	)		(357.1	)
Payment for Trans Mountain (Note 2)		(549.1	)		—
Acquisitions of investments		(9.5	)		—
Additions to property, plant and equip. for expansion and maintenance projects		(1,142.9	)		(811.1	)
Sale of property, plant and equipment, and other net assets net of removal costs		11.6			71.5
Property casualty indemnifications		8.0			—
Net proceeds from (Investments in) margin deposits		(40.3	)		1.4
Contributions to equity investments		(46.6	)		(0.1	)
Natural gas stored underground and natural gas liquids line-fill		12.3			(12.9	)
Other		—			(3.4	)
Net Cash Used in Investing Activities		(1,908.7	)		(1,111.7	)

Cash Flows From Financing Activities
Issuance of debt		6,206.6			3,730.0
Payment of debt		(4,941.0	)		(3,005.4	)
Repayments from loans to related party		2.2			1.1
Debt issue costs		(13.5	)		(1.6	)
Increase (Decrease) in cash book overdrafts		(9.3	)		12.8
Proceeds from issuance of common units		—			248.4
Proceeds from issuance of i-units		297.9			—
Contributions from minority interest		4.8			109.3
Distributions to partners:
Common units		(409.1	)		(380.2	)
Class B units		(13.3	)		(12.9	)
General Partner		(410.3	)		(388.4	)
Minority interest		(11.9	)		(115.4	)
Other, net		0.1			(2.6	)
Net Cash Provided by Financing Activities		703.2			195.1

Effect of exchange rate changes on cash and cash equivalents		2.5			0.1

Increase in Cash and Cash Equivalents		51.7			—
Cash and Cash Equivalents, beginning of period		6.7			12.1
Cash and Cash Equivalents, end of period	$	58.4		$	12.1

Noncash Investing and Financing Activities:
Contribution of net assets to partnership investments	$	—		$	17.0
Assets acquired by the assumption or incurrence of liabilities		19.5			3.7

The accompanying notes are an integral part of these consolidated financial statements.

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 our 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. Our consolidated financial statements reflect normal adjustments, and also 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, 2006, and in our Current Report on Form 8-K filed August 22, 2007.

Knight Inc. (formerly known as Kinder Morgan, Inc.), Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC

On August 28, 2006, Kinder Morgan, Inc., a Kansas corporation referred to as “KMI” in this report, 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 (other than shares held by certain stockholders and investors) for $107.50 per share in cash. Additional investors in the going-private transaction included the following: other senior members of KMI management, most of whom are also senior officers of Kinder Morgan G.P., Inc. (our general partner) and of Kinder Morgan Management, LLC (our general partner’s delegate, discussed below); Kinder Morgan co-founder William V. Morgan; KMI board members Fayez Sarofim and Michael C. Morgan; and affiliates of (i) Goldman Sachs Capital Partners; (ii) American International Group, Inc.; (iii) The Carlyle Group; and (iv) Riverstone Holdings LLC.

On May 30, 2007, this acquisition and merger closed, with KMI continuing as the surviving legal entity and renamed “Knight Inc.” Knight Inc., referred to as “Knight” in this report, is privately owned, and remains the sole indirect common stockholder of Kinder Morgan G.P., Inc., our general partner. On July 27, 2007, our general partner issued and sold 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057. The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us, or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line LLC.

Kinder Morgan Management, LLC, referred to as “KMR” in this report, is a Delaware limited liability company. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, delegated to KMR, 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. More information on these entities and the delegation of control agreement is contained in our Annual Report on Form 10-K for the year ended December 31, 2006, and in our Current Report on Form 8-K filed August 22, 2007.

Our consolidated financial statements include our accounts and those of our operating partnerships and their majority-owned and controlled subsidiaries. Our accounting records are maintained in United States dollars, and all references to dollars are United States dollars, except where stated otherwise. All significant intercompany items

have been eliminated in consolidation. Certain amounts from prior periods have been reclassified to conform to the current presentation. Our accompanying consolidated financial statements reflect amounts on a historical cost basis, and, accordingly, do not reflect any purchase accounting adjustments related to the management buyout of KMI, now known as Knight. In addition, as discussed in Note 2 below, our financial statements included in this report include the transactions, balances and results of operations of our Trans Mountain pipeline system as if it had been transferred to us on January 1, 2006.

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.

Emerging Issues Task Force Issue No. 03-6, or EITF 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its securities. For partnerships, under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed regardless of whether a general partner has discretion over the amount of distribution to be made for any particular period.

EITF 03-6 does not impact our overall net income or other financial results because we do not have undistributed earnings in any period presented in this report. Our Annual Report on Form 10-K for the year ended December 31, 2006 contains additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including minority interests.

During the first nine months of 2007, we completed the following acquisitions, and except for our acquisition of the Trans Mountain pipeline system (as discussed below), these acquisitions were accounted for as business combinations involving unrelated entities according to the provisions of Statement of Financial Accounting Standards No. 141, “Business Combinations.” SFAS No. 141 requires business combinations involving unrelated entities to be accounted for using the purchase method of accounting, which establishes a new basis of accounting for the purchased assets and liabilities—the acquirer records all the acquired assets and assumed liabilities at their estimated fair market values (not the acquired entity’s book values) as of the acquisition date.

The preliminary allocation of these assets (and any liabilities assumed) may be adjusted to reflect the final determined amounts, and although the time that is required to identify and measure the fair value of the assets acquired and the liabilities assumed in a business combination will vary with circumstances, generally our allocation period ends when we no longer are waiting for information that is known to be available or obtainable. The results of operations from these acquisitions accounted for as business combinations involving unrelated entities are included in our consolidated financial statements from the acquisition date.

Effective January 1, 2007, we acquired the remaining approximate 50.2% interest in the Cochin pipeline system that we did not already own for an aggregate consideration of approximately $47.8 million, consisting of $5.5 million in cash and a note payable having a fair value of $42.3 million. As part of the transaction, the seller also agreed to reimburse us for certain pipeline integrity management costs over a five-year period in an aggregate amount not to exceed $50 million. Upon closing, we became the operator of the pipeline.

The Cochin Pipeline is a multi-product liquids pipeline consisting of approximately 1,900 miles of 12-inch diameter pipe operating between Fort Saskatchewan, Alberta, and Windsor, Ontario, Canada. The entire Cochin pipeline system traverses three provinces in Canada and seven states in the United States, serving the Midwestern United States and eastern Canadian petrochemical and fuel markets. Its operations are included as part of our Products Pipelines business segment.

As of September 30, 2007, we allocated our entire purchase price to “Property, Plant and Equipment, net” on our accompanying consolidated balance sheet. Our allocation of the purchase price was preliminary, pending final determination of working capital and deferred income tax balances at the time of acquisition. We expect these final purchase price adjustments to be made by the end of 2007.

On May 30, 2007, we purchased the Vancouver Wharves bulk marine terminal from British Columbia Railway Company, a crown corporation owned by the Province of British Columbia, for an aggregate consideration of $56.6 million, consisting of $38.3 million in cash and $18.3 million in assumed liabilities. We allocated $6.3 million of our combined purchase price to current assets and the remaining $50.3 million to “Property, Plant and Equipment, net.”

The Vancouver Wharves facility is located on the north shore of the Port of Vancouver’s main harbor, and includes five deep-sea vessel berths situated on a 139-acre site. The terminal assets include significant rail infrastructure, dry bulk and liquid storage, and material handling systems which allow the terminal to handle over 3.5 million tons of cargo annually. Vancouver Wharves also has access to three major rail carriers connecting to shippers in western and central Canada, and the U.S. Pacific Northwest. The acquisition both expanded and complemented our existing terminal operations, and all of the acquired assets are included in our Terminals business segment.

Effective September 1, 2007, we acquired certain bulk terminals assets from Marine Terminals, Inc. for an aggregate consideration of approximately $101.4 million, consisting of $100.4 million in cash and an assumed liability of $1.0 million. The acquired assets and operations are primarily involved in the handling and storage of steel and alloys, and also provide stevedoring and harbor services, scrap handling, and scrap processing services to customers in the steel and alloys industry. The operations consist of two separate facilities located in Blytheville, Arkansas, and individual terminal facilities located in Decatur, Alabama; Hertford, North Carolina; and Berkley, South Carolina. Combined, the five facilities handled approximately 13.4 million tons of steel products in 2006. Under long-term contracts, the acquired terminal facilities will continue to provide handling, processing, harboring and warehousing services to Nucor Corporation, one of the nation’s largest steel and steel products companies in the world.

As of September 30, 2007, we have preliminarily allocated $60.6 million of our combined purchase price to “Property, Plant and Equipment, net,” $39.8 million to “Other Intangibles, net,” and the remaining $1.0 million to other current and long-term assets. The $39.8 million of intangibles represents the estimated 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. As of acquisition date, we estimated the expected useful life of these intangibles to be 20 years. The acquisition both expanded and complemented our existing ferro alloy terminal operations and will provide Nucor and other customers further access to our growing national network of marine and rail terminals. All of the acquired assets are included in our Terminals business segment.

On April 30, 2007, we acquired the Trans Mountain pipeline system from Knight for $549.1 million. The transaction was approved by the independent directors of both KMI and KMR following the receipt, by such directors, of separate fairness opinions from different investment banks. We paid $549 million of the purchase price on April 30, 2007, and we paid the remaining $0.1 million in July 2007.

Effective January 1, 2006, Knight (formerly KMI), our ultimate parent as determined by the provisions of Emerging Issues Task Force Issue 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,” was deemed to have control over us and no longer accounted for its investment in us under the equity method of accounting, but instead included our accounts, balances and results of operations in its consolidated financial statements. As required by the provisions of SFAS No. 141, we accounted for our acquisition of Trans Mountain as a transfer of net assets between entities under common control. For combinations of entities under common control, the purchase cost provisions (as they relate to purchase business combinations involving unrelated entities) of SFAS No. 141 explicitly do not apply; instead the method of accounting prescribed by SFAS No. 141 for such transfers is essentially identical to the pooling-of-interests method of accounting. Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination (that is, no recognition is made for a purchase premium or discount representing any difference between the cash consideration paid and the book value of the net assets acquired).

Therefore, following our acquisition of Trans Mountain from Knight on April 30, 2007, we recognized the Trans Mountain assets and liabilities acquired at their carrying amounts (historical cost) in the accounts of Knight (the transferring entity) at the date of transfer. The accounting treatment for combinations of entities under common control is consistent with the concept of poolings as combinations of common shareholder (or unitholder) interests, as all of Trans Mountain’s equity accounts were also carried forward intact initially, and subsequently adjusted due to the cash consideration we paid for the acquired net assets.

In addition to requiring that assets and liabilities be carried forward at historical costs, SFAS No. 141 also prescribes that for transfers of net assets between entities under common control, the income statement of the combined entity for the year of combination must be presented as if the entities had been combined for the full year, and all comparative financial statements must be presented as if the entities had previously been combined. Accordingly, our consolidated financial statements and all other financial information included in this report have been restated to assume that the transfer of Trans Mountain net assets from Knight to us had occurred at the date when both Trans Mountain and we met the accounting requirements for entities under common control (January 1, 2006). As a result, financial statements and financial information presented for prior periods in this report have been restated. These restatements include Knight’s recognition of a goodwill impairment expense of $377.1 million recorded in the first quarter of 2007, based on supporting third-party information obtained regarding the fair values of the Trans Mountain pipeline system assets. For more information on this impairment expense, see Note 6.

The Trans Mountain pipeline system, which transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the State of Washington, recently completed a pump station expansion and currently transports approximately 260,000 barrels per day. An additional 35,000 barrel per day expansion that will increase capacity of the pipeline to 300,000 barrels per day is expected to be in service by late 2008. In addition, due to the fact that Trans Mountain’s operations are managed separately, involve different products and marketing strategies, and produce discrete financial information that is separately evaluated internally by our management, we have identified our Trans Mountain pipeline system as a separate reportable business segment.

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, 2006, including the ones listed above, had occurred as of the beginning of each period presented, is not materially different from the information presented in our accompanying consolidated statements of income.

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

the net assets we sold in this transaction, 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.

Additionally, 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 three and nine months ended September 30, 2006. For more information on our accounting for derivative contracts, see Note 10.

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 approximately 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 operated the fractionator and the associated Millis terminal and storage facilities for its own account.

On July 2, 2007, we announced that we entered into an agreement to sell the North System natural gas liquids pipeline and our 50% ownership interest in the Heartland Pipeline Company (collectively referred to in this report as our North System) to ONEOK Partners, L.P. for approximately $300 million in cash. The North System consists of an approximately 1,600-mile interstate common carrier pipeline system that delivers natural gas liquids and refined petroleum products from south central Kansas to the Chicago area. Also included in the sale are eight propane truck-loading terminals, located at various points in three states along the pipeline system, and one multi-product terminal complex located in Morris, Illinois. All of the assets are included in our Products Pipelines business segment.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we accounted for the North System business as a discontinued operation whereby (i) the financial results of the North System have been reclassified to discontinued operations for all periods presented in this report, and (ii) the assets and liabilities of the North System are now classified as held-for-sale and are presented separately in our consolidated balance sheet as of September 30, 2007 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.” The transaction closed on October 5, 2007, and it is expected that a gain of approximately $150 million will be recognized in the fourth quarter of 2007 with respect to this transaction.

In accordance with SFAS No. 144, the financial results of the North System operations have been reclassified to discontinued operations for all periods presented and reported in the caption, “Income from Discontinued Operations” in our accompanying consolidated statements of income. Summarized financial results information of these operations is as follows (in millions):

In addition, in our accompanying consolidated statements of cash flows, we elected to not separately present the North System’s operating and investing cash flows as discontinued operations, and, due to the fact that the sale of the North System will not change the structure of our internal organization in a manner that causes a change to our reportable business segments pursuant to the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” we have included the North System’s financial disclosures within our Products Pipelines business segment disclosures for all periods presented in this report.

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during the nine months ended September 30, 2007. Additional information with respect to these proceedings can be found in Note 16 to our audited financial statements that were filed with our Annual Report on Form 10-K for the year ended December 31, 2006. This Note also contains a description of any material legal proceedings that were initiated during the nine months ended September 30, 2007.

SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. The tariffs and rates charged by our Pacific operations are subject to numerous ongoing proceedings at the Federal Energy Regulatory Commission, referred to in this report as the FERC, including shippers’ complaints and protests regarding interstate rates on our Pacific operations’ pipeline systems. In general, these complaints allege the rates and tariffs charged by our Pacific operations are not just and reasonable. The issues involved in these proceedings include, among others: (i) whether certain of our Pacific operations’ rates are “grandfathered” under the Energy Policy Act of 1992, referred to in this note as EPAct 1992, and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) the capital structure to be used in computing the “starting rate base” of our Pacific operations; (iv) the level of income tax allowance we may include in our rates; and (v) the recovery of civil and regulatory litigation expenses and certain pipeline reconditioning and environmental costs incurred by our Pacific operations.

In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. The new tax allowance policy and the FERC’s application of that policy to our Pacific operations were appealed to the United States Court of Appeals for the District of Columbia Circuit, referred to in this note as the D.C. Court.

On May 29, 2007, the D.C. Court issued an opinion upholding the FERC’s tax allowance policy. Because the extent to which an interstate oil pipeline is entitled to an income tax allowance is subject to a case-by-case review at the FERC, the level of income tax allowance to which SFPP will ultimately be entitled is not certain. The D.C. Court’s May 29 decision also upheld the FERC’s determination that a rate is no longer subject to grandfathering protection under EPAct 1992 when there has been a substantial change in the overall rate of return of

the pipeline, rather than in one cost element. Further, the D.C. Court declined to consider arguments that there were errors in the FERC’s method for determining substantial change, finding that the parties had not first raised such allegations with the FERC. On July 13, 2007, SFPP filed a petition for rehearing with the D.C. Court, arguing that SFPP did raise allegations with the FERC respecting these calculation errors. The D.C. Circuit denied rehearing of the May 29, 2007 decision on August 20, 2007. Petitions for writ of Certiorari to the United States Supreme Court regarding such decision are due within 90 days of the August 20th D.C. Circuit order.

In this Note, we refer to SFPP, L.P. as SFPP; CALNEV Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as ExxonMobil; Tosco Corporation as Tosco; ConocoPhillips Company as ConocoPhillips; Ultramar Diamond Shamrock Corporation as Ultramar; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; and America West Airlines, Inc., Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airline Complainants.

Following is a listing of certain current FERC proceedings pertaining to our Pacific operations:

In 2003, we made aggregate payments of $44.9 million for reparations and refunds pursuant to a FERC order related to Docket Nos. OR92-8, et al. In 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it to submit compliance filings and revised tariffs. Pursuant to the compliance filing, SFPP reduced its rates effective May 1, 2006. We currently estimate the impact of the rate reductions in 2007 to be approximately $25 million. In 2005, we also recorded an accrual of $105.0 million for an expense attributable to an increase in our reserves related to our rate case liability. We assume that any additional reparations and accrued interest thereon will be paid no earlier than the fourth quarter of 2007. We had previously estimated the combined annual impact of the rate reductions and the payment of reparations sought by shippers would be approximately 15 cents of distributable cash flow per unit. Based on our review of two separate orders issued by the FERC (on December 16, 2005 and on February 13, 2006), 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.

In general, if the shippers are successful in proving their claims, they are entitled to reparations or refunds of any excess tariffs or rates paid during the two year period prior to the filing of their complaint, and our Pacific operations may be required to reduce the amount of its tariffs or rates for particular services. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Based on our review of these FERC proceedings, we estimate that shippers are seeking approximately $275 million in reparation and refund payments and approximately $30 million in additional annual rate reductions.

On April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission, referred to in this Note as the CPUC. 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.

In October 2002, the CPUC issued a resolution, referred to in this Note 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 December 26, 2006, Tesoro filed a complaint challenging the reasonableness of SFPP’s intrastate rates for the three-year period from December 2003 through December 2006 and requesting approximately $8 million in

reparations. As a result of previous SFPP rate filings and related protests, the rates that are the subject of the Tesoro complaint are being collected subject to refund.

SFPP also has various, pending ratemaking matters before the CPUC that are unrelated to the above-referenced complaints and the Power Surcharge Resolution. Protests to these rate increase applications have been filed by various shippers. As a consequence of the protests, the related rate increases are being collected subject to refund.

All of the above matters have been consolidated and assigned to a single administrative law judge. At the time of this report, it is unknown when a decision from the CPUC regarding the CPUC complaints and the Power Surcharge Resolution will be received. No schedule has been established for hearing and resolution of the consolidated proceedings other than the 1997 CPUC complaint and the Power Surcharge Resolution. Based on our review of these CPUC proceedings, we estimate that shippers are seeking approximately $100 million in reparation and refund payments and approximately $35 million in annual rate reductions.

Kinder Morgan CO₂ Company, L.P. (referred to in this Note as Kinder Morgan CO₂), 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. 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).

Gerald O. Bailey et al. v. Shell Oil Co. et al/Southern District of Texas Lawsuit

Kinder Morgan CO₂, Kinder Morgan Energy Partners, L.P. and Cortez Pipeline Company are among the defendants in a proceeding in the federal courts for the southern district of Texas. Gerald O. Bailey et al. v. Shell Oil Company et al., (Civil Action Nos. 05-1029 and 05-1829 in the U.S. District Court for the Southern District of Texas—consolidated by Order dated July 18, 2005). The plaintiffs are asserting claims for the underpayment of royalties on carbon dioxide produced from the McElmo Dome unit. The plaintiffs 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. Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray & Co. have also asserted claims as private relators under the False Claims Act and for violation of federal and Colorado antitrust laws. The plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The defendants have filed motions for summary judgment on all claims. No trial date has been set.

Effective March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed a final settlement agreement which provides for the dismissal of these plaintiffs’ claims with prejudice to being refiled. On June 10, 2007, the Houston federal district court entered an order of partial dismissal by which the claims by and against the settling plaintiffs were dismissed with prejudice. The claims asserted by Bailey, Ptasynski, and Gray are not included within the settlement or the order of partial dismissal.

On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Bailey action discussed 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, 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 voluntarily dismissed the case on May 19, 2006. Ptasynski also filed an appeal in the Tenth Circuit seeking to overturn the Colorado court’s order transferring the case to Houston federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-1231 (10th Cir.). Briefing in the appeal was completed on November 27, 2006. On April 4, 2007, the Tenth Circuit Court of Appeals dismissed the appeal as moot in light of Ptasynksi’s voluntary dismissal of the case.

Cortez Pipeline Company and Kinder Morgan CO₂, successor 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. 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. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. On October 25, 2006, the defendants filed an application to confirm the arbitration decision in New Mexico federal district court. On June 21, 2007, the New Mexico federal district court entered final judgment confirming the August 7, 2006 arbitration decision.

On October 2, 2007, the plaintiff initiated a second arbitration (CO₂ Committee, Inc. v. Shell CO₂ Company, Ltd., aka Kinder Morgan CO₂ Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO₂ and a Mobil entity. The second arbitration asserts claims similar to those asserted in the first arbitration. On October 11, 2007, the defendants filed a Complaint for Declaratory Judgment and Injunctive Relief in federal district court in New Mexico. The Complaint seeks dismissal of the second arbitration on the basis of res judicata. No hearing or briefing schedule has been set.

On December 20, 2006, Kinder Morgan CO₂ received a “Notice of Noncompliance and Civil Penalty: Knowing or Willful Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO₂ Company, L.P., Case No. CP07-001” from the U.S. Department of the Interior, Minerals Management Service. This Notice, and the MMS’ position that Kinder Morgan CO₂ has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO₂ concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties. The Notice of Noncompliance and Civil Penalty assesses a civil penalty of approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for each of 17 alleged violations) for Kinder Morgan CO₂’s alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO₂ produced at McElmo Dome, during the period from June 2005 through October 2006. The MMS contends that false, inaccurate, or misleading information was submitted in the 17 monthly Form 2014s containing remittance advice reflecting the royalty payments for the referenced period because they reflected Kinder Morgan CO₂’s use of the Cortez Pipeline tariff as the transportation allowance. The MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO₂ should have used its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations as amended effective June 1, 2005. The MMS stated that civil penalties will continue to accrue at the same rate until the alleged violations are corrected.

The MMS set a due date of January 20, 2007 for Kinder Morgan CO₂’s payment of the approximately $2.2 million in civil penalties, with interest to accrue daily on that amount in the event payment is not made by such date. Kinder Morgan CO₂ has not paid the penalty. On January 2, 2007, Kinder Morgan CO₂ submitted a response to the Notice of Noncompliance and Civil Penalty challenging the assessment in the Office of Hearings and Appeals of the Department of the Interior. On February 1, 2007, Kinder Morgan CO₂ filed a petition to stay the accrual of penalties until the dispute is resolved. On February 22, 2007, an administrative law judge of the U.S. Department of the Interior issued an order denying Kinder Morgan CO₂’s petition to stay the accrual of penalties. A hearing on the Notice of Noncompliance and Civil Penalty is set for December 10, 2007.

Kinder Morgan CO₂ disputes the Notice of Noncompliance and Civil Penalty and believes that it has meritorious defenses. Kinder Morgan CO₂ contends that use of the Cortez pipeline tariff as the transportation allowance for purposes of calculating federal royalties was approved by the MMS in 1984. This approval was later affirmed as open-ended by the Interior Board of Land Appeals in the 1990s. Accordingly, Kinder Morgan CO₂ has stated to the MMS that its use of the Cortez tariff as the approved federal transportation allowance is authorized and proper. Kinder Morgan CO₂ also disputes the allegation that it has knowingly or willfully submitted false, inaccurate, or misleading information to the MMS. Kinder Morgan CO₂’s use of the Cortez Pipeline tariff as the approved federal transportation allowance has been the subject of extensive discussion between the parties. The MMS was, and is, fully apprised of that fact and of the royalty valuation and payment process followed by Kinder Morgan CO₂ generally.

On March 20, 2007, Kinder Morgan CO₂ received an “Order to Report and Pay” from the Minerals Management Service. The MMS contends that Kinder Morgan CO₂ has over-reported transportation allowances and underpaid royalties in the amount of approximately $4.6 million for the period from January 1, 2005 through December 31, 2006 as a result of its use of the Cortez pipeline tariff as the transportation allowance in calculating federal royalties. As noted in the discussion of the Notice of Noncompliance and Civil Penalty proceeding, the MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO₂ must use its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations. The MMS set a due date of April 13, 2007 for Kinder Morgan CO₂’s payment of the $4.6 million in claimed additional royalties, with possible late payment charges and civil penalties for failure to pay the assessed amount. Kinder Morgan CO₂ has not paid the $4.6 million, and on April 19, 2007, it submitted a notice of appeal and statement of reasons in response to the Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 CFR 290.100, et seq. Also on April 19, 2007, Kinder Morgan CO₂ submitted a petition to suspend compliance with the Order to Report and Pay pending the appeal. The MMS granted Kinder Morgan CO₂’s petition to suspend, and approved self-bonding on June 12, 2007. Kinder Morgan CO₂ filed a supplemental statement of reasons in support of its appeal of the Order to Report and Pay on June 15, 2007.

In addition to the March 2007 Order to Report and Pay, in April 2007, Kinder Morgan CO₂ received an “Audit Issue Letter” sent by the Colorado Department of Revenue on behalf of the U.S. Department of the Interior. In the letter, the Department of Revenue states that Kinder Morgan CO₂ has over-reported transportation allowances and underpaid royalties (due to the use of the Cortez pipeline tariff as the transportation allowance for purposes of federal royalties) in the amount of $8.5 million for the period from April 2000 through December 2004. Kinder Morgan CO₂ responded to the letter in May 2007, outlining its position why use of the Cortez tariff-based transportation allowance is proper. On August 8, 2007, Kinder Morgan CO₂ received an “Order to Report and Pay Additional Royalties” from the MMS. As alleged in the Colorado Audit Issue Letter, the MMS contends that Kinder Morgan CO₂ has over-reported transportation allowances and underpaid royalties in the amount of approximately $8.5 million for the period from April 2000 through December 2004. The MMS’s claims underlying the August 2007 Order to Report and Pay are similar to those at issue in the March 2007 Order to Report and Pay. On September 7, 2007, Kinder Morgan CO₂ submitted a notice of appeal and statement of reasons in response to the August 2007 Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 CFR 290.100, et seq. Also on September 7, 2007, Kinder Morgan CO₂ submitted a petition to suspend compliance with the Order to Report and Pay pending the appeal. The MMS granted Kinder Morgan CO₂’s petition to suspend, and approved self-bonding on September 11, 2007. Kinder Morgan CO₂ will file a supplemental statement of reasons in support of its appeal of the August 2007 Order to Report and Pay on or before November 6, 2007.

Kinder Morgan CO₂ disputes both the March and August 2007 Orders to Report and Pay and the Colorado Department of Revenue Audit Issue Letter, and as noted above, it contends that use of the Cortez pipeline tariff as the transportation allowance for purposes of calculating federal royalties was approved by the MMS in 1984 and was affirmed as open-ended by the Interior Board of Land Appeals in the 1990s. The appeals to the MMS Director of the Orders to Report and Pay do not provide for an oral hearing. No further submission or briefing deadlines have been set.

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 alleging that it has failed to pay the full royalty and overriding royalty (“royalty interests”) on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit in the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit. The plaintiffs allege that they were members of a class previously certified as a class action by the United States District Court for the District of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-0012 (the “Feerer Class Action”). Plaintiffs allege that Kinder Morgan CO₂’s method of paying royalty interests is contrary to the settlement of the Feerer Class Action. Kinder Morgan CO₂ 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. Kinder Morgan CO₂ appealed this decision to the New Mexico Court of Appeals, which affirmed the decision of the trial court. The New Mexico Supreme Court granted further review in October 2006, and after hearing oral argument, the New Mexico Supreme Court quashed its prior order granting review. In August 2007, Kinder Morgan CO₂ filed a petition for writ of certiorari with the United States Supreme Court seeking further review. Plaintiffs waived their right to file a response to the petition, but in September 2007, the United States Supreme Court ordered Plaintiffs to file a response to the petition on or before October 29, 2007.

In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO₂’s payments on carbon dioxide produced from the McElmo Dome Unit are currently ongoing. These audits and inquiries involve federal agencies and the State of Colorado.

SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company and referred to in this Note as UPRR) are engaged in a 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). In February 2007, a trial began to determine the amount payable for easements on UPRR rights-of-way. The trial is ongoing and is expected to conclude in the fourth quarter of 2007.

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 the judge determined that we must pay for any relocations resulting from any legitimate

business purpose of the UPRR. We have appealed this decision. 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 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.

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 multi-district litigation proceeding involves four lawsuits filed in 1997 against numerous Kinder Morgan companies. These suits were filed pursuant to the federal False Claims Act and allege underpayment of royalties due to mismeasurement of natural gas produced from federal and Indian lands. The complaints are part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants) in various courts throughout the country which were consolidated and transferred to the District of Wyoming.

In May 2005, a Special Master appointed in this litigation found that because there was a prior public disclosure of the allegations and that Grynberg was not an original source, the Court lacked subject matter jurisdiction. As a result, the Special Master recommended that the Court dismiss all the Kinder Morgan defendants. In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the Kinder Morgan defendants on jurisdictional grounds. Grynberg has appealed this Order to the Tenth Circuit Court of Appeals. A procedural schedule has been issued and briefing will be complete in the fourth quarter of 2007.

Prior to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his Complaint without evidentiary support and for an improper purpose. On January 8, 2007, after the dismissal order, the Kinder Morgan defendants also filed a Motion for Attorney Fees under the False Claim Act. On April 24, 2007 the Court held a hearing on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees. A decision on those matters has not yet issued.

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 Kinder Morgan defendants. 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 Kinder Morgan defendants, 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. On June 8, 2007, the Arkansas Supreme Court held that the Arkansas Public Service Commission has exclusive jurisdiction over any Arkansas plaintiffs’ claims that consumers were overcharged for gas in Arkansas and mandated

that any such claims be dismissed from this lawsuit. 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.

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.

After our October 17, 2007 third quarter earnings press release, we reached a civil settlement in principle with the U.S. Attorney’s office for the Southern District of Illinois pursuant to which we would agree to pay approximately $25 million, in aggregate, to the Tennessee Valley Authority and other customers of the Cora and Grand Rivers terminals from 1997-1999. We will make no admission or acknowledgment of improper conduct as part of the proposed settlement, and while we continue to believe that our actions at our terminals were appropriate, we determined that a civil resolution of the matter would be in our best interest. We are currently in the process of documenting this settlement, which must be approved by the Department of Justice. Accordingly, we recorded a $25 million increase in expense in the third quarter of 2007 associated with the probable settlement of this liability.

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. A class action complaint and a suit filed by the City of Cincinnati arising out of this accident have been settled. However, one member of the settlement class, the Estate of George W. Dameron, opted out of the settlement, and the Adminstratrix of the Dameron Estate filed a wrongful death lawsuit on November 15, 2006 in the Hamilton County Court of Common Pleas, Case No. A0609990. The complaint, which is asserted against each of the defendants involved in the class action suit, alleges that styrene exposure caused the death of Mr. Dameron. Kinder Morgan intends to vigorously defend against the estate’s claim.

As part of the settlement of the class action claims, 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.

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”).

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 May 30, 2003, 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. 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 the same defendants and alleging the same claims as in the Jernee case with respect to Stephanie Suzanne Sands. The Jernee case has been consolidated for pretrial purposes with the Sands case. In May 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 portions of the complaint. 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. Plaintiff has also filed a motion to dismiss the United States and/or to remand the case back to state court. By order dated September 27, 2007, the United States District Court granted the motion to dismiss the United States from the case and remanded the Jernee and Sands cases back to the Second Judicial District Court, State of Nevada, County of Washoe. The cases will now proceed in the State Court. 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 remaining claims against us in these matters are without merit and intend to defend against them vigorously.

From time to time, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. Often these leaks and ruptures are caused by third parties that strike and rupture our pipelines during excavation or construction. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

We believe that we conduct our operations in accordance with applicable law and many of these incidents are caused by the negligence of third parties. We seek to cooperate with state and federal regulatory authorities in connection with the clean-up of the environment caused by such leaks and ruptures and with any investigations as to the facts and circumstances surrounding the incidents.

On November 9, 2004, excavation equipment operated by Mountain Cascade, Inc., a third-party contractor on a water main installation project hired by East Bay Municipal Utility District, 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 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 approximately $0.1 million based upon our alleged failure to mark the location of the pipeline properly prior to the excavation of the site by the contractor. On June 27, 2005, the Office of the California State Fire Marshal, Pipeline Safety Division, referred to in this report as the CSFM, issued a notice of violation against us which also alleged 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 $0.5

million. 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.

On September 21, 2007, KMGP Services Company, Inc., an affiliate of Knight, entered into a plea agreement and civil settlement with the District Attorney of Contra Costa County pertaining to this accident. Under the terms of the plea agreement, KMGP Services Company, Inc. agreed to plead no contest to six counts of violating the California Labor Code. While initially constituted as felonies under the California Labor Code, the plea agreement contemplates that following the successful completion of an independent audit of our right-of-way protection policies and practices (likely in approximately one year), we may move to reduce the felony counts to misdemeanors. Pursuant to the plea agreement and civil settlement, in October 2007, we paid approximately $15 million.

As a result of the accident, nineteen separate lawsuits were filed. The majority of the cases were personal injury and wrongful death actions that alleged, among other things, that SFPP/Kinder Morgan failed to properly field mark the area where the accident occurred.

Following court ordered mediation, the Kinder Morgan defendants have settled with plaintiffs in all of the wrongful death cases and the personal injury and property damages cases. These settlements have either become final by order of the court or are awaiting court approval. The only civil cases which remain unsettled at present are certain cross-claims for contribution and indemnity by and between various engineering company defendants and the Kinder Morgan defendants. The parties are currently continuing discovery on the remaining cases.

Additionally, following this accident, we reviewed and when appropriate, revised our pipeline policies and procedures to improve safety. We have undertaken a number of actions to reduce future third-party damage to our pipelines, including adding line riders and locators, retaining third-party expertise, instituting enhanced line location training and education of employees and contractors, and investing in additional state-of-the-art line locating equipment. We have also committed to various procedural requirements pertaining to construction near our pipelines.

Consent Agreement Regarding Cordelia, Oakland and Donner Summit California Releases

On May 21, 2007, we and SFPP entered into a Consent Agreement with various governmental agencies to resolve civil claims relating to the unintentional release of petroleum products during three pipeline incidents in northern California. The releases occurred (i) in the Suisun Marsh area near Cordelia in Solano County, in April 2004; (ii) in Oakland in February 2005; and (iii) near Donner Pass in April 2005. The agreement was reached with the United States Environmental Protection Agency, referred to in this Note as the EPA, Department of the Interior, Department of Justice and the National Oceanic and Atmospheric Administration, as well as the State of California Department of Fish and Game, Office of Spill Prevention and Response, and the Regional Water Quality Control Boards for the San Francisco and Lahontan regions. Under the Consent Agreement, we agreed to pay approximately $3.8 million in civil penalties, $1.3 million in natural resource damages and assessment costs and approximately $0.2 million in agency response and future remediation monitoring costs. All of the civil penalties have been reserved for as of September 30, 2007. In addition, we agreed to perform enhancements in our Pacific Operations relative to its spill prevention, response and reporting practices, the majority of which have already been implemented.

The Consent Agreement was filed with the United States District Court for the Eastern District of California on May 29, 2007 and became effective July 26, 2007. We have substantially completed remediation and restoration activities in consultation with the appropriate state and federal regulatory agencies at the location of each release. Remaining restoration work at the Suisun Marsh and Donner Pass areas is expected to be completed in the fall of 2007.

On August 21, 2007, SFPP received a Notice of Proposed Debarment issued by the United States Environmental Protection Agency, referred to in this report as the EPA. Pursuant to the Notice, the Suspension and Debarment Division of the EPA is proposing to debar SFPP from participation in future Federal contracts and assistance activities for a period of three years. The purported basis for the proposed debarment is SFPP’s April, 2005 agreement with the California Attorney General and the District Attorney of Solano County, California to settle misdemeanor charges of the unintentional, non-negligent discharge of diesel fuel, and the failure to provide timely notice of a threatened discharge to appropriate state agencies, in connection with the April 28, 2004 spill of diesel fuel into a marsh near Cordelia, California. SFPP believes that the proposed debarment is factually and legally unwarranted and intends to contest it. In addition, SFPP is currently engaged in discussions with the EPA to attempt to resolve this matter.

In November 2004, our CALNEV Pipeline experienced a failure from external damage near Baker, California, resulting in a release of gasoline that affected approximately two acres of land in the high desert administered by the U.S. Bureau of Land Management. 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 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.

On April 17, 2006, Plantation Pipe Line Company, 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 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, referred to in this report as VDEQ. Following settlement negotiations and discussions with VDEQ, Plantation and VDEQ entered into a Special Order on Consent under which Plantation agreed to pay a civil penalty of approximately $0.7 million to VDEQ as well as reimburse VDEQ for less than $0.1 million in expenses and oversight costs to resolve the matter. Plantation satisfied $0.2 million of the civil penalty by completing a supplemental environmental project in the form of a $0.2 million donation to the Henrico County Fire Department for the purchase of hazardous material spill response equipment.

In June 2006, our SFPP pipeline experienced a leak near Dublin, California, resulting in a release of product that affected a limited area along a recreation path. We have completed remediation activities and have petitioned the California Regional Water Quality Control Board for closure. The cause of the release was outside force damage.

In August 2006, our SFPP pipeline 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. Remediation and monitoring activities are ongoing under the supervision of the California Department of Fish & Game and Nevada County. The cause of the release was determined to be pinhole corrosion in an unpiggable 2-inch diameter bypass to the mainline valve. The bypass was installed to allow pipeline maintenance activity. The bypass piping was replaced at this location and all other similar designs on the pipeline segment were excavated, evaluated and replaced as necessary to avoid future

risk of release. We are currently engaged in discussions with representatives of Nevada County regarding the potential payment of civil penalties and certain unreimbursed response costs which total less that $0.2 million.

On November 11, 2006, a bulldozer operated by an employee of Associated Pipeline Contractors, Inc, (a third-party contractor to Rockies Express Pipeline LLC, referred to in this Note as REX), struck an existing subsurface natural gas pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline Group. The pipeline was ruptured, resulting in an explosion and fire. The incident occurred in a rural area approximately nine miles southwest of Cheyenne, Wyoming. The incident resulted in one fatality (the operator of the bulldozer) and there were no other reported injuries. The cause of the incident is under investigation by the PHMSA. We are cooperating with this agency. Immediately following the incident, REX and El Paso Pipeline Group reached an agreement on a set of additional enhanced safety protocols designed to prevent the reoccurrence of such an incident.

In September 2007, the family of the deceased bulldozer operator filed a wrongful death action against us, Rockies Express Pipeline LLC and several other parties in the District Court of Harris County, Texas, 189 Judicial District, at case number 2007-57916. The plaintiffs seek unspecified compensatory and exemplary damages plus interest, attorney’s fees and costs of suit. We have asserted contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers. Defendants have filed answers denying liability along with a motion to compel mediation. The parties currently plan to mediate this matter in December 2007. We do not expect the cost of any settlement or eventual judgment, if any, to be material.

On November 27, 2006, the Plantation Pipeline experienced a release of approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company block valve on a delivery line into a terminal owned by a third party company. Upon discovery of the release, Plantation immediately locked out the delivery of gasoline through that pipe to prevent further releases. Product had flowed onto the surface and into a nearby stream, which is a tributary of Paw Creek, and resulted in loss of fish and other biota. Product recovery and remediation efforts were implemented immediately, including removal of product from the stream. The line was repaired and put back into service within a few days. Remediation efforts are continuing under the direction of the North Carolina Department of Environment and Natural Resources (the “NCDENR”), which issued a Notice of Violation and Recommendation of Enforcement against Plantation on January 8, 2007. Plantation continues to cooperate fully with the NCDENR.

Although Plantation does not believe that penalties are warranted, it is engaging in settlement discussions with the EPA regarding a potential civil penalty for the November 2006 release as part of broader settlement negotiations with the EPA regarding this spill and two other historic releases from Plantation, including a February 2003 release near Hull, Georgia. The EPA’s most recent demand for all four releases is approximately $0.7 million, plus some additional work to be performed to prevent future releases. 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.

In addition, in April 2007, during pipeline maintenance activities near Charlotte, North Carolina, Plantation discovered the presence of historic soil contamination near the pipeline, and reported the presence of impacted soils to the NCDENR. Subsequently, Plantation contacted the owner of the property to request access to the property to investigate the potential contamination. The results of that investigation indicate that there is soil and groundwater contamination which appears to be from historic turbine fuel release. The groundwater contamination is underneath at least two lots on which there is current construction of single family homes as part of a new residential development. Further investigation and remediation are being conducted under the oversight of the NCDENR. Plantation is working with the owner of the property and the builder of the residential subdivision to address any potential claims that they may bring.

The United States Department of Navy has alleged that historic releases of methyl tertiary-butyl ether, referred to in this report as MTBE, from CalNev Pipe Line Company’s Barstow terminal has (i) migrated underneath the Navy’s Marine Corps Logistics Base in Barstow; (ii) impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by CalNev, and (iii) could affect the MCLB’s water supply system. Although CalNev believes that it has certain meritorious defenses to the Navy’s claims, we are working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for CERCLA Removal Action to reimburse the Navy for $0.5 million in past response actions, plus perform other work to ensure protection of the Navy’s existing treatment system and water supply.

On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within our Trans Mountain pipeline system near its Westridge terminal in Burnaby, BC, resulting in a release of approximately 1,400 barrels of crude oil. The release impacted the surrounding neighborhood, several homes and nearby Burrard Inlet. No injuries were reported. To address the release, we initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the BC Ministry of Environment, the National Energy Board, and the National Transportation Safety Board. Cleanup and environmental remediation is continuing. The incident is currently under investigation by Federal and Provincial agencies. We are also conducting an internal investigation of the release. We do not expect this matter to have a material adverse impact on our results of operations or cash flows.

Although no assurances can be given, we believe that we have meritorious defenses to all pending pipeline integrity actions set forth in this note. 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. Additionally, although no assurance can be given, we also believe, based on our experiences to date, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or cash flows.

As of September 30, 2007, and December 31, 2006, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $137.1 million and $112.0 million, respectively. The reserve is primarily related to various claims from lawsuits arising from SFPP, L.P.’s pipeline transportation rates, discussed above, 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.

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, later owned 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 are currently involved in mandatory mediation with respect to the claims set out in the lawsuit.

On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against Exxon Mobil Corporation and GATX Terminals Corporation. The complaint was filed in Gloucester County, New Jersey. The plaintiffs have not yet served the complaint on either of the named defendants. The plaintiffs seek the costs and damages that the plaintiffs allegedly have incurred or will incur as a result of the discharge of pollutants and hazardous substances at the Paulsboro, New Jersey facility. The costs and damages that the plaintiffs seek include damages to natural resources. In addition, the plaintiffs seek an order compelling the defendants to perform or fund the assessment and restoration of those natural resource damages that are the result of the defendants’ actions. As in the case brought by Exxon Mobil against GATX Terminals Corporation, the issue is whether the plaintiffs’ claims are within the scope of the indemnity obligations GATX Terminals and therefore, Kinder Morgan Liquids Terminals, owes to ST Services.

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. NCO41463.

We and some of our subsidiaries are defendants in a lawsuit filed in 2005 alleging 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. The judge bifurcated that rent issue from the causes of action related to the cleanup costs and a trial regarding the rent issue was set for October 2007.

Plaintiff and the Kinder Morgan defendants have since agreed to a settlement in principle under which we agreed to pay $3.2 million in satisfaction of all past and future rent obligations. The settlement is contingent upon court approval, and within the next thirty days we anticipate finalizing the settlement terms and then filing with the court for that approval. Accordingly, we recorded a reserve in the third quarter of 2007 of $3.2 million to reflect this liability.

In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the city’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On September 26, 2007, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. On October 3, 2007, we filed a Motion to Dismiss all counts of the Complaint, which motion is currently pending. To the extent any claims survive the Motion to Dismiss, we intend to vigorously defend against the claims asserted in the complaint. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. We do not expect the cost of any settlement and remediation to be material.

We have been informed that the United States Department of Justice and the United States Environmental Protection Agency are continuing to investigate an alleged instance of improper disposal at sea of potash which allegedly occurred at the request of or with the knowledge of employees or third parties at a bulk terminal facility in Portland, Oregon which we operate. We are fully cooperating with the investigation.

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 air, water and waste violations issued by various governmental authorities related to compliance with environmental regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these violations will have a material adverse affect on our business.

We are also 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.

In addition, we are 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 Releases” above for additional information with respect to ruptures and leaks from 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 and changing circumstances could cause these matters to have a material adverse impact. As of September 30, 2007, we have accrued an environmental reserve of $77.9 million, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations. Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.

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.

According to the provisions of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” we record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations 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 increase due to the change in their present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

In our CO₂ business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of September 30, 2007 and December 31, 2006, we have recognized asset retirement obligations in the aggregate amount of $48.8 million and $47.2 million, respectively, 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 certain surface facilities and equipment from land belonging to our customers and others. We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities and as of both September 30, 2007 and December 31, 2006, we have recognized asset retirement obligations in the aggregate amount of $3.1 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, 2007 with “Accrued other current liabilities” in our accompanying consolidated balance sheet. The remaining $50.5 million obligation is reported separately as a non-current liability. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the nine months ended September 30, 2007 and 2006 is as follows (in millions):

We have various other obligations throughout our businesses to remove facilities and equipment on rights-of- way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain bulk and liquids terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

On August 14, 2007, we paid a cash distribution of $0.85 per unit to our common unitholders and our Class B unitholders for the quarterly period ended June 30, 2007. KMR, our sole i-unitholder, received 1,143,661 additional i units based on the $0.85 cash distribution per common unit. The distributions were declared on July 18, 2007, payable to unitholders of record as of July 31, 2007.

On October 17, 2007, we declared a cash distribution of $0.88 per unit for the quarterly period ended September 30, 2007. The distribution will be paid on November 14, 2007, to unitholders of record as of October 31, 2007. Our common unitholders and Class B unitholders will receive cash. KMR will receive a distribution of 1,258,778 additional i units based on the $0.88 distribution per common unit. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.017686) will be issued. This fraction was determined by dividing:

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. The carrying amount of our goodwill as of September 30, 2007 is summarized as follows (in millions):

Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount. On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from Knight (formerly KMI), and this transaction was completed April 30, 2007 (see Note 2). Following the provisions of generally accepted accounting principles, the consideration of this transaction caused Knight to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired. Based on supporting third-party information obtained regarding the fair values of the Trans Mountain pipeline system assets, Knight recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007, and because we have included all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006, this impairment expense is now reflected in our consolidated results of operations.

Changes in the carrying amount of our goodwill for the nine months ended September 30, 2007 are summarized as follows (in millions):

In addition, according to the provisions of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock,” we identify any premium or excess cost we pay over our proportionate share of the underlying fair value of net assets acquired and accounted for as investments under the equity method of accounting. This premium or excess cost is referred to as equity method goodwill and is not subject to amortization but rather to periodic impairment testing. As of both September 30, 2007 and December 31, 2006, we have reported $138.2 million in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, technology-based assets, and lease value. 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 millions):

The increase in the carrying amount of customer relationships, contracts and agreements since December 31, 2006 was primarily due to our acquisition of intangible customer relationships included in our purchase of certain assets from Marine Terminals, Inc. on September 1, 2007. For more information on this acquisition, see Note 2 “Acquisitions and Joint Ventures—Marine Terminals, Inc., Assets.”

As of September 30, 2007, we have preliminarily allocated $60.6 million of our combined purchase price to “Property, Plant and Equipment, net,” $39.8 million to “Other Intangibles, net,” and the remaining $1.0 million to other current and long-term assets, subject to the receipt of independent valuation reports. The $39.8 million of intangibles represents the estimated 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. As of the acquisition date, we estimated the expected useful life of these intangibles to be 20 years. The acquisition both expanded and complemented our existing ferro alloy terminal operations and will provide Nucor and other customers further access to our growing national network of marine and rail terminals. All of the acquired assets are included in our Terminals business segment.

Amortization expense on our intangibles consisted of the following (in millions):

As of September 30, 2007, the weighted average amortization period for our intangible assets was approximately 18.5 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $15.5 million, $14.7 million, $14.2 million, $14.1 million and $14.1 million, respectively.

Our outstanding short-term debt as of September 30, 2007 was $597.0 million. The balance consisted of (i) $576.4 million of commercial paper borrowings; (ii) a $9.5 million portion of a 5.40% long-term note payable (described below in “—Kinder Morgan Operating L.P. “A” Debt”); (iii) a $6.1 million portion of 5.23% senior notes (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes); and (iv) a $5.0 million portion of 7.84% senior notes (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes). The weighted average interest rate on all of our borrowings was approximately 6.47% during the third quarter of 2007 and approximately 6.30% during the third quarter of 2006.

Our $1.85 billion five-year unsecured bank credit facility matures August 18, 2010 and can be amended to allow for borrowings up to $2.1 billion. Borrowings under our credit facility can be used for partnership purposes and as a backup for our commercial paper program. There were no borrowings under the credit facility as of September 30, 2007 or as of December 31, 2006.

Our five-year credit facility is with a syndicate of financial institutions and Wachovia Bank, National Association is the administrative agent. As of September 30, 2007, the amount available for borrowing under our credit facility was reduced by an aggregate amount of $1,030.5 million, consisting of (i) our outstanding commercial paper borrowings ($576.4 million as of September 30, 2007); (ii) a combined $208 million in three letters of credit that support our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil; (iii) a $100 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the State of California; (iv) a combined $48 million in two letters of credit that support tax-exempt bonds; (v) a combined $39.7 million in two letters of credit that support the construction of our Kinder Morgan Louisiana Pipeline (a natural gas pipeline); (vi) a $37.5 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (vii) a combined $20.9 million in other letters of credit supporting other obligations of us and our subsidiaries.

Our commercial paper program provides for the issuance of up to $1.85 billion of commercial paper. Our $1.85 billion unsecured five-year bank credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. As of September 30, 2007, we had $576.4 million of commercial paper outstanding with an average interest rate of approximately 5.75%. As of December 31, 2006, we had $1,098.2 million of commercial paper outstanding with an average interest rate of approximately 5.42%. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during 2007 and 2006.

During the first nine months of 2007, we completed three separate public offerings of senior notes, and on August 15, 2007, we repaid $250 million of 5.35% senior notes that matured on that date. With regard to the three offerings, we received proceeds, net of underwriting discounts and commissions, as follows:

We used the proceeds from each of these offerings to reduce the borrowings under our commercial paper program.

Effective January 1, 2007, we acquired the remaining approximate 50.2% interest in the Cochin pipeline system that we did not already own (see Note 2). As part of our purchase price, two of our subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. We valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%. The principal amount of the note, along with interest, is due in five annual installments of $10.0 million beginning March 31, 2008. The final payment is due March 31, 2012. Our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note, and as of September 30, 2007, the outstanding balance under the note was $43.9 million.

As prescribed by 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,” we disclose certain types of guarantees or indemnifications we have made. These disclosures cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote. The following is a description of our contingent debt agreements as of September 30, 2007.

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, proportional percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. Furthermore, 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, a wholly-owned subsidiary of Cortez Pipeline Company.

As of September 30, 2007, the debt facilities of Cortez Capital Corporation consisted of (i) $64.3 million of Series D notes due May 15, 2013; (ii) a $125 million short-term commercial paper program; and (iii) 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, 2007, Cortez Capital Corporation had $86.5 million of commercial paper outstanding with an average interest rate of approximately 5.64%, the average interest rate on the Series D notes was 7.14%, and there were no borrowings under the credit facility.

With respect to Cortez’s Series D notes, 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 and JP Morgan Chase issued a letter of credit on our behalf in December 2006 in the amount of $37.5 million to secure our indemnification obligations to Shell for 50% of the $75 million in principal amount of Series D notes outstanding as of December 31, 2006.

As a result of Red Cedar Gathering Company’s March 2007 retirement of the remaining $31.4 million outstanding principal amount of its Senior Notes due October 31, 2010, we are no longer contingently liable for any Red Cedar Gathering Company debt.

When we acquired Nassau Terminals LLC in July 2002, we became the guarantor of a letter of credit guaranteed by the previous parent company. In December 2002, we issued a $28 million letter of credit under our then-existing credit facilities and the former letter of credit guarantee was terminated. Similar to the previous letter of credit, the December 2002 letter of credit was issued as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority. The bonds were issued

for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. Nassau Terminals LLC is the operator of the marine port facilities.

The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020. 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, 2007, this letter of credit had an outstanding balance under our credit facility of $23.8 million.

Pursuant to certain guaranty agreements, all three member owners of West2East Pipeline LLC (which owns all of the member interests in Rockies Express Pipeline LLC) have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in West2East Pipeline LLC, borrowings under Rockies Express’ (i) $2.0 billion five-year, unsecured revolving credit facility, due April 28, 2011; (ii) $2.0 billion commercial paper program; and (iii) $600 million in principal amount of floating rate senior notes due August 20, 2009. The three member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline LLC – 51%, a subsidiary of Sempra Energy – 25%, and a subsidiary of ConocoPhillips – 24%.

Borrowings under the Rockies Express commercial paper program are primarily used to finance the construction of the Rockies Express interstate natural gas pipeline and to pay related expenses. The credit facility, which can be amended to allow for borrowings up to $2.5 billion, supports borrowings under the commercial paper program, and borrowings under the commercial paper program reduce the borrowings allowed under the credit facility. On September 20, 2007, Rockies Express issued $600 million in principal amount of senior unsecured floating rate notes. The notes have a maturity date of August 20, 2009, and interest on these notes is paid and computed quarterly on an interest rate of three-month LIBOR plus a spread. Upon issuance of the notes, Rockies Express entered into two floating-to-fixed interest rate swap agreements having a combined notional principal amount of $600 million and a maturity date of August 20, 2009.

In addition to the $600 million in senior notes, as of September 30, 2007, Rockies Express Pipeline LLC had $1,380.2 million of commercial paper outstanding with an average interest rate of approximately 5.76%, and there were no borrowings under its five-year credit facility. Accordingly, as of September 30, 2007, our contingent share of Rockies Express’ debt was $1,009.9 million (51% of total borrowings).

For additional information regarding our debt facilities and our contingent debt agreements, see Note 9 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006.

As of September 30, 2007 and December 31, 2006, our partners’ capital included the following limited partner units:

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, 2007, our total common units consisted of 148,734,661 units held by third parties, 12,631,735 units held by Knight and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner. As of December 31, 2006, our total common units consisted of 148,460,568 units held by third parties, 12,631,735 units held by Knight and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner.

On both September 30, 2007 and December 31, 2006, all of our 5,313,400 Class B units were held by a wholly-owned subsidiary of Knight. 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 Knight in December 2000.

On both September 30, 2007 and December 31, 2006, 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. 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 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. Based on the preceding, KMR received a distribution of 1,143,661 i-units from us on August 14, 2007, based on the $0.85 per unit distributed to our common unitholders on that date.

In addition, on May 17, 2007, KMR issued 5,700,000 of its shares in a public offering at a price of $52.26 per share, less underwriter discounts and commissions. The net proceeds from the offering were used by KMR to buy additional i-units from us, and we received net proceeds of $297.9 million for the issuance of 5,700,000 i-units. We used the proceeds from this equity issuance to reduce the borrowings under our commercial paper program.

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 $0.85 per unit paid on August 14, 2007 for the second quarter of 2007 required an incentive distribution to our general partner of $147.6 million. 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. The increased incentive distribution to our general partner paid for the second quarter of 2007 over the distribution paid for the second quarter of 2006 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 2007 of $0.88 per unit will result in an incentive distribution to our general partner of $155.2 million. This compares to our distribution of $0.81 per unit and incentive distribution to our general partner of $133.0 million for the third quarter of 2006.

Comprehensive income is the change in our Partners’ Capital that results from periodic revenues, expenses, gains and losses, as well as any other recognized changes that occur for reasons other than investments by and distributions to our partners. The difference between our comprehensive income and our net income represents our other comprehensive income.

For the nine month periods ended September 30, 2007 and 2006, the components of our other comprehensive included (i) unrealized gains or losses on energy commodity derivative contracts utilized for hedging purposes (including our proportionate interest in derivative contracts of our equity investee Rockies Express

Pipeline LLC); (ii) foreign currency translation adjustments (including those adjustments resulting from the process of translating the financial statements of Trans Mountain since January 1, 2006); (iii) minimum pension liability adjustments and reclassifications of both pension and post-retirement benefit gains/losses and prior service credits to net income (these three amounts are reported in table below combined); and (iv) our proportionate share of the other comprehensive income related to (a) the post-retirement benefit and pension plans of our equity investee Plantation Pipe Line Company; and (b) the unrealized gains or losses on interest rate swap agreements of Rockies Express Pipeline LLC.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Net Income:	$	213.8		$	229.5		$	297.0		$	736.8
Other comprehensive income (loss):
Change in fair value of derivative contracts utilized for hedging purposes		(111.6	)		203.6			(338.5	)		(281.3	)
Reclassification of change in fair value of derivative contracts to net income		94.5			118.8			258.6			338.0
Equity in other comprehensive income of equity method investees related to post-retirement benefit and pension plans, and interest expense hedging		(0.4	)		—			1.1			—
Minimum pension liability adjustments, reclassifications of post-retirement benefit actuarial gains and prior service credits to net income		(0.6	)		—			(1.0	)		(1.4	)
Change in foreign currency translation adjustments		71.6			(7.3	)		123.3			(5.5	)
Total other comprehensive income		53.5			315.1			43.5			49.8

Comprehensive income	$	267.3		$	544.6		$	340.5		$	786.6

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 our expected future 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.

Reflecting the portion of changes in the value of derivative contracts that were not effective in offsetting underlying changes in expected cash flows (the ineffective portion of hedges), we recognized a loss of $0.1 million and a gain of $0.8 million, respectively, during the three and nine month periods ended September 30, 2007; and 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. These recognized gains and losses resulting from hedge ineffectiveness 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, and for each of the first nine months of 2007 and 2006, we did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness.

Furthermore, during the three and nine month periods ended September 30, 2007, we reclassified $94.5 million and $258.6 million, respectively, of “Accumulated other comprehensive loss” into earnings, including approximately $0.1 million in the first quarter of 2007 resulting from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter. The remaining $258.5 million reclassified into net income during the first nine months of 2007 resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred).

During the three and nine month periods ended September 30, 2006, we reclassified $118.8 million and $338.0 million, respectively, of “Accumulated other comprehensive loss” into earnings, and 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), no other reclassification of Accumulated other comprehensive loss into earnings during the first nine months of 2006 resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter.

Our consolidated “Accumulated other comprehensive loss” balance was $822.8 million as of September 30, 2007 and $866.1 million as of December 31, 2006. These consolidated totals included “Accumulated other comprehensive loss” amounts associated with the commodity price risk management activities of ourselves, and our 51% equity investee Rockies Express Pipeline LLC, of $918.7 million as of September 30, 2007 and $838.7 million as of December 31, 2006. Approximately $414.2 million of the total amount associated with our commodity price risk management activities as of September 30, 2007 is expected to be reclassified into earnings during the next twelve months.

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,” and “Other long-term liabilities and deferred credits.” 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, 2007 and December 31, 2006 (in millions):

As discussed in our financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006, we have counterparty credit risk as a result of our use of financial derivative contracts. 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, 2007 and December 31, 2006, we had three outstanding letters of credit totaling $208.0 million and $243.0 million, respectively, in support of our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.

Additionally, as of September 30, 2007, we had cash margin deposits associated with our commodity contract positions and over-the-counter swap partners totaling $38.0 million, and we reported this amount as “Restricted deposits” in our accompanying consolidated balance sheet as of September 30, 2007. As of December 31, 2006, our counterparties associated with our commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $2.3 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet as of December 31, 2006.

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. We use interest rate swap agreements to manage the interest rate risk associated with the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve our desired mix of fixed and variable rate debt.

Since the fair value of fixed rate debt varies inversely with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest in order to convert the interest expense associated with certain of our senior notes from fixed rates to floating rates, resulting in future cash flows that vary with the market rate of interest. These swaps, therefore, hedge against changes in the fair value of our fixed rate debt that result from market interest rate changes.

As of December 31, 2006, we were a party to interest rate swap agreements with notional principal amounts of $2.1 billion. In the first six months of 2007, we both entered into additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $500 million and terminated an existing fixed-to-floating interest rate swap agreement having a notional principal amount of $100 million and a maturity date of March 15, 2032. We received $15.0 million from the early termination of this swap agreement, and this amount is being amortized over the remaining term of the original swap period.

On August 15, 2007, two separate fixed-to-floating interest rate swap agreements having a combined notional principal amount of $200 million matured, and as of September 30, 2007, we had a combined notional principal amount of $2.3 billion of fixed-to-floating interest rate swap agreements effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. The two swap agreements that matured on August 15, 2007 were associated with the $250 million of 5.35% senior notes that also matured on that date.

These swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of September 30, 2007, 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 January 15, 2038.

Our interest rate swap contracts have been designated as fair value hedges and meet the conditions required to assume no ineffectiveness under SFAS No. 133. Therefore, we have accounted for them using the “shortcut” method prescribed by SFAS No. 133 and accordingly, we adjust the carrying value of each swap contract 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 swap contracts.

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 included within “Value of interest rate swaps” on our accompanying consolidated balance sheets, which also includes any unamortized portion of proceeds received from the early termination of interest rate swap agreements. As of September 30, 2007, this unamortized premium totaled $14.4 million.

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, 2007 and December 31, 2006 (in millions):

Furthermore, we are exposed to credit related losses in the event of nonperformance by counterparties to our interest rate swap agreements, and 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, 2007, all of our interest rate swap agreements were with counterparties with investment grade credit ratings.

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.

For a more complete discussion of our risk management activities, see Note 14 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006.

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 are managed separately, provide different products and services, and employ different 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 and sale of crude oil from fields in the Permian Basin of West Texas, and from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals. Our Trans Mountain business segment derives its revenues primarily from the transportation of crude oil and refined products from Edmonton, Alberta to marketing terminals and refineries in the Greater Vancouver area and Puget Sound in Washington State.

As discussed in Note 2, due to the announced sale of our North System, an approximate 1,600-mile interstate common carrier pipeline system whose operating results are included as part of our Products Pipelines business segment, we accounted for the North System business as a discontinued operation. Consistent with the management approach of identifying and reporting discrete financial information on operating segments, we have included the North System’s financial disclosures within our Products Pipelines business segment disclosures for all periods presented in this report and, as prescribed by SFAS No. 131, we have reconciled the total of our reportable segment’s financial results to our consolidated financial results by separately identifying, in the following pages where applicable, the North System amounts as discontinued operations.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Revenues
Products Pipelines
Revenues from external customers	$	217.0		$	207.7		$	642.4		$	577.2
Intersegment revenues		—			—			—			—
Natural Gas Pipelines
Revenues from external customers		1,526.8			1,650.4			4,755.3			5,082.2
Intersegment revenues		—			—			—			—
CO₂
Revenues from external customers(a)		210.6			192.3			601.7			552.8
Intersegment revenues		—			—			—			—
Terminals
Revenues from external customers		247.1			223.0			690.8			649.3
Intersegment revenues		0.1			0.1			0.5			0.5
Trans Mountain
Revenues from external customers		43.7			33.6			119.8			94.1
Intersegment revenues		—			—			—			—
Total segment revenues		2,245.3			2,307.1			6,810.5			6,956.1
Less: Total intersegment revenues		(0.1	)		(0.1	)		(0.5	)		(0.5	)
		2,245.2			2,307.0			6,810.0			6,955.6
Less: Discontinued operations		(14.4	)		(10.2	)		(41.1	)		(29.4	)
Total consolidated revenues	$	2,230.8		$	2,296.8		$	6,768.9		$	6,926.2

Operating expenses(b)
Products Pipelines(c)	$	66.0		$	94.6		$	216.2		$	234.2
Natural Gas Pipelines(d)		1,387.8			1,519.2			4,348.9			4,694.0
CO₂		75.8			68.8			222.6			194.1
Terminals		133.0			122.1			365.9			354.8
Trans Mountain		19.3			14.2			47.2			38.7
Total segment operating expenses		1,681.9			1,818.9			5,200.8			5,515.8
Less: Total intersegment operating expenses		(0.1	)		(0.1	)		(0.5	)		(0.5	)
		1,681.8			1,818.8			5,200.3			5,515.3
Less: Discontinued operations		(4.1	)		(6.0	)		(14.8	)		(15.8	)
Total consolidated operating expenses	$	1,677.7		$	1,812.8		$	5,185.5		$	5,499.5

Other expense (income)
Products Pipelines	$	(0.6	)	$	—		$	(2.9	)	$	—
Natural Gas Pipelines(e)		(0.4	)		—			(3.1	)		(15.1	)
CO₂		—			—			—			—
Terminals(f)		(1.5	)		—			(5.9	)		—
Trans Mountain(g)		—			—			377.1			(0.9	)
Total segment other expense (income)		(2.5	)		—			365.2			(16.0	)
Less: Discontinued operations		—			—			—			—
Total consolidated other expense (income)	$	(2.5	)	$	—		$	365.2		$	(16.0	)

Depreciation, depletion and amortization
Products Pipelines	$	23.0		$	20.8		$	67.8		$	61.5
Natural Gas Pipelines		16.3			15.9			48.5			47.9
CO₂ (h)		73.1			50.8			213.2			132.1
Terminals		22.2			19.3			63.9			55.3
Trans Mountain		5.7			4.6			15.4			14.3
Total segment depreciation, depletion and amortization		140.3			111.4			408.8			311.1
Less: Discontinued operations		(2.3	)		(2.3	)		(7.0	)		(6.6	)
Total consol. depreciation, depletion and amortization	$	138.0		$	109.1		$	401.8		$	304.5

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Earnings from equity investments
Products Pipelines(i)	$	8.0		$	0.5		$	24.4		$	11.1
Natural Gas Pipelines(j)		4.0			10.0			14.2			31.8
CO₂		4.1			3.4			14.3			14.1
Terminals		0.3			0.1			0.3			0.2
Trans Mountain		—			—			—			—
Total segment earnings from equity investments		16.4			14.0			53.2			57.2
Less: Discontinued operations		(0.6	)		(0.4	)		(1.8	)		(1.7	)
Total consolidated equity earnings	$	15.8		$	13.6		$	51.4		$	55.5

Amortization of excess cost of equity investments
Products Pipelines	$	0.9		$	0.8		$	2.5		$	2.5
Natural Gas Pipelines		—			0.1			0.3			0.2
CO₂		0.5			0.5			1.5			1.5
Terminals		—			—			—			—
Trans Mountain		—			—			—			—
Total segment amortization of excess cost of investments		1.4			1.4			4.3			4.2
Less: Discontinued operations		—			—			—			—
Total consol. amortization of excess cost of investments	$	1.4		$	1.4		$	4.3		$	4.2

Interest income
Products Pipelines	$	1.1		$	1.2		$	3.3		$	3.4
Natural Gas Pipelines		—			—			—			0.1
CO₂		—			—			—			—
Terminals		—			—			—			—
Trans Mountain		—			—			—			—
Total segment interest income		1.1			1.2			3.3			3.5
Unallocated interest income		0.3			0.4			0.8			1.8
Total consolidated interest income	$	1.4		$	1.6		$	4.1		$	5.3

Other, net – income (expense)
Products Pipelines(k)	$	1.8		$	1.6		$	4.9		$	7.8
Natural Gas Pipelines		—			0.5			0.2			0.8
CO₂		—			0.3			—			0.3
Terminals		0.3			1.0			0.3			2.3
Trans Mountain		2.9			0.6			4.0			2.0
Total segment other, net – income (expense)		5.0			4.0			9.4			13.2
Less: Discontinued operations		—			(0.1	)		—			(0.1	)
Total consolidated other, net – income
(expense)	$	5.0		$	3.9		$	9.4		$	13.1

Income tax benefit (expense)
Products Pipelines(l)	$	(6.4	)	$	0.6		$	(14.8	)	$	(3.3	)
Natural Gas Pipelines		(1.4	)		(1.0	)		(2.6	)		(0.9	)
CO₂		(0.9	)		(0.1	)		(1.1	)		(0.2	)
Terminals		(6.9	)		(3.7	)		(11.9	)		(7.5	)
Trans Mountain		(5.2	)		(4.0	)		(6.0	)		(8.2	)
Total consolidated income tax benefit (expense)	$	(20.8	)	$	(8.2	)	$	(36.4	)	$	(20.1	)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Segment earnings before depreciation, depletion,
amortization and amortization of excess cost of
equity investments(m)
Products Pipelines	$	156.1		$	117.0		$	446.9		$	362.0
Natural Gas Pipelines		142.0			140.7			421.3			435.1
CO₂		138.0			127.1			392.3			372.9
Terminals		109.4			98.4			320.0			290.0
Trans Mountain		22.1			16.0			(306.5	)		50.1
Total segment earnings before DD&A		567.6			499.2			1,274.0			1,510.1
Total segment depreciation, depletion and amortization		(140.3	)		(111.4	)		(408.8	)		(311.1	)
Total segment amortization of excess cost of investments		(1.4	)		(1.4	)		(4.3	)		(4.2	)
Interest and corporate administrative expenses(n)		(212.1	)		(156.9	)		(563.9	)		(458.0	)
Total consolidated net income	$	213.8		$	229.5		$	297.0		$	736.8

Capital expenditures
Products Pipelines	$	68.1		$	30.7		$	170.9		$	151.9
Natural Gas Pipelines		63.7			18.7			162.8			228.3
CO₂		111.7			75.3			273.4			208.4
Terminals		139.0			65.4			350.8			162.7
Trans Mountain		70.0			34.9			185.0			59.8
Total consolidated capital expenditures(o)	$	452.5		$	225.0		$	1,142.9		$	811.1

We do not attribute interest and debt expense to any of our reportable business segments. For the three months ended September 30, 2007 and 2006, we reported total consolidated interest expense of $103.8 million and $91.7 million, respectively. For the nine months ended September 30, 2007 and 2006, we reported total consolidated interest expense of $294.4 million and $256.6 million, respectively.

Following is geographic information regarding the revenues and long-lived assets of our business segments.(in millions):

Due to our acquisition of Trans Mountain (see Notes 1 and 2), we are a sponsor of pension plans for eligible Trans Mountain employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements, which provide pension benefits in excess of statutory limits, and defined contributory plans. We also provide post-retirement benefits other than pensions for retired employees. Our combined net periodic benefit costs for these Trans Mountain pension and post-retirement benefit plans for each of the first nine months of 2007 and 2006 was approximately $3.2 million, recognized ratably over the period. As of December 31, 2006, we estimate our overall net periodic pension and post-retirement benefit costs for these plans for the year 2007 will be approximately $4.3 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. We expect to contribute approximately $4.9 million to these benefit plans in 2007.

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.

Our net periodic benefit costs for the SFPP post-retirement benefit plan for each of the first nine months of 2007 and 2006 were credits of $0.2 million, respectively, recognized ratably over the periods. The credits in both periods resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost. As of September 30, 2007, we estimate our overall net periodic post-retirement benefit cost for the year 2007 will be a credit of approximately $0.3 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities.

The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Knight 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.

We have a seven-year note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, our 51.17%-owned equity investee. The outstanding note receivable balance was $93.1 million and $90.9 million as of December 31, 2006 and September 30, 2007, respectively. Of these amounts, $3.4 million and $2.3 million were included within “Accounts, notes and interest receivable, net—Related parties” as of December 31, 2006 and September 30, 2007, respectively, and the remainder was included within “Notes receivable—Related parties” at each reporting date.

In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from Knight in December 1999 and December 2000; and (ii) all of the partnership interest in TransColorado Gas Transmission Company from two wholly-owned subsidiaries of Knight on November 1, 2004, Knight agreed to indemnify us and Kinder Morgan G.P., Inc. with respect to approximately $733.5 million of our debt. Knight would be obligated to perform under this indemnity only if we are unable and/or our assets were insufficient to satisfy our obligations.

As of September 30, 2007, an affiliate of Knight owed to us a long-term note with a principal amount of $1.6 million, and we included this balance within “Notes receivable—Related parties” on our consolidated balance sheet as of that date. This note currently has no fixed terms of repayment and is denominated in Canadian dollars. As of December 31, 2006, we had an additional note receivable denominated in Canadian dollars from a second affiliate of Knight, and combined, the two notes had a translated principal amount of $6.5 million. The above amounts represent the translated amounts included in our consolidated financial statements in U.S. dollars.

Additionally, prior to our acquisition of Trans Mountain on April 30, 2007, Knight and certain of its affiliates advanced cash to Trans Mountain. The advances were primarily used by Trans Mountain for capital expansion projects. Knight and its affiliates also funded Trans Mountain’s cash book overdrafts (outstanding checks) as of April 30, 2007. Combined, the funding for these items totaled $67.5 million, and we reported this amount as a separate cash inflow within the financing section of our accompanying consolidated statement of cash flows.

As discussed in Note 1, as a result of the going private transaction of Knight, a number of individuals and entities became significant investors in Knight. By virtue of the size of their ownership interest in Knight, two of those investors became “related parties” to us (as that term is defined in authoritative accounting literature): (i) American International Group, Inc. and certain of its affiliates; and (ii) Goldman Sachs Capital Partners and certain of its affiliates.

We and/or our affiliates enter into transactions with certain AIG affiliates in the ordinary course of their conducting insurance and insurance-related activities, although no individual transaction is, and all such transactions collectively are not, material to our consolidated financial statements.

We conduct commodity risk management activities in the ordinary course of implementing our risk management strategies in which the counterparty to certain of our derivative transactions is an affiliate of Goldman Sachs. In conjunction with these activities, we are a party (through one of our subsidiaries engaged in the production of crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs which requires us to provide certain

periodic information, but does not require the posting of margin. As a result of changes in the market value of our derivative positions, we have created both amounts receivable from and payable to Goldman Sachs affiliates.

The following table summarizes the fair values of these energy commodity derivative contracts associated with our commodity price risk management activities with related parties and included on our accompanying consolidated balance sheets as of September 30, 2007 (in millions):

The following updates the disclosure in Note 17 to our audited financial statements that were filed with our Annual Report on Form 10-K for the year ended December 31, 2006 with respect to developments that occurred during the nine months ended September 30, 2007.

Since November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C, and 2004-D, adopting new Standards of Conduct as applied to natural gas pipelines. The primary change from existing regulation was to make such standards applicable to an interstate natural gas pipeline’s interaction with many more affiliates (referred to as “energy affiliates”), including intrastate/Hinshaw natural gas pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or within a state boundary, is regulated by an agency of that state, and all the gas it transports is consumed within that state), processors and gatherers and any company involved in natural gas or electric markets (including natural gas marketers) even if they do not ship on the affiliated interstate natural gas pipeline. Local distribution companies were excluded, however, if they do not make sales to customers not physically attached to their system. The Standards of Conduct require, among other things, separate staffing of interstate pipelines and their energy affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an energy affiliate.

Every interstate natural gas pipeline was required to file an Order No. 2004 compliance plan with the FERC, and on July 20, 2006, the FERC accepted our interstate pipelines’ May 19, 2005 compliance filing under Order No. 2004. On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A, 2004-B, 2004-C, and 2004-D as applied to natural gas pipelines, and remanded these same orders back to the FERC.

On January 9, 2007, the FERC issued an Interim Rule, effective January 9, 2007, in response to the court’s action. In the Interim Rule, the FERC readopted the Standards of Conduct, but revised or clarified with respect to issues which had been appealed to the court. Specifically, the following changes were made:

The FERC clarified that all exemptions and waivers issued under Order No. 2004 remain in effect. On January 18, 2007, the FERC issued a notice of proposed rulemaking seeking comments regarding whether or not the Interim Rule should be made permanent for natural gas transmission providers. On March 21, 2007, FERC issued an Order on Clarification and Rehearing of the Interim Rule that granted clarification that the Standards of Conduct only apply to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on such gas transmission provider’s pipeline.

On February 15, 2007, the FERC issued a notice of inquiry seeking comment on the need for changes or revisions to the FERC’s reporting requirements contained in the financial forms for gas and oil pipelines and electric utilities. Initial comments were filed by numerous parties on March 27, 2007, and reply comments were filed on April 27, 2007.

On September 20, 2007, FERC issued for public comment in Docket No. RM07-9 a proposed rule which would revise its financial forms to require that additional information be reported by natural gas companies. The proposed rule would require, among other things, that natural gas companies: (1) submit additional revenue information, including revenue from shipper-supplied gas; (2) identify the costs associated with affiliate transactions; and (3) provide additional information on incremental facilities and on discounted and negotiated rates. The FERC Chairman stated that the changes will provide more detail so that the FERC and the public can assess whether pipeline rates are just and reasonable and assure public access to sufficient information for a Section 5 rate complaint. FERC proposes an effective date of January 1, 2008, which means that forms reflecting the new requirements for 2008 would be filed in early 2009. Comments on the proposed rule are due on November 13, 2007.

On September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on whether it should change its current policy and prescribe a uniform method for all interstate gas pipelines to use in recovering fuel gas and gas lost and unaccounted for. The Notice of Inquiry included numerous questions regarding fuel recovery issues and the effects of fixed fuel percentages as compared with tracking provisions. Comments on the Notice of Inquiry are due November 30, 2007.

On April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos. RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section 23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC proposes to revise its regulations to (i) require that intrastate pipelines post daily the capacities of, and volumes flowing through, their major receipt and delivery points and mainline segments in order to make available the information to track daily flows of natural gas throughout the United States; and (ii) require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC in order to make possible an estimate of the size of the physical U.S. natural gas market, assess the importance of the use of index pricing in that market, and determine the size of the fixed-price trading market that produces the information. The FERC believes these revisions to its regulations will facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. Initial comments were filed on July 11, 2007 and reply comments are due on August 23, 2007. In addition, the FERC scheduled an informal workshop in this proceeding on July 24, 2007, to discuss implementation and other technical issues associated with the proposals set forth in the NOPR. Since this is a proposed rulemaking in which the FERC will consider initial and reply comments from industry participants, it is not clear what impact the final rule will have on the business of our intrastate and interstate pipeline companies.

We operate and own a 51% ownership interest in West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC. ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25% interest. When construction of the entire Rockies Express Pipeline 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. According to the provisions of current accounting standards, due to the fact that we will receive 50% of the economics of the Rockies Express project on an ongoing basis, we are not considered the primary beneficiary of West2East Pipeline LLC and thus, we account for our investment under the equity method of accounting.

On August 9, 2005, the FERC approved the application of Rockies Express Pipeline LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of pipeline facilities in two phases. For phase I (consisting of two pipeline segments), Rockies Express was granted authorization to construct and operate approximately 136 miles of pipeline extending northward from the Meeker Hub, located at the northern end of our TransColorado pipeline system in Rio Blanco County, Colorado, to the Wamsutter Hub in Sweetwater County, Wyoming (segment 1), and then construct approximately 191 miles of pipeline eastward to the Cheyenne Hub in Weld County, Colorado (segment 2). Construction of segments 1 and 2 has been completed, with interim service commencing on segment 1 on February 24, 2006, and full in-service of both segments on February 14, 2007. For phase II, Rockies Express was authorized to construct three compressor stations referred to as the Meeker, Big Hole and Wamsutter compressor stations. The Meeker and Wamsutter stations are currently under construction and are planned to be in service in the fourth quarter of 2007. Construction of the Big Hole compressor station is planned to commence in the fourth quarter of 2008, in order to meet an expected in-service date of June 30, 2009.

On April 19, 2007, the FERC issued a final order approving the Rockies Express 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, and it 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. Construction commenced on May 21, 2007, and the project is expected to be completed by January 1, 2008.

On April 30, 2007, Rockies Express filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the Rockies Express-East Project. The Rockies Express-East Project will be comprised of approximately 639 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline to a terminus near the town of Clarington in Monroe County, Ohio and will be capable of transporting approximately 1.8 billion cubic feet per day of natural gas. On September 7, 2007, the FERC issued a Notice of Schedule for Environmental Review for the Rockies Express-East Project. Rockies Express has requested that the FERC issue an updated scheduling order. Without a modification of the schedule, Rockies Express has concerns about its ability to complete its project by June 2009. Rockies Express is working closely with the FERC staff and other cooperating agencies to develop a revised schedule more consistent with Rockies Express’s filing of September 25, 2007. That schedule was developed in consultation with the FERC staff at a public meeting convened on September 21, 2007. While there can be no assurance that the FERC will approve the revised schedule, subject to that approval, the Rockies Express-East Project is expected to begin partial service on December 31, 2008, and to be in full service in June 2009.

On April 19, 2007, the FERC issued an order approving TransColorado Gas Transmission Company’s 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. Construction commenced on May 9, 2007, and the project is expected to be completed by January 1, 2008.

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 natural gas 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 Knight’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 $517 million project is expected to be in service by January 1, 2009.

On March 15, 2007, the FERC issued a preliminary determination that the authorizations requested, subject to some minor modifications, will be in the public interest. This order does not consider or evaluate any of the environmental issues in this proceeding. On April 19, 2007, the FERC issued the final Environmental Impact Statement, which addressed the potential environmental effects of the construction and operation of the Kinder Morgan Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of the National Environmental Policy Act. It concluded that approval of the Kinder Morgan Louisiana Pipeline project would have limited adverse environmental impacts. On June 22, 2007, the FERC issued an order granting construction and operation of the project. Kinder Morgan Louisiana Pipeline officially accepted the order on July 10, 2007.

On October 9, 2007, in Docket No. CP08-6-000, Midcontinent Express Pipeline LLC filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the approximate 500-mile Midcontinent Express Pipeline natural gas transmission system. Subject to the receipt of regulatory approvals, construction of the pipeline is expected to commence in August 2008 and be in service during the first quarter of 2009.

The Midcontinent Express Pipeline will create long-haul, firm transportation takeaway capacity either directly or indirectly connected to natural gas producing regions located in Texas, Oklahoma and Arkansas. The pipeline will originate in southeastern Oklahoma and traverse east through Texas, Louisiana, Mississippi, and Alabama, providing capability to transport natural gas supplies to major pipeline interconnects along the route up to its terminus at Transco’s Station 85. The Midcontinent Express Pipeline will have an initial capacity of up to 1.5 billion cubic feet and a total capital cost of approximately $1.3 billion. The pipeline is a 50/50 joint venture between ourselves and Energy Transfer Partners, L.P.

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.

Nonetheless, as a result of EITF 04-5, as of January 1, 2006, our financial statements are consolidated into the consolidated financial statements of Knight. Notwithstanding the consolidation of our financial statements into the consolidated financial statements of Knight pursuant to EITF 04-5, Knight is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or Knight’s financial statements is a legal determination based on the entity that incurs the liability. The determination of responsibility for payment among entities in our consolidated group of subsidiaries was not impacted by the adoption of EITF 04-5.

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.” This Statement 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. For us, this Statement became effective January 1, 2007. Adoption of this Statement has had no effect on our consolidated financial statements.

On March 17, 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This Statement amends SFAS No. 140 and addresses the recognition and measurement of separately recognized servicing assets and liabilities, such as those common with mortgage securitization activities, 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. For us, this Statement became effective January 1, 2007. Adoption of this Statement has had no effect on our consolidated financial statements.

On June 28, 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: (i) 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 (ii) 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 applies 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 on a prospective basis, the adoption of EITF 06-3 had no effect on our consolidated financial statements.

In July 2006, the FASB issued Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109,” which became effective January 1, 2007. FIN 48 addressed the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate resolution.

Our adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative effect adjustment to “Partners’ Capital” on our consolidated balance sheet. At January 1, 2007, we had $3.2 million of unrecognized tax benefits on our consolidated balance sheet, of which, $0.7 million would affect the effective income tax rate in future periods. Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense. We had $1.1 million of accrued interest and no accrued penalties as of January 1, 2007. We believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $1.3 million in the next 12 months. In addition, we have U.S. and state tax years open to examination for the periods 2003 – 2006.

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 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.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement provides companies with an option to report selected financial assets and liabilities at fair value. The Statement’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. The Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.

SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. The Statement does not eliminate disclosure requirements included in

other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157, discussed above, and SFAS No. 107 “Disclosures about Fair Value of Financial Instruments.”

This Statement is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007 (January 1, 2008 for us). Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS No. 157. We are currently reviewing the effects of this Statement.

The following information should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report); and (ii) 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, 2006, and in our Current Report on Form 8-K filed August 22, 2007.

In addition, as discussed in Note 2 to our consolidated financial statements included elsewhere in this report, our consolidated financial statements:

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.

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, 2006, and in our Current Report on Form 8-K filed August 22, 2007. There have not been any significant changes in these policies and estimates during the nine months ended September 30, 2007.

	Three Months Ended
	September 30,						Earnings
	2007			2006			Increase/(decrease)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)		(In millions, except percentages)
Products Pipelines(b)	$	156.1		$	117.0		$	39.1		33	%
Natural Gas Pipelines		142.0			140.7			1.3		1	%
CO2		138.0			127.1			10.9		9	%
Terminals		109.4			98.4			11.0		11	%
Trans Mountain(c)		22.1			16.0			6.1		38	%

Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		567.6			499.2			68.4		14	%

Depreciation, depletion and amortization expense(d)		(140.3	)		(111.4	)		(28.9	)	(26	)%
Amortization of excess cost of equity investments		(1.4	)		(1.4	)		—		—
Interest and corporate administrative expenses(e)		(212.1	)		(156.9	)		(55.2	)	(35	)%
Net income	$	213.8		$	229.5		$	(15.7	)	(7	)%

	Nine Months Ended
	September 30,						Earnings
	2007			2006			Increase/(decrease)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		(In millions, except percentages)
Products Pipelines(f)	$	446.9		$	362.0		$	84.9		23	%
Natural Gas Pipelines(g)		421.3			435.1			(13.8	)	(3	)%
CO2 (h)		392.3			372.9			19.4		5	%
Terminals(i)		320.0			290.0			30.0		10	%
Trans Mountain(j)		(306.5	)		50.1			(356.6	)	(712	)%
Segment earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments		1,274.0			1,510.1			(236.1	)	16	%

Depreciation, depletion and amortization expense(k)		(408.8	)		(311.1	)		(97.7	)	(31	)%
Amortization of excess cost of equity investments		(4.3	)		(4.2	)		(0.1	)	(2	)%
Interest and corporate administrative expenses(l)		(563.9	)		(458.0	)		(105.9	)	(23	)%
Net income	$	297.0		$	736.8		$	(439.8	)	(60	)%

Our consolidated net income for the quarterly period ended September 30, 2007 was $213.8 million ($0.24 per diluted unit), compared to $229.5 million ($0.42 per diluted unit) for the quarterly period ending September 30, 2006. Continued investment in our diversified portfolio of energy transportation and storage assets since the end of the third quarter of 2006 resulted in higher interest expenses and higher non-cash depreciation, depletion, and amortization expenses in the third quarter of 2007, when compared to the same prior year period. We also recognized higher general and administrative expenses in the third quarter of 2007, primarily due to settlements reached on certain litigation and environmental matters.

For the nine months ended September 30, 2007 and 2006, we earned net income of $297.0 million and $736.8 million, respectively; however, in addition to the incremental expenses described above, our 2007 year-to-date net income included an impairment expense of $377.1 million associated with a non-cash reduction in the carrying value of Trans Mountain’s goodwill. The goodwill impairment charge was recognized by Knight in March 2007, and following our purchase of Trans Mountain from Knight on April 30, 2007, the financial results of Trans Mountain since January 1, 2006, including the impact of the goodwill impairment, are reflected in our results. Also, our overall carrying value for the net assets of Trans Mountain reflects Knight’s carrying value, which is considerably higher than the cash price we paid. For more information on this acquisition and the goodwill impairment, see Notes 2 and 6 to our consolidated financial statements included elsewhere in this report.

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 segment earnings before depreciation, depletion and amortization expenses (defined in the table above and sometimes referred to in this report as EBDA) internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments.

Our total segment earnings before depreciation, depletion and amortization increased $68.4 million (14%) in the third quarter of 2007 compared to the third quarter of 2006. The two certain items described in the footnotes to the table above accounted for $15.1 million of the total difference between total segment earnings before depreciation, depletion and amortization in the third quarter of 2007, when compared to the third quarter of 2006. The remaining $83.5 million (17%) increase in quarter-to-quarter segment earnings before depreciation, depletion and amortization resulted from higher earnings from all five of our business segments—driven by a $38.2 million (33%) increase from our Products Pipelines segment and incremental earnings of $22.1 million from Trans Mountain. For the comparable nine month periods, the certain items described in the footnotes to the table above accounted for a decrease in segment earnings before depreciation, depletion and amortization by $406.3 million, when compared to the first nine months of 2006. The remaining $170.2 million (12%) increase in year-to-date segment earnings before depreciation, depletion and amortization resulted from incremental earnings from our Products Pipelines, Trans Mountain, Terminals and CO₂ business segments.

Combined, the certain items described in the footnotes to the table above increased our Products Pipelines’ third quarter 2007 segment earnings before depreciation, depletion and amortization expenses by $0.9 million, when compared to the third quarter of 2006, and increased the segment’s nine month 2007 earnings before depreciation, depletion and amortization by $10.3 million, relative to the first nine months last year. Following is information related to the increases and decreases, in the same comparable periods of 2007 and 2006, of the segment’s (i) remaining changes to earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (EBDA); and (ii) operating revenues:

All of the assets in our Products Pipelines business segment produced higher earnings before depreciation, depletion and amortization expenses in the third quarter of 2007 than in the comparable quarter last year. The overall increases in segment earnings before depreciation, depletion and amortization in the three and nine month periods ended September 30, 2007, relative to the same periods a year ago, were driven by incremental earnings from our Cochin pipeline system. The higher earnings and revenues from Cochin were largely attributable to our January 1, 2007 acquisition of the remaining approximately 50.2% ownership interest that we did not already own. Upon closing of the transaction, we became the operator of the pipeline. For more information on this acquisition, see Note 2 to our consolidated financial statements included elsewhere in this report.

We also benefited from favorable results from our North System common carrier natural gas liquids pipeline, our approximate 51% equity investment in Plantation Pipe Line Company, our Pacific operations, our West Coast terminal operations and our petroleum pipeline transmix operations. The earnings increases from the North System were chiefly due to higher period-to-period revenues in 2007, due to increases in both throughput volumes and in the average tariff per barrel moved.

In July 2007, we entered into an agreement to sell our North System and our 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $300 million, and this transaction closed in October 2007. We expect to use 50% of the proceeds we receive to pay down short-term debt borrowings, and the remaining 50% to reduce equity requirements. We accounted for our North System business as a discontinued operation pursuant to generally accepted accounting principals which require that the income statement be formatted to separate the divested business from our continuing operations. We earned net income from our North System (discontinued operations) of $8.6 million and $2.4 million, respectively, for the three months ended September 30, 2007 and 2006, and we earned net income of $21.1 million and $8.8 million, respectively, for the nine months ended September 30, 2007 and 2006.

We do not expect the impact of the discontinued operations to materially affect our overall business, financial position, results of operations or cash flows, and consistent with the management approach of identifying and reporting financial information on operating segments, we have included the North System’s financial disclosures within our Products Pipelines business segment disclosures for all periods presented in this discussion and analysis. This decision was based on the way our management organizes segments internally to make operating decisions and assess performance. For information on our reconciliation of segment information with our consolidated general-purpose financial statements, see Note 11 to our consolidated financial statements included elsewhere in this report.

The increases in earnings from our equity investment in Plantation was due to higher overall net income earned by Plantation Pipe Line Company, largely resulting from both higher pipeline revenues and lower period-to-period operating expenses. The increase in revenues was largely due to higher oil loss allowance tariff rates in 2007, relative to last year, and the drop in operating expenses, including fuel, power and pipeline maintenance expenses, was due to both decreases in period-to-period delivery volumes and lower pipeline integrity expenses in 2007 versus 2006.

The quarterly increase in earnings before depreciation, depletion and amortization from our Pacific operations was attributable to both higher revenues and lower operating expenses in 2007 versus 2006. The higher revenues reflected a 1.4% increase in average tariff rates and a 0.7% increase in total mainline delivery volumes. The drop in operating expenses was largely due to lower pipeline maintenance expenses in the third quarter of 2007, relative to the third quarter of 2006, related to a change in the third quarter of 2006 that both recognized and transferred a portion of 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).

For the comparable nine month periods, our Pacific operations’ increase in earnings before depreciation, depletion and amortization expenses was largely revenue related, attributable to increases in both transportation volumes and average tariff rates. Combined mainline delivery and terminal revenues increased 6.5% in the first nine months of 2007 versus the same period a year ago, due largely to higher delivery volumes to Arizona, partly due to

the completed expansion of our East Line pipeline during the summer of 2006, and to various West Coast military bases.

The period-to-period earnings increases from our West Coast terminal operations were due to higher operating revenues, lower operating expenses and (for the comparable nine month periods) incremental gains from asset sales in the second quarter of 2007. The increases in terminal revenues were driven by higher throughput volumes from our combined Carson/Los Angeles Harbor terminal system, and from our Linnton and Willbridge terminals located in Portland, Oregon. The decrease in operating expenses in 2007 versus 2006 was largely related to higher environmental expenses recognized in 2006, due to adjustments to accrued environmental liabilities.

The period-to-period increases in earnings before depreciation, depletion and amortization from our petroleum pipeline transmix operations were directly related to higher revenues, reflecting incremental revenues from our Greensboro, North Carolina facility and higher processing revenues from our Colton, California facility. In May 2006, we completed construction and placed into service the Greensboro facility (for a cost of approximately $11 million), and during 2007, the plant has continued to handle higher than budgeted processing volumes. For the comparable three and nine month periods, our Greensboro facility has contributed incremental earnings before depreciation, depletion and amortization of $0.6 million and $3.8 million, respectively, in 2007 compared to 2006. The increases in earnings and revenues from our Colton facility, which processes transmix generated from volumes transported to the Southern California and Arizona markets by our Pacific operations’ pipelines, were primarily due to period-to-period increases in average processing contract rates, which more than offset slightly lower processing volumes.

Combining all of the segment’s operations, revenues from refined petroleum products deliveries increased 3.8% in the third quarter of 2007, compared to the third quarter last year, while total products delivery volumes decreased 0.8%. Compared to the third quarter last year, gasoline delivery volumes decreased, while diesel and jet fuel volumes were up. Excluding Plantation, which continued to be impacted by a competing pipeline that began service in mid-2006, total refined products delivery volumes increased by 0.6% for the quarter and by 2% for the first nine months of 2007, compared to the same prior year periods. Volumes on our CALNEV and Central Florida pipelines were up 1.2% and 1.8%, respectively, in the third quarter of 2007, compared to the third quarter last year.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In millions, except operating statistics)
Revenues	$	1,526.8		$	1,650.4		$	4,755.3		$	5,082.2
Operating expenses(a)		(1,387.8	)		(1,519.2	)		(4,348.9	)		(4,694.0	)
Other income(b)		0.4			—			3.1			15.1
Earnings from equity investments(c)		4.0			10.0			14.2			31.8
Interest income and Other, net-income (expense)		—			0.5			0.2			0.9
Income tax benefit (expense)		(1.4	)		(1.0	)		(2.6	)		(0.9	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	142.0		$	140.7		$	421.3		$	435.1

Natural gas transport volumes (Trillion Btus)(d)		402.4			384.9			1,175.2			1,067.4
Natural gas sales volumes (Trillion Btus)(e)		224.4			243.5			641.0			690.0

Driven by higher natural gas transmission and storage revenues, our Natural Gas Pipelines business segment reported a 1% increase in earnings before depreciation, depletion and amortization expenses for the third quarter of 2007, when compared to last year’s third quarter. The net effect of the certain other items described in the footnotes to the table above resulted in a $20.9 million reduction in the segment’s earnings before depreciation, depletion and amortization for the nine months ended September 30, 2007, when compared to the same period of 2006. The largest of these items was a comparable decrease in earnings of $15.1 million in 2007 due to the April 2006 sale of our Douglas natural gas gathering system and Painter Unit fractionation facility. Effective April 1, 2006, we sold these two assets 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 nine months ended 2006. For more information on this gain, see Note 2 to our consolidated financial statements included elsewhere in this report.

Following is information related to the quarter-to-quarter increases and decreases, and the remaining increases and decreases in the comparable nine month periods of 2007 and 2006, of the segment’s (i) earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (EBDA); and (ii) operating revenues:

The segment’s overall increases in earnings before depreciation, depletion and amortization expenses in both the three and nine months ended September 30, 2007, when compared to the same periods last year, were driven by a strong third quarter 2007 performance from our Texas intrastate natural gas pipeline group, which collectively, serves the Texas Gulf Coast region by transporting, buying, selling, processing and storing natural gas

from multiple onshore and offshore supply sources. The higher earnings in 2007 compared to 2006 were primarily due to higher sales margins on renewal and incremental contracts, increased transportation revenue from higher volumes and rates, greater value from natural gas storage activities (including sales of cushion gas due to the termination of a storage facility lease), and higher natural gas processing margins. Although natural gas sales volumes were down 8% in the third quarter of 2007 versus the third quarter of 2006, natural gas transport volumes on our Texas intrastate systems increased nearly 5%, resulting in higher transportation revenues. The Intrastate group also benefited from incremental natural gas storage revenues due to a long-term contract with one of its largest customers that became effective April 1, 2007.

Our Texas intrastate group accounted for more than half of the segment’s total earnings before depreciation, depletion and amortization expenses in both the three and nine months ended September 30, 2007, when compared to the same periods a year ago. Because the group also buys and sells natural gas (typically matching purchases with sales), the variances from period to period in both segment revenues and segment operating expenses (which include natural gas costs of sales) are due to changes in our intrastate groups’ average prices and volumes for natural gas purchased and sold.

The increases in earnings from our Casper and Douglas natural gas processing operations were driven by a strong third quarter 2007 performance that included an overall 25% increase in operating revenues, when compared to the third quarter of 2006. The increase was primarily attributable to higher natural gas liquids sales revenues, due to increases in both prices and volume.

The decreases in earnings in both comparable periods from our Rocky Mountain interstate natural gas pipeline group, which is comprised of Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company, TransColorado Gas Transmission Company, and our current 51% equity investment in Rockies Express Pipeline LLC, resulted primarily from period-to-period decreases of $4.1 million and $9.7 million, respectively, in equity earnings from our investment in Rockies Express. The decreases in earnings from Rockies Express, which began interim service in February 2006, reflects lower net income due primarily to incremental depreciation and interest expense allocable to a segment of the project that was placed in service in February 2007 and, until the completion of the Rockies Express-West project, has limited natural gas reservation revenues and volumes. Rockies Express-West has an in-service target date of January 1, 2008.

Third quarter earnings from our Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline systems decreased $3.7 million (11%) and increased $0.8 million (6%), respectively, in 2007, compared to 2006. The decrease from KMIGT was largely related to lower margins from sales of both operational natural gas and cushion natural gas volumes; lower net fuel recoveries; higher property tax expenses, due to tax accrual adjustments; and higher gas transmission expenses, related to higher transport volumes in the third quarter of 2007. The increase in earnings from Trailblazer was due largely to higher quarter-to-quarter revenues, due to an over 4% increase in natural gas transmission volumes, partially offset by lower earnings due to timing differences on the settlements of pipeline operational imbalances.

The drop in period-to-period earnings before depreciation, depletion and amortization from our 49% equity investment in the Red Cedar Gathering Company was mainly due to higher prices on incremental sales of excess fuel gas and to higher natural gas gathering revenues in 2006, relative to the third quarter and first nine months of 2007.

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.

As described in footnote (a) to the table above, the segment’s overall increase in earnings before depreciation, depletion and amortization expenses and in revenues in the nine months ended September 30, 2007, compared to the same period of 2006, included an increase of $1.8 million from a second quarter 2006 loss on derivative contracts used to hedge forecasted crude oil sales. For each of the segment’s two primary businesses, following is information related to the quarter-to-quarter increases and decreases, and the remaining nine-month period-to-period increases and decreases, of the segment’s (i) earnings before depreciation, depletion and amortization (EBDA); and (ii) operating revenues:

The overall period-to-period increases in segment earnings before depreciation, depletion and amortization expenses were driven by higher earnings from the segment’s oil and gas producing activities, which include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants. Highlights for the third quarter of 2007 compared to the third quarter of 2006 included an increase in oil production at the Yates field unit and higher earnings from natural gas liquids sales volumes, due largely to increased recoveries at our SACROC field unit gas processing operations.

Revenues from the segment’s oil and gas producing activities’ crude oil sales and natural gas liquids sales increased $7.6 million (7%) and $12.3 million (33%), respectively, in the third quarter of 2007 compared to the third quarter of 2006, and increased $26.8 million (8%) and $21.4 million (20%), respectively, in the first nine months of 2007 compared to the first nine months of 2006. The increases in both quarterly and nine month crude oil revenues in 2007 versus 2006 resulted from a 13% increase in our realized weighted average price per barrel, partially offset by decreases in sales volumes of 6% and 4%, respectively. Average gross oil production for the third quarter of 2007 was 27.1 thousand barrels per day at the Yates unit, up 3% from the third quarter of 2006, and 27.3 thousand barrels per day at SACROC, a decline of 10% versus the third quarter of 2006. The period-to-period increases in revenues from the sales of natural gas liquids were almost equally due to favorable sales-volume and price variances—liquids sales volumes increased 18% and 10%, respectively, and our realized weighted average price per barrel increased 13% and 9%, respectively.

The period-to-period decreases in earnings before depreciation, depletion and amortization from the segment’s sales and transportation activities were primarily due to decreases in carbon dioxide sales revenues, caused by lower year-over-year prices for carbon dioxide in 2007. The segment’s average price received for all carbon dioxide sales decreased 19% in both the three and nine month periods ended September 30, 2007, when compared to the same periods in 2006. The decreases in average carbon dioxide sales price were primarily attributable to the expiration of a significantly high-priced sales contract in December 2006.

In addition, period-to-period carbon dioxide delivery volumes decreased 8% and 6%, respectively, in the comparable three and nine month periods, and as always, we do not recognize profits on carbon dioxide sales to ourselves. As of September 30, 2007, we expect our CO₂ business segment to fall substantially short of its published annual budget of earnings before depreciation, depletion and amortization for 2007, primarily due to the lower crude oil production at the SACROC unit.

The segment’s operating expenses increased $7.0 million (10%) in the third quarter of 2007, and $28.5 million (15%) in the first nine months of 2007, when compared to the same year earlier periods. The increases were largely due to additional labor and field expenses, driven by higher well workover and completion expenses related to infrastructure expansions at the SACROC and Yates oil field units, and to higher severance tax expenses, related to the increases in crude oil revenues.

Because our CO₂ segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids, we mitigate this risk through a long-term hedging strategy that is intended to generate more stable realized prices by using derivative contracts as hedges to the exposure of fluctuating expected future cash flows produced by changes in commodity sales prices. All of our hedge gains and losses for crude oil and natural gas liquids are included in our realized average price for oil. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $73.12 per barrel in the third quarter of 2007, and $68.20 per barrel in the third quarter of 2006. For more information on our hedging activities, see Note 10 to our consolidated financial statements included elsewhere in this report.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In millions, except operating statistics)
Revenues	$	247.2		$	223.1		$	691.3		$	649.8
Operating expenses		(133.0	)		(122.1	)		(365.9	)		(354.8	)
Other income (expense)(a)		1.5			—			5.9			—
Earnings from equity investments		0.3			0.1			0.3			0.2
Other, net-income (expense)		0.3			1.0			0.3			2.3
Income tax expense		(6.9	)		(3.7	)		(11.9	)		(7.5	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	109.4		$	98.4		$	320.0		$	290.0

Bulk transload tonnage (MMtons)(b)		22.6			25.4			63.2			69.6
Liquids leaseable capacity (MMBbl)		46.3			43.5			46.3			43.5
Liquids utilization %		96.5	%		97.8	%		96.5	%		97.8	%

Our Terminals business segment includes the operations of our petroleum and petrochemical-related liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, steel and other dry-bulk material services facilities. As described in footnote (a) to the table above, the segment’s overall increase in earnings before depreciation, depletion and amortization expenses in the first nine months of 2007, compared to the first half of 2006, included a $1.8 million gain (recognized in January 2007) based upon our final determination of the book value of fixed assets damaged or destroyed during Hurricanes Katrina and Rita in 2005.

The segment’s $11.0 million (11%) increase in earnings before depreciation, depletion and amortization in the third quarter of 2007 versus the third quarter of 2006, and its remaining $28.2 million (10%) increase in earnings before depreciation, depletion and amortization in the first nine months of 2007 versus the first nine months a year ago, were due to a combination of internal expansions and strategic acquisitions completed since the third quarter of 2006. Since the end of the third quarter of 2006, we have invested approximately $178.1 million in cash and $1.7 million in common units to acquire terminal assets and equity investments and combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $8.4 million, revenues of $22.5 million and operating expenses of $14.4 million, respectively, in the third quarter of 2007, and incremental earnings before depreciation, depletion and amortization of $13.8 million, revenues of $41.1 million and operating expenses of $27.5 million, respectively, in the first nine months of 2007. All of the incremental amounts represent the earnings, revenues and expenses from the acquired terminals’ operations during the additional months of ownership in 2007, and do not include increases or decreases during the same months we owned the assets in 2006.

Our significant terminal acquisitions since the end of the second quarter of 2006 included the following:

For all other terminal operations (those owned during identical periods in both 2007 and 2006), earnings before depreciation, depletion and amortization expenses and the property casualty gain increased $2.6 million (3%) in the third quarter of 2007, and $14.4 million (5%) in the first nine months of 2007, when compared to the same prior year periods.

The overall increases in earnings represent net changes in terminal results at various locations, but quarterly highlights in the third quarter of 2007 included higher earnings from (i) our Texas Petcoke region, due largely to higher petroleum coke throughput volumes at our Port of Houston facility; (ii) the combined operations of our Argo and Chicago, Illinois liquids terminals, due to increased ethanol throughput and incremental liquids storage and handling business; (iii) our Lower Mississippi (Louisiana) terminals, which include our 66 2/3% ownership interest in the International Marine Terminals partnership and our Port of New Orleans liquids facility located in Harvey, Louisiana; and (iv) our Pier IX terminal, located in Newport News, Virginia, largely due to a 27% quarter-to-quarter increase in coal transfer volumes. The earnings increases from our Louisiana terminals continue to reflect incremental business recovery from the effects of past hurricane damage.

In addition, for the comparable nine month periods, we received incremental contributions from our two large Gulf Coast liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas. The two terminals continued to benefit from recent expansions that have added new liquids tank capacity in 2007, relative to 2006. Expansion projects completed since the end of the third quarter of 2006 have increased our liquids terminals’ leaseable capacity by over 6%, more than offsetting a slight 1% drop in our overall utilization percentage.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In millions, except operating statistics)
Revenues	$	43.7		$	33.6		$	119.8		$	94.1
Operating expenses		(19.3	)		(14.2	)		(47.2	)		(38.7	)
Other income (expense)(a)		—			—			(377.1	)		0.9
Earnings from equity investments		—			—			—			—
Other, net-income (expense)		2.9			0.6			4.0			2.0
Income tax benefit (expense)		(5.2	)		(4.0	)		(6.0	)		(8.2	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(b)	$	22.1		$	16.0		$	(306.5	)	$	50.1

Transport volumes (MMBbl)		25.3			21.8			70.1			63.0

Our Trans Mountain segment includes the operations of the Trans Mountain Pipeline, which we acquired from Knight effective April 30, 2007. Trans Mountain transports crude oil and refined products from Edmonton, Alberta to marketing terminals and refineries in British Columbia and the State of Washington. An additional 35,000 barrel per day expansion that will increase capacity on the pipeline to approximately 300,000 barrels per day is currently under construction and is expected to be in service by late 2008.

According to the provisions of generally accepted accounting principles that prescribe the standards used to account for business combinations, due to the fact that our acquisition of Trans Mountain from Knight represented a transfer of assets between entities under common control, we initially recorded the assets and liabilities of Trans Mountain transferred to us from Knight at their carrying amounts in the accounts of Knight. Furthermore, our accompanying financial statements included in this report, and the information in the table above, reflect the results of operations for the third quarter and first nine months of 2007 as though the transfer of Trans Mountain from Knight had occurred at the beginning of the period (January 1, 2006 for us).

After taking into effect the certain items described in the footnotes to the table above, the remaining increases in earnings before depreciation, depletion and amortization totaled $22.1 million and $42.7 million, respectively, and related entirely to our acquisition of Trans Mountain effective April 30, 2007.

of KMI (now Knight Inc.); (iv) a $0.8 million increase in expense related to the cancellation of certain commercial insurance policies; and (v) a $0.4 million increase in expense for certain Trans Mountain acquisition costs. 2006 amount includes Trans Mountain expenses of $3.8 million.

Items not attributable to any segment include general and administrative expenses, unallocable interest income, interest expense, and minority interest. Our 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 services.

As described in the footnotes to the table above, the overall increases in our general and administrative expenses in the third quarter and first nine months 2007, versus the same periods of 2006, included incremental expenses of $1.5 million and $24.9 million, respectively, associated with the activities required to complete the previously announced management buyout proposal for all of the outstanding shares of KMI (now Knight Inc.). These amounts were allocated to us from Knight and we were required to recognize the full amounts allocated to us as expense on our income statements. However, due to the fact that almost all of the allocated expenses were associated with the acceleration of cashouts of grants of both KMI restricted stock and options on KMI stock, we were not responsible for paying these buyout expenses, and accordingly, recognized the unpaid amount as both a contribution to “Partners’ Capital” and an increase to “Minority interest” on our balance sheet.

The remaining quarter-to-quarter increase in our general and administrative expenses was largely associated with an incremental litigation expense of $43.2 million incurred in the third quarter of 2007. As briefly described in the footnotes to the table above, this expense relates to (i) litigation reserves established after our third quarter earnings press release on October 17, 2007, due to developments in certain matters after that date, primarily related to our Cora terminal; and (ii) a plea agreement and civil settlement reached between us and the District Attorney of Contra Costa County, California in the third quarter of 2007 pertaining to the November 2004 rupture of an underground petroleum pipeline owned and operated by our Pacific operations. For more information on our litigation matters, see Note 3 to our consolidated financial statements included elsewhere in this report.

For the comparable nine month periods, the certain items described in the footnotes to the table above increased our nine month 2007 general and administrative expenses by $64.0 million, when compared to the first nine months of 2006 (combining to increase expenses by $77.5 million in the 2007 period, and by $13.5 million in the 2006 period). The remaining $6.8 million (4%) increase was largely due to (i) higher shared services expenses, which include legal, corporate secretary, tax, information technology and other shared services; and (ii) higher payroll-related expenses resulting from the acquisitions we have made since September 30, 2006.

Unallocable interest expense, net of interest income, increased $12.2 million (13%) in the third quarter of 2007, compared to the third quarter of 2006. The quarter-to-quarter increase was due to both a 3% increase in the weighted average interest rate on all of our borrowings and an over 21% increase in average borrowings. For the comparable nine month periods, net interest expense increased $38.8 million (15%) in 2007 versus 2006, due to a 5% increase in average borrowing rates and a 19% increase in average borrowings.

The increases in our average borrowing rates reflect a general rise in variable interest rates in 2007 over 2006, and the increases in our average debt levels for the comparable three and nine month periods were largely due to both higher period-to-period capital expenditures in 2007, relative to 2006, and to the business acquisitions we have made since the end of the third quarter of 2006.

We attempt to maintain a relatively 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 millions):

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 for expansion capital expenditures through borrowings under our credit facility, issuing short-term commercial paper, long-term notes or additional common units or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of additional KMR shares. Further information on our financing strategies and activities can be found in our Annual Report on Form 10-K for the year ended December 31, 2006, and in our Current Report on Form 8-K filed August 22, 2007.

As part of our financial strategy, we try to maintain an investment-grade credit rating, which involves, among other things, issuing additional limited partner units in connection with our acquisitions and internal growth

activities in order to maintain acceptable financial ratios. On May 30, 2006, Standard & Poor’s Rating Services and Moody’s Investors Service each placed our ratings on credit watch pending the resolution of the management buyout proposal for all of the outstanding shares of KMI (now Knight Inc.). On January 5, 2007, in anticipation of the buyout closing, S&P downgraded us one level to BBB and removed our rating from credit watch with negative implications. Currently, our debt credit rating is still rated BBB by S&P. As previously noted by Moody’s in its credit opinion dated November 15, 2006, it downgraded our credit rating from Baa1 to Baa2 on May 30, 2007, following the closing of the management buyout. Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007.

Our principal sources of short-term liquidity are (i) our $1.85 billion five-year senior unsecured revolving credit facility that matures August 18, 2010; (ii) 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 (iii) cash from operations (discussed following).

Borrowings under our five-year credit facility can be used for general partnership purposes and as a backup for our commercial paper program. The facility can be amended to allow for borrowings up to $2.1 billion. There were no borrowings under our credit facility as of September 30, 2007. As of September 30, 2007, we had $576.4 million of commercial paper outstanding. As of December 31, 2006, there were no borrowings under our credit facility, and we had $1,098.2 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 reduction for our outstanding commercial paper borrowings and letters of credit, the remaining available borrowing capacity under our bank credit facility was $819.5 million as of September 30, 2007. As of September 30, 2007, our outstanding short-term debt was $597.0 million. Currently, we believe our liquidity to be adequate.

Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, we believe we have provided adequate allowance for such customers.

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 by utilizing the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.

In the third quarter of 2007, we closed a public offering of $500 million in principal amount of 5.85% senior notes due September 15, 2012. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $497.8 million, and we used the proceeds to reduce the borrowings under our commercial paper program. As of September 30, 2007, our total liability balance due on the various series of our senior notes was $7,053.8 million, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $189.0 million.

We are subject 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. For additional information regarding our debt securities and credit facility, see Note 9 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006, and in our Current Report on Form 8-K filed August 22, 2007.

Net cash provided by operating activities was $1,254.7 million for the nine months ended September 30, 2007, versus $916.5 million in the comparable period of 2006. The period-to-period increase of $338.2 million (37%) in cash flow from operations principally consisted of:

Net cash used in investing activities was $1,908.7 million for the nine month period ended September 30, 2007, compared to $1,111.7 million in the comparable prior year period. The $797.0 million (72%) increase in cash used in investing activities was primarily attributable to:

Our sustaining capital expenditures, defined as capital expenditures which do not increase the capacity of an asset, were $95.0 million for the first nine months of 2007, compared to $76.2 million for the first nine months of 2006. The above amounts do not include the sustaining capital expenditures of our Trans Mountain business segment for periods prior to our acquisition date of April 30, 2007. Trans Mountain had sustaining capital expenditures of $1.1 million for the first four months of 2007, and it had sustaining capital expenditures of $6.6 million for the nine months ended September 30, 2006. Our forecasted expenditures for the remaining three months of 2007 for sustaining capital expenditures are approximately $59.5 million. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary;

Net cash provided by financing activities amounted to $703.2 million for the first nine months of 2007. For the same nine month period last year, our financing activities provided net cash of $195.1 million. The $508.1 million (260%) increase from the comparable 2006 period was primarily due to:

The decrease in commercial paper borrowings includes a decrease of $412.5 million from borrowings under the commercial paper program of Rockies Express Pipeline LLC in the first half of 2006. We held and consolidated a 66 2/3% ownership interest in Rockies Express Pipeline LLC until June 30, 2006. Effective June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline LLC), and West2East Pipeline LLC was then deconsolidated and subsequently accounted for under the equity method of accounting. Generally accepted accounting principles required us to include its

cash inflows and outflows in our consolidated statement of cash flows for the six months ended June 30, 2006; however, following the change from full consolidation to the equity method, Rockies Express’ debt balances were not included in our consolidated balance sheet as of or subsequent to June 30, 2006.

The $1,784.5 million increase in cash inflows from changes in senior notes outstanding during the comparable nine month periods was associated with public debt offerings completed on January 30, 2007, June 21, 2007 and August 28, 2007. On these dates, we completed offerings of $1.0 billion, $550 million and $500 million, respectively, in principal amount of senior notes in four separate series: $600 million of 6.00% notes due February 1, 2017, $400 million of 6.50% notes due February 1, 2037, $550 million of 6.95% notes due January 15, 2038 and $500 million of 5.85% notes due September 15, 2012. Combined, we received proceeds, net of underwriting discounts and commissions, of $2,034.5 million from these long-term debt offerings and we used the proceeds from each of these offerings to reduce the borrowings under our commercial paper program. In addition, on August 15, 2007, we repaid $250 million of 5.35% senior notes that matured on that date;

The overall decrease in period-to-period partnership distributions (described above) was also largely related to the activities of our Rockies Express Pipeline LLC subsidiary in 2006 driven by incremental minority interest distributions of $105.2 million paid from Rockies Express Pipeline LLC to Sempra Energy in the second quarter 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. During the quarter, 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 in 2006, our overall distributions increased $52.9 million, primarily resulting from higher distributions, in 2007, of “Available Cash,” as described below in “—Partnership Distributions.” The increase in “Available Cash” distributions in 2007 versus 2006 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;

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. Our Annual Report on Form 10-K for the year ended December 31, 2006 contains additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including minority interests.

In addition, as discussed in Note 2 to our consolidated financial statements included elsewhere in this report, the transactions, balances and results of operations of our Trans Mountain pipeline system were included in our consolidated financial information as if it had been transferred to us on January 1, 2006; however, the effective date of this acquisition was April 30, 2007, and the acquisition had no impact on the distributions we made (including incentive distributions paid to our general partner) prior to this date.

On August 14, 2007, we paid a quarterly distribution of $0.85 per unit for the second quarter of 2007. This distribution was 5% greater than the $0.81 distribution per unit we paid in August 2006 for the second quarter of 2006. We paid this distribution in cash to our general partner and to our common and Class B unitholders. KMR, our sole i-unitholder, received additional i-units based on the $0.85 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.

Additionally, on October 17, 2007, we declared a cash distribution of $0.88 per unit for the third quarter of 2007 (an annualized rate of $3.52 per unit). This distribution was 9% higher than the $0.81 per unit distribution we made for the third quarter of 2006. We expect to declare cash distributions in excess of our budget of $3.44 per unit for 2007; however, no assurance can be given that we will be able to achieve this level of distribution. Our projection does not include any benefits from unidentified acquisitions or take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’ interstate pipelines.

The incentive distribution that we paid on August 14, 2007 to our general partner (for the second quarter of 2007) was $147.6 million. Our general partner’s incentive distribution that we paid in August 2006 (for the second quarter of 2006) was $129.0 million. Our general partner’s incentive distribution for the distribution that we declared for the third quarter of 2007 will be $155.2 million, and our general partner’s incentive distribution for the distribution that we paid for the third quarter of 2006 was $133.0 million. The period-to-period increases in our general partner incentive distributions resulted from both increased cash distributions per unit and increases in the number of common units and i units outstanding.

As of September 30, 2007, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $77.9 million. In addition, we have recorded a receivable of $26.9 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, 2007, and December 31, 2006, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $137.1 million and $112.0 million, respectively. The reserve is primarily related to various claims from lawsuits arising from SFPP, L.P.’s pipeline transportation rates, and the contingent amount is based on both probability of realization and our ability to reasonably estimate liability dollar amounts. 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.

There have been no material changes in our contractual obligations that would affect the disclosures presented as of December 31, 2006 in our 2006 Annual Report on Form 10-K and in our Current Report on Form 8-K filed August 22, 2007.

Except as set forth under “—Red Cedar Gathering Company Debt” and “—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, 2006 in our 2006 Annual Report on Form 10-K and in our Current Report on Form 8-K filed August 22, 2007.

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

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, 2006, 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 both our 2006 Annual Report on Form 10-K and this report. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, 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.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2006, in Item 7A of our 2006 Annual Report on Form 10-K and in our Current Report on Form 8-K filed August 22, 2007. For more information on our risk management activities, see Note 10 to our consolidated financial statements included elsewhere in this report.

As of September 30, 2007, 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 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, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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.

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, 2006.

The tax treatment applied to us depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our partners. The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes. In order for us to be treated as a partnership for federal income tax purposes, current law requires that 90% or more of our gross income for every taxable year consist of “qualifying income,” as defined in Section 7704 of the Internal Revenue Code. We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service on this or any other matter affecting us.

If we were to be treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Under current law, distributions to our partners would generally be taxed again as corporate distributions, and no income, gain, losses or deductions would flow through to our partners. Because a tax would be imposed on us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our partners, likely causing substantial reduction in the value of our units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are now subject to a new entity-level tax on the portion of our total revenue that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our total revenue that is apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce our cash available for distribution to our partners.

Our partnership agreement provides that if a law is enacted that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the target distribution levels will be adjusted to reflect the impact on us of that law.

We adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units. When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. This methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge these valuation methods, or our allocation of the Section 743(b) adjustment attributable to our

tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our partners. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Our treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of the common units. Because we cannot match transferors and transferees of common units, we are required to maintain the uniformity of the economic and tax characteristics of these units in the hands of the purchasers and sellers of these units. We do so by adopting certain depreciation conventions that do not conform to all aspects of the United States Treasury regulations. An IRS challenge to these conventions could adversely affect the tax benefits to a unitholder of ownership of the common units and could have a negative impact on their value or result in audit adjustments to unitholders’ tax returns.

The recently completed Knight, formerly known as KMI, going-private transaction resulted in substantially more debt at Knight and could have an adverse affect on us, such as a downgrade in the ratings of our debt securities. On May 30, 2007, Knight completed its transaction whereby investors led by Richard D. Kinder, Chairman and CEO of Knight, acquired all of the outstanding shares of Knight (other than shares held by certain stockholders and investors) for $107.50 per share in cash. In connection with the transaction, Knight incurred substantially more debt. In conjunction with the going-private transaction, Moody’s Investor Service, Inc. and Standard & Poor’s Rating Services reviewed and adjusted the credit ratings of both Knight and us. Following these adjustments, our senior unsecured debt is rated BBB/Baa2 by Standard & Poor’s and Moody’s, respectively. Though steps have been taken which are intended to allow our senior unsecured indebtedness to continue to be rated investment grade, we can provide no assurance that that will be the case.

Our senior management’s attention may be diverted from our daily operations because of significant transactions by Knight following the completion of the going-private transaction. The investors in the KMI going-private transaction include members of senior management of Knight, most of whom are also senior officers of our general partner and of KMR. Prior to consummation of the going-private transaction, KMI had publicly disclosed that several significant transactions were being considered that, if pursued, would require substantial management time and attention. As a result, our senior management’s attention may be diverted from the management of our daily operations.

Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect operations. There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities, and refined petroleum products and carbon dioxide transportation activities—such as leaks, explosions and mechanical problems that could result in substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of operations, any of which also could result in substantial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. If losses in excess of our insurance coverage were to occur, they could have a material adverse effect on our business, financial condition and results of operations.

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.

DELAWARE		76-0380342
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

Proceedings	Complainants/Protestants	Defendants	Summary
FERC Docket No. OR92-8, et al.	Chevron; Navajo; ARCO; BP WCP; Western Refining; ExxonMobil; Tosco; and Texaco (Ultramar is an intervenor).	SFPP	Consolidated proceeding involving shipper complaints against certain East Line and West Line rates. All five issues (and others) described four paragraphs above this chart are involved in these proceedings. Portions of this proceeding have been appealed (and re-appealed) to the D.C. Court and remanded to the FERC. BP WCP, Chevron, and ExxonMobil have requested a hearing on remanded grandfathering and income tax allowance issues, which is pending action by FERC.
FERC Docket Nos. OR92-8-028, et al.	BP WCP; ExxonMobil; Chevron; ConocoPhillips; and Ultramar	SFPP	Proceeding involving shipper complaints against SFPP’s Watson Station rates. A settlement was reached for April 1, 1999 forward; whether SFPP owes reparations for shipments prior to that date is still before the FERC.

FERC Docket No. OR96-2, et al.	All Shippers except Chevron (which is an intervenor)	SFPP	Consolidated proceeding involving shipper complaints against all SFPP rates. All five issues (and others) described four paragraphs above this chart are involved in these proceedings. Portions of this proceeding have been appealed (and re-appealed) to the D.C. Court and remanded to the FERC. On May 29, 2007, the D.C. Court upheld the FERC’s income tax allowance policy and upheld FERC’s determination that SFPP’s West Line rates were no longer grandfathered under EPAct 1992; however, the D.C. Court refused to consider arguments that there were errors in the FERC’s method for determining substantial change as to the rates at issue in the OR96-2 proceeding, finding that the parties had not first raised such allegations with FERC. SFPP has filed a petition for rehearing with the D.C. Court. SFPP’s compliance filings establishing the amount of its income tax allowance for the years at issue in the OR92-8 and OR96-2 proceedings are currently pending before FERC, and certain shippers have filed a motion for a hearing on this issue. On July 5, 2007, BP WCP and Chevron filed a motion for immediate payment of reparations to shippers. The FERC has not acted on this motion. BP WCP, Chevron, and ExxonMobil have requested a hearing on remanded grandfathering and income tax allowance issues, which is pending action by FERC. On August 3, 2007, BP WCP, Chevron, and ExxonMobil filed a motion for expedited consideration on their request for hearing, which SFPP answered. On August 31, 2007, BP WCP and ExxonMobil filed a motion to reopen the record on the issue of SFPP’s appropriate rate of return on equity, which SFPP answered. FERC has not yet acted on the August 3 and August 31 motions. With respect to the FERC’s order on the Sepulveda rate, a compliance filing has been made and requests for rehearing have been filed.
FERC Docket Nos. OR02-4 and OR03-5	Chevron	SFPP	Chevron initiated proceeding to permit Chevron to become complainant in OR96-2. Appealed to D.C. Court and held in abeyance pending final disposition of the OR96-2 proceedings.
FERC Docket No. OR04-3	America West Airlines; Southwest Airlines; Northwest Airlines; and Continental Airlines	SFPP	Complaint alleges that West Line and Watson Station rates are unjust and unreasonable. Watson Station issues severed and consolidated into a proceeding focused only on Watson-related issues. No FERC action on complaint against West Line rates; request for hearing and for consolidation with other proceedings filed and pending before the FERC.
FERC Docket Nos. OR03-5, OR05-4 and OR05-5	BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)	SFPP	Complaints allege that SFPP’s interstate rates are not just and reasonable. The FERC has held these complaints in abeyance pending conclusion of other pending SFPP proceedings. Request for hearing and for consolidation with other proceedings filed and pending before the FERC.

FERC Docket No. OR03-5-001	BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)	SFPP	The FERC severed the portions of the complaints in Docket Nos. OR03-5, OR05-4, and OR05-5 regarding SFPP’s North and Oregon Line rates into a separate proceeding in Docket No. OR03-5-001. The Presiding Judge issued a procedural schedule on October 18, 2007 setting a hearing on these issues for April 29, 2008. Requests for hearing, for certification of certain questions to the FERC, and for consolidation with other proceedings filed and pending before the FERC and the Presiding Judge.
FERC Docket No. OR07-1	Tesoro	SFPP	Complaint alleges that SFPP’s North Line rates are not just and reasonable. Complaint held in abeyance pending resolution at the D.C. Court of, among other things, income tax allowance and grandfathering issues. The D.C. Court issued an opinion on these issues on May 29, 2007, upholding the FERC’s income tax allowance policy.
FERC Docket No. OR07-2	Tesoro	SFPP	Complaint alleges that SFPP’s West Line rates are not just and reasonable. Complaint held in abeyance pending resolution at the D.C. Court of, among other things, income tax allowance and grandfathering issues. The D.C. Court issued an opinion on these issues on May 29, 2007, upholding the FERC’s income tax allowance policy. A request that the FERC set the complaint for hearing – which SFPP opposed – is pending before the FERC.
FERC Docket No. OR07-3	BP WCP; Chevron; ExxonMobil; Tesoro; and Valero Marketing	SFPP	Complaint alleges that SFPP’s North Line indexed rate increase was not just and reasonable. Complaint dismissed; requests for rehearing filed by Chevron, Tesoro and Valero. Petitions for review filed by BP WCP and ExxonMobil at the D.C. Court. Petitions for review held in abeyance.
FERC Docket No. OR07-4	BP WCP; Chevron; and ExxonMobil;	SFPP; Kinder Morgan G.P., Inc.; Kinder Morgan, Inc.	Complaint alleges that SFPP’s rates are not just and reasonable. Complaint held in abeyance pending resolution at the D.C. Court of, among other things, income tax allowance and grandfathering issues. The D.C. Court issued an opinion on these issues on May 29, 2007, upholding the FERC’s income tax allowance policy.

FERC Docket Nos. OR07-5 and OR07-7 (consolidated)	ExxonMobil Tesoro	Calnev; Kinder Morgan G.P., Inc.; Kinder Morgan, Inc.	Complaints allege that none of Calnev’s current rates are just or reasonable. In light of the D.C. Court’s May 29, 2007 ruling, on July 19, 2007, the FERC gave complainants 90 days to amend their complaints with respect to challenges against the pipeline’s grandfathered rates; accepted the complaints to the extent they challenge the rates in excess of the grandfathered rate; held the complaints in abeyance pending a FERC decision on any amended complaints; dismissed with prejudice the complaints against Kinder Morgan GP Inc. and Kinder Morgan Inc.; denied Tesoro’s request for consolidation with Docket No. IS06-296; and consolidated Docket Nos. OR07-5 and OR07-7. ExxonMobil filed a request for rehearing of the dismissal of the complaints against Kinder Morgan GP, Inc. and Kinder Morgan, Inc., which is currently pending before the FERC.
FERC Docket No. OR07-6	ConocoPhillips	SFPP	Complaint alleges that SFPP’s North Line indexed rate increase was not just and reasonable. Complaint dismissed.
FERC Docket No. OR07-8 (consolidated with Docket No. OR07-11)	BP WCP	SFPP	Complaint alleges that SFPP’s 2005 indexed rate increase was not just and reasonable. On June 6, 2007, the FERC dismissed challenges to SFPP’s underlying rate but held in abeyance the portion of the Complaint addressing SFPP’s July 1, 2005 index-based rate increases. SFPP requested rehearing on July 6, 2007.
FERC Docket No. OR07-9	BP WCP	SFPP	Complaint alleges that SFPP’s ultra low sulphur diesel (ULSD) recovery fee violates the filed rate doctrine and that, in any event, the recovery fee is unjust and urnreasonable. On July 6, 2007, the FERC dismissed the complaint.
FERC Docket No. OR07 10	BP WCP, ConocoPhillips, Valero, ExxonMobil	Calnev	Calnev filed a petition with the FERC on May 14, 2007, requesting that the FERC issue a declaratory order approving Calnev’s proposed rate methodology and granting other relief with respect to a substantial proposed expansion of Calnev’s mainline pipeline system. On July 20, 2007, the FERC granted Calnev’s petition for declaratory order.
FERC Docket No. OR07 11 (consolidated with Docket No. OR07-8)	ExxonMobil	SFPP	Complaint alleges that SFPP’s 2005 indexed rate increase was not just and reasonable. The FERC has not acted on this complaint, which is now consolidated with the complaint in Docket No. OR07-8.

FERC Docket No. OR07 14	BP WCP Chevron	SFPP, Calnev Operating Limited Partnership D, Kinder Morgan Energy Partners, L.P., Kinder Morgan Management LLC, Kinder Morgan General Partner, Inc., Kinder Morgan Inc., and Knight Holdco, LLC	Complaint alleges violations of the Interstate Commerce Act and FERC’s cash management regulations, seeks review of the FERC Form 6 annual reports of SFPP and Calnev, and again requests interim refunds and reparations. The FERC has not acted on this complaint.
FERC Docket No. OR07-16	Tesoro	Calnev	Complaint challenges Calnev’s 2005, 2006, and 2007 indexing adjustments. The FERC has not yet issued a decision regarding Tesoro’s complaint. Settlement discussions are ongoing, and a joint motion to hold this proceedings in abeyance is currently pending at FERC.
FERC Docket No. OR07-18	Airline Complainants Chevron Valero Marketing	Calnev	Complaint alleges that Calnev’s rates are unjust and unreasonable and that none of Calnev’s rates are grandfathered under EPAct 1992. The FERC has not acted on this complaint.
FERC Docket No. OR07-19	ConocoPhillips	Calnev	Complaint alleges that Calnev’s rates are unjust and unreasonable and that none of Calnev’s rates are grandfathered under EPAct 1992. The FERC has not acted on this complaint.
FERC Docket No. OR07-20	BP WCP	SFPP	Complaint alleges that SFPP’s 2007 indexed rate increase was not just and reasonable. The FERC has not acted on this complaint.
FERC Docket No. OR07-22	BP WCP	Calnev	Complaint alleges that Calnev’s rates are unjust and unreasonable and that none of Calnev’s rates are grandfathered under EPAct 1992. The FERC has not acted on this complaint.
FERC Docket No. IS05 230 (North Line rate case)	Shippers	SFPP	SFPP filed to increase North Line rates to reflect increased costs due to installation of new pipe between Concord and Sacramento, California. Various shippers protested. Administrative law judge decision pending before the FERC on exceptions. On August 31, 2007, BP WCP and ExxonMobil filed a motion to reopen the record on the issue of SFPP’s appropriate rate of return on equity, which SFPP answered. This motion is currently pending before FERC.

FERC Docket No. IS05 327	Shippers	SFPP	SFPP filed to increase certain rates on its pipelines pursuant to FERC’s indexing methodology. Various shippers protested, but FERC determined that the tariff filings were consistent with its regulations. The D.C. Court dismissed a petition for review, citing a lack of jurisdiction to review a decision by FERC not to order an investigation.
FERC Docket No. IS06-283 (East Line rate case)	Shippers	SFPP	SFPP filed to increase East Line rates to reflect increased costs due to installation of new pipe between El Paso, Texas and Tucson, Arizona. Various shippers protested. Procedural schedule suspended pending resolution at the D.C. Court of, among other things, income tax allowance and grandfathering issues. The D.C. Court issued an opinion on these issues on May 29, 2007, upholding the FERC’s income tax allowance policy. Because the Parties to this proceeding have reached agreement on a settlement in principle that will resolve all issues set for hearing in this case, the procedural schedule has been suspended.
FERC Docket No. IS06 296	ExxonMobil	Calnev	Calnev sought to increase its interstate rates pursuant to the FERC’s indexing methodology. ExxonMobil filed a protest respecting Calnev’s indexing adjustments. This proceeding is currently held in abeyance pending ongoing settlement discussions. Calnev has also filed a motion to dismiss, which has been protested and a procedural schedule is in place. Calnev’s motion to dismiss or to hold the investigation in abeyance is currently pending before the FERC.
FERC Docket No. IS06 356	Shippers	SFPP	SFPP filed to increase certain rates on its pipelines pursuant to FERC’s indexing methodology. Various shippers protested, but FERC found the tariff filings consistent with its regulations. FERC has rescinded the index increase for the East Line rates, and SFPP has requested rehearing. The D.C. Court dismissed a petition for review, citing the rehearing request pending before FERC. On September 20, 2007, the FERC denied SFPP’s request for rehearing.

FERC Docket No. IS07 137 (ULSD Surcharge)	Shippers	SFPP	SFPP filed tariffs to include a per - barrel ULSD recovery fee and a surcharge for ULSD-related litigation costs on diesel products. Various shippers protested. Tariffs accepted subject to refund and proceeding held in abeyance pending resolution of other proceedings involving SFPP. With no investigation established, SFPP rescinded the ULSD litigation surcharge in compliance with FERC order. Request for rehearing filed by Chevron and Tesoro.
FERC Docket No. IS07 229	BP WCP ExxonMobil	SFPP	SFPP filed to increase certain rates on its pipelines pursuant to FERC’s indexing methodology. Two shippers protested, but FERC found the tariff filings consistent with its regulations.
FERC Docket No. IS07 234	BP WCP ExxonMobil	Calnev	Calnev filed to increase certain rates on its pipeline pursuant to FERC’s indexing methodology. Two shippers protested, but FERC found the tariff filings consistent with its regulations.
Motions to compel payment of interim damages (Various dockets)	Shippers	SFPP, Kinder Morgan G.P., Inc., Kinder Morgan, Inc.	Proceeding seeks payment of interim damages or escrow of funds pending resolution of various complaints and protests involving SFPP. No FERC action on motions.

	Nine Months Ended September 30,
	2007			2006
Balance at beginning of period	$	50.3		$	43.2
Liabilities incurred		0.2			5.0
Liabilities settled		(0.6	)		(1.8	)
Accretion expense		2.0			1.9
Balance at end of period	$	51.9		$	48.3

	Products			Natural Gas					Trans
	Pipelines			Pipelines		CO₂			Mountain		Terminals			Total
Gross carrying amount	$	268.2		$	288.4	$	48.1		$	249.0	$	236.4		$	1,090.1
Accumulated amortization(a)		(5.0	)		—		(2.0	)		—		(7.1	)		(14.1	)
Net carrying amount	$	263.2		$	288.4	$	46.1		$	249.0	$	229.3		$	1,076.0

Derivatives-net asset/(liability)
Deferred charges and other assets	$	0.5
Accrued other current liabilities		(129.2	)
Other long-term liabilities and deferred credits	$	(169.6	)

Gasoline (MMBbl)	112.9	117.1	336.3	344.1
Diesel fuel (MMBbl)	43.0	42.2	124.5	120.2
Jet fuel (MMBbl)	31.9	30.0	94.0	89.4
Total refined product volumes (MMBbl)	187.8	189.3	554.8	553.7
Natural gas liquids (MMBbl)	13.5	13.0	41.3	42.4
Total delivery volumes (MMBbl)(e)	201.3	202.3	596.1	596.1

Three months ended September 30, 2007 versus Three months ended September 30, 2006
	EBDA				Revenues
	increase/(decrease)				increase/(decrease)
	(In millions, except percentages)
Cochin Pipeline System	$	11.9	1,090	%	$	9.7		133	%
North System		6.2	135	%		4.2		41	%
Plantation Pipeline		4.3	96	%		0.2		2	%
Pacific operations		4.1	6	%		1.7		2	%
West Coast Terminals		3.2	40	%		1.0		6	%
Transmix operations		1.1	18	%		1.6		17	%
All other (including eliminations)		7.4	26	%		(9.1	)	(16	)%
Total Products Pipelines	$	38.2	33	%	$	9.3		4	%

Nine months ended September 30, 2007 versus Nine months ended September 30, 2006
	EBDA				Revenues
	increase/(decrease)				increase/(decrease)
	(In millions, except percentages)
Cochin Pipeline System	$	18.7	182	%	$	27.9		104	%
North System		12.7	82	%		11.7		40	%
Plantation Pipeline		5.7	23	%		0.8		2	%
Pacific operations		8.6	5	%		17.6		7	%
West Coast Terminals		10.3	38	%		5.1		11	%
Transmix operations		6.2	38	%		8.4		36	%
All other (including eliminations)		12.4	14	%		(6.3	)	4	%
Total Products Pipelines	$	74.6	20	%	$	65.2		11	%

Carbon dioxide delivery volumes (Bcf)(b)		150.4		164.3		472.6		503.4
SACROC oil production (gross)(MBbl/d)(c)		27.3		30.3		28.4		30.8
SACROC oil production (net)(MBbl/d)(d)		22.8		25.3		23.6		25.7
Yates oil production (gross)(MBbl/d)(c)		27.1		26.3		26.7		25.9
Yates oil production (net)(MBbl/d)(d)		12.0		11.7		11.9		11.5
Natural gas liquids sales volumes (net)(MBbl/d)(d)		10.0		8.4		9.8		8.9
Realized weighted average oil price per Bbl(e)(f)	$	36.77	$	32.49	$	35.56	$	31.42
Realized weighted average natural gas liquids price per Bbl(f)(g)	$	53.68	$	47.68	$	48.66	$	44.82

	Three Months Ended Sept. 30,				Earnings
	2007		2006		increase/(decrease)
	(In millions-income (expense), except percentages)
General and administrative expenses(a)	$	(106.2)	$	(63.5)	$	(42.7)	(67	%)
Unallocable interest expense, net of interest income(b)		(103.5)		(91.3)		(12.2)	(13	%)
Minority interest		(2.4)		(2.1)		(0.3 )	(14	%)
Total interest and corporate administrative expenses	$	(212.1)	$	(156.9)	$	(55.2)	(35	%)

	Nine Months Ended Sept. 30,				Earnings
	2007		2006		increase/(decrease)
	(In millions-income (expense), except percentages)
General and administrative expenses(c)	$	(265.9)	$	(195.1)	$	(70.8)	(36	%)
Unallocable interest expense, net of interest income(d)		(293.6)		(254.8)		(38.8)	(15	%)
Minority interest		(4.4)		(8.1)		3.7)	46	%
Total interest and corporate administrative expenses	$	(563.9)	$	(458.0)	$	(105.9)	(23	%)

Capitalization:
Long-term debt, excluding value of interest rate swaps	54.3	%	42.7	%
Minority interest	0.5	%	0.6	%
Partners’ capital, excluding accumulated other comprehensive loss	45.2	%	56.7	%
	100.0	%	100.0	%

Invested Capital:
Total debt, less cash and cash equivalents and excluding
value of interest rate swaps	56.3	%	49.4	%
Partners’ capital and minority interest, excluding accumulated
Other comprehensive loss	43.7	%	50.6	%
	100.0	%	100.0	%

4.1 --	Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
4.2 --	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.85% Senior Notes due 2012.
10.1 --	Amendment No. 1 to Delegation of Control Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8 K on July 20, 2007 and incorporated herein by reference).
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.

	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
		(principal financial and accounting officer)
		Date: November 7, 2007