10-K

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

Form 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2007
	Or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from          to

Commission file number: 1-11234

Kinder Morgan Energy Partners, L.P.
(Exact name of registrant as specified in its charter)

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

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

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units	New York Stock Exchange

Securities registered Pursuant to Section 12(g) of the Act:
None

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes x  No o

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o  No x

          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 o

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

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          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

          Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 29, 2007 was approximately $8,185,538,074. As of January 31, 2008, the registrant had 170,224,734 Common Units outstanding.

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KINDER MORGAN ENERGY PARTNERS, L.P.

          TABLE OF CONTENTS

		Page Number
	PART I
Items 1 and 2.	Business and Properties	4
	General Development of Business	4
	Organizational Structure	4
	Recent Developments	5
	Financial Information about Segments	10
	Narrative Description of Business	10
	Business Strategy	10
	Business Segments	10
	Products Pipelines	11
	Natural Gas Pipelines	16
	CO2	24
	Terminals	29
	Trans Mountain	30
	Major Customers	31
	Regulation	31
	Environmental Matters	34
	Other	36
	Financial Information about Geographic Areas	36
	Available Information	36
Item 1A.	Risk Factors	37
Item 1B.	Unresolved Staff Comments	46
Item 3.	Legal Proceedings	46
Item 4.	Submission of Matters to a Vote of Security Holders	46
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	47
Item 6.	Selected Financial Data	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
	Critical Accounting Policies and Estimates	51
	Results of Operations	53
	Liquidity and Capital Resources	68
	Recent Accounting Pronouncements	77
	Information Regarding Forward-Looking Statements	77
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	79
	Energy Commodity Market Risk	79
	Interest Rate Risk	81
Item 8.	Financial Statements and Supplementary Data	82
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	82
Item 9A.	Controls and Procedures	83
Item 9B.	Other Information	83
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	84
	Directors and Executive Officers of our General Partner and its Delegate	84
	Corporate Governance	86
	Section 16(a) Beneficial Ownership Reporting Compliance	87
Item 11.	Executive Compensation	88
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	103
Item 13.	Certain Relationships and Related Transactions, and Director Independence	105
Item 14.	Principal Accounting Fees and Services	109
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	110
	Index to Financial Statements	114
Signatures		211

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PART I

Items 1 and 2. Business and Properties.

          In this report, unless the context requires otherwise, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., a Delaware limited partnership formed in August 1992, our operating limited partnerships and their subsidiaries. Our common units, which represent limited partner interests in us, trade on the New York Stock Exchange under the symbol “KMP.” The address of our principal executive offices is 500 Dallas, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000. You should read the following discussion and analysis in conjunction with our consolidated financial statements included elsewhere in this report. All dollars in this report are United States dollars, except where stated otherwise. Canadian dollars are designated as C$.

           (a) General Development of Business

          Organizational Structure

          Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America. We own an interest in or operate more than 25,000 miles of pipelines and approximately 165 terminals. Our pipelines transport natural gas, gasoline, crude oil, carbon dioxide and other products, and our terminals store petroleum products and chemicals and handle bulk materials like coal and petroleum coke. We are also the leading provider of carbon dioxide, commonly called “CO₂,” for enhanced oil recovery projects in North America. As one of the largest publicly traded pipeline limited partnerships in America, we have an enterprise value of approximately $20 billion.

          Our general partner is Kinder Morgan G.P., Inc., a Delaware corporation. 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.

          Knight Inc., a Kansas corporation and a private company formerly known as Kinder Morgan, Inc., indirectly is the sole owner of the common stock of our general partner. 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 generally each share of KMI common stock would be converted into the right to receive $107.50 in cash without interest. KMI in turn would merge with a wholly owned subsidiary of Knight Holdco LLC, a privately owned company in which Richard D. Kinder, Chairman and Chief Executive Officer of KMI, would be a major investor. On May 30, 2007, the merger closed, with KMI continuing as the surviving legal entity and subsequently renamed “Knight Inc.,” referred to as “Knight” in this report. Additional investors in Knight Holdco LLC include the following: other senior members of Knight 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); KMI 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. This transaction is referred to in this report as the “going-private transaction.”

          As of December 31, 2007, Knight and its consolidated subsidiaries owned, through its general and limited partner interests, an approximately 13.9% interest in us. In addition to the distributions it receives from its limited and general partner interests, Knight also receives an incentive distribution from us as a result of its ownership of our general partner. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to our unitholders exceed specified target levels as set forth in our partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit per quarter. Including both its general and limited partner interests in us, at the 2007 distribution level, Knight received approximately 49% of all quarterly “Available Cash” distributions (as defined in our partnership agreement) from us, with approximately 43% and 6% of all quarterly distributions from us attributable to Knight’s general partner and limited partner interests, respectively. The actual level of distributions Knight will receive in the future will vary with the level of distributions to our limited partners determined in accordance with our partnership agreement.

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          Kinder Morgan Management, LLC, referred to as “KMR” in this report, is a Delaware limited liability company formed in February 2001. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, our general partner has 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, except that KMR cannot take certain specified actions without the approval of our general partner. Under the delegation of control agreement, KMR, as the delegate of our general partner, manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR’s activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries.

          KMR’s shares represent limited liability company interests and trade on the New York Stock Exchange under the symbol “KMR.” Since its inception, KMR has used substantially all of the net proceeds received from the public offerings of its shares to purchase i-units from us. The i-units are a separate class of limited partner interests in us and are issued only to KMR. Under the terms of our partnership agreement, the holders of our i-units are entitled to vote on all matters on which the holders of our common units are entitled to vote.

          In general, our limited partner units, consisting of i-units, common units and Class B units (the Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange), will vote together as a single class, with each i-unit, common unit and Class B unit having one vote. We pay our quarterly distributions from operations and interim capital transactions to our common and Class B unitholders in cash, and we pay our quarterly distributions to KMR in additional i-units rather than in cash. As of December 31, 2007, KMR, through its ownership of our i-units, owned approximately 29.2% of all of our outstanding limited partner units.

          Recent Developments

          The following is a brief listing of significant developments since December 31, 2006. Additional information regarding most of these items may be found elsewhere in this report.

•	Effective January 1, 2007, we acquired the remaining approximate 50.2% interest in the Cochin pipeline system that we did not already own from affiliates of BP 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;
•	On January 17, 2007, we announced that our CO2 business segment will invest approximately $120 million to further expand its operations and enable it to meet the increased demand for carbon dioxide in the Permian Basin. The expansion activities will take place in southwest Colorado and include developing a new carbon dioxide source field (named the Doe Canyon Deep Unit that went in service during the first quarter of 2008) and adding infrastructure at both the McElmo Dome Unit and the Cortez Pipeline. The entire expansion is expected to be completed by the middle of 2008;
•	On January 30, 2007, we completed a public offering of senior notes. We issued a total of $1.0 billion in principal amount of senior notes, consisting of $600 million of 6.00% notes due February 1, 2017, and $400 million of 6.50% notes due February 1, 2037. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $992.8 million, and we used the proceeds to reduce the borrowings under our commercial paper program;
•	On February 14, 2007, the first phase of the Rockies Express pipeline system, the 327-mile REX-Entrega Project, was placed in service at a cost of approximately $745 million and provided up to 500 million cubic feet of natural gas capacity from the Meeker Hub in Rio Blanco County, Colorado and Wamsutter Hub in Sweetwater County, Wyoming to the Cheyenne Hub in Weld County, Colorado.
	The Rockies Express pipeline project is an approximate $4.9 billion, 1,679-mile natural gas pipeline system which is owned and currently being developed by Rockies Express Pipeline LLC. The Rockies Express

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pipeline project is to be completed in three phases: (i) a 327-mile, $745 million pipeline running from the Meeker Hub to the Cheyenne Hub with a nominal capacity of 500 million cubic feet per day; (ii) a 713-mile, $1.6 billion pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri, transporting up to 1.5 billion cubic feet per day; and (iii) a 639-mile, $2.6 billion pipeline from Audrain County, Missouri to Clarington, located in Monroe County, Ohio. When fully completed, the Rockies Express pipeline system will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for all of the pipeline capacity. On January 12, 2008, interim service on the REX-West Project (second phase) commenced. Full service on the REX-West system for 1.5 billion cubic feet per day of contracted capacity is expected to commence in mid-March 2008. See “—(c) Narrative Description of Business—Business Segments—Natural Gas Pipelines—Rockies Express Pipeline” for more information;

• On February 28, 2007, we announced plans to invest up to $100 million to expand our liquids terminal facilities in order to help serve the growing biodiesel market. We entered into long-term agreements as lessors with Green Earth Fuels, LLC to build tankage that will handle biodiesel at our Houston Ship Channel liquids facility. Green Earth Fuels completed construction of an 86 million gallon biodiesel production facility at our Galena Park, Texas liquids terminal in the fourth quarter of 2007;

• On April 30, 2007, we acquired the Trans Mountain pipeline system from Knight for $549.1 million. 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, currently transports approximately 260,000 barrels per day. An additional expansion that will increase capacity of the pipeline to 300,000 barrels per day is expected to be in service by November 2008. Current accounting principles require our consolidated financial statements and all other financial information included in this report to be stated 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 to reflect our acquisition. 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. For additional information regarding this acquisition, see Note 3 to our consolidated financial statements;

• On May 14, 2007, we announced plans to construct a $72 million natural gas pipeline designed to bring new supplies out of East Texas to markets in the Houston and Beaumont, Texas areas. The new pipeline will consist of approximately 63 miles of 24-inch diameter pipe and multiple interconnections with other pipelines. It will connect our Kinder Morgan Tejas system in Harris County, Texas to our Kinder Morgan Texas Pipeline system in Polk County near Goodrich, Texas. In addition, we entered into a long-term binding agreement with CenterPoint Energy Services, Inc. to provide firm transportation for a significant portion of the initial project capacity, which will consist of approximately 225 million cubic feet per day of natural gas using existing compression and be expandable to over 400 million cubic feet per day with additional compression;

• On May 17, 2007, KMR closed the public offering of 5,700,000 of its shares at a price of $52.26 per share. The net proceeds from the offering were used by KMR to buy additional i-units from us. We used the proceeds of $297.9 million from our i-unit issuance to reduce the borrowings under our commercial paper program;

• 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 $57.2 million, consisting of $38.8 million in cash and $18.4 million in assumed liabilities. 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;

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• On June 21, 2007, we closed a public offering of $550 million in principal amount of 6.95% senior notes. The notes are due January 15, 2038. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $543.9 million, and we used the proceeds to reduce our commercial paper debt;

• On June 22, 2007, the Federal Energy Regulatory Commission, referred to in this report as the FERC, issued an order granting construction and operation of our Kinder Morgan Louisiana Pipeline project, and we officially accepted the order on July 10, 2007. The Kinder Morgan Louisiana Pipeline is expected to cost approximately $510 million and will provide approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal, located in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including Natural Gas Pipeline Company of America. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total and is expected to be in service by January 1, 2009;

• On July 10, 2007, we announced a combined $41 million investment for two terminal expansions to help meet the growing need for terminal services in key markets along the Gulf Coast. The investment consists of (i) the construction of a terminal that will include liquids storage, transfer and packaging facilities at the Rubicon Plant site in Geismar, Louisiana; and (ii) the purchase of liquids storage tanks from Royal Vopak in Westwego, Louisiana. The tanks have a storage capacity of approximately 750,000 barrels for vegetable oil, biodiesel, ethanol and other liquids products. The new terminal being built in Geismar will be capable of handling inbound and outbound material via pipeline, rail, truck and barge/vessel. Construction is expected to be complete by the fourth quarter of 2008;

• On July 23, 2007, following the FERC’s expedited approval of our CALNEV Pipeline’s proposed tariff rate structure, we announced our continuing development of the approximate $426 million expansion of the pipeline system into Las Vegas, Nevada. The expansion involves the construction of a new 16-inch diameter pipeline, which will parallel existing utility corridors between Colton, California and Las Vegas in order to minimize environmental impacts. System capacity would increase to approximately 200,000 barrels per day upon completion of the expansion, and could be increased as necessary to over 300,000 barrels per day with the addition of pump stations. The CALNEV expansion is expected to be complete in early 2011;

• On August 6, 2007, Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, filed for regulatory approval to construct and operate a 41-mile, $29 million natural gas pipeline from the Cheyenne Hub to markets in and around Greeley, Colorado. When completed, the Colorado Lateral expansion project will provide firm transportation of up to 55 million cubic feet per day to a local utility under long-term contract. On February 21, 2008, the FERC granted the certification application;

• On August 23, 2007, we announced that we have begun construction on the approximately C$467 million  Anchor Loop project, the second phase of the Trans Mountain pipeline system expansion that will increase pipeline capacity from approximately 260,000 to 300,000 barrels of crude oil per day. The project is expected to be complete in November 2008. In April 2007, we commissioned 10 new pump stations which boosted capacity on Trans Mountain from 225,000 to approximately 260,000 barrels per day. The pipeline is currently operating at full capacity;

• On August 28, 2007, we closed a public offering of $500 million in principal amount of 5.85% senior notes. The notes are 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 our commercial paper debt;

• Effective September 1, 2007, we acquired five bulk terminal facilities from Marine Terminals, Inc. for an aggregate consideration of approximately $101.5 million, consisting of $100.3 million in cash and an assumed liability of $1.2 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 are located in Blytheville, Arkansas; Decatur, Alabama; Hertford, North Carolina; and Berkley, South Carolina. Combined, the five

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facilities handled approximately 13.7 million tons of steel products in 2007. 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;

• Effective October 5, 2007, we sold our North System natural gas liquids and refined petroleum products pipeline system and our 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6 million in cash. Our investment in net assets, including all transaction related accruals, was approximately $145.8 million, most of which represented property, plant and equipment, and we recognized approximately $152.8 million of gain on the sale of these net assets. In accordance with generally accepted accounting principles, we accounted for the North System business as a discontinued operation for all periods presented in this report, and we reported the gain with the caption as “Gain on disposal of North System” on our accompanying consolidated statement of income;

• On October 9, 2007, 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. We own a 50% interest in Midcontinent Express Pipeline LLC and Energy Transfer Partners L.P. owns the remaining interest. The Midcontinent Express Pipeline will create long-haul, firm natural gas transportation takeaway capacity, either directly or indirectly, from natural gas producing regions located in Texas, Oklahoma and Arkansas. The total project is expected to cost approximately $1.3 billion, and will have an initial transportation capacity of approximately 1.4 billion cubic feet per day of natural gas.

The Midcontinent Express Pipeline will originate near Bennington, Oklahoma and terminate at an interconnect with Williams’ Transco natural gas pipeline system near Butler, Alabama. It will also connect to Natural Gas Pipeline Company of America’s natural gas pipeline and to Energy Transfer Partners’ 135-mile natural gas pipeline, which extends from the Barnett Shale natural gas producing area in North Texas to an interconnect with the Texoma Pipeline near Paris, Texas. The Midcontinent Express Pipeline now has long-term binding commitments from multiple shippers for approximately 1.2 billion cubic feet per day and, in order to provide a seamless transportation path from various locations in Oklahoma, the pipeline has also executed a firm capacity lease agreement with Enogex, Inc., an Oklahoma-based intrastate natural gas gathering and pipeline company that is wholly-owned by OGE Energy Corp. 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.

In January 2008, in conjunction with the signing of additional binding transportation commitments, Midcontinent Express and MarkWest entered into an option agreement which provides MarkWest a one-time right to purchase a 10% ownership interest in Midcontinent Express after the pipeline is fully constructed and placed into service. If the option is exercised, we and Energy Transfer Partners will each own 45% of Midcontinent Express, while MarkWest will own the remaining 10%;

• On October 17, 2007, we announced that we will invest approximately $23 million to expand our Kinder Morgan Interstate Gas Transmission pipeline system in order to serve five separate industrial plants (four of which produce ethanol) near Grand Island, Nebraska. The project is fully subscribed with long-term customer contracts, and subject to the receipt of regulatory approvals filed December 21, 2007, the expansion project is expected to be fully operational by the fall of 2008. Since 2000, our KMIGT system has connected to 17 new ethanol plants, 11 of which are located in the state of Nebraska;

• On November 26, 2007, we announced that we expect to declare cash distributions of $4.02 per unit for 2008, an almost 16% increase over our cash distributions of $3.48 per unit for 2007. This expectation includes contributions from assets owned by us as of the announcement date and does not include any potential benefits from unidentified acquisitions. Additionally, our expectation does not take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’

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interstate pipelines. Our expected growth in distributions in 2008 will be fueled by incremental earnings from Rockies Express-West (the western portion of the Rockies Express Pipeline), higher hedge prices on our

crude oil production (budgeted production volumes for the SACROC oil field unit in 2008 are approximately equal to the volumes realized in 2007), and an anticipated strong performance from our remaining business portfolio;

• In December 2007, we completed a public offering of 7,130,000 of our common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $48.09 per unit, less commissions and underwriting expenses. We received net proceeds of $342.9 million for the issuance of these 7,130,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program;

• In December 2007, we completed a second expansion of our Pacific operations’ East Line pipeline segment. This expansion consisted of replacing approximately 130 miles of 12-inch diameter pipe between El Paso, Texas and Tucson, Arizona with new 16-inch diameter pipe, constructing additional pump stations, and adding new storage tanks at Tucson. The project, completed at a cost of approximately $154 million, will increase East Line capacity by 36% (to approximately 200,000 barrels per day) to meet the demand for refined petroleum products, and will provide the platform for further incremental expansions through horsepower additions to the system;

• On December 31, 2007, TransColorado Gas Transmission LLC completed an approximate $50 million expansion to provide up to 250 million cubic feet per day of natural gas transportation, starting January 1, 2008, from the Blanco Hub to an interconnect with the Rockies Express pipeline system at the Meeker Hub;

• During 2007, we spent $1,691.6 million for additions to our property, plant and equipment, including both expansion and maintenance projects. Our capital expenditures included the following:

•	$480.0 million in our Terminals segment, largely related to expanding the petroleum products storage capacity at our liquids terminal facilities, including the construction of additional liquids storage tanks at our facilities in Canada and at our facilities located on the Houston Ship Channel and the New York Harbor, and to various expansion projects and improvements undertaken at multiple terminal facilities;
•	$382.5 million in our CO2 segment, mostly related to additional infrastructure, including wells and injection and compression facilities, to support the expanding carbon dioxide flooding operations at the SACROC and Yates oil field units in West Texas and to expand our capacity to produce and deliver CO2 from our McElmo Dome and Doe Canyon Source Fields;
•	$305.7 million in our Trans Mountain segment, mostly related to pipeline expansion and improvement projects undertaken to increase crude oil and refined products delivery volumes;
•	$264.0 million in our Natural Gas Pipelines segment, mostly related to current construction of our Kinder Morgan Louisiana Pipeline and to various expansion and improvement projects on our Texas intrastate natural gas pipeline systems, including the development of additional natural gas storage capacity at our natural gas storage facilities located at Markham and Dayton, Texas; and
•	$259.4 million in our Products Pipelines segment, mostly related to the continued expansion work on our Pacific operations’ East Line products pipeline, completion of construction projects resulting in additional capacity, and an additional refined products line on our CALNEV Pipeline in order to increase delivery service to the growing Las Vegas, Nevada market;
Our capital expansion program in 2007 was approximately $2.6 billion (including our share of capital expenditures for both the Rockies Express and Midcontinent Express natural gas pipeline projects). Including all of our business acquisition expenditures, total spending was $3.3 billion. Our capital expansion program will continue to be significant in 2008, as we expect to invest approximately $3.3 billion in expansion capital expenditures (including our share of capital expenditures for both the Rockies Express and Midcontinent Express natural gas pipeline projects), which will help drive earnings and cash flow growth in 2009 and beyond;

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• On January 16, 2008, we announced that we plan to invest approximately $56 million to construct a petroleum coke terminal at the BP refinery located in Whiting, Indiana. We have entered into a long-term contract to build and operate the facility, which will handle approximately 2.2 million tons of petroleum coke per year from a coker unit BP plans to construct to process heavy crude oil from Canada. The facility is expected to be in service in mid-year 2011;

• On February 12, 2008, we completed an additional public offering of senior notes. We issued a total of $900 million in principal amount of senior notes, consisting of $600 million of 5.95% notes due February 15, 2018, and $300 million of 6.95% notes due January 15, 2038. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $894.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program; and

• On February 12, 2008, we completed an additional offering of 1,080,000 of our common units at a price of $55.65 per unit in a privately negotiated transaction. We received net proceeds of $60.1 million for the issuance of these 1,080,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

           (b) Financial Information about Segments

          For financial information on our five reportable business segments, see Note 15 to our consolidated financial statements.

           (c) Narrative Description of Business

           Business Strategy

          The objective of our business strategy is to grow our portfolio of businesses by:

• focusing on stable, fee-based energy transportation and storage assets that are core to the energy infrastructure of growing markets within North America;

• increasing utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;

• leveraging economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are accretive to cash flow and earnings; and

• maximizing the benefits of our financial structure to create and return value to our unitholders.

          Business Segments

          We own and manage a diversified portfolio of energy transportation and storage assets. Our operations are conducted through our five operating limited partnerships and their subsidiaries and are grouped into five reportable business segments. These segments are as follows:

• Products Pipelines—which consists of approximately 8,300 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;

• Natural Gas Pipelines—which consists of approximately 14,700 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;

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• CO₂— which produces, markets and transports, through approximately 1,300 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates ten oil fields in West Texas; and owns and operates a 450 mile crude oil pipeline system in West Texas;

• Terminals—which consists of approximately 108 owned or operated liquids and bulk terminal facilities and more than 45 rail transloading and materials handling facilities located throughout the United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and

• Trans Mountain—which consists of over 700 miles of common carrier pipelines, originating at Edmonton, Alberta, for the transportation of crude oil and refined petroleum to the interior of British Columbia and to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington State; plus five associated product terminals.

          Generally, as utilization of our pipelines and terminals increases, our fee-based revenues increase. We do not face significant risks relating directly to short-term movements in commodity prices for two principal reasons. First, we primarily transport and/or handle products for a fee and are not engaged in significant unmatched purchases and resales of commodity products. Second, in those areas of our business where we do face exposure to fluctuations in commodity prices, primarily oil production in our CO₂ business segment, we engage in a hedging program to mitigate this exposure.

          We regularly consider and enter into discussions regarding potential acquisitions, including those from Knight or its affiliates, and are currently contemplating potential acquisitions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions and approval of the parties’ respective boards of directors. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.

          It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A “Risk Factors” below, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.

          Products Pipelines

          Our Products Pipelines segment consists of our refined petroleum products and natural gas liquids pipelines and their associated terminals, our Southeast terminals and our transmix processing facilities.

          Pacific Operations

          Our Pacific operations include our SFPP, L.P. operations, our CALNEV Pipeline operations and our West Coast Liquid Terminals operations. The assets include interstate common carrier pipelines regulated by the FERC, intrastate pipelines in the state of California regulated by the California Public Utilities Commission, and certain non rate-regulated operations and terminal facilities.

          Our Pacific operations serve seven western states with approximately 3,000 miles of refined petroleum products pipelines and related terminal facilities that provide refined products to some of the fastest growing population centers in the United States, including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. For 2007, the three main product types transported were gasoline (59%), diesel fuel (23%) and jet fuel (18%).

          Our Pacific operations also includes CALNEV Pipeline which consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from our facilities at Colton, California to Las Vegas, Nevada, and which also serves Nellis Air Force Base located in Las Vegas. It also includes approximately 55 miles of pipeline serving Edwards Air Force Base.

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          Our Pacific operations include 15 truck-loading terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate usable tankage capacity of approximately 13.7 million barrels. The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and oxygenate blending.

          Our Pacific operation’s West Coast Liquid Terminals are fee-based terminals located in the Seattle, Portland, San Francisco and Los Angeles areas along the west coast of the United States with a combined total capacity of approximately 8.3 million barrels of storage for both petroleum products and chemicals.

          Markets. Combined, our Pacific operations’ pipelines transport approximately 1.3 million barrels per day of refined petroleum products, providing pipeline service to approximately 31 customer-owned terminals, 11 commercial airports and 14 military bases. Currently, our Pacific operations’ pipelines serve approximately 100 shippers in the refined petroleum products market; the largest customers being major petroleum companies, independent refiners, and the United States military.

          A substantial portion of the product volume transported is gasoline. Demand for gasoline depends on such factors as prevailing economic conditions, vehicular use patterns and demographic changes in the markets served. If current trends continue, we expect the majority of our Pacific operations’ markets to maintain growth rates that will exceed the national average for the foreseeable future. The volume of products transported is affected by various factors, principally demographic growth, economic conditions, product pricing, vehicle miles traveled, population and fleet mileage. Certain product volumes can experience seasonal variations and, consequently, overall volumes may be lower during the first and fourth quarters of each year.

          Supply. The majority of refined products supplied to our Pacific operations’ pipeline system come from the major refining centers around Los Angeles, San Francisco, El Paso and Puget Sound, as well as from waterborne terminals and connecting pipelines located near these refining centers.

          Competition. The two most significant competitors of our Pacific operations’ pipeline system are proprietary pipelines owned and operated by major oil companies in the area where our pipeline system delivers products and also refineries with terminals that have trucking arrangements within our market areas. We believe that high capital costs, tariff regulation, and environmental and right-of-way permitting considerations make it unlikely that a competing pipeline system comparable in size and scope to our Pacific operations will be built in the foreseeable future. However, the possibility of individual pipelines being constructed or expanded to serve specific markets is a continuing competitive factor.

          The use of trucks for product distribution from either shipper-owned proprietary terminals or from their refining centers continues to compete for short haul movements by pipeline. Our Pacific terminal operations compete with terminals owned by our shippers and by third party terminal operators in California, Arizona and Nevada. Competitors include Shell Oil Products U.S., BP (formerly Arco Terminal Services Company), Wilmington Liquid Bulk Terminals (Vopak), NuStar, and Chevron. We cannot predict with any certainty whether the use of short haul trucking will decrease or increase in the future.

          Plantation Pipe Line Company

          We own approximately 51% of Plantation Pipe Line Company, referred to in this report as Plantation, a 3,100-mile refined petroleum products pipeline system serving the southeastern United States. An affiliate of ExxonMobil owns the remaining 49% ownership interest. ExxonMobil is the largest shipper on the Plantation system both in terms of volumes and revenues. We operate the system pursuant to agreements with Plantation Services LLC and Plantation. Plantation serves as a common carrier of refined petroleum products to various metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area.

          For the year 2007, Plantation delivered an average of 535,672 barrels per day of refined petroleum products. These delivered volumes were comprised of gasoline (63%), diesel/heating oil (23%) and jet fuel (14%). Average delivery volumes for 2007 were 3.5% lower than the 555,063 barrels per day delivered during 2006. The decrease was predominantly driven by (i) the full year impact of alternative pipeline service (initial startup mid-2006) into Southeast markets, and (ii) changes in production patterns from Louisiana refineries related to refiners directing

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higher margin products (such as reformulated gasoline blendstock for oxygenate blending) into markets not directly served by Plantation.

          Markets. Plantation ships products for approximately 30 companies to terminals throughout the southeastern United States. Plantation’s principal customers are Gulf Coast refining and marketing companies, fuel wholesalers, and the United States Department of Defense. Plantation’s top five shippers represent approximately 80% of total system volumes.

          The eight states in which Plantation operates represent a collective pipeline demand of approximately two million barrels per day of refined petroleum products. Plantation currently has direct access to about 1.5 million barrels per day of this overall market. The remaining 0.5 million barrels per day of demand lies in markets (e.g., Nashville, Tennessee; North Augusta, South Carolina; Bainbridge, Georgia; and Selma, North Carolina) currently served by another pipeline company. Plantation also delivers jet fuel to the Atlanta, Georgia; Charlotte, North Carolina; and Washington, D.C. airports (Ronald Reagan National and Dulles). Combined jet fuel shipments to these four major airports increased 3% in 2007 compared to 2006, with the majority of this growth occurring at Dulles Airport.

          Supply. Products shipped on Plantation originate at various Gulf Coast refineries from which major integrated oil companies and independent refineries and wholesalers ship refined petroleum products. Plantation is directly connected to and supplied by a total of ten major refineries representing approximately 2.3 million barrels per day of refining capacity.

          Competition. Plantation competes primarily with the Colonial pipeline system, which also runs from Gulf Coast refineries throughout the southeastern United States and extends into the northeastern states.

          Central Florida Pipeline

          Our Central Florida pipeline system consists of a 110-mile, 16-inch diameter pipeline that transports gasoline and an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando, with an intermediate delivery point on the 10-inch pipeline at Intercession City, Florida. In addition to being connected to our Tampa terminal, the pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, BP, and Marathon Petroleum. The 10-inch diameter pipeline is connected to our Taft, Florida terminal (located near Orlando) and is also the sole pipeline supplying jet fuel to the Orlando International Airport in Orlando, Florida. In 2007, the pipeline system transported approximately 113,800 barrels per day of refined products, with the product mix being approximately 69% gasoline, 12% diesel fuel, and 19% jet fuel.

          We also own and operate liquids terminals in Tampa and Taft, Florida. The Tampa terminal contains approximately 1.5 million barrels of storage capacity and is connected to two ship dock facilities in the Port of Tampa. The Tampa terminal provides storage for gasoline, diesel fuel and jet fuel for further movement into either trucks or into the Central Florida pipeline system. The Tampa terminal also provides storage and truck rack blending services for ethanol and bio-diesel. The Taft terminal contains approximately 0.7 million barrels of storage capacity, for gasoline and diesel fuel for further movement into trucks.

          Markets. The estimated total refined petroleum products demand in the state of Florida is approximately 800,000 barrels per day. Gasoline is, by far, the largest component of that demand at approximately 545,000 barrels per day. The total refined petroleum products demand for the Central Florida region of the state, which includes the Tampa and Orlando markets, is estimated to be approximately 360,000 barrels per day, or 45% of the consumption of refined products in the state. We distribute approximately 150,000 barrels of refined petroleum products per day, including the Tampa terminal truck loadings. The balance of the market is supplied primarily by trucking firms and marine transportation firms. Most of the jet fuel used at Orlando International Airport is moved through our Tampa terminal and the Central Florida pipeline system. The market in Central Florida is seasonal, with demand peaks in March and April during spring break and again in the summer vacation season, and is also heavily influenced by tourism, with Disney World and other attractions located near Orlando.

          Supply. The vast majority of refined petroleum products consumed in Florida is supplied via marine vessels from major refining centers in the Gulf Coast of Louisiana and Mississippi and refineries in the Caribbean basin. A

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lesser amount of refined petroleum products is being supplied by refineries in Alabama and by Texas Gulf Coast refineries via marine vessels and through pipeline networks that extend to Bainbridge, Georgia. The supply into Florida is generally transported by ocean-going vessels to the larger metropolitan ports, such as Tampa, Port Everglades near Miami, and Jacksonville. Individual markets are then supplied from terminals at these ports and other smaller ports, predominately by trucks, except the Central Florida region, which is served by a combination of trucks and pipelines.

          Competition. With respect to the Central Florida pipeline system, the most significant competitors are trucking firms and marine transportation firms. Trucking transportation is more competitive in serving markets close to the marine terminals on the east and west coasts of Florida. We are utilizing tariff incentives to attract volumes to the pipeline that might otherwise enter the Orlando market area by truck from Tampa or by marine vessel into Cape Canaveral. We believe it is unlikely that a new pipeline system comparable in size and scope to our Central Florida Pipeline system will be constructed, due to the high cost of pipeline construction, tariff regulation and environmental and right-of-way permitting in Florida. However, the possibility of such a pipeline or a smaller capacity pipeline being built is a continuing competitive factor.

          With respect to the terminal operations at Tampa, the most significant competitors are proprietary terminals owned and operated by major oil companies, such as Marathon Petroleum, BP and Citgo, located along the Port of Tampa, and the Chevron and Motiva terminals in Port Tampa. These terminals generally support the storage requirements of their parent or affiliated companies’ refining and marketing operations and provide a mechanism for an oil company to enter into exchange contracts with third parties to serve its storage needs in markets where the oil company may not have terminal assets.

          Federal regulation of marine vessels, including the requirement under the Jones Act that United States-flagged vessels contain double-hulls, is a significant factor influencing the availability of vessels that transport refined petroleum products. Marine vessel owners are phasing in the requirement based on the age of the vessel and some older vessels are being redeployed into use in other jurisdictions rather than being retrofitted with a double-hull for use in the United States.

          Cochin Pipeline System

          Our Cochin pipeline system consists of an approximate 1,900-mile, 12-inch diameter multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor, Ontario, including five terminals.

          The pipeline operates on a batched basis and has an estimated system capacity of approximately 70,000 barrels per day. It includes 31 pump stations spaced at 60 mile intervals and five United States propane terminals. Underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario through third parties. In 2007, the pipeline system transported approximately 40,600 barrels per day of natural gas liquids.

          Markets. The pipeline traverses three provinces in Canada and seven states in the United States transporting high vapor pressure ethane, propane, butane and natural gas liquids to the Midwestern United States and eastern Canadian petrochemical and fuel markets. Current operations involve only the transportation of propane on Cochin.

          Supply. Injection into the system can occur from BP, Provident, Keyera or Dow facilities with connections at Fort Saskatchewan, Alberta and from Spectra at interconnects at Regina and Richardson, Saskatchewan.

          Competition. The pipeline competes with railcars and Enbridge Energy Partners for natural gas liquids long-haul business from Fort Saskatchewan, Alberta and Windsor, Ontario. The pipeline’s primary competition in the Chicago natural gas liquids market comes from the combination of the Alliance pipeline system, which brings unprocessed gas into the United States from Canada, and from Aux Sable, which processes and markets the natural gas liquids in the Chicago market.

          Cypress Pipeline

          Our Cypress pipeline is an interstate common carrier natural gas liquids pipeline originating at storage facilities in Mont Belvieu, Texas and extending 104 miles east to a major petrochemical producer in the Lake Charles,

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Louisiana area. Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for natural gas liquids gathering, transportation, fractionation and storage in the United States.

          Markets. The pipeline was built to service Westlake Petrochemicals Corporation in the Lake Charles, Louisiana area under a 20-year ship-or-pay agreement that expires in 2011. The contract requires a minimum volume of 30,000 barrels per day.

          Supply. The Cypress pipeline originates in Mont Belvieu where it is able to receive ethane and ethane/propane mix from local storage facilities. Mont Belvieu has facilities to fractionate natural gas liquids received from several pipelines into ethane and other components. Additionally, pipeline systems that transport natural gas liquids from major producing areas in Texas, New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and ethane/propane mix to Mont Belvieu.

          Competition. The pipeline’s primary competition into the Lake Charles market comes from Louisiana onshore and offshore natural gas liquids.

          Southeast Terminals

          Our Southeast terminal operations consist of Kinder Morgan Southeast Terminals LLC and its consolidated affiliate, Guilford County Terminal Company, LLC. Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to in this report as KMST, was formed for the purpose of acquiring and operating high-quality liquid petroleum products terminals located primarily along the Plantation/Colonial pipeline corridor in the Southeastern United States.

          Combined, our Southeast terminal operations consist of 24 petroleum products terminals with a total storage capacity of approximately 8.0 million barrels. These terminals transferred approximately 361,000 barrels of refined products per day during 2007 and approximately 347,000 barrels of refined products per day during 2006.

          Markets. KMST’s acquisition and marketing activities are focused on the Southeastern United States from Mississippi through Virginia, including Tennessee. The primary function involves the receipt of petroleum products from common carrier pipelines, short-term storage in terminal tankage, and subsequent loading onto tank trucks. KMST also offered ethanol blending and storage services in northern Virginia during 2007. Longer term storage is available at many of the terminals. KMST has a physical presence in markets representing almost 80% of the pipeline-supplied demand in the Southeast and offers a competitive alternative to marketers seeking a relationship with a truly independent truck terminal service provider.

          Supply. Product supply is predominately from Plantation and/or Colonial pipelines. To the maximum extent practicable, we endeavor to connect KMST terminals to both Plantation and Colonial.

          Competition. There are relatively few independent terminal operators in the Southeast. Most of the refined petroleum products terminals in this region are owned by large oil companies (BP, Motiva, Citgo, Marathon, and Chevron) who use these assets to support their own proprietary market demands as well as product exchange activity. These oil companies are not generally seeking third party throughput customers. Magellan Midstream Partners and TransMontaigne Product Services represent the other significant independent terminal operators in this region.

          Transmix Operations

          Our Transmix operations include the processing of petroleum pipeline transmix, a blend of dissimilar refined petroleum products that have become co-mingled in the pipeline transportation process. During pipeline transportation, different products are transported through the pipelines abutting each other, and generate a volume of different mixed products called transmix. At our transmix processing facilities, we process and separate pipeline transmix into pipeline-quality gasoline and light distillate products. We process transmix at six separate processing facilities located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina. Combined, our transmix facilities processed approximately 10.4 million barrels of transmix in 2007 and approximately 9.1 million barrels in 2006.

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          In 2007, we increased the processing capacity of the recently constructed Greensboro, North Carolina transmix facility to better serve the needs of Plantation. The facility, which is located within KMST’s refined products tank farm, now has the capability to process approximately 8,500 barrels of transmix per day. In addition to providing additional processing business, the facility continues to provide Plantation a lower cost alternative compared to other transmix processing arrangements that recover ultra low sulfur diesel, and also more fully utilizes current KMST tankage at the Greensboro, North Carolina tank farm.

          Markets. The Gulf and East Coast refined petroleum products distribution system, particularly the Mid-Atlantic region, is the target market for our East Coast transmix processing operations. The Mid-Continent area and the New York Harbor are the target markets for our Illinois and Pennsylvania assets, respectively. Our West Coast transmix processing operations support the markets served by our Pacific operations in Southern California.

          Supply. Transmix generated by Plantation, Colonial, Explorer, Sun, Teppco, and our Pacific operations provide the vast majority of the supply. These suppliers are committed to the use of our transmix facilities under long-term contracts. Individual shippers and terminal operators provide additional supply. Shell acquires transmix for processing at Indianola, Richmond and Wood River; Colton is supplied by pipeline shippers of our Pacific operations; Dorsey Junction is supplied by Colonial Pipeline Company and Greensboro is supplied by Plantation.

          Competition. Placid Refining is our main competitor in the Gulf Coast area. There are various processors in the Mid-Continent area, primarily ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete with our transmix facilities. Motiva Enterprises’s transmix facility located near Linden, New Jersey is the principal competition for New York Harbor transmix supply and for our Indianola facility. A number of smaller organizations operate transmix processing facilities in the West and Southwest. These operations compete for supply that we envision as the basis for growth in the West and Southwest. Our Colton processing facility also competes with major oil company refineries in California.

          Natural Gas Pipelines

          Our Natural Gas Pipelines segment contains both interstate and intrastate pipelines. Its primary businesses consist of natural gas sales, transportation, storage, gathering, processing and treating. Within this segment, we own approximately 14,700 miles of natural gas pipelines and associated storage and supply lines that are strategically located at the center of the North American pipeline grid. Our transportation network provides access to the major gas supply areas in the western United States, Texas and the Midwest, as well as major consumer markets.

          Texas Intrastate Natural Gas Pipeline Group

          The group, which operates primarily along the Texas Gulf Coast, consists of the following four natural gas pipeline systems:

• our Kinder Morgan Texas Pipeline;

• our Kinder Morgan Tejas Pipeline;

• our Mier-Monterrey Mexico Pipeline; and

• our Kinder Morgan North Texas Pipeline.

          The two largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder Morgan Tejas Pipeline. These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability. The combined system includes approximately 6,000 miles of intrastate natural gas pipelines with a peak transport and sales capacity of approximately 5.2 billion cubic feet per day of natural gas and approximately 120 billion cubic feet of system natural gas storage capacity. In addition, the combined system, through owned assets and contractual arrangements with third parties, has the capability to process 915 million cubic feet per day of natural gas for liquids extraction and to treat approximately 250 million cubic feet per day of natural gas for carbon dioxide removal.

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          Collectively, the combined system primarily serves the Texas Gulf Coast by selling, transporting, processing and treating gas from multiple onshore and offshore supply sources to serve the Houston/Beaumont/Port Arthur industrial markets, local gas distribution utilities, electric utilities and merchant power generation markets. It serves as a buyer and seller of natural gas, as well as a transporter of natural gas. The purchases and sales of natural gas are primarily priced with reference to market prices in the consuming region of its system. The difference between the purchase and sale prices is the rough equivalent of a transportation fee and fuel costs.

          Included in the operations of our Kinder Morgan Tejas system is our Kinder Morgan Border Pipeline system. Kinder Morgan Border owns and operates an approximately 97-mile, 24-inch diameter pipeline that extends from a point of interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica at the International Border between the United States and Mexico, to a point of interconnection with other intrastate pipeline facilities of Kinder Morgan Tejas located at King Ranch, Kleburg County, Texas. The 97-mile pipeline, referred to as the import/export facility, is capable of importing Mexican gas into the United States, and exporting domestic gas to Mexico. The imported Mexican gas is received from, and the exported domestic gas is delivered to, Pemex. The capacity of the import/export facility is approximately 300 million cubic feet of natural gas per day.

          Our Mier-Monterrey Pipeline consists of a 95-mile, 30-inch diameter natural gas pipeline that stretches from south Texas to Monterrey, Mexico and can transport up to 375 million cubic feet per day. The pipeline connects to a 1,000-megawatt power plant complex and to the PEMEX natural gas transportation system. We have entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for all of the pipeline’s capacity.

          Our Kinder Morgan North Texas Pipeline consists of an 86-mile, 30-inch diameter pipeline that transports natural gas from an interconnect with the facilities of Natural Gas Pipeline Company of America LLC, referred to in this report as NGPL, in Lamar County, Texas to a 1,750-megawatt electric generating facility located in Forney, Texas, 15 miles east of Dallas, Texas. It has the capacity to transport 325 million cubic feet per day of natural gas and is fully subscribed under a long-term contract that expires in 2032. In 2006, the existing system was enhanced to be bi-directional, so that deliveries of additional supply coming out of the Barnett Shale area can be delivered into NGPL’s pipeline as well as power plants in the area.

          We also own and operate various gathering systems in South and East Texas. These systems aggregate natural gas supplies into our main transmission pipelines, and in certain cases, aggregate natural gas that must be processed or treated at its own or third-party facilities. We own plants that can process up to 115 million cubic feet per day of natural gas for liquids extraction. In addition, we have contractual rights to process approximately 800 million cubic feet per day of natural gas at various third-party owned facilities. We also own and operate three natural gas treating plants that provide carbon dioxide and/or hydrogen sulfide removal. We can treat up to 155 million cubic feet per day of natural gas for carbon dioxide removal at our Fandango Complex in Zapata County, Texas, 50 million cubic feet per day of natural gas at our Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic feet per day of natural gas at our Thompsonville Facility located in Jim Hogg County, Texas.

          Our North Dayton natural gas storage facility, located in Liberty County, Texas, has two existing storage caverns providing approximately 6.3 billion cubic feet of total capacity, consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of cushion gas. We have entered into a long-term storage capacity and transportation agreement with NRG covering two billion cubic feet of natural gas working capacity that expires in March 2017. In June 2006, we announced an expansion project that will significantly increase natural gas storage capacity at our North Dayton facility. The project is now expected to cost between $105 million and $115 million and involves the development of a new underground storage cavern that will add an estimated 6.5 billion cubic feet of incremental working natural gas storage capacity. The additional capacity is expected to be available in mid-2010.

          We also own the West Clear Lake natural gas storage facility located in Harris County, Texas. Under a long term contract that expires in 2012, Coral Energy Resources, L.P. operates the facility and controls the 96 billion cubic feet of natural gas working capacity, and we provide transportation service into and out of the facility.

          Additionally, we lease a salt dome storage facility located near Markham, Texas according to the provisions of an operating lease that expires in March 2013. We can, at our sole option, extend the term of this lease for two

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additional ten-year periods. The facility was expanded in 2007 and now consists of four salt dome caverns with approximately 17.3 billion cubic feet of working natural gas capacity and up to 1.1 billion cubic feet per day of peak deliverability. We also lease two salt dome caverns, known as the Stratton Ridge Facilities, from BP America Production Company in Brazoria County, Texas. The Stratton Ridge Facilities have a combined working natural gas capacity of 1.4 billion cubic feet and a peak day deliverability of 100 million cubic feet per day. A lease with Dow Hydrocarbon & Resources, Inc. for a salt dome cavern containing approximately 5.0 billion cubic feet of working capacity expired during the third quarter of 2007.

          Markets. Texas is one of the largest natural gas consuming states in the country. The natural gas demand profile in our Texas intrastate pipeline group’s market area is primarily composed of industrial (including on-site cogeneration facilities), merchant and utility power, and local natural gas distribution consumption. The industrial demand is primarily year-round load. Merchant and utility power demand peaks in the summer months and is complemented by local natural gas distribution demand that peaks in the winter months. As new merchant gas fired generation has come online and displaced traditional utility generation, we have successfully attached many of these new generation facilities to our pipeline systems in order to maintain and grow our share of natural gas supply for power generation. Additionally, in 2007, we have increased our capability and commitment to serve the growing local natural gas distribution market in the greater Houston metropolitan area.

          We serve the Mexico market through interconnection with the facilities of Pemex at the United States-Mexico border near Arguellas, Mexico and our Mier-Monterrey Mexico pipeline. In 2007, deliveries through the existing interconnection near Arguellas fluctuated from zero to approximately 206 million cubic feet per day of natural gas, and there were several days of exports to the United States which ranged up to 250 million cubic feet per day. Deliveries to Monterrey also generally ranged from zero to 312 million cubic feet per day. We primarily provide transport service to these markets on a fee for service basis, including a significant demand component, which is paid regardless of actual throughput. Revenues earned from our activities in Mexico are paid in U.S. dollar equivalent.

          Supply. We purchase our natural gas directly from producers attached to our system in South Texas, East Texas, West Texas and along the Texas Gulf Coast. In addition, we also purchase gas at interconnects with third-party interstate and intrastate pipelines. While our intrastate group does not produce gas, it does maintain an active well connection program in order to offset natural declines in production along its system and to secure supplies for additional demand in its market area. Our intrastate system has access to both onshore and offshore sources of supply, and is well positioned to interconnect with liquefied natural gas projects currently under development by others along the Texas Gulf Coast.

          Competition. The Texas intrastate natural gas market is highly competitive, with many markets connected to multiple pipeline companies. We compete with interstate and intrastate pipelines, and their shippers, for attachments to new markets and supplies and for transportation, processing and treating services.

          Rocky Mountain Natural Gas Pipeline Group

          The group, which operates primarily along the Rocky Mountain region of the Western portion of the United States, consists of the following four natural gas pipeline systems:

• our Kinder Morgan Interstate Gas Transmission Pipeline;

• our Trailblazer Pipeline;

• our Trans-Colorado Pipeline; and

• our 51% ownership interest in the Rockies Express Pipeline.

          Kinder Morgan Interstate Gas Transmission LLC

          Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, owns approximately 5,100 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska. The pipeline system is

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powered by 28 transmission and storage compressor stations with approximately 160,000 horsepower. KMIGT also owns the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, which has approximately 10 billion cubic feet of firm capacity commitments and provides for withdrawal of up to 169 million cubic feet of natural gas per day.

          Under transportation agreements and FERC tariff provisions, KMIGT offers its customers firm and interruptible transportation and storage services, including no-notice service and park and loan services. For these services, KMIGT charges rates which include the retention of fuel and gas lost and unaccounted for in-kind. Under KMIGT’s tariffs, firm transportation and storage customers pay reservation charges each month plus a commodity charge based on the actual transported or stored volumes. In contrast, interruptible transportation and storage customers pay a commodity charge based upon actual transported and/or stored volumes. Under the no-notice service, customers pay a fee for the right to use a combination of firm storage and firm transportation to effect deliveries of natural gas up to a specified volume without making specific nominations. KMIGT also has the authority to make gas purchases and sales, as needed for system operations, pursuant to its currently effective FERC gas tariff.

          KMIGT also offers its Cheyenne Market Center service, which provides nominated storage and transportation service between its Huntsman storage field and multiple interconnecting pipelines at the Cheyenne Hub, located in Weld County, Colorado. This service is fully subscribed through May 2014.

          Markets. Markets served by KMIGT provide a stable customer base with expansion opportunities due to the system’s access to growing Rocky Mountain supply sources. Markets served by KMIGT are comprised mainly of local natural gas distribution companies and interconnecting interstate pipelines in the mid-continent area. End-users of the local natural gas distribution companies typically include residential, commercial, industrial and agricultural customers. The pipelines interconnecting with KMIGT in turn deliver gas into multiple markets including some of the largest population centers in the Midwest. Natural gas demand to power pumps for crop irrigation during the summer from time-to-time exceeds heating season demand and provides KMIGT relatively consistent volumes throughout the year. In addition, KMIGT has seen a significant increase in demand from ethanol producers, and is actively seeking ways to meet the demands from the ethanol producing community.

          Supply. Approximately 7%, by volume, of KMIGT’s firm contracts expire within one year and 51% expire within one to five years. Over 99% of the system’s total firm transport capacity is currently subscribed, with 78% of the total contracted capacity held by KMIGT’s top nine shippers.

          Competition. KMIGT competes with other interstate and intrastate gas pipelines transporting gas from the supply sources in the Rocky Mountain and Hugoton Basins to mid-continent pipelines and market centers.

          Trailblazer Pipeline Company LLC

          Our subsidiary, Trailblazer Pipeline Company LLC, owns a 436-mile natural gas pipeline system. Trailblazer’s pipeline originates at an interconnection with Wyoming Interstate Company Ltd.’s pipeline system near Rockport, Colorado and runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where it interconnects with NGPL and Northern Natural Gas Company’s pipeline systems. NGPL, an investee of Knight, manages, maintains and operates Trailblazer, for which it is reimbursed at cost.

          Trailblazer provides transportation services to third-party natural gas producers, marketers, local distribution companies and other shippers. Pursuant to transportation agreements and FERC tariff provisions, Trailblazer offers its customers firm and interruptible transportation. Under Trailblazer’s tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported.

          Markets. Significant growth in Rocky Mountain natural gas supplies has prompted a need for additional pipeline transportation service. Trailblazer has a certificated capacity of 846 million cubic feet per day of natural gas.

          Supply. As of December 31, 2007, none of Trailblazer’s firm contracts, by volume, expire before one year and 54%, by volume, expire within one to five years. Affiliated entities have contracted for less than 1% of the total firm transportation capacity. All of the system’s firm transport capacity is currently subscribed.

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          Competition. The main competition that Trailblazer currently faces is that the gas supply in the Rocky Mountain area either stays in the area or is moved west and therefore is not transported on Trailblazer’s pipeline. In addition, El Paso’s Cheyenne Plains Pipeline can transport approximately 730 million cubic feet per day of natural gas from Weld County, Colorado to Greensburg, Kansas and competes with Trailblazer for natural gas pipeline transportation demand from the Rocky Mountain area. Additional competition could come from the Rockies Express pipeline system or from proposed pipeline projects. No assurance can be given that additional competing pipelines will not be developed in the future.

          TransColorado Gas Transmission Company LLC

          Our subsidiary, TransColorado Gas Transmission Company LLC, owns a 300-mile interstate natural gas pipeline that extends from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico. It has multiple points of interconnection with various interstate and intrastate pipelines, gathering systems, and local distribution companies. The pipeline system is powered by eight compressor stations having an aggregate of approximately 39,000 horsepower. Knight manages, maintains and operates TransColorado, for which it is reimbursed at cost.

          TransColorado has the ability to flow gas south or north. TransColorado receives gas from one coal seam natural gas treating plant located in the San Juan Basin of Colorado and from pipeline, processing plant and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. Gas flowing south through the pipeline moves onto the El Paso, Transwestern and Questar Southern Trail pipeline systems. Gas moving north flows into the Colorado Interstate, Wyoming Interstate and Questar pipeline systems at the Greasewood Hub and the Rockies Express pipeline system at the Meeker Hub. TransColorado provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers.

          Pursuant to transportation agreements and FERC tariff provisions, TransColorado offers its customers firm and interruptible transportation and interruptible park and loan services. For these services, TransColorado charges rates which include the retention of fuel and gas lost and unaccounted for in-kind. Under TransColorado’s tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. The underlying reservation and commodity charges are assessed pursuant to a maximum recourse rate structure, which does not vary based on the distance gas is transported. TransColorado has the authority to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure.

          TransColorado’s approximately $50 million Blanco-Meeker Expansion Project was completed in the fourth quarter of 2007 and placed into service on January 1, 2008. The project boosted capacity on the pipeline by 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 pipeline for deliveries to the Rockies Express Pipeline at an existing point of interconnection located at the Meeker Hub in Rio Blanco County, Colorado. All of the incremental capacity is subscribed under a long-term contract with ConocoPhillips.

          Markets. TransColorado acts principally as a feeder pipeline system from the developing natural gas supply basins on the Western Slope of Colorado into the interstate natural gas pipelines that lead away from the Blanco Hub area of New Mexico and the interstate natural gas pipelines that lead away eastward from northwestern Colorado and southwestern Wyoming. TransColorado is one of the largest transporters of natural gas from the Western Slope supply basins of Colorado and provides a competitively attractive outlet for that developing natural gas resource. In 2007, TransColorado transported an average of approximately 734 million cubic feet per day of natural gas from these supply basins.

          Supply. During 2007, 94% of TransColorado’s transport business was with producers or their own marketing affiliates, and 6% was with marketing companies and various gas marketers. Approximately 64% of TransColorado’s transport business in 2007 was conducted with its two largest customers. All of TransColorado’s southbound pipeline capacity is committed under firm transportation contracts that extend at least through year-end 2008. TransColorado’s pipeline capacity is 62% subscribed during 2009 through 2012, and TransColorado is actively pursuing contract extensions and or replacement contracts to increase firm subscription levels beyond 2008.

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          Competition. TransColorado competes with other transporters of natural gas in each of the natural gas supply basins it serves. These competitors include both interstate and intrastate natural gas pipelines and natural gas gathering systems. TransColorado’s shippers compete for market share with shippers drawing upon gas production facilities within the New Mexico portion of the San Juan Basin. TransColorado has phased its past construction and expansion efforts to coincide with the ability of the interstate pipeline grid at Blanco, New Mexico to accommodate greater natural gas volumes. TransColorado’s transport concurrently ramped up over that period such that TransColorado now enjoys a growing share of the outlet from the San Juan Basin to the southwestern United States marketplace.

          Historically, the competition faced by TransColorado with respect to its natural gas transportation services has generally been based upon the price differential between the San Juan and Rocky Mountain basins. New pipelines servicing these producing basins have had the effect of reducing that price differential; however, given the growth in the Piceance and Paradox basins and the direct accessibility of the TransColorado system to these basins, we believe that TransColorado’s transport business to be sustainable and not significantly impacted by any new entry of competition.

          Rockies Express Pipeline

          We operate and currently own 51% of the 1,679-mile Rockies Express Pipeline system, which when fully completed, will be one of the largest natural gas pipelines ever constructed in North America. The approximately $4.9 billion project will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity.

          Our ownership is through our 51% interest in West2East Pipeline LLC. the sole owner of Rockies Express Pipeline LLC. Sempra Pipelines & Storage, a unit of Sempra Energy, and ConocoPhillips hold the remaining ownership interests in the Rockies Express project. We account for our investment under the equity method of accounting due to the fact that our ownership interest will be reduced to 50% when construction of the entire project is completed. At that time, the capital accounts of West2East Pipeline LLC will be trued up to reflect our 50% economics in the project. We do not anticipate any additional changes in the ownership structure of the project.

          On August 9, 2005, the FERC approved Rockies Express Pipeline LLC’s application to construct 327 miles of pipeline facilities in two phases. Phase I consisted of the following two pipeline segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming; and (ii) a 191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado. Phase II of the project includes the construction of three compressor stations referred to as the Meeker, Big Hole and Wamsutter compressor stations. The Meeker and Wamsutter stations were completed and placed in-service in January 2008. Construction of the Big Hole compressor station is planned to commence in the second 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 Rockies Express Pipeline LLC’s 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 Pipeline LLC’s original certificated facilities, and is comprised of approximately 713 miles of 42-inch diameter pipeline extending eastward from the Cheyenne Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The segment extension transports approximately 1.5 billion cubic feet per day of natural gas across the following five states: Wyoming, Colorado, Nebraska, Kansas and Missouri and includes certain improvements to pre-existing Rockies Express facilities located to the west of the Cheyenne Hub. Construction of the Rockies Express-West project commenced on May 21, 2007, and interim firm transportation service with capacity of approximately 1.4 billion cubic feet per day began January 12, 2008. The entire project (Rockies Express-West pipeline segment) is expected to become fully operational in mid-March 2008.

          On April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC requesting approval to construct and operate the REX-East Project, the third segment of the Rockies Express pipeline system. The REX-East Project will be comprised of approximately 639 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline in Audrain County, Missouri to a terminus near the town of

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Clarington in Monroe County, Ohio. The pipeline segment will be capable of transporting approximately 1.8 billion cubic feet per day of natural gas. The FERC issued a draft environmental report in late November 2007 for the REX-East Project, and subject to receipt of regulatory approvals, the REX-East Project is expected to begin partial service on December 31, 2008, and to be in full service in June 2009.

          In December 2007, Rockies Express Pipeline LLC completed a non-binding open season undertaken to solicit market interest for the “Northeast Express Project,” a 375-mile extension and expansion of the Rockies Express pipeline system from Clarington, Ohio, to Princeton, New Jersey. Significant expressions of interest were received on the Northeast Express Project and negotiations with prospective shippers to enter into binding commitments are currently underway. Subject to receipt of sufficient binding commitments and regulatory approvals, the Northeast Express Project would go into service in late 2010. When complete, the Northeast Express Project would provide up to 1.8 billion cubic feet of transportation capacity to northeast markets from the Lebanon Hub and other pipeline receipt points between Lebanon, Ohio and Clarington, Ohio.

          Markets. The Rockies Express Pipeline is capable of delivering gas to multiple markets along its pipeline system, primarily through interconnects with other interstate pipeline companies and direct connects to local distribution companies. Rockies Express Pipeline’s Zone 1 encompasses receipts and deliveries of natural gas west of the Cheyenne Hub, located in Northern Colorado near Cheyenne, Wyoming. Through the Zone 1 facilities, Rockies Express can deliver gas to TransColorado Gas Transmission Company LLC in northwestern Colorado, which can in turn transport the gas further south for delivery into the San Juan Basin area. In Zone 1, Rockies Express Pipeline can also deliver gas into western Wyoming through leased capacity on the Overthrust Pipeline Company system, or through its interconnections with Colorado Interstate Gas Company and Wyoming Interstate Company in southern Wyoming. REX-West has the ability to deliver natural gas to points at the Cheyenne Hub, which could be used in markets along the Front Range of Colorado, or could be transported further east through either Rockies Express Pipeline’s Zone 2 facilities or other pipeline systems.

          Rockies Express Pipeline’s Zone 2 extends from the Cheyenne Hub to an interconnect with the Panhandle Eastern Pipeline in Audrain County, Missouri. Through the Zone 2 facilities, Rockies Express facilitates the delivery of natural gas into the Midcontinent area of the Unites States through various interconnects with other major interstate pipelines in Nebraska (Northern Natural Gas Pipeline and NGPL), Kansas (ANR Pipeline), and Missouri (Panhandle Eastern Pipeline). Rockies Express Pipeline’s transportation capacity under interim service is currently 1.4 billion cubic feet per day, and when this system is placed into full service it will be capable of delivering 1.5 billion cubic feet per day through these interconnects to the Midcontinent market.

          Supply. Rockies Express Pipeline directly accesses major gas supply basins in western Colorado and western Wyoming. In western Colorado, Rockies Express Pipeline has access to gas supply from the Uinta and Piceance basins in eastern Utah and western Colorado. In western Wyoming, Rockies Express Pipeline accesses the Green River Basin through its facilities that are leased from Overthrust. With its connections to numerous other pipeline systems along its route, Rockies Express Pipeline has access to almost all of the major gas supply basins in Wyoming, Colorado and eastern Utah.

          Competition. Although there are some competitors to the Rockies Express Pipeline system that provide a similar service, there are none that can compete with the economy-of-scale that Rockies Express Pipeline provides to its shippers to transport gas from the Rocky Mountain region to the Midcontinent markets. The REX-East Project, noted above, will put the Rockies Express Pipeline system in a very unique position of being the only pipeline capable of offering a large volume of transportation service from Rocky Mountain gas supply directly to customers in Ohio.

          Rockies Express Pipeline could also experience competition for its Rocky Mountain gas supply from both existing and proposed systems. Questar Pipeline Company accesses many of the same basins as Rockies Express Pipeline and transports gas to its markets in Utah and to other interconnects, which have access to the California market. In addition, there are pipelines that are proposed to use Rocky Mountain gas to supply markets on the West Coast.

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          Kinder Morgan Louisiana Pipeline

          In September 2006, we filed an application with the FERC requesting approval to construct and operate our Kinder Morgan Louisiana Pipeline. The natural gas pipeline project is expected to cost approximately $510 million and will provide approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron Parish, Louisiana. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total.

          The Kinder Morgan Louisiana Pipeline will consist of two segments:

• a 132-mile, 42-inch diameter pipeline with firm capacity of approximately 2.0 billion cubic feet per day of natural gas that will extend from the Sabine Pass terminal to a point of interconnection with an existing Columbia Gulf Transmission line in Evangeline Parish, Louisiana (an offshoot will consist of approximately 2.3 miles of 24-inch diameter pipeline with firm peak day capacity of approximately 300 million cubic feet per day extending away from the 42-inch diameter line to the existing Florida Gas Transmission Company compressor station in Acadia Parish, Louisiana). This segment is expected to be in service by January 1, 2009; and

• a 1-mile, 36-inch diameter pipeline with firm capacity of approximately 1.2 billion cubic feet per day that will extend from the Sabine Pass terminal and connect to NGPL’s natural gas pipeline. This portion of the project is expected to be in service in the third quarter of 2008.

          We have designed and will construct the Kinder Morgan Louisiana Pipeline in a manner that will minimize environmental impacts, and where possible, existing pipeline corridors will be used to minimize impacts to communities and to the environment. As of December 31, 2007, there were no major pipeline re-routes as a result of any landowner requests.

          Midcontinent Express Pipeline LLC

          On October 9, 2007, 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. We currently own a 50% interest in Midcontinent Express Pipeline LLC and we account for our investment under the equity method of accounting. Energy Transfer Partners, L.P. owns the remaining 50% interest. The Midcontinent Express Pipeline will create long-haul, firm natural gas transportation takeaway capacity, either directly or indirectly, from natural gas producing regions located in Texas, Oklahoma and Arkansas. The total project is expected to cost approximately $1.3 billion, and will have an initial transportation capacity of approximately 1.4 billion cubic feet per day of natural gas.

          For additional information regarding the Midcontinent Express Pipeline, see “(a) General Development of Business—Recent Developments.”

          Casper and Douglas Natural Gas Processing Systems

          We own and operate our Casper and Douglas, Wyoming natural gas processing plants, which have the capacity to process up to 185 million cubic feet per day of natural gas depending on raw gas quality.

          Markets. Casper and Douglas are processing plants servicing gas streams flowing into KMIGT. Natural gas liquids processed by our Casper plant are sold into local markets consisting primarily of retail propane dealers and oil refiners. Natural gas liquids processed by our Douglas plant are sold to ConocoPhillips via their Powder River natural gas liquids pipeline for either ultimate consumption at the Borger refinery or for further disposition to the natural gas liquids trading hubs located in Conway, Kansas and Mont Belvieu, Texas.

          Competition. Other regional facilities in the Greater Powder River Basin include the Hilight plant (80 million cubic feet per day) owned and operated by Anadarko, the Sage Creek plant (50 million cubic feet per day) owned and operated by Merit Energy, and the Rawlins plant (230 million cubic feet per day) owned and operated by El

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Paso. Casper and Douglas, however, are the only plants which provide straddle processing of natural gas flowing into KMIGT.

          Red Cedar Gathering Company

          We own a 49% equity interest in the Red Cedar Gathering Company, a joint venture organized in August 1994 and referred to in this report as Red Cedar. The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe. Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado. The Ignacio Blanco Field lies within the Colorado portion of the San Juan Basin, most of which is located within the exterior boundaries of the Southern Ute Indian Tribe Reservation. Red Cedar gathers coal seam and conventional natural gas at wellheads and several central delivery points, for treating, compression and delivery into any one of four major interstate natural gas pipeline systems and an intrastate pipeline.

          Red Cedar also owns Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. The inlet gas stream treated by Coyote Gulch contains an average carbon dioxide content of between 12% and 13%. The plant treats the gas down to a carbon dioxide concentration of 2% in order to meet interstate natural gas pipeline quality specifications, and then compresses the natural gas into the TransColorado Gas Transmission pipeline for transport to the Blanco, New Mexico-San Juan Basin Hub.

          Red Cedar’s gas gathering system currently consists of over 1,100 miles of gathering pipeline connecting more than 920 producing wells, 85,000 horsepower of compression at 24 field compressor stations and two carbon dioxide treating plants. The capacity and throughput of the Red Cedar system as currently configured is approximately 750 million cubic feet per day of natural gas.

          Thunder Creek Gas Services, LLC

          We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek. Devon Energy owns the remaining 75%. Thunder Creek provides gathering, compression and treating services to a number of coal seam gas producers in the Powder River Basin of Wyoming. Throughput volumes include both coal seam and conventional plant residue gas.

          Thunder Creek’s operations are a combination of mainline and low pressure gathering assets. The mainline assets include 125 miles of mainline pipeline, 230 miles of high and low pressure laterals, 26,635 horsepower of mainline compression and carbon dioxide removal facilities consisting of a 220 million cubic feet per day carbon dioxide treating plant complete with dehydration. The mainline assets receive gas from 53 receipt points and can deliver treated gas to seven delivery points including Colorado Interstate Gas, Wyoming Interstate Gas Company, KMIGT and three power plants. The low pressure gathering assets include five systems consisting of 194 miles of gathering pipeline and 35,329 horsepower of field compression.

          CO₂

          Our CO₂ segment consists of Kinder Morgan CO₂ Company, L.P. and its consolidated affiliates, referred to in this report as KMCO₂. Carbon dioxide is used in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. Our carbon dioxide pipelines and related assets allow us to market a complete package of carbon dioxide supply, transportation and technical expertise to the customer. Together, our CO₂ business segment produces, transports and markets carbon dioxide for use in enhanced oil recovery operations. We also hold ownership interests in several oil-producing fields and own a 450-mile crude oil pipeline, all located in the Permian Basin region of West Texas.

          Carbon Dioxide Reserves

          We own approximately 45% of, and operate, the McElmo Dome unit in Colorado, which contains more than nine trillion cubic feet of recoverable carbon dioxide. Deliverability and compression capacity exceeds one billion cubic feet per day. We are currently installing facilities and drilling 8 wells to increase the production capacity from

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McElmo Dome by approximately 200 million cubic feet per day. We also own approximately 11% of the Bravo Dome unit in New Mexico, which contains more than one trillion cubic feet of recoverable carbon dioxide and produces approximately 290 million cubic feet per day.

          We also own approximately 88% of the Doe Canyon Deep unit in Colorado, which contains more than 1.5 trillion cubic feet of carbon dioxide. We have installed facilities and drilled six wells to produce approximately 100 million cubic feet per day of carbon dioxide beginning in January 2008.

          Markets. Our principal market for carbon dioxide is for injection into mature oil fields in the Permian Basin, where industry demand is expected to grow modestly for the next several years. We are exploring additional potential markets, including enhanced oil recovery targets in California, Wyoming, the Gulf Coast, Mexico, and Canada, and coal bed methane production in the San Juan Basin of New Mexico.

          Competition. Our primary competitors for the sale of carbon dioxide include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide reserves, and Petro-Source Carbon Company, which gathers waste carbon dioxide from natural gas production in the Val Verde Basin of West Texas. There is no assurance that new carbon dioxide sources will not be discovered or developed, which could compete with us or that new methodologies for enhanced oil recovery will not replace carbon dioxide flooding.

          Carbon Dioxide Pipelines

          As a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50% equity interest in and operate the approximate 500-mile, Cortez pipeline. The pipeline carries carbon dioxide from the McElmo Dome and Doe Canyon source fields near Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline currently transports over one billion cubic feet of carbon dioxide per day, including approximately 99% of the carbon dioxide transported downstream on our Central Basin pipeline and our Centerline pipeline. The tariffs charged by Cortez Pipeline are not regulated.

          Our Central Basin pipeline consists of approximately 143 miles of pipe and 177 miles of lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas with a throughput capacity of 600 million cubic feet per day. At its origination point in Denver City, our Central Basin pipeline interconnects with all three major carbon dioxide supply pipelines from Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO₂) and the Bravo and Sheep Mountain pipelines (operated by Oxy Permian). Central Basin’s mainline terminates near McCamey where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the Central Basin pipeline are not regulated.

          Our Centerline pipeline consists of approximately 113 miles of pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas. The pipeline has a capacity of 300 million cubic feet per day. The tariffs charged by the Centerline pipeline are not regulated.

          We own a 13% undivided interest in the 218-mile, Bravo pipeline, which delivers CO2 from the Bravo Dome source field in northeast New Mexico to the Denver City hub and has a capacity of more than 350 million cubic feet per day. Tariffs on the Bravo pipeline are not regulated.

          In addition, we own approximately 98% of the Canyon Reef Carriers pipeline and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline extends 139 miles from McCamey, Texas, to the SACROC unit. The pipeline has a capacity of approximately 290 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The Pecos pipeline is a 25-mile pipeline that runs from McCamey to Iraan, Texas. It has a capacity of approximately 120 million cubic feet per day of carbon dioxide and makes deliveries to the Yates unit. The tariffs charged on the Canyon Reef Carriers and Pecos pipelines are not regulated.

          Markets. The principal market for transportation on our carbon dioxide pipelines is to customers, including ourselves, using carbon dioxide for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to grow modestly for the next several years.

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          Competition. Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines. We also compete with other interest owners in McElmo Dome and Bravo Dome for transportation of carbon dioxide to the Denver City, Texas market area.

          Oil Acreage and Wells

          KMCO₂ also holds ownership interests in oil-producing fields, including an approximate 97% working interest in the SACROC unit, an approximate 50% working interest in the Yates unit, a 21% net profits interest in the H.T. Boyd unit, an approximate 65% working interest in the Claytonville unit, an approximate 95% working interest in the Katz CB Long unit, an approximate 64% working interest in the Katz SW River unit, a 100% working interest in the Katz East River unit, and lesser interests in the Sharon Ridge unit, the Reinecke unit and the MidCross unit, all of which are located in the Permian Basin of West Texas.

          The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas. SACROC was discovered in 1948 and has produced over 1.29 billion barrels of oil since inception. It is estimated that SACROC originally held approximately 2.7 billion barrels of oil. We have expanded the development of the carbon dioxide project initiated by the previous owners and increased production over the last several years. The Yates unit is also one of the largest oil fields ever discovered in the United States. It is estimated that it originally held more than five billion barrels of oil, of which about 29% has been produced. The field, discovered in 1926, is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas.

          As of December 2007, the SACROC unit had 391 producing wells, and the purchased carbon dioxide injection rate was 211 million cubic feet per day, down from an average of 247 million cubic feet per day as of December 2006. The average oil production rate for 2007 was approximately 27,600 barrels of oil per day, down from an average of approximately 30,800 barrels of oil per day during 2006. The average natural gas liquids production rate (net of the processing plant share) for 2007 was approximately 6,300 barrels per day, an increase from an average of approximately 5,700 barrels per day during 2006.

          Our plan has been to increase the production rate and ultimate oil recovery from Yates by combining horizontal drilling with carbon dioxide injection to ensure a relatively steady production profile over the next several years. We are implementing our plan and as of December 2007, the Yates unit was producing about 27,600 barrels of oil per day. As of December 2006, the Yates unit was producing approximately 27,200 barrels of oil per day. Unlike our operations at SACROC, where we use carbon dioxide and water to drive oil to the producing wells, we are using carbon dioxide injection to replace nitrogen injection at Yates in order to enhance the gravity drainage process, as well as to maintain reservoir pressure. The differences in geology and reservoir mechanics between the two fields mean that substantially less capital will be needed to develop the reserves at Yates than is required at SACROC.

          We also operate and own an approximate 65% gross working interest in the Claytonville oil field unit located in Fisher County, Texas. The Claytonville unit is located nearly 30 miles east of the SACROC unit in the Permian Basin of West Texas and is currently producing approximately 230 barrels of oil per day. We are presently evaluating operating and subsurface technical data from the Claytonville unit to further assess redevelopment opportunities including carbon dioxide flood operations.

          We also operate and own working interests in the Katz CB Long unit, the Katz Southwest River unit and Katz East River unit. The Katz field is located in the Permian Basin area of West Texas and, as of December 2007, was producing approximately 400 barrels of oil equivalent per day. We are presently evaluating operating and subsurface technical data to further assess redevelopment opportunities for the Katz field including the potential for carbon dioxide flood operations.

          The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which we own interests as of December 31, 2007. When used with respect to acres or wells, gross refers to the total acres or wells in which we have a working interest; net refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us:

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	Productive Wells (a)				Service Wells (b)				Drilling Wells (c)
	Gross		Net		Gross		Net		Gross		Net
Crude Oil		2,463		1,587		1,066		789		2		2
Natural Gas		8		4		—		—		—		—
Total Wells		2,471		1,591		1,066		789		2		2

(a)	Includes active wells and wells temporarily shut-in. As of December 31, 2007, we did not operate any productive wells with multiple completions.
(b)	Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of saltwater into an underground formation; a service well is a well drilled in a known oil field in order to inject liquids that enhance recovery or dispose of salt water.
(c)	Consists of development wells in the process of being drilled as of December 31, 2007.A development well is a well drilled in an already discovered oil field.

          The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. The following table reflects our net productive and dry wells that were completed in each of the three years ended December 31, 2007, 2006 and 2005:

	2007		2006		2005
Productive
Development		31		37		42
Exploratory		—		—		—
Dry
Development		—		—		—
Exploratory		—		—		—
Total Wells		31		37		42

Notes: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling operations were not completed as of the end of the applicable year. Development wells include wells drilled in the proved area of an oil or gas resevoir.

          The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2007:

	Gross		Net
Developed Acres		72,435		67,731
Undeveloped Acres		8,788		8,129
Total		81,223		75,860

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          Operating Statistics

          Operating statistics from our oil and gas producing activities for each of the years 2007, 2006 and 2005 are shown in the following table:

Results of Operations for Oil and Gas Producing Activities – Unit Prices and Costs

	Year Ended December 31,
	2007		2006		2005
Consolidated Companies(a)
Production costs per barrel of oil equivalent(b)(c)(d)	$	16.22	$	13.30	$	10.00
Crude oil production (MBbl/d)		35.6		37.8		37.9
Natural gas liquids production (MBbl/d)(d)		5.5		5.0		5.3
Natural gas liquids production from gas plants(MBbl/d)(e)		4.1		3.9		4.1
Total natural gas liquids production(MBbl/d)		9.6		8.9		9.4
Natural gas production (MMcf/d)(d)(f)		0.8		1.3		3.7
Natural gas production from gas plants(MMcf/d)(e)(f)		0.3		0.3		3.1
Total natural gas production(MMcf/d)(f)		1.1		1.6		6.8
Average sales prices including hedge gains/losses:
Crude oil price per Bbl(g)	$	36.05	$	31.42	$	27.36
Natural gas liquids price per Bbl(g)	$	52.22	$	43.52	$	38.79
Natural gas price per Mcf(h)	$	6.08	$	6.36	$	5.84
Total natural gas liquids price per Bbl(e)	$	52.91	$	43.90	$	38.98
Total natural gas price per Mcf(e)	$	5.89	$	7.02	$	5.80
Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl(g)	$	69.63	$	63.27	$	54.45
Natural gas liquids price per Bbl(g)	$	52.22	$	43.52	$	38.79
Natural gas price per Mcf(h)	$	6.08	$	6.36	$	5.84

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Computed using production costs, excluding transportation costs, as defined by the United States Securities and Exchange Commisson. Natural gas volumes were converted to barrels of oil equivalent (BOE) using a conversion factor of six mcf of natural gas to one barrel of oil.
(c)	Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, property taxes, severance taxes, and general and administrative expenses directly related to oil and gas producing activities.
(d)	Includes only production attributable to leasehold ownership.
(e)	Includes production attributable to our ownership in processing plants and third party processing agreements.
(f)	Excludes natural gas production used as fuel.
(g)	Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
(h)	Natural gas sales were not hedged.

          See Note 20 to our consolidated financial statements included in this report for additional information with respect to operating statistics and supplemental information on our oil and gas producing activities.

          Gas and Gasoline Plant Interests

          We operate and own an approximate 22% working interest plus an additional 28% net profits interest in the Snyder gasoline plant. We also operate and own a 51% ownership interest in the Diamond M gas plant and a 100% ownership interest in the North Snyder plant, all of which are located in the Permian Basin of West Texas. The Snyder gasoline plant processes gas produced from the SACROC unit and neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell units, all of which are located in the Permian Basin area of West Texas. The Diamond M and the North Snyder plants contract with the Snyder plant to process gas. Production of natural gas liquids at the Snyder gasoline plant as of December 2007 was approximately 15,500 barrels per day as compared to 15,000 barrels per day as of December 2006.

          Crude Oil Pipeline

          We own our Kinder Morgan Wink Pipeline, a 450-mile Texas intrastate crude oil pipeline system consisting of three mainline sections, two gathering systems and numerous truck delivery stations. The segment that runs from Wink to El Paso has a total capacity of 130,000 barrels of crude oil per day. The pipeline allows us to better manage crude oil deliveries from our oil field interests in West Texas, and we have entered into a long-term throughput

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agreement with Western Refining Company, L.P. to transport crude oil into Western’s 120,000 barrel per day refinery in El Paso. The 20-inch pipeline segment transported approximately119,000 barrels of oil per day in 2007. The Kinder Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad Commission.

          Terminals

          Our Terminals segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel, ores and dry-bulk material services, including all transload, engineering, conveying and other in-plant services. Combined, the segment is composed of approximately100 owned or operated liquids and bulk terminal facilities, and more than 45 rail transloading and materials handling facilities located throughout the United States, Canada and the Netherlands. In 2007, the number of customers from whom our Terminals segment received more than $0.1 million of revenue was approximately 650.

          Liquids Terminals

          Our liquids terminals operations primarily store refined petroleum products, petrochemicals, industrial chemicals and vegetable oil products in aboveground storage tanks and transfer products to and from pipelines, vessels, tank trucks, tank barges, and tank railcars. Combined, our liquids terminals facilities possess liquids storage capacity of approximately 47.5 million barrels, and in 2007, these terminals handled approximately 557 million barrels of petroleum, chemicals and vegetable oil products.

          In September 2006, we announced major expansions at our Pasadena and Galena Park, Texas terminal facilities. The expansions will provide additional infrastructure to help meet the growing need for refined petroleum products storage capacity along the Gulf Coast. The investment of approximately $195 million includes the construction of the following: (i) new storage tanks at both our Pasadena and Galena Park terminals; (ii) an additional cross-channel pipeline to increase the connectivity between the two terminals; (iii) a new ship dock at Galena Park; and (iv) an additional loading bay at our fully automated truck loading rack located at our Pasadena terminal. The expansions are supported by long-term customer commitments and will result in approximately 3.4 million barrels of additional tank storage capacity at the two terminals. Construction began in October 2006, and all of the projects are expected to be completed by the spring of 2008, with the exception of the of the Galena Park ship dock which is now scheduled to be in-service by the third quarter of 2008.

          At Perth Amboy, New Jersey, we completed construction and placed into service nine new storage tanks with a capacity of 1.4 million barrels for gasoline, diesel and jet fuel. These tanks have been leased on a long-term basis to two customers. Our total investment in these facilities was approximately $69 million.

          In June 2006, we announced the construction of a new crude oil tank farm located in Edmonton, Alberta, Canada, and long-term contracts with customers for all of the available capacity at the facility. Situated on approximately 24 acres, the new storage facility will have nine tanks with a combined storage capacity of approximately 2.2 million barrels for crude oil. Service is expected to begin in the first quarter of 2008, and when completed, the tank farm will serve as a premier blending and storage hub for Canadian crude oil. Originally estimated at $115 million, due primarily to additional labor costs, total investment in this tank farm is projected to be $162 million on a constant U.S. dollar basis. The tank farm will have access to more than 20 incoming pipelines and several major outbound systems, including a connection with our Trans Mountain pipeline system, which currently transports up to 260,000 barrels per day of heavy crude oil and refined products from Edmonton to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington state.

          Competition. We are one of the largest independent operators of liquids terminals in North America. Our primary competitors are IMTT, Magellan, Morgan Stanley, NuStar, Oil Tanking, Teppco, and Vopak.

          Bulk Terminals

          Our bulk terminal operations primarily involve dry-bulk material handling services; however, we also provide conveyor manufacturing and installation, engineering and design services and in-plant services covering material

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handling, conveying, maintenance and repair, railcar switching and miscellaneous marine services. Combined, our dry-bulk and material transloading facilities handled approximately 87.1 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2007. We own or operate approximately 93 dry-bulk terminals in the United States, Canada and the Netherlands.

          In May 2007, we purchased certain buildings and equipment and completed a 40 year agreement to operate Vancouver Wharves, a bulk marine terminal located at the entrance to the Port of Vancouver, British Columbia. The facility consists of five vessel berths situated on a 139-acre site, extensive 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 has access to three major rail carriers connecting to shippers in western and central Canada and the U.S. Pacific Northwest. Vancouver Wharves offers a variety of inbound, outbound and value-added services for mineral concentrates, wood products, agri-products and sulfur. In addition to the aggregate consideration of approximately $57.2 million ($38.8 million in cash and the assumption of $18.4 million of assumed liabilities) paid for this facility, we plan to invest an additional $46 million at Vancouver Wharves over the next two years to upgrade and relocate certain rail track and transloading systems, buildings and a shiploader.

          Effective September 1, 2007, we purchased the assets of Marine Terminals, Inc. for an aggregate consideration of approximately $101.5 million. Combined, the assets handle approximately 13.5 million tons of alloys and steel products annually from five facilities located in the southeast United States. These strategically located terminals provide handling, processing, harboring and warehousing services primarily to Nucor Corporation, one of the largest steel and steel products companies in the world, under long-term contracts.

          Competition. Our bulk terminals compete with numerous independent terminal operators, other terminals owned by oil companies, stevedoring companies, and other industrials opting not to outsource terminal services. Many of our bulk terminals were constructed pursuant to long-term contracts for specific customers. As a result, we believe other terminal operators would face a significant disadvantage in competing for this business.

          Materials Services (rail transloading)

          Our materials services operations include rail or truck transloading operations conducted at 45 owned and non-owned facilities. The Burlington Northern Santa Fe, CSX, Norfolk Southern, Union Pacific, Kansas City Southern and A&W railroads provide rail service for these terminal facilities. Approximately 50% of the products handled are liquids, including an entire spectrum of liquid chemicals, and 50% are dry-bulk products. Many of the facilities are equipped for bi-modal operation (rail-to-truck, and truck-to-rail) or connect via pipeline to storage facilities. Several facilities provide railcar storage services. We also design and build transloading facilities, perform inventory management services, and provide value-added services such as blending, heating and sparging. In 2007, our materials services operations handled approximately 347,000 railcars.

          Competition Our material services operations compete with a variety of national transload and terminal operators across the United States, including Savage Services, Watco and Bulk Plus Logistics. Additionally, single or multi-site terminal operators are often entrenched in the network of Class 1 rail carriers.

          Trans Mountain

          Our Trans Mountain common carrier pipeline system originates at Edmonton, Alberta and transports crude oil and refined petroleum to destinations in the interior and on the west coast of British Columbia. A connecting pipeline owned by us delivers petroleum to refineries in the state of Washington.

          Trans Mountain’s pipeline is 715 miles. The capacity of the line out of Edmonton ranges from 260,000 barrels per day when heavy crude represents 20% of the total throughput to 300,000 barrels per day with no heavy crude. The pipeline system utilizes 21 pump stations controlled by a centralized computer control system.

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          Trans Mountain also operates a 5.3 mile spur line from its Sumas Pump Station to the U.S. – Canada international border where it connects with a 63 mile pipeline system owned and operated by us. The pipeline system in Washington State has a sustainable throughput capacity of approximately 135,000 barrels per day when heavy crude represents approximately 25% of throughput and connects to four refineries located in northwestern Washington State. The volumes of petroleum shipped to Washington State fluctuate in response to the price levels of Canadian crude oil in relation to petroleum produced in Alaska and other offshore sources.

          In 2007, deliveries on Trans Mountain averaged 258,540 barrels per day. This was an increase of 13% from average 2006 deliveries of 229,369 barrels per day. In April 2007, we commissioned ten new pump stations that boosted capacity on Trans Mountain from 225,000 to approximately 260,000 barrels per day. The crude oil and refined petroleum transported through Trans Mountain’s pipeline system originates in Alberta and British Columbia. The refined and partially refined petroleum transported to Kamloops, British Columbia and Vancouver originates from oil refineries located in Edmonton. Petroleum products delivered through Trans Mountain’s pipeline system are used in markets in British Columbia, Washington State and elsewhere.

          Overall Alberta crude oil supply has been increasing steadily over the past few years as a result of significant oilsands development with projects led by Shell Canada, Suncor Energy and Syncrude Canada. Further development is expected to continue into the future with expansions to existing oilsands production facilities as well as with new projects. In its moderate growth case, the Canadian Association of Petroleum Producers (“CAPP”) forecasts Western Canadian crude oil production to increase by over 1.6 million barrels per day by 2015. This increasing supply will likely result in constrained export pipeline capacity from Western Canada, which supports Trans Mountain’s view that both the demand for transportation services provided by Trans Mountain’s pipeline and the supply of crude oil will remain strong for the foreseeable future.

          Shipments of refined petroleum represent a significant portion of Trans Mountain’s throughput. In 2007, shipments of refined petroleum and iso-octane represented 25% of throughput, as compared with 28% in 2006.

          Major Customers

          Our total operating revenues are derived from a wide customer base.For each of the years ended December 31, 2007, 2006 and 2005, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. Our Texas intrastate natural gas pipeline group buys and sells significant volumes of natural gas within the state of Texas and, to a far lesser extent, our CO2 business segment also sells natural gas. Combined, total revenues from the sales of natural gas from our Natural Gas Pipelines and CO2 business segments in 2007, 2006 and 2005 accounted for 63.3%, 66.8% and 73.9%, respectively, of our total consolidated revenues.

          As a result of our Texas intrastate group selling natural gas in the same price environment in which it is purchased, both our total consolidated revenues and our total consolidated purchases (cost of sales) increase considerably due to the inclusion of the cost of gas in both financial statement line items. However, these higher revenues and higher purchased gas costs do not necessarily translate into increased margins in comparison to those situations in which we charge a fee to transport gas owned by others as we seek to match the purchase and sales indexes and lock in a transport fee. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

          Regulation

          Interstate Common Carrier Pipeline Rate Regulation – U.S. Operations

          Some of our pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC, which tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the

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FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

          On October 24, 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. The rates we charged for transportation service on our Cypress Pipeline were not suspended or subject to protest or complaint during the relevant 365-day period established by the Energy Policy Act. For this reason, we believe these rates should be grandfathered under the Energy Policy Act. Certain rates on our Pacific operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the Pacific pipelines’ rates have been, and continue to be, subject to complaints with the FERC, as is more fully described in Note 16 to our consolidated financial statements included elsewhere in this report.

          Petroleum products pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances.

          Common Carrier Pipeline Rate Regulation – Canadian Operations

          The Canadian portion of our crude oil and refined petroleum products pipeline system is under the regulatory jurisdiction of Canada’s National Energy Board, referred to in this report as the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service. In November 2004, Trans Mountain entered into negotiations with the Canadian Association of Petroleum Producers and principal shippers for a new incentive toll settlement to be effective for the period starting January 1, 2006 and ending December 31, 2010. In January 2006, Trans Mountain reached agreement in principle, which was reduced to a memorandum of understanding for the 2006 toll settlement. A final agreement was reached with the Canadian Association of Petroleum Producers in October 2006 and NEB approval was received in November 2006.

          The 2006 toll settlement incorporates an incentive toll mechanism that is intended to provide Trans Mountain with the opportunity to earn a return on equity greater than that calculated using the formula established by the NEB. In return for this opportunity, Trans Mountain has agreed to assume certain risks and provide cost certainty in certain areas. Part of the incentive toll mechanism specifies that Trans Mountain is allowed to keep 75% of the net revenue generated by throughput in excess of 92.5% of the capacity of the pipeline. The 2006 incentive toll settlement provides for base tolls which will, other than recalculation or adjustment in certain specified circumstances, remain in effect for the five-year period. The toll settlement also governs the financial arrangements for the approximately C$638 million expansions to Trans Mountain that will add 75,000 barrels per day of incremental capacity to the system by November 2008. The toll charged for the portion of Trans Mountain’s pipeline system located in the United States falls under the jurisdiction of the FERC. See “Interstate Common Carrier Pipeline Rate Regulation – U.S. Operations.”

          Interstate Natural Gas Transportation and Storage Regulation

          Both the performance of and rates charged by companies performing interstate natural gas transportation and storage services are regulated by the FERC under the Natural Gas Act of 1938 and, to a lesser extent, the Natural Gas Policy Act of 1978. Beginning in the mid-1980’s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were:

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• Order No. 436 (1985) requiring open-access, nondiscriminatory transportation of natural gas;

• Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction; and

• Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies whether purchased from the pipeline or from other merchants such as marketers or producers.

          Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage). Order 636 contains a number of procedures designed to increase competition in the interstate natural gas industry, including: (i) requiring the unbundling of sales services from other services; (ii) permitting holders of firm capacity on interstate natural gas pipelines to release all or a part of their capacity for resale by the pipeline; and (iii) the issuance of blanket sales certificates to interstate pipelines for unbundled services. Order 636 has been affirmed in all material respects upon judicial review, and our own FERC orders approving our unbundling plans are final and not subject to any pending judicial review.

          On November 25, 2003, the FERC issued Order No. 2004, adopting revised Standards of Conduct that apply uniformly to interstate natural gas pipelines and public utilities. In light of the changing structure of the energy industry, these Standards of Conduct govern relationships between regulated interstate natural gas pipelines and all of their energy affiliates. These new Standards of Conduct were designed to eliminate the loophole in the previous regulations that did not cover an interstate natural gas pipeline’s relationship with energy affiliates that are not marketers. The rule is designed to prevent interstate natural gas pipelines from giving an undue preference to any of their energy affiliates and to ensure that transmission is provided on a nondiscriminatory basis. In addition, unlike the prior regulations, these requirements apply even if the energy affiliate is not a customer of its affiliated interstate pipeline. Our interstate natural gas pipelines are in compliance with these Standards of Conduct.

          On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated Order No. 2004, as applied to natural gas pipelines, and remanded the Order back to the FERC. On January 9, 2007, the FERC issued an interim rule regarding standards of conduct in Order 690 to be effective immediately. The interim rule repromulgated the standards of conduct that were not challenged before the court. On January 18, 2007, the FERC issued a notice of proposed rulemaking soliciting comments on whether or not the interim rule should be made permanent for natural gas transmission providers.

          Please refer to Note 17 to our consolidated financial statements included elsewhere in this report for additional information regarding FERC Order No. 2004 and other Standards of Conduct rulemaking.

          On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, directed the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and significantly increased the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.

          California Public Utilities Commission Rate Regulation

          The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the California Public Utilities Commission, referred to in this report as the CPUC, under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of our Pacific operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates could also arise with respect to

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our intrastate rates. Certain of our Pacific operations’ pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 16 to our consolidated financial statements included elsewhere in this report.

          Texas Railroad Commission Rate Regulation

          The intrastate common carrier operations of our natural gas and crude oil pipelines in Texas are subject to certain regulation with respect to such intrastate transportation by the Texas Railroad Commission. Although the Texas Railroad Commission has the authority to regulate our rates, the Commission has generally not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.

          Safety Regulation

          Our interstate pipelines are subject to regulation by the United States Department of Transportation, referred to in this report as U.S. DOT, and our intrastate pipelines and other operations are subject to comparable state regulations with respect to their design, installation, testing, construction, operation, replacement and management. Comparable regulation exists in some states in which we conduct pipeline operations. In addition, our truck and terminal loading facilities are subject to U.S. DOT regulations dealing with the transportation of hazardous materials by motor vehicles and railcars. We believe that we are in substantial compliance with U.S. DOT and comparable state regulations.

          The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication. The Pipeline Safety Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Testing consists of hydrostatic testing, internal magnetic flux or ultrasonic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. The U.S. DOT has approved our qualification program. We believe that we are in substantial compliance with this law’s requirements and have integrated appropriate aspects of this pipeline safety law into our internal Operator Qualification Program. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001.

          We are also subject to the requirements of the Federal Occupational Safety and Health Act and other comparable federal and state statutes. We believe that we are in substantial compliance with Federal OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to hazardous substances.

          In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards. Some of these changes, such as U.S. DOT implementation of additional hydrostatic testing requirements, could significantly increase the amount of these expenditures. Such increases in our expenditures cannot be accurately estimated at this time.

          State and Local Regulation

          Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and safety.

          Environmental Matters

          Our operations are subject to federal, state and local, and some foreign laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe that our operations are in substantial compliance with applicable environmental laws and regulations.

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          We accrue liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate our actual joint and several liability exposures. Although no assurance can be given, we believe that the ultimate resolution of all these environmental matters will not have a material adverse effect on our business, financial position or results of operations. We have accrued an environmental reserve in the amount of $92.0 million as of December 31, 2007. Our reserve estimates range in value from approximately $92.0 million to approximately $142.7 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 16 to our consolidated financial statements included elsewhere in this report.

          Solid Waste

          We generate both hazardous and non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. From time to time, state regulators and the United States Environmental Protection Agency consider the adoption of stricter disposal standards for non-hazardous waste. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during pipeline or liquids or bulk terminal operations, may in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

          Superfund

          The Comprehensive Environmental Response, Compensation and Liability Act, also known as the “Superfund” law or “CERCLA,” and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of “potentially responsible persons” for releases of “hazardous substances” into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the U.S. EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although “petroleum” is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations, we have and will generate materials that may fall within the definition of “hazardous substance.” By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.

          Clean Air Act

          Our operations are subject to the Clean Air Act, as amended, and analogous state statutes. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. The Clean Air Act, as amended, contains lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our pipelines, treating facilities, storage facilities and terminals. Depending on the nature of those requirements and any additional requirements that may be imposed by state and local regulatory authorities, we may be required to incur certain capital and operating expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission-related issues.

          Due to the broad scope and complexity of the issues involved and the resultant complexity and nature of the regulations, full development and implementation of many Clean Air Act regulations by the U.S. EPA and/or various state and local regulators have been delayed. Therefore, until such time as the new Clean Air Act requirements are implemented, we are unable to fully estimate the effect on earnings or operations or the amount

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and timing of such required capital expenditures. At this time, however, we do not believe that we will be materially adversely affected by any such requirements.

          Clean Water Act

          Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act as they pertain to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release. We believe we are in substantial compliance with these laws.

          Other

          KMGP Services Company, Inc., Knight and Kinder Morgan Canada Inc. employ all persons necessary for the operation of our business. Generally, we reimburse these entities for the services of their employees. As of December 31, 2007, KMGP Services Company, Inc., Knight and Kinder Morgan Canada Inc. had, in the aggregate, approximately 7,600 full-time employees. Approximately 920 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2008 and 2012. KMGP Services Company, Inc., Knight and Kinder Morgan Canada Inc. each consider relations with their employees to be good. For more information on our related party transactions, see Note 12 of the notes to our consolidated financial statements included elsewhere in this report.

          We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property or the interests in those properties or the use of such properties in our businesses. We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee.

          (d) Financial Information about Geographic Areas

          For geographic information concerning our assets and operations, see Note 15 to our consolidated financial statements.

          (e) Available Information

          We make available free of charge on or through our Internet website, at www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

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Item 1A. Risk Factors.

          You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations. There are also risks associated with being an owner of common units in a partnership that are different than being an owner of common stock in a corporation. Investors in our common units must be aware that the realization of any of those risks could result in a decline in the trading price of our common units, and they might lose all or part of their investment.

          Risks Related to Our Business

          Pending Federal Energy Regulatory Commission and California Public Utilities Commission proceedings seek substantial refunds and reductions in tariff rates on some of our pipelines. If the proceedings are determined adversely to us, they could have a material adverse impact on us.

          Regulators and shippers on our pipelines have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the Federal Energy Regulatory Commission and California Public Utilities Commission that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates on our Pacific operations’ pipeline system. We may face challenges, similar to those described in Note 16 to our consolidated financial statements included elsewhere in this report, to the rates we receive on our pipelines in the future. Any successful challenge could adversely and materially affect our future earnings and cash flows.

          Rulemaking and oversight, as well as changes in regulations, by the Federal Energy Regulatory Commission or other regulatory agencies having jurisdiction over our operations could adversely impact our income and operations.

          The rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) we charge shippers on our natural gas pipeline systems are subject to regulatory approval and oversight. Furthermore, regulators and shippers on our natural gas pipelines have rights to challenge the rates shippers are charged under certain circumstances prescribed by applicable regulations. We can provide no assurance that we will not face challenges to the rates we receive on our pipeline systems in the future. Any successful challenge could materially adversely affect our future earnings and cash flows. New laws or regulations or different interpretations of existing laws or regulations applicable to our assets could have a material adverse impact on our business, financial condition and results of operations.

          Increased regulatory requirements relating to the integrity of our pipelines will require us to spend additional money to comply with these requirements.

          Through our regulated pipeline subsidiaries, we are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines for the U.S. Department of Transportation and pipeline companies in the areas of testing, education, training and communication. Compliance with laws and regulations requires significant expenditures. We have increased our capital expenditures to address these matters and expect to significantly increase these expenditures in the foreseeable future. Additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures.

          Cost overruns and delays on our expansion and new build projects could adversely affect our business.

          We currently have several major expansion and new build projects planned or underway, including the approximate $4.9 billion Rockies Express Pipeline and the approximate $1.3 billion Midcontinent Express Pipeline. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third party contractors has resulted in, and may continue to result in, increased costs or delays in construction. Cost overruns or delays in completing a project could have a material adverse effect on our results of operations and cash flows.

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          Our rapid growth may cause difficulties integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions.

          Part of our business strategy includes acquiring additional businesses, expanding existing assets, or constructing new facilities that will allow us to increase distributions to our unitholders. If we do not successfully integrate acquisitions, expansions, or newly constructed facilities, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including:

• demands on management related to the increase in our size after an acquisition, an expansion, or a completed construction project;

• the diversion of our management’s attention from the management of daily operations;

• difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems;

• difficulties in the assimilation and retention of necessary employees; and

• potential adverse effects on operating results.

          We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each acquisition, expansion, or construction project will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

          Our acquisition strategy and expansion programs require access to new capital. Tightened credit markets or more expensive capital would impair our ability to grow.

          Part of our business strategy includes acquiring additional businesses. We may need new capital to finance these acquisitions. Limitations on our access to capital will impair our ability to execute this strategy. We normally fund acquisitions with short-term debt and repay such debt through the issuance of equity and long-term debt. An inability to access the capital markets may result in a substantial increase in our leverage and have a detrimental impact on our credit profile.

          Environmental regulation and liabilities could result in increased operating and capital costs.

          Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the United States and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other products occurs at or from our pipelines or at or from our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities. The costs of environmental regulation are already significant, and additional or more stringent regulation could increase these costs or could otherwise negatively affect our business.

          In addition, our oil and gas development and production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, we are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be

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abandoned and reclaimed to the satisfaction of state authorities. The costs of environmental regulation are already significant, and additional or more stringent regulation could increase these costs or could otherwise negatively affect our business.

          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.

          The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable.

          The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves and revenues of our oil producing assets within our CO₂ business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we will be liable to perform on hedges currently valued at greater than $1.3 billion in favor of our counter-parties.

          The development of oil and gas properties involves risks that may result in a total loss of investment.

          The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well, or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

          The volatility of natural gas and oil prices could have a material adverse effect on our business.

          The revenues, profitability and future growth of our CO₂ business segment and the carrying value of our oil and natural gas properties depend to a large degree on prevailing oil and gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things, weather conditions and events such as hurricanes in the United States; the condition of the United States economy; the activities of the Organization of Petroleum Exporting Countries; governmental regulation; political stability in the Middle East and elsewhere; the foreign supply of oil and natural gas; the price of foreign imports; and the availability of alternative fuel sources.

          A sharp decline in the price of natural gas or oil prices would result in a commensurate reduction in our revenues, income and cash flows from the production of oil and natural gas and could have a material adverse effect on the carrying value of our proved reserves. In the event prices fall substantially, we may not be able to realize a

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profit from our production and would operate at a loss. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand.

          Our use of hedging arrangements could result in financial losses or reduce our income.

          We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.

          The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or to balance our exposure to fixed and floating interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

          We do not own approximately 97.5% of the land on which our pipelines are constructed, and we are subject to the possibility of increased costs to retain necessary land use.

          We obtain the right to construct and operate pipelines on other owners’ land for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be affected negatively.

          Whether we have the power of eminent domain for our pipelines varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas or carbon dioxide—and the laws of the particular state. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. For the year ended December 31, 2007, all of our right-of-way related expenses totaled $14.6 million.

          Our debt instruments may limit our financial flexibility and increase our financing costs.

          The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. The agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more restrictive restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.

          Because a portion of our debt is subject to variable interest rates, if interest rates increase, our earnings could be adversely affected.

          As of December 31, 2007, we had approximately $3.0 billion of debt, excluding the value of interest rate swaps, subject to variable interest rates. This amount included $2.3 billion of long-term fixed rate debt effectively converted to variable rate debt through the use of interest rate swaps. Should interest rates increase significantly, our earnings could be adversely affected. For information on our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

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          Current or future distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the services we provide.

          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 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, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

          The general uncertainty associated with the current world economic and political environments in which we exist may adversely impact our financial performance.

          Our financial performance is impacted by overall marketplace spending and demand. We are continuing to assess the effect that terrorism would have on our businesses and in response, we have increased security with respect to our assets. Recent federal legislation provides an insurance framework that should cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies. Nonetheless, there is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable throughout 2008.

          Knight’s recently completed going-private transaction resulted in substantially more debt at Knight and could have an adverse effect on us, such as a downgrade in the ratings of our debt securities.

          On May 30, 2007, Knight completed its going-private transaction. 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 and 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. Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007.

          Our senior management’s attention may be diverted from our daily operations because of recent significant transactions by Knight following the completion of the going-private transaction.

          The investors in Knight Holdco LLC include members of Knight’s senior management, 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.

          Competition could ultimately lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation capacity at favorable rates.

          Trans Mountain’s pipeline to the West Coast of North America is one of several pipeline alternatives for Western Canadian petroleum production. This pipeline, like all our petroleum pipelines, competes against other pipeline companies who could be in a position to offer different tolling structures, which may provide them with a competitive advantage in new pipeline development. Throughput on our pipelines may decline if tolls become uncompetitive compared to alternatives.

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          Future business development of our products pipelines is dependent on the supply of, and demand for, crude oil and other liquid hydrocarbons, particularly from the Alberta oilsands.

          Our pipelines depend on production of natural gas, oil and other products in the areas serviced by our pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut down production at lower product prices or higher production costs, especially where the existing cost of production exceeds other extraction methodologies, such as at the Alberta oilsands. Producers in areas serviced by us may not be successful in exploring for and developing additional reserves, and the gas plants and the pipelines may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at a level which encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.

          Changes in the business environment, such as a decline in crude oil prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from the Alberta oilsands. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil. Each of these factors impact our customers shipping through our pipelines, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts.

          Throughput on our products pipelines may also decline as a result of changes in business conditions. Over the long term, business will depend, in part, on the level of demand for oil and natural gas in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas and crude oil, increase our costs and may have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas and oil.

          We are subject to U.S. dollar/Canadian dollar exchange rate fluctuations.

          As a result of our acquisition of the Trans Mountain pipeline system, the Vancouver Wharves terminal, the Cochin pipeline system, and our terminal expansion projects located in Edmonton, Alberta, Canada, a portion of our assets, liabilities, revenues and expenses are denominated in Canadian dollars. We are a U.S. dollar reporting company. Fluctuations in the exchange rate between United States and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our partners’ capital under applicable accounting rules.

          Risks Related to Our Common Units

          The interests of Knight may differ from our interests and the interests of our unitholders.

          Knight indirectly owns all of the stock of our general partner and elects all of its directors. Our general partner owns all of KMR’s voting shares and elects all of its directors. Furthermore, some of KMR’s directors and officers are also directors and officers of Knight and our general partner and have fiduciary duties to manage the businesses of Knight in a manner that may not be in the best interests of our unitholders. Knight has a number of interests that differ from the interests of our unitholders. As a result, there is a risk that important business decisions will not be made in the best interests of our unitholders.

          Common unitholders have limited voting rights and limited control.

          Holders of common units have only limited voting rights on matters affecting us. Our general partner manages partnership activities. Under a delegation of control agreement, our general partner has delegated the management and control of our and our subsidiaries’ business and affairs to KMR. Holders of common units have no right to elect the general partner on an annual or other ongoing basis. If the general partner withdraws, however, its successor may be elected by the holders of a majority of the outstanding common units (excluding units owned by the departing general partner and its affiliates).

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          The limited partners may remove the general partner only if (i) the holders of at least 66 2/3% of the outstanding common units, excluding common units owned by the departing general partner and its affiliates, vote to remove the general partner; (ii) a successor general partner is approved by at least 66 2/3% of the outstanding common units, excluding common units owned by the departing general partner and its affiliates; and (iii) we receive an opinion of counsel opining that the removal would not result in the loss of limited liability to any limited partner, or the limited partner of an operating partnership, or cause us or the operating partnership to be taxed other than as a partnership for federal income tax purposes.

          A person or group owning 20% or more of the common units cannot vote.

          Any common units held by a person or group that owns 20% or more of the common units cannot be voted. This limitation does not apply to the general partner and its affiliates. This provision may (i) discourage a person or group from attempting to remove the general partner or otherwise change management; and (ii) reduce the price at which the common units will trade under certain circumstances. For example, a third party will probably not attempt to take over our management by making a tender offer for the common units at a price above their trading market price without removing the general partner and substituting an affiliate of its own.

          The general partner’s liability to us and our unitholders may be limited.

          Our partnership agreement contains language limiting the liability of the general partner to us or the holders of common units. For example, our partnership agreement provides that (i) the general partner does not breach any duty to us or the holders of common units by borrowing funds or approving any borrowing (the general partner is protected even if the purpose or effect of the borrowing is to increase incentive distributions to the general partner); (ii) the general partner does not breach any duty to us or the holders of common units by taking any actions consistent with the standards of reasonable discretion outlined in the definitions of available cash and cash from operations contained in our partnership agreement; and (iii) the general partner does not breach any standard of care or duty by resolving conflicts of interest unless the general partner acts in bad faith.

          Unitholders may have liability to repay distributions.

          Unitholders will not be liable for assessments in addition to their initial capital investment in the common units. Under certain circumstances, however, holders of common units may have to repay us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of such a distribution, a limited partner who receives the distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to the assignee at the time the assignee became a limited partner if the liabilities could not be determined from the partnership agreement.

          Unitholders may be liable if we have not complied with state partnership law.

          We conduct our business in a number of states. In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established. The unitholders might be held liable for the partnership’s obligations as if they were a general partner if (i) a court or government agency determined that we were conducting business in the state but had not complied with the state’s partnership statute; or (ii) unitholders’ rights to act together to remove or replace the general partner or take other actions under our partnership agreement constitute “control” of our business.

          The general partner may buy out minority unitholders if it owns 80% of the units.

          If at any time the general partner and its affiliates own 80% or more of the issued and outstanding common units, the general partner will have the right to purchase all, and only all, of the remaining common units. Because of this right, a unitholder could have to sell its common units at a time or price that may be undesirable. The purchase price

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for such a purchase will be the greater of (i) the 20-day average trading price for the common units as of the date five days prior to the date the notice of purchase is mailed; or (ii) the highest purchase price paid by the general partner or its affiliates to acquire common units during the prior 90 days. The general partner can assign this right to its affiliates or to us.

          We may sell additional limited partner interests, diluting existing interests of unitholders.

          Our partnership agreement allows the general partner to cause us to issue additional common units and other equity securities. When we issue additional equity securities, including additional i-units to KMR when it issues additional shares, unitholders’ proportionate partnership interest in us will decrease. Such an issuance could negatively affect the amount of cash distributed to unitholders and the market price of common units. Issuance of additional common units will also diminish the relative voting strength of the previously outstanding common units. Our partnership agreement does not limit the total number of common units or other equity securities we may issue.

          The general partner can protect itself against dilution.

          Whenever we issue equity securities to any person other than the general partner and its affiliates, the general partner has the right to purchase additional limited partnership interests on the same terms. This allows the general partner to maintain its proportionate partnership interest in us. No other unitholder has a similar right. Therefore, only the general partner may protect itself against dilution caused by issuance of additional equity securities.

          Our partnership agreement and the KMR limited liability company agreement restrict or eliminate a number of the fiduciary duties that would otherwise be owed by our general partner and/or its delegate to our unitholders.

          Modifications of state law standards of fiduciary duties may significantly limit the ability of our unitholders to successfully challenge the actions of our general partner in the event of a breach of fiduciary duties. These state law standards include the duties of care and loyalty. The duty of loyalty, in the absence of a provision in the limited partnership agreement to the contrary, would generally prohibit our general partner from taking any action or engaging in any transaction as to which it has a conflict of interest. Our limited partnership agreement contains provisions that prohibit limited partners from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law. For example, that agreement provides that the general partner may take into account the interests of parties other than us in resolving conflicts of interest. It also provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general partner will not be a breach of any duty. The provisions relating to the general partner apply equally to KMR as its delegate. It is not necessary for a limited partner to sign our limited partnership agreement in order for the limited partnership agreement to be enforceable against that person.

          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.

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          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. A successful 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.

          Our tax treatment 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 if 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. Members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly-traded partnerships. For example, federal income tax legislation has been proposed that would eliminate partnership tax treatment for certain publicly-traded partnerships. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

          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.

          The issuance of additional i-units may cause more taxable income to be allocated to the common units.

          The i-units we issue to KMR generally are not allocated income, gain, loss or deduction for federal income tax purposes until such time as we are liquidated. Therefore, the issuance of additional i-units may cause more taxable income and gain to be allocated to the common unitholders.

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          Risks Related to Ownership of Our Common Units if We or Knight Defaults on Debt

          Unitholders may have negative tax consequences if we default on our debt or sell assets.

          If we default on any of our debt, the lenders will have the right to sue us for non-payment. Such an action could cause an investment loss and cause negative tax consequences for unitholders through the realization of taxable income by unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, unitholders could have increased taxable income without a corresponding cash distribution.

          There is the potential for a change of control if Knight defaults on debt.

          Knight owns all of the outstanding capital stock of our general partner. Knight has operations which provide cash independent of dividends that Knight receives from our general partner. Nevertheless, if Knight defaults on its debt, in exercising their rights as lenders, Knight’s lenders could acquire control of our general partner or otherwise influence our general partner through control of Knight.

Item 1B. Unresolved Staff Comments.

          None.

Item 3. Legal Proceedings.

          See Note 16 of the notes to our consolidated financial statements included elsewhere in this report.

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

          There were no matters submitted to a vote of our unitholders during the fourth quarter of 2007.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

          The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the New York Stock Exchange, the principal market in which our common units are traded, the amount of cash distributions declared per common and Class B unit, and the fractional i-unit distribution declared per i-unit.

	Price Range
	High		Low		Cash Distributions		i-unit Distributions
2007
First Quarter	$	53.50	$	47.28	$	0.8300		0.015378
Second Quarter		57.35		52.11		0.8500		0.016331
Third Quarter		56.70		46.61		0.8800		0.017686
Fourth Quarter		54.71		48.51		0.9200		0.017312
2006
First Quarter	$	56.22	$	44.70	$	0.8100		0.018566
Second Quarter		48.80		43.62		0.8100		0.018860
Third Quarter		46.53		42.80		0.8100		0.018981
Fourth Quarter		48.98		43.01		0.8300		0.016919

          Distribution information is for distributions declared with respect to that quarter. The declared distributions were paid within 45 days after the end of the quarter. We currently expect to declare cash distributions of at least $4.02 per unit for 2008; however, no assurance can be given that we will be able to achieve this level of distribution, and our expectation does not take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’ interstate pipelines.

          As of January 31, 2008, there were approximately 190,660 holders of our common units (based on the number of record holders and individual participants in security position listings), one holder of our Class B units and one holder of our i-units.

          For information on our equity compensation plans, see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Equity Compensation Plan Information”.

          We did not repurchase any units during 2007 or sell any unregistered units in the fourth quarter of 2007.

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Item 6. Selected Financial Data

          The following tables set forth, for the periods and at the dates indicated, our summary historical financial and operating data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements. See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information.

	Year Ended December 31,
	2007(6)			2006(7)			2005(8)			2004(9)			2003(10)
	(In millions, except per unit and ratio data)
Income and Cash Flow Data:
Revenues	$	9,217.7		$	9,048.7		$	9,745.9		$	7,893.0		$	6,583.6
Costs, Expenses and Other:
Gas purchases and other costs of sales		5,809.8			5,990.9			7,167.3			5,767.0			4,880.0
Operations and maintenance		1,024.6			777.0			719.5			488.6			388.6
Fuel and power		237.5			223.7			178.5			146.4			102.2
Depreciation, depletion and amortization		540.0			423.9			341.6			281.1			212.2
General and administrative		278.7			238.4			216.7			170.5			150.5
Taxes, other than income taxes		153.8			134.4			106.5			79.1			60.3
Other expense (income)		365.6			(31.2	)		—			—			—
		8,410.0			7,757.1			8,730.1			6,932.7			5,793.8
Operating income		807.7			1,291.6			1,015.8			960.3			789.8
Other income/(expense):
Earnings from equity investments		69.7			74.0			89.6			81.8			91.2
Amortization of excess cost of equity investments		(5.8	)		(5.6	)		(5.5	)		(5.6	)		(5.5	)
Interest, net		(391.4	)		(337.8	)		(259.0	)		(192.9	)		(181.4	)
Other, net		14.2			12.0			3.3			2.2			7.6
Minority interest		(7.0	)		(15.4	)		(7.3	)		(9.6	)		(9.0	)
Income tax provision		(71.0	)		(29.0	)		(24.5	)		(19.7	)		(16.6	)
Income from continuing operations		416.4			989.8			812.4			816.5			676.1
Income (loss) from discontinued operations(1)		173.9			14.3			(0.2	)		15.1			17.8
Income before cumulative effect of a change in accounting principle		590.3			1,004.1			812.2			831.6			693.9
Cumulative effect of a change in accounting principle		—			—			—			—			3.4
Net income	$	590.3		$	1,004.1		$	812.2		$	831.6		$	697.3
Less: General Partner’s interest in net income		(611.6	)		(513.3	)		(477.3	)		(395.1	)		(326.5	)
Limited Partners’ interest in net income (loss)	$	(21.3	)	$	490.8		$	334.9		$	436.5		$	370.8
Basic Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations and before cumulative effect of a change in accounting principle(2)	$	(0.82	)	$	2.12		$	1.58		$	2.14		$	1.89
Income from discontinued operations		0.73			0.07			—			0.08			0.09
Cumulative effect of a change in accounting principle		—			—			—			—			0.02
Net income (loss) per unit	$	(0.09	)	$	2.19		$	1.58		$	2.22		$	2.00
Diluted Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations and bef. cumulative effect of a change in acctg. principle(2)	$	(0.82	)	$	2.12		$	1.58		$	2.14		$	1.89
Income from discontinued operations		0.73			0.06			—			0.08			0.09
Cumulative effect of a change in accounting principle		—			—			—			—			0.02
Net income (loss) per unit	$	(0.09	)	$	2.18		$	1.58		$	2.22		$	2.00
Per unit cash distribution declared(3)	$	3.48		$	3.26		$	3.13		$	2.87		$	2.63
Ratio of earnings to fixed charges(4)	$	2.13		$	3.64			3.76			4.84			4.68
Additions to property, plant and equipment	$	1,691.6		$	1,182.1		$	863.1		$	747.3		$	577.0
Balance Sheet Data (at end of period):
Net property, plant and equipment	$	11,591.3		$	10,106.1		$	8,864.6		$	8,168.9		$	7,091.6
Total assets	$	15,177.8		$	13,542.2		$	11,923.5		$	10,552.9		$	9,139.2
Long-term debt(5)	$	6,455.9		$	4,384.3		$	5,220.9		$	4,722.4		$	4,316.7

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(1)	Represents income or loss from the operations of our North System natural gas liquids pipeline system. For 2007 only, also includes a gain of $152.8 million on disposal of our North System. For more information on our discontinued operations, see Note 3 to our consolidated financial statements included elsewhere in this report.
(2)	Represents income from continuing operations before cumulative effect of a change in accounting principle per unit. Basic Limited Partners’ income per unit from continuing operations before cumulative effect of a change in accounting principle was computed by dividing the interest of our unitholders in income from continuing operations before cumulative effect of a change in accounting principle 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.
(3)	Represents the amount of cash distributions declared with respect to that year.
(4)	For the purpose of computing the ratio of earnings to fixed charges, earnings are defined as income from continuing operations before income taxes and cumulative effect of a change in accounting principle, and before minority interest in consolidated subsidiaries, equity earnings (including amortization of excess cost of equity investments) and unamortized capitalized interest, plus fixed charges and distributed income of equity investees. Fixed charges are defined as the sum of interest on all indebtedness (excluding capitalized interest), amortization of debt issuance costs and that portion of rental expense which we believe to be representative of an interest factor.
(5)	Excludes value of interest rate swaps. Increases to long-term debt for value of interest rate swaps totaled $152.2 million as of December 31, 2007, $42.6 million as of December 31, 2006, $98.5 million as of December 31, 2005, $130.2 million as of December 31, 2004, and $121.5 million as of December 31, 2003.
(6)	Includes results of operations for an approximate 50.2% interest in the Cochin pipeline system, the Vancouver Wharves marine terminal, and terminal assets acquired from Marine Terminals, Inc. since effective dates of acquisition. We acquired the remaining 50.2% interest in Cochin that we did not already own from affiliates of BP effective January 1, 2007. We acquired the Vancouver Wharves bulk marine terminal operations from British Columbia Railway Company effective May 30, 2007, and we acquired certain bulk terminal assets from Marine Terminals, Inc. effective September 1, 2007. Also includes Trans Mountain since January 1, 2007 as discussed below.
(7)	Includes results of operations for the net assets of Trans Mountain acquired on April 30, 2007 from Knight Inc. (formerly Kinder Morgan, Inc.) since January 1, 2006. Also includes results of operations for the oil and gas properties acquired from Journey Acquisition-I, L.P. and Journey 2000, L.P., the terminal assets and operations acquired from A&L Trucking, L.P. and U.S. Development Group, Transload Services, LLC, and Devco USA L.L.C. since effective dates of acquisition. The April 5, 2006 acquisition of the Journey oil and gas properties were made effective March 1, 2006. The assets and operations acquired from A&L Trucking and U.S. Development Group were acquired in three separate transactions in April 2006. We acquired all of the membership interests in Transload Services, LLC effective November 20, 2006, and we acquired all of the membership interests in Devco USA L.L.C. effective December 1, 2006. We also acquired a 66 2/3% ownership interest in Entrega Pipeline LLC effective February 23, 2006, however, our earnings were not materially impacted during 2006 due to the fact that regulatory accounting provisions required capitalization of revenues and expenses until the second segment of the Entrega Pipeline was complete and in-service.
(8)	Includes results of operations for the 64.5% interest in the Claytonville unit, the seven bulk terminal operations acquired from Trans-Global Solutions, Inc., the Kinder Morgan Staten Island terminal, the terminal facilities located in Hawesville, Kentucky and Blytheville, Arkansas, General Stevedores, L.P., the North Dayton natural gas storage facility, the Kinder Morgan Blackhawk terminal, the terminal repair shop acquired from Trans-Global Solutions, Inc., and the terminal assets acquired from Allied Terminals, Inc. since effective dates of acquisition. We acquired the 64.5% interest in the Claytonville unit effective January 31, 2005. We acquired the seven bulk terminal operations from Trans-Global Solutions, Inc. effective April 29, 2005. The Kinder Morgan Staten Island terminal, the Hawesville, Kentucky terminal and the Blytheville, Arkansas terminal were each acquired separately in July 2005. We acquired all of the partnership interests in General Stevedores, L.P. effective July 31, 2005. We acquired the North Dayton natural gas storage facility effective August 1, 2005. We acquired the Kinder Morgan Blackhawk terminal in August 2005 and the terminal repair shop in September 2005. We acquired the terminal assets from Allied Terminals, Inc. effective November 4, 2005.
(9)	Includes results of operations for the seven refined petroleum products terminals acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an additional 5% interest in the Cochin Pipeline System, Kinder Morgan River Terminals LLC and its consolidated subsidiaries, TransColorado Gas Transmission Company LLC, interests in nine refined petroleum products terminals acquired from Charter Terminal Company and Charter-Triad Terminals, LLC, and the Kinder Morgan

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Fairless Hills terminal since effective dates of acquisition. We acquired the seven refined petroleum products terminals from ExxonMobil effective March 9, 2004. We acquired Kinder Morgan Wink Pipeline, L.P. effective August 31, 2004. The additional interest in Cochin was acquired effective October 1, 2004. We acquired Kinder Morgan River Terminals LLC and its consolidated subsidiaries effective October 6, 2004. We acquired TransColorado effective November 1, 2004, the interests in the nine Charter Terminal Company and Charter-Triad Terminals, LLC refined petroleum products terminals effective November 5, 2004, and the Kinder Morgan Fairless Hills terminal effective December 1, 2004.

(10)

Includes results of operations for the bulk terminal operations acquired from M.J. Rudolph Corporation, the additional 12.75% interest in the SACROC unit, the five refined petroleum products terminals acquired from Shell, the additional 42.5% interest in the Yates field unit, the crude oil gathering operations surrounding the Yates field unit, an additional 65% interest in the Pecos Carbon Dioxide Company, the remaining approximate 32% interest in MidTex Gas Storage Company, LLP, the seven refined petroleum products terminals acquired from ConocoPhillips and two bulk terminal facilities located in Tampa, Florida since dates of acquisition. We acquired certain bulk terminal operations from M.J. Rudolph effective January 1, 2003. The additional 12.75% interest in SACROC was acquired effective June 1, 2003. The five refined petroleum products terminals were acquired effective October 1, 2003. The additional 42.5% interest in the Yates field unit, the Yates gathering system and the additional 65% interest in Pecos Carbon Dioxide Company were acquired effective November 1, 2003. The additional 32% ownership interest in MidTex was acquired November 1, 2003. The seven refined petroleum products terminals were acquired December 11, 2003, and the two bulk terminal facilities located in Tampa, Florida were acquired effective December 10 and 23, 2003.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

          The following discussion and analysis of our financial condition and results of operations provides a narrative of our financial results. It contains a discussion and analysis of the results of operations for each segment of our business, followed by a discussion and analysis of our financial condition. The following discussion and analysis is based on our consolidated financial statements, which are included elsewhere in this report and were prepared in accordance with accounting principles generally accepted in the United States of America.

          The following discussion and analysis should be read in conjunction with our consolidated financial statements included elsewhere in this report. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2007, found in Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”

          In addition, as discussed in Note 3 of the accompanying notes to our consolidated financial statements, our financial statements reflect:

• the April 30, 2007 transfer of Trans Mountain as if such transfer had taken place on January 1, 2006, the effective date of common control pursuant to generally accepted accounting principles. The financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations includes the financial results of Trans Mountain for all periods subsequent to January 1, 2006; and

• the reclassifications necessary to reflect the results of our North System as discontinued operations. However, due to the fact that the sale of our North System does 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 results within our Products Pipelines business segment disclosures for all periods presented in this report.

          We begin with a discussion of our Critical Accounting Polices and Estimates, those areas that are both very important to the portrayal of our financial condition and results and which require our management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.

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Critical Accounting Policies and Estimates

          Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of generally accepted accounting principles involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements.

          We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

          In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining:

• the economic useful lives of our assets;

• the fair values used to allocate purchase price and to determine possible asset impairment charges;

• reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities;

• provisions for uncollectible accounts receivables;

• exposures under contractual indemnifications; and

• unbilled revenues.

          For a summary of our significant accounting policies, see Note 2 to our consolidated financial statements included elsewhere in this report. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.

          Environmental Matters

          With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. We do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

          Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates.

          These environmental liability adjustments are recorded pursuant to our management’s requirement to recognize contingent environmental liabilities whenever the associated environmental issue is likely to occur and the amount of our liability can be reasonably estimated. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. For more information on our environmental disclosures, see Note 16 to our consolidated financial statements included elsewhere in this report.

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          Legal Matters

          We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available.

          As of December 31, 2007, our most significant ongoing litigation proceedings involve our SFPP, L.P, subsidiary, which is the limited partnership that owns our Pacific operations’ pipelines, excluding CALNEV Pipe Line LLC. Tariffs charged by our Pacific operations’ pipeline systems are subject to certain proceedings at the FERC involving shippers’ complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services. Generally, the interstate rates on our Pacific operations’ pipeline systems are “grandfathered” under the Energy Policy Act of 1992 unless “substantially changed circumstances” are found to exist. To the extent “substantially changed circumstances” are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints and could, therefore, owe reparations and/or refunds to complainants as mandated by the FERC or the United States’ judicial system. For more information on our Pacific operations’ regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report.

          Intangible Assets

          Intangible assets are those assets which provide future economic benefit but have no physical substance. We account for our intangible assets according to the provisions of Statement of Financial Accounting Standards No. 141, “Business Combinations” and Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.” These accounting pronouncements introduced the concept of indefinite life intangible assets and provided that all identifiable intangible assets having indefinite useful economic lives, including goodwill, will not be subject to regular periodic amortization. Such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We have selected an impairment measurement test date of January 1 of each year, and we have determined that our goodwill was not impaired as of January 1, 2008.

          As of December 31, 2007, our goodwill was $1,077.8 million. Included in this goodwill balance is $251.0 million related to our Trans Mountain business segment, which we acquired from Knight on April 30, 2007. Following the provisions of generally accepted accounting principles, 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. Knight recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007. This impairment is also reflected on our books due to the accounting principles for transfers of assets between entities under common control, which require us to account for Trans Mountain as if the transfer had taken place on January 1, 2006.

          Our remaining intangible assets, excluding goodwill, 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. As of December 31, 2007 and 2006, these intangibles totaled $238.6 million and $213.2 million, respectively.

          Estimated Net Recoverable Quantities of Oil and Gas

          We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are

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capitalized or expensed, the amount and timing of costs depleted or amortized into income and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas.

          Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.

          Hedging Activities

          We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices and to balance our exposure to fixed and floating interest rates, and we believe that these hedges are generally effective in realizing these objectives. However, the accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes.

          According to the provisions of current accounting standards, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. A perfectly effective hedge is one in which changes in the value of the derivative contract exactly offset changes in the value of the hedged item or expected cash flow of the future transactions in reporting periods covered by the derivative contract. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately; accordingly, our financial statements may reflect some volatility due to these hedges.

          In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations. Even when we cannot enter into a completely effective hedge, we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all, but due to the fact that the part of the hedging transaction that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

Results of Operations

Our business model is built to support two principal components:
•	helping customers by providing energy, bulk commodity and liquids products transportation, storage and distribution; and
•	creating long-term value for our unitholders.

          To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, bulk and liquids terminal facilities, and carbon dioxide and petroleum reserves. Our reportable business segments are based on the way our management organizes our enterprise, and each of our five segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.

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Consolidated
	Year Ended December 31,
	2007			2006			2005
		(In millions)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(b)	$	569.6		$	491.2		$	370.1
Natural Gas Pipelines(c)		600.2			574.8			500.3
CO2 (d)		537.0			488.2			470.9
Terminals(e)		416.0			408.1			314.6
Trans Mountain(f)		(293.6	)		76.5			—
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		1,829.2			2,038.8			1,655.9
Depreciation, depletion and amortization expense(g)		(547.0	)		(432.8	)		(349.8	)
Amortization of excess cost of equity investments		(5.8	)		(5.7	)		(5.6	)
Interest and corporate administrative expenses(h)		(686.1	)		(596.2	)		(488.3	)
Net income	$	590.3		$	1,004.1		$	812.2

(a)	Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses, and taxes, other than income taxes.
(b)	2007 amount includes (i) a $152.8 million gain from the sale of our North System; (ii) a $136.8 million increase in expense associated with rate case and other legal liability adjustments; (iii) a $15.9 million increase in expense associated with environmental liability adjustments; (iv) a $15.0 million expense for a litigation settlement reached with Contra Costa County, California; (v) a $3.2 million increase in expense from the settlement of certain litigation matters related to our West Coast refined products terminal operations; and (vi) a $1.8 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions. 2006 amount includes a $16.5 million increase in expense associated with environmental liability adjustments, and a $5.7 million increase in income resulting from certain transmix contract settlements. 2005 amount includes a $105.0 million increase in expense resulting from a rate case liability adjustment, a $13.7 million increase in expense resulting from a North System liquids inventory reconciliation adjustment, and a $19.6 million increase in expense associated with environmental liability adjustments.
(c)	2007 amount includes an expense of $1.0 million, reflecting our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company, and a $0.4 million decrease in expense associated with environmental liability adjustments. 2006 amount includes a $1.5 million increase in expense associated with environmental liability adjustments, a $15.1 million gain from the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation facility, and a $6.3 million reduction in expense due to the release of a reserve related to a natural gas purchase/sales contract. 2005 amount includes a $0.1 million reduction in expense associated with environmental liability adjustments.
(d)	2007 amount includes a $0.2 million increase in expense associated with environmental liability adjustments. 2006 amount includes a $1.8 million loss on derivative contracts used to hedge forecasted crude oil sales. 2005 amount includes a $0.3 million increase in expense associated with environmental liability adjustments.
(e)	2007 amount includes (i) a $25.0 million increase in expense from the settlement of certain litigation matters related to our Cora coal terminal; (ii) a $2.0 million increase in expense associated with environmental liability adjustments; (iii) an increase in income of $1.8 million from property casualty gains associated with the 2005 hurricane season; and (iv) a $1.2 million increase in expense associated with legal liability adjustments. 2006 amount includes an $11.3 million net increase in income from the net effect of a property casualty insurance gain and incremental repair and clean-up expenses (both associated with the 2005 hurricane season). 2005 amount includes a $3.5 million increase in expense associated with environmental liability adjustments.
(f)	As discussed in Note 3 to our consolidated financial statements included elsewhere in this report, our consolidated financial statements, and all other financial information included in this report, are presented as though the April 30, 2007 transfer of Trans Mountain net assets had occurred on the date when both Trans Mountain and we met the accounting requirements for entities under common control (January 1, 2006). 2007 amount includes losses of $349.2 million for periods prior to our acquisition date of April 30, 2007 (including a goodwill impairment expense of $377.1 million), and a $1.3 million decrease in income from an oil loss allowance. 2006 amount represents earnings for a period prior to our acquisition date of April 30, 2007.

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(g)

2007 and 2006 amounts include Trans Mountain expenses of $6.3 million and $19.0 million, respectively, for periods prior to our acquisition date of April 30, 2007.

(h)

Includes unallocated interest income and income tax expense, interest and debt expense, general and administrative expenses (including unallocated litigation and environmental expenses), and minority interest expense. 2007 amount includes the following: (i) a $26.2 million increase in expense, allocated to us from Knight, associated with closing the going-private transaction. Knight Inc. was responsible for the payment of the costs resulting from this transaction; (ii) a combined $6.7 million increase in expense, related to Trans Mountain interest and general and administrative expenses for periods prior to our acquisition date of April 30, 2007; (iii) a $2.4 million increase in interest expense related to our Cochin Pipeline acquisition; (iv) a $2.1 million expense due to the adjustment of certain insurance related liabilities; (v) a $1.7 million increase in expense associated with the 2005 hurricane season; (vi) a $1.5 million expense for certain Trans Mountain acquisition costs; (vii) a $0.8 million expense related to the cancellation of certain commercial insurance policies; and (viii) a total $3.9 million decrease in minority interest expense, related to the minority interest effect from all of the previously listed items. 2006 amount includes a combined $25.1 million expense related to Trans Mountain interest and general and administrative expenses, a $2.0 million increase in expense, primarily related to the cancellation of certain commercial insurance policies and a $3.5 million increase in minority interest expense, primarily related to the minority interest effect from the property casualty insurance gain described in footnote (e). 2005 amount includes a $25.0 million expense for a litigation settlement reached between us and a former joint venture partner on our Kinder Morgan Tejas natural gas pipeline system, a cumulative $8.4 million expense related to settlements of environmental matters at certain of our operating sites located in the state of California, and a $3.0 million decrease in expense related to proceeds received in connection with the settlement of claims in the Enron Corp. bankruptcy proceeding.

          For the year 2007, our net income was $590.3 million on revenues of $9,217.7 million. This compares with net income of $1,004.1 million on revenues of $9,048.7 million in 2006, and net income of $812.2 million on revenues of $9,745.9 million in 2005. The certain items described in the footnotes to the table above account for $483.3 million of the year-to-year decrease of $413.8 million. The remaining increase in net income is associated with better performance from our operating segments.

          The primary reason for the decrease in our 2007 net income, when compared to last year, was related to an impairment expense of $377.1 million associated with a non-cash reduction in the carrying value of Trans Mountain’s goodwill. Included within the certain items footnoted in the table above, and discussed above in “ — Intangibles,” the goodwill impairment charge was recognized by Knight in March 2007. 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 3 and 8 to our consolidated financial statements included elsewhere in this report.

          Segment earnings before depreciation, depletion and amortization expenses

          Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use 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.

          Combined, the certain items described in the footnotes to the table above decreased total segment earnings before depreciation, depletion and amortization by $489.1 million in 2007, relative to 2006 (combining to decrease total segment EBDA by $394.0 million in 2007 and to increase segment EBDA by $95.1 million in 2006). The remaining $279.5 million (14%) increase in segment earnings before depreciation, depletion and amortization in 2007 versus 2006 was driven by strong financial results from increased margins on natural gas transport, storage and processing activities, incremental earnings from dry-bulk product and petroleum liquids terminal operations, higher crude oil and natural gas liquids revenues, incremental earnings from completed expansion projects, and our acquisition of the Trans Mountain pipeline system and the remaining interest in the Cochin pipeline system that we did not already own.

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          In 2006, the certain items described above combined to increase total segment earnings before depreciation, depletion and amortization by$237.1 million, compared to the previous year (combining to increase total segment EBDA by $95.1 million in 2006 and to decrease segment EBDA by $142.0 million in 2005). The remaining $145.8 million (8%) increase in segment earnings before depreciation, depletion and amortization in 2006 versus 2005 was primarily attributable to internal growth and expansion across our business portfolio and to incremental contributions from assets and operations acquired since the end of 2005.

Products Pipelines

	Year Ended December 31,
	2007			2006			2005
	(In millions, except operating statistics)
Revenues	$	844.4		$	776.3		$	711.8
Operating expenses(a)		(451.8	)		(308.3	)		(366.0	)
Other income(b)		154.8			—			—
Earnings from equity investments(c)		32.5			16.3			28.5
Interest income and Other, net-income (expense)(d)		9.4			12.1			6.1
Income tax benefit (expense)(e)		(19.7	)		(5.2	)		(10.3	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	569.6		$	491.2		$	370.1
Gasoline (MMBbl)		435.5			449.8			452.1
Diesel fuel (MMBbl)		164.1			158.2			163.1
Jet fuel (MMBbl)		125.1			119.5			118.1
Total refined product volumes (MMBbl)		724.7			727.5			733.3
Natural gas liquids (MMBbl)		30.4			34.0			33.5
Total delivery volumes (MMBbl)(f)		755.1			761.5			766.8

(a)	2007, 2006 and 2005 amounts include increases in expense of $15.9 million, $13.5 million and $19.6 million, respectively, associated with environmental liability adjustments. 2007 amount also includes a $136.7 million increase in expense associated with rate case and other legal liability adjustments, a $15.0 million expense for a litigation settlement reached with Contra Costa County, California, and a $3.2 million increase in expense from the settlement of certain litigation matters related to our West Coast refined products terminal operations. 2005 amount also includes a $105.0 million increase in expense associated with a rate case liability adjustment, and a $13.7 million increase in expense associated with a North System liquids inventory reconciliation adjustment.
(b)	2007 amount includes a $152.8 million gain from the sale of our North System.
(c)	2007 amount includes a $0.1 million increase in expense associated with our proportional share of legal liability adjustments on Plantation Pipe Line Company. 2006 amount includes a $4.9 million increase in expense associated with our proportional share of environmental liability adjustments on Plantation Pipe Line Company.
(d)	2007 amount includes a $1.8 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions. 2006 amount includes a $5.7 million increase in income resulting from transmix contract settlements.
(e)	2006 amount includes a $1.9 million decrease in expense associated with our proportional share of the tax effect on our share of environmental expenses incurred by Plantation Pipe Line Company and described in footnote (c).
(f)	Includes Pacific, Plantation, CALNEV, Central Florida, Cochin, and Cypress pipeline volumes.

          Our Products Pipelines segment’s primary businesses include transporting refined petroleum products and natural gas liquids through pipelines and operating liquid petroleum products terminals and petroleum pipeline transmix processing facilities. Combined, the certain items described in the footnotes to the table above decreased earnings before depreciation, depletion and amortization by $5.5 million in 2007 compared to 2006, and increased earnings before depreciation, depletion and amortization by $127.5 million in 2006 compared to 2005.

          Following is information related to the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses (EBDA); and (ii) operating revenues in both 2007 and 2006, when compared to the respective prior year:

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Year Ended December 31, 2007 versus Year Ended December 31, 2006
	EBDA				Revenues
	increase/(decrease)				Increase/(decrease)
	(In millions, except percentages)
Cochin Pipeline System	$	30.0	212	%	$	39.2		110	%
West Coast Terminals		12.3	34	%		7.5		12	%
Plantation Pipeline		8.6	27	%		1.0		2	%
Transmix operations		8.0	36	%		10.6		32	%
Pacific operations		5.8	2	%		18.4		5	%
CALNEV Pipeline		5.1	11	%		3.4		5	%
Southeast Terminals		5.0	13	%		(12.9	)	(16	)%
North System		4.9	21	%		(2.6	)	(6	)%
All other (including eliminations)		4.2	11	%		3.5		7	%
Total Products Pipelines	$	83.9	17	%	$	68.1		9	%

Year Ended December 31, 2006 versus Year Ended December 31, 2005
	EBDA					Revenues
	Increase/(decrease)					increase/(decrease)
	(In millions, except percentages)
Cochin Pipeline System	$	(5.2	)	(27	)%	$	(0.5	)	(1	)%
Southeast Terminals		4.9		15	%		24.5		43	%
Plantation Pipeline		(4.2	)	(12	)%		1.5		4	%
Pacific operations		(5.4	)	(2	)%		16.2		5	%
West Coast Terminals		(2.6	)	(7	)%		6.5		11	%
Transmix operations		2.6		13	%		3.9		13	%
All other (including eliminations)		3.5		3	%		12.4		8	%
Total Products Pipelines	$	(6.4	)	(1	)%	$	64.5		9	%

          All of the assets in our Products Pipelines business segment produced higher earnings before depreciation, depletion and amortization expenses in 2007 than in the previous year. The overall increase in segment earnings before depreciation, depletion and amortization in 2007 compared to 2006 was driven largely 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 approximate 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 3 to our consolidated financial statements included elsewhere in this report.

          The year-to-year earnings increase from our West Coast terminal operations in 2007 was due to higher operating revenues, lower operating expenses and incremental gains from asset sales. The increases in terminal revenues were driven by higher throughput volumes from our combined Carson/Los Angeles Harbor terminal system, partly due to completed storage expansion projects since the end of 2006, 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 (these incremental environmental expenses were not associated with the expenses described in footnote (a) to the table above).

          The increase in earnings in 2007 from our approximate 51% equity investment in Plantation Pipe Line Company was due to higher overall net income earned by Plantation, largely resulting from both higher pipeline revenues and lower period-to-period operating expenses. The increase in revenues was largely due to a higher oil loss allowance percentage in 2007, relative to last year, and the drop in operating expenses—including fuel, power and pipeline maintenance expenses, was due to decreases in both refined products delivery volumes and pipeline integrity expenses in 2007 versus 2006 (pipeline integrity expenses are discussed more fully below).

          The year-to-year increase in earnings before depreciation, depletion and amortization from our petroleum pipeline transmix operations was 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, and during 2007, the plant

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processed greater volumes than in 2006. In 2007, our Greensboro facility contributed incremental earnings before depreciation, depletion and amortization of $4.5 million and incremental revenues of $5.4 million 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 year-to-year increases in average processing contract rates.

          We also benefited from higher earnings before depreciation, depletion and amortization from our Pacific operations, our CALNEV Pipeline and our North System in 2007, when compared to last year. The increase in our Pacific operations’ earnings was largely revenue related, attributable to increases in both transportation volumes and average tariff rates. Combined mainline delivery and terminal revenues increased 5% in 2007, compared to 2006, due largely to higher delivery volumes to Arizona, the completed expansion of our East Line pipeline during the summer of 2006, and higher deliveries to various West Coast military bases. The increase from CALNEV was also driven by higher year-over-year revenues, due to increased military and commercial tariff rates in 2007, and higher terminal revenues associated with ethanol blending at our Las Vegas terminal that more than offset a 2% drop in refined products delivery volumes. The increase from our North System was mainly due to lower combined operating expense, due to its sale in the fourth quarter of 2007 (the decline in expense was greater than the associated decline in revenue).

          Effective October 5, 2007, we sold our North System common carrier natural gas liquids pipeline and our 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6 million, and we used the proceeds we received to pay down short-term debt borrowings. We accounted for our North System business as a discontinued operation pursuant to generally accepted accounting principles which require that the income statement be formatted to separate the divested business from our continuing operations; however, consistent with the management approach of identifying and reporting financial information on operating segments, we have included the North System’s financial results 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. We do not expect the impact of the discontinued operations to materially affect our overall business, financial position, results of operations or cash flows. For information on our reconciliation of segment information with our consolidated general-purpose financial statements, see Note 15 to our consolidated financial statements included elsewhere in this report.

          Combining all of the segment’s operations, while revenues from refined petroleum products deliveries increased 6.2% in 2007, compared to last year, total refined products delivery volumes decreased 0.4%. Compared to last year, gasoline delivery volumes decreased 3.2% (primarily due to Plantation), while diesel and jet fuel volumes were up 3.7% and 4.7%, respectively. Excluding Plantation, which continued to be impacted by a competing pipeline that began service in mid-2006, total refined products delivery volumes increased by 0.8% in 2007, when compared to 2006. Volumes on our Pacific operations and our Central Florida pipelines were up 1% and 2%, respectively, in 2007, and while natural gas liquids delivery volumes were down in 2007 versus 2006, revenues were up substantially due to our increased ownership in the Cochin pipeline system.

          The $6.4 million (1%) decrease in earnings before depreciation, depletion and amortization expenses in 2006, when compared to 2005, was largely due to a combined decrease in earnings of $24.2 million in 2006—due to incremental pipeline maintenance expenses recognized in the last half of the year. Beginning in the third quarter of 2006, the refined petroleum products pipelines and associated terminal operations included within our Products Pipelines segment (including Plantation Pipe Line Company, our 51%-owned equity investee) began recognizing certain costs incurred as part of their pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. Combined, this change reduced the segment’s earnings before depreciation, depletion and amortization expenses by $24.2 million in 2006—increasing maintenance expenses by $20.1 million, decreasing earnings from equity investments by $6.6 million, and decreasing income tax expenses by $2.5 million.

          Pipeline integrity costs encompass those costs incurred as part of an overall pipeline integrity management program, which is a process for assessing and mitigating pipeline risks in order to reduce both the likelihood and consequences of incidents. Our pipeline integrity program is designed to provide our management the information needed to effectively allocate resources for appropriate prevention, detection and mitigation activities.

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          The remaining $17.8 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005, primarily consisted of the following items:

• a $4.9 million (15%) increase from our Southeast refined products terminal operations, driven by higher liquids throughput volumes at higher rates, relative to 2005, and higher margins from ethanol blending and sales activities;

• a $4.1 million (1%) increase from our combined Pacific and CALNEV Pipeline operations, primarily due to a $22.6 million (6%) increase in operating revenues, which more than offset an $18.3 million (18%) increase in combined operating expenses. The increase in operating revenues consisted of a $14.7 million (5%) increase from refined products deliveries and a $7.9 million (8%) increase from terminal and other fee revenue. The increase in operating expenses was primarily due to higher fuel and power expenses; and

• a $3.7 million (12%) increase from our Central Florida Pipeline, mainly due to higher product delivery revenues in 2006 driven by higher average tariff and terminal rates.

          Combining all of the segment’s operations, while total delivery volumes of refined petroleum products decreased 0.8% in 2006 compared to 2005, total delivery volumes from our Pacific operations were up 1.7% compared to 2005, due in part to the East Line expansion which was in service for the last seven months of 2006. The expansion project substantially increased pipeline capacity from El Paso, Texas to Tucson and Phoenix, Arizona. In addition, our CALNEV Pipeline delivery volumes were up 4.2% in 2006 versus 2005, due primarily to strong demand from the Southern California and Las Vegas, Nevada markets. The overall decrease in year-to-year segment deliveries of refined petroleum products was largely related to a 6.8% drop in volumes from the Plantation Pipeline in 2006, as described above.

          Natural Gas Pipelines

	Year Ended December 31,
	2007			2006			2005
	(In millions, except operating statistics)
Revenues	$	6,466.5		$	6,577.7		$	7,718.4
Operating expenses(a)		(5,882.9	)		(6,057.8	)		(7,255.0	)
Other income(b)		3.2			15.1			—
Earnings from equity investments(c)		19.2			40.5			36.8
Interest income and Other, net-income (expense)		0.2			0.7			2.7
Income tax benefit (expense)		(6.0	)		(1.4	)		(2.6	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	600.2		$	574.8		$	500.3
Natural gas transport volumes (Trillion Btus)(d)		1,577.3			1,440.9			1,317.9
Natural gas sales volumes (Trillion Btus)(e)		865.5			909.3			924.6

(a)	2007, 2006 and 2005 amounts include a $0.4 million decrease in expense, a $1.5 million increase in expense and a $0.1 million decrease in expense, respectively, associated with environmental liability adjustments. 2006 amount also includes a $6.3 million reduction in expense due to the release of a reserve related to a natural gas purchase/sales contract.
(b)	2006 amount represents a $15.1 million gain from the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation facility.
(c)	2007 amount includes an expense of $1.0 million reflecting our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company.
(d)	Includes Rocky Mountain pipeline group and Texas intrastate natural gas pipeline group pipeline volumes.
(e)	Represents Texas intrastate natural gas pipeline group.

          Our Natural Gas Pipelines segment’s primary businesses involve marketing, transporting, storing, gathering, treating and processing natural gas through both intrastate and interstate pipeline systems and related facilities. Combined, the certain items described in the footnotes to the table above decreased earnings before depreciation, depletion and amortization by $20.5 million in 2007, relative to 2006, and increased earnings before depreciation, depletion and amortization by $19.8 million in 2006, relative to 2005.

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          Following is information related to the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses (EBDA); and (ii) operating revenues in both 2007 and 2006, when compared to the respective prior year:

Year Ended December 31, 2007 versus Year Ended December 31, 2006
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Texas Intrastate Natural Gas Pipeline Group	$	57.0		19	%	$	(142.2	)	(2	)%
Casper and Douglas gas processing		8.6		67	%		5.6		6	%
Rocky Mountain Pipeline Group		(11.6	)	(6	)%		29.0		10	%
Red Cedar Gathering Company		(7.4	)	(20	)%		—		—
All others		(0.7	)	(15	)%		(3.8	)	(94	)%
Intrasegment Eliminations		—		—			0.2		11	%
Total Natural Gas Pipelines	$	45.9		8	%	$	(111.2	)	(2	)%

Year Ended December 31, 2006 versus Year Ended December 31, 2005
	EBDA Increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Texas Intrastate Natural Gas Pipeline Group	$	34.6		13	%	$	(1,165.7	)	(16	)%
Rocky Mountain Pipeline Group		14.3		8	%		27.9		11	%
Red Cedar Gathering Company		4.3		13	%		—		—
Casper and Douglas gas processing		2.9		30	%		(6.4	)	(6	)%
All others		(1.4	)	(21	)%		2.5		167	%
Intrasegment Eliminations		—		—			1.0		39	%
Total Natural Gas Pipelines	$	54.7		11	%	$	(1,140.7	)	(15	)%

          The segment’s overall increases in earnings before depreciation, depletion and amortization expenses in both 2007 and 2006 were driven by strong year-over-year performances from our Texas intrastate natural gas pipeline group, which includes the operations of the following four natural gas pipeline systems: Kinder Morgan Tejas (including Kinder Morgan Border Pipeline), Kinder Morgan Texas Pipeline, Kinder Morgan North Texas Pipeline and our Mier-Monterrey Mexico Pipeline. Collectively, our Texas intrastate group serves the Texas Gulf Coast region by transporting, buying, selling, processing, treating and storing natural gas from multiple onshore and offshore supply sources.

          The higher earnings in both 2007 and 2006, when compared to the respective prior years, 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, and higher natural gas processing margins. Our Texas intrastate natural gas pipeline group also benefited, in 2007, from higher sales of cushion gas, due to the termination of a storage facility lease, and from incremental natural gas storage revenues, due to a long-term contract with one of its largest customers that became effective April 1, 2007. Although natural gas sales volumes were down almost 5% in 2007 compared to 2006, natural gas transport volumes on our Texas intrastate systems increased 21% in 2007 and 5% in 2006, resulting in higher year-over-year transportation revenues. Because the group also buys and sells natural gas, 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 group’s average prices and volumes for natural gas purchased and sold.

          The increase in earnings from our Casper and Douglas natural gas processing operations in 2007, when compared to 2006, was driven by an overall 6% increase in operating revenues. The increase was primarily attributable to higher natural gas liquids sales revenues, due to increases in both prices and volume. The 2006 increase in earnings was primarily related to incremental earnings associated with favorable hedge settlements from our natural gas gathering and processing operations. We benefited from comparative differences in hedge settlements associated with the rolling-off of older low price crude oil and propane positions at December 31, 2005.

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          The decrease in earnings in 2007 from our Rocky Mountain interstate natural gas pipeline group, which is comprised of Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, and our current 51% equity investment in Rockies Express Pipeline LLC, resulted primarily from a $12.6 million decrease in equity earnings from our investment in Rockies Express. The decrease in earnings from Rockies Express, which began interim service in February 2006, reflected 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, had limited natural gas reservation revenues and volumes. Rockies Express-West is a 713-mile, 42-inch diameter natural gas pipeline that extends eastward from the Cheyenne Hub in Weld County, Colorado to Audrain County, Missouri. It has the capacity to transport up to 1.5 billion cubic feet of natural gas per day and it began interim service for up to 1.4 billion cubic feet per day on approximately 500 miles of line on January 12, 2008. Rockies Express-West is expected to become fully operational in mid-March 2008.

          The $14.3 million (8%) increase in earnings in 2006, relative to 2005, from our Rocky Mountain interstate natural gas pipeline group was driven by a $10.2 million (10%) increase in earnings from our Kinder Morgan Interstate Gas Transmission system and a $3.8 million (10%) increase from TransColorado Pipeline. The increase from KMIGT was due largely to higher revenues earned in 2006 from both operational sales of natural gas and natural gas park and loan services. KMIGT’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and recovery of storage cushion gas volumes. The increase from TransColorado was largely due to higher natural gas transmission revenues earned in 2006 compared to 2005, chiefly related to higher natural gas delivery volumes resulting from both system improvements and the successful negotiation of incremental firm transportation contracts. The pipeline system improvements were associated with an expansion, completed since the end of the first quarter of 2005, on the northern portion of the pipeline.

          Both the drop, in 2007, and the increase, in 2006, in earnings before depreciation, depletion and amortization from our 49% equity investment in the Red Cedar Gathering Company were mainly due to higher prices on incremental sales of excess fuel gas and to higher natural gas gathering revenues in 2006, relative to both 2007 and 2005.

          CO₂

	Year Ended December 31,
	2007				2006				2005
	(In millions, except operating statistics)
Revenues(a)		$	824.1			$	736.5			$	657.6
Operating expenses(b)			(304.2	)			(268.1	)			(212.6	)
Other income			—				—				—
Earnings from equity investments			19.2				19.2				26.3
Other, net-income (expense)			—				0.8				—
Income tax benefit (expense)			(2.1	)			(0.2	)			(0.4	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	537.0			$	488.2			$	470.9
Carbon dioxide delivery volumes (Bcf)(c)			637.3				669.2				649.3
SACROC oil production (gross)(MBbl/d)(d)			27.6				30.8				32.1
SACROC oil production (net)(MBbl/d)(e)			23.0				25.7				26.7
Yates oil production (gross)(MBbl/d)(d)			27.0				26.1				24.2
Yates oil production (net)(MBbl/d)(e)			12.0				11.6				10.8
Natural gas liquids sales volumes (net)(MBbl/d)(e)			9.6				8.9				9.4
Realized weighted average oil price per Bbl(f)(g)		$	36.05			$	31.42			$	27.36
Realized weighted average natural gas liquids price per Bbl(g)(h)		$	52.91			$	43.90			$	38.98

(a)	2006 amount includes a $1.8 million loss (from a decrease in revenues) on derivative contracts used to hedge forecasted crude oil sales.
(b)	2007 and 2005 amounts include increases in expense associated with environmental liability adjustments of $0.2 million and $0.3 million, respectively.

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(c)	Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes.
(d)	Represents 100% of the production from the field. We own an approximate 97% working interest in the SACROC unit and an approximate 50% working interest in the Yates unit.
(e)	Net to Kinder Morgan, after royalties and outside working interests.
(f)	Includes all Kinder Morgan crude oil production properties.
(g)	Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
(h)	Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

          Our CO₂ segment consists of Kinder Morgan CO₂ Company, L.P. and its consolidated affiliates. The segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO₂) and crude oil, and the production and marketing of natural gas and natural gas liquids.

          Combined, the certain items described in the footnotes to the table above increased earnings before depreciation, depletion and amortization by $1.6 million in 2007, relative to 2006, and decreased earnings before depreciation, depletion and amortization by $1.5 million in 2006, relative to 2005. For each of the segment’s two primary businesses, the following is information related to the remaining year-to-year increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization (EBDA); and (ii) operating revenues:

Year Ended December 31, 2007 versus Year Ended December 31, 2006
	EBDA					Revenues
	increase/(decrease)					increase/(decrease)
	(In millions, except percentages)
Sales and Transportation Activities	$	(9.3	)	(5	)%	$	(8.8	)	(4	)%
Oil and Gas Producing Activities		56.5		19	%		81.6		14	%
Intrasegment Eliminations		—		—			13.0		21	%
Total CO2	$	47.2		10	%	$	85.8		12	%

Year Ended December 31, 2006 versus Year Ended December 31, 2005
	EBDA					Revenues
	increase/(decrease)					increase/(decrease)
	(In millions, except percentages)
Sales and Transportation Activities	$	24.4		15	%	$	35.78		22	%
Oil and Gas Producing Activities		(5.6	)	(2	)%		57.1		10	%
Intrasegment Eliminations		—		—			(12.1	)	(25	)%
Total CO2	$	18.8		4	%	$	80.7		12	%

          The overall $47.2 million (10%) increase in segment earnings before depreciation, depletion and amortization expenses in 2007 versus 2006 was driven by higher earnings from the segment’s oil and gas producing activities, which include its ownership interests in oil-producing fields and natural gas processing plants. The increase was largely due to higher oil production at the Yates oil field unit, higher realized average oil prices in 2007 relative to 2006, and higher earnings from natural gas liquids sales—due largely to increased recoveries at the Snyder, Texas gas plant and to an increase in our realized weighted average price per barrel.

          The year-to-year decrease in earnings before depreciation, depletion and amortization from the segment’s sales and transportation activities was primarily due to a decrease in carbon dioxide sales revenues, resulting mainly from lower average prices for carbon dioxide in 2007, and partly from a 3% drop in average carbon dioxide delivery volumes. The segment’s average price received for all carbon dioxide sales decreased 9% in 2007, when compared to 2006. The decrease was mainly attributable to the expiration of a significantly high-priced sales contract in December 2006.

          The segment’s $18.8 million (4%) increase in earnings before depreciation, depletion and amortization in 2006 compared with 2005 was driven by higher earnings from the segment’s carbon dioxide sales and transportation activities, largely due to higher revenues—from both carbon dioxide sales and deliveries, and from crude oil pipeline transportation. The overall increase in segment earnings before depreciation, depletion and amortization was partly offset by lower earnings from oil and gas producing activities and by lower equity earnings from the segment’s 50% ownership interest in Cortez Pipeline Company.

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          The decrease in earnings from oil and gas producing activities in 2006 compared with 2005 was primarily due to higher combined operating expenses and to the previously disclosed drop in crude oil production at the SACROC oil field unit, discussed below. The higher operating expenses included higher field operating and maintenance expenses (including well workover expenses), higher property and severance taxes, and higher fuel and power expenses. The increases in expenses more than offset higher overall crude oil and natural gas plant product sales revenues, which increased primarily from higher realized sales prices and partly from higher crude oil production at the Yates field unit.

          The overall increases in segment revenues in 2007 and 2006, when compared to respective prior years, were mainly due to higher revenues from the segment’s oil and gas producing activities’ crude oil sales and natural gas liquids sales. Combined, crude oil and plant product sales revenues increased $77.9 million (14%) in 2007 compared to 2006, and $63.9 million (12%) in 2006 compared to 2005.

          The year-over-year increases in revenues from the sales of natural gas liquids were driven by favorable sales price variances—our realized weighted average price per barrel increased 21% in 2007 and 13% in 2006, when compared to the respective prior year. The year-over-year increases in revenues from the sales of crude oil reflected annual increases in our realized weighted average price per barrel of 15% in both 2007 and 2006, and although total crude oil sales volumes were relatively flat in 2006 compared to 2005, sales volumes decreased 6% in 2007 compared to 2006. Average gross oil production for 2007 was 27.0 thousand barrels per day at the Yates unit, up 3% from 2006, and 27.6 thousand barrels per day at SACROC, a decline of 10% versus 2006.

          The year-to-year decline in crude oil production at the SACROC field unit is attributable to lower observed recoveries from recent project areas and due to an intentional slow down in development pace given this reduction in recoveries. For more information on our ownership interests in the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see Note 20 to our consolidated financial statements included elsewhere in this report.

          In addition, 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 $69.63 per barrel in 2007, $63.27 per barrel in 2006 and $54.45 per barrel in 2005. For more information on our hedging activities, see Note 14 to our consolidated financial statements included elsewhere in this report.

          Terminals

	Year Ended December 31,
	2007				2006				2005
	(In millions, except operating statistics)
Revenues		$	963.7			$	864.8			$	699.3
Operating expenses(a)			(536.4	)			(461.9	)			(373.4	)
Other income(b)			6.3				15.2				—
Earnings from equity investments			0.6				0.2				0.1
Other, net-income (expense)			1.0				2.1				(0.2	)
Income tax benefit (expense)(c)			(19.2	)			(12.3	)			(11.2	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	416.0			$	408.1			$	314.6
Bulk transload tonnage (MMtons)(d)			87.1				95.1				85.5
Liquids leaseable capacity (MMBbl)			47.5				43.5				42.4
Liquids utilization %			95.9	%			96.3	%			95.4	%

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(a)	2007 and 2005 amounts include increases in expense associated with environmental liability adjustments of $2.0 million and $3.5 million, respectively.2007 amount also includes a $25.0 million increase in expense from the settlement of certain litigation matters related to our Cora coal terminal, and a $1.2 million increase in expense associated with legal liability adjustments. 2006 amount includes a $2.8 million increase in expense related to hurricane clean-up and repair activities.
(b)	2007 and 2006 amounts include increases in income of $1.8 million and $15.2 million, respectively, from property casualty gains associated with the 2005 hurricane season.
(c)	2006 amount includes a $1.1 million increase in expense associated with hurricane expenses and casualty gain.
(d)	Volumes for acquired terminals are included for 2007 and 2006.

          Our Terminals segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities.

          Combined, the certain items described in the footnotes to the table above decreased earnings before depreciation, depletion and amortization by $37.7 million in 2007, relative to 2006, and increased earnings before depreciation, depletion and amortization by $14.8 million in 2006, relative to 2005. The segment’s remaining $45.6 million (11%) increase in earnings before depreciation, depletion and amortization expenses in 2007 compared with 2006, and its remaining $78.7 million (25%) increase in 2006 compared to 2005, were driven by a combination of internal expansions and strategic acquisitions completed since the end of 2005. We have made and continue to seek terminal acquisitions in order to gain access to new markets, to complement and/or enlarge our existing terminal operations, and to benefit from the economies of scale resulting from increases in storage, handling and throughput capacity.

          In 2007, we invested approximately $158.9 million to acquire terminal assets and equity investments, and our significant terminal acquisitions since the fourth quarter of 2006 included the following:

• all of the membership interests of Transload Services, LLC, which provides material handling and steel processing services at 14 steel-related terminal facilities located in the Chicago metropolitan area and various cities in the United States, acquired November 20, 2006;

• all of the membership interests of Devco USA L.L.C., which includes a proprietary technology that transforms molten sulfur into solid pellets that are environmentally friendly and easier to transport, acquired December 1, 2006;

• the Vancouver Wharves bulk marine terminal, which includes five deep-sea vessel berths and terminal assets located on the north shore of the Port of Vancouver’s main harbor. The assets include significant rail infrastructure, dry bulk and liquid storage, and material handling systems, and were acquired May 30, 2007; and

• the terminal assets and operations acquired from Marine Terminals, Inc., which are primarily involved in the handling and storage of steel and alloys and consist of two separate facilities located in Blytheville, Arkansas, and individual terminal facilities located in Decatur, Alabama, Hertford, North Carolina, and Berkley, South Carolina. The assets were acquired effective September 1, 2007.

          Combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $31.2 million, revenues of $83.9 million, operating expenses of $53.2 million and equity earnings of $0.5 million, respectively, in 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.

          In 2006, we also benefited significantly from the incremental contributions attributable to the bulk and liquids terminal businesses we acquired during 2005 and 2006. In addition to the two acquisitions acquired in the fourth quarter of 2006 and referred to above, these acquisitions included the following significant businesses:

• our Texas Petcoke terminals, located in and around the Ports of Houston and Beaumont, Texas, acquired effective April 29, 2005;

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• three terminals acquired separately in July 2005: our Kinder Morgan Staten Island terminal, a dry-bulk terminal located in Hawesville, Kentucky and a liquids/dry-bulk facility located in Blytheville, Arkansas; and

• all of the ownership interests in General Stevedores, L.P., which operates a break-bulk terminal facility located along the Houston Ship Channel, acquired effective July 31, 2005.

          Combined, these terminal acquisitions accounted for incremental amounts of earnings before depreciation, depletion and amortization of $33.5 million, revenues of $68.8 million and operating expenses of $35.3 million, respectively, in 2006. A majority of these increases in earnings, revenues and expenses were attributable to the inclusion of our Texas petroleum coke terminals, which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an aggregate consideration of approximately $247.2 million. The primary assets acquired included facilities and railway equipment located at the Port of Houston, the Port of Beaumont and the TGS Deepwater terminal located on the Houston Ship Channel.

          For all other terminal operations (those owned during identical periods in both 2007 and 2006), earnings before depreciation, depletion and amortization expenses increased $14.4 million (4%) in 2007, and $45.2 million (14%) in 2006, when compared to the respective prior years. The increases in earnings represent net changes in terminal results at various locations, but the year-over-year increase in 2007 compared to 2006 was largely due to higher earnings in 2007 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 both recent expansions that have added new liquids tank and truck loading rack capacity since 2006, and incremental business from ethanol and biodiesel storage and transfer activity (for the entire segment, our expansion projects and acquisitions completed since the end of 2006 have increased our liquids terminals’ leaseable capacity by 9%, more than offsetting a less than 1% drop in our overall utilization percentage). Higher earnings in 2007 also resulted from (i) the combined operations of our Argo and Chicago, Illinois liquids terminals, due to increased ethanol throughput and incremental liquids storage and handling business; (ii) our Texas Petcoke terminals, due largely to higher petroleum coke throughput volumes at our Port of Houston facility; and (iii) our Pier IX bulk terminal, located in Newport News, Virginia, largely due to a 19% year-to-year increase in coal transfer volumes and higher rail incentives.

          The increase in earnings in 2006 compared to 2005 from terminals owned during both years included higher earnings in 2006 from (i) our Pasadena and Galena Park Gulf Coast liquids terminals, driven by higher revenues, in 2006, from new and incremental customer agreements, additional liquids tank capacity from capital expansions completed at our Pasadena terminal since the end of 2005, higher truck loading rack service fees, higher ethanol throughput, and incremental revenues from customer deficiency charges; (ii) our Shipyard River terminal, located in Charleston, South Carolina, due to higher revenues from liquids warehousing and coal and cement handling; (iii) our Texas Petcoke terminals, mainly resulting from an increase in petroleum coke handling volumes; and (iv) our Lower Mississippi River (Louisiana) terminals, primarily due to incremental earnings from our Amory and DeLisle Mississippi bulk terminals. Our Amory terminal began operations in July 2005. The higher earnings from our DeLisle terminal, which was negatively impacted by hurricane damage in 2005, was primarily due to higher bulk transfer revenues in 2006.

          Trans Mountain

	Year Ended December 31,
	2007				2006(c)				2005
	(In millions, except operating statistics)
Revenues		$	160.8			$	137.8			$	—
Operating expenses			(65.9	)			(53.3	)			—
Other income (expense)(a)			(377.1	)			0.9				—
Earnings from equity investments			—				—				—
Other, net-income (expense)			8.0				1.0				—
Income tax benefit (expense)			(19.4	)			(9.9	)			—
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(b)		$	(293.6	)		$	76.5			$	—
Transport volumes (MMBbl)			94.4				83.7				—

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(a)	2007 amount represents a goodwill impairment expense recorded by Knight in the first quarter of 2007.
(b)	2007 amount includes losses of $349.2 million for periods prior to our acquisition date of April 30, 2007, and a $1.3 million decrease in income from an oil loss allowance.
(c)	2006 amounts relate to periods prior to our acquisition date of April 30, 2007. See discussion below.

          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 both 2007 and 2006 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 increase in earnings before depreciation, depletion and amortization in 2007 versus 2006 totaled $56.9 million, and related entirely to our acquisition of Trans Mountain effective April 30, 2007.

          Other

	Year Ended December 31,						Earnings
	2007			2006			increase/(decrease)
	(In millions-income (expense), except percentages)
General and administrative expenses(a)	$	(278.7	)	$	(238.4	)	$	(40.3	)	(17	)%
Interest expense, net of unallocable interest income(b)		(395.8	)		(342.4	)		(53.4	)	(16	)%
Unallocable income tax benefit (expense)		(4.6	)		—			(4.6	)	—
Minority interest(c)		(7.0	)		(15.4	)		8.4		55	%
Total interest and corporate administrative expenses	$	(686.1	)	$	(596.2	)	$	(89.9	)	(15	)%

	Year Ended December 31,						Earnings
	2006			2005			increase/(decrease)
	(In millions-income (expense), except percentages)
General and administrative expenses(a)	$	(238.4	)	$	(216.7	)	$	(21.7	)	(10	)%
Interest expense, net of unallocable interest income(b)		(342.4	)		(264.3	)		(78.1	)	(30	)%
Minority interest(c)		(15.4	)		(7.3	)		(8.1	)	(111	)%
Total interest and corporate administrative expenses	$	(596.2	)	$	(488.3	)	$	(107.9	)	(22	)%

(a) 2007 amount includes (i) a $26.2 million increase in expense, allocated to us from Knight, associated with closing the going-private transaction. Knight Inc. was responsible for the payment of the costs resulting from this transaction; (ii) a $5.5 million expense related to Trans Mountain expenses for periods prior to our acquisition date of April 30, 2007; (iii) a $2.1 million expense due to the adjustment of certain insurance related liabilities; (iv) a $1.7 million increase in expense associated with the 2005 hurricane season; (v) a $1.5 million expense for certain Trans Mountain acquisition costs; and (vi) a $0.8 million expense related to the cancellation of certain commercial insurance policies. 2006 amount includes Trans Mountain expenses of $18.8 million, a $2.4 million increase in expense related to the cancellation of certain commercial insurance policies, and a $0.4 million decrease in expense related to the allocation of general and administrative expenses on hurricane related capital expenditures for the replacement and repair of assets. 2005 amount includes a $25.0 million expense for a litigation settlement reached between us and a former joint venture partner on our Kinder Morgan Tejas natural gas pipeline system, a cumulative $8.4 million expense related to settlements of environmental matters at certain of our operating sites located in the state of California, and a $3.0 million decrease in expense related to proceeds received in connection with the settlement of claims in the Enron Corp. bankruptcy proceeding.

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(b)	2007 amount includes a $2.4 million increase in expense related to imputed interest on our Cochin Pipeline acquisition, and Trans Mountain expenses of $1.2 million for periods prior to our acquisition date of April 30, 2007. 2006 amount includes Trans Mountain expenses of $6.3 million.
(c)	2007 amount includes a $3.9 million decrease in expense, related to the minority interest effect from all of the 2007 items listed in footnotes (a) and (b). 2006 amount includes a $3.5 million increase in expense, primarily related to the minority interest effect from the property casualty insurance gain associated with the 2005 hurricane season.

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

          Compared to 2006, the certain items described in footnote (a) to the tables above increased our 2007 general and administrative expenses by $17.0 million. The remaining $23.3 million (11%) increase in expenses 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 and incremental expansions we have made since the end of 2006.

          Compared to 2005, the certain items described in footnote (a) decreased our 2006 general and administrative expenses by $9.6 million. The remaining $31.3 million (17%) increase in overall general and administrative expenses in 2006 compared to 2005 was primarily due to higher corporate service charges and higher corporate and employee-related insurance expenses in 2006. The increase in corporate services was largely due to higher corporate overhead expenses associated with the business operations we acquired since the end of 2005. The increase in insurance expenses was partly due to incremental expenses related to the cancellation of certain commercial insurance polices, as well as to the overall variability in year-to-year commercial property and medical insurance costs. Pursuant to certain provisions that gave us the right to cancel certain commercial policies prior to maturity, we took advantage of the opportunity to reinsure at lower rates.

          Interest expense, net of unallocable interest income, totaled $395.8 million in 2007, $342.4 million in 2006 and $264.3 million in 2005. Compared to 2006, net interest expense decreased $2.7 million in 2007 due to the items described in footnote (b) to the tables above. The remaining $56.1 million (17%) increase in expense in 2007 compared to 2006 was due to both a 4% increase in average borrowing rates (the weighted average interest rate on all of our borrowings was approximately 6.40% during 2007 and 6.18% during 2006) and a 17% increase in average borrowings (excluding the market value of interest rate swaps). The increase in average borrowings was mainly due to capital spending in 2007, and the acquisition of external assets and businesses since the end of 2006.

          We incurred incremental net interest expense of $6.3 million in 2006 due to the inclusion of Trans Mountain, and the remaining $71.8 million (27%) increase in expense in 2006 compared to 2005 was due to both higher average debt levels and higher effective interest rates. In 2006, average borrowings increased 10% and the weighted average interest rate on all of our borrowings increased 17%, when compared to 2005 (the weighted average interest rate on all of our borrowings was approximately6.18% during 2006 and 5.30% during 2005).

          Generally, we initially fund both our capital spending (including payments for pipeline project construction costs) and our acquisition outlays from borrowings under our commercial paper program. From time to time, we issue senior notes in order to refinance our commercial paper borrowings. For more information on our capital expansion and acquisition expenditures, see “—Liquidity and Capital Resources—Investing Activities.”

          The year-to-year increases in our average borrowing rates in 2007 and 2006 reflect a general rise in variable interest rates since the end of 2005. We use interest rate swap agreements to help manage our interest rate risk. The swaps are contractual agreements we enter into in order to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. However, in a period of rising interest rates, these swaps will result in period-to-period increases in our interest expense. For more information on our interest rate swaps, see Note 14 to our consolidated financial statements, included elsewhere in this report.

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          Liquidity and Capital Resources

          Capital Structure

          We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 50% equity and 50% debt. In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.” The following table illustrates the sources of our invested capital (dollars in millions):

	December 31,
	2007			2006			2005
Long-term debt, excluding market value of interest rate swaps	$	6,455.9		$	4,384.3		$	5,220.9
Minority interest		54.2			60.2			42.3
Partners’ capital, excluding accumulated other comprehensive loss		5,712.3			5,814.4			4,693.5
Total capitalization		12,222.4			10,258.9			9,956.7
Short-term debt, less cash and cash equivalents		551.3			1,352.4			(12.1	)
Total invested capital	$	12,773.7		$	11,611.3		$	9,944.6
Capitalization:
Long-term debt, excluding market value of interest rate swaps		52.8	%		42.7	%		52.4	%
Minority interest		0.5	%		0.6	%		0.4	%
Partners’ capital, excluding accumulated other comprehensive loss		46.7	%		56.7	%		47.2	%
		100.0	%		100.0	%		100.0	%
Invested Capital:
Total debt, less cash and cash equivalents and excluding market value of interest rate swaps		54.9	%		49.4	%		52.4	%
Partners’ capital and minority interest, excluding accumulated other comprehensive loss		45.1	%		50.6	%		47.6	%
		100.0	%		100.0	%		100.0	%

          Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements 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 KMR shares.

          In general, we expect to fund:

• cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;

• expansion capital expenditures and working capital deficits with retained cash (resulting from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings, the issuance of additional common units or the proceeds from purchases of additional i-units by KMR;

• interest payments with cash flows from operating activities; and

• debt principal payments with additional borrowings, as such debt principal payments become due, or by the issuance of additional common units or the proceeds from purchases of additional i-units by KMR.

          As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. We are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors.

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

          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 KMI’s going-private transaction. 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 going-private transaction. Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007.

          Short-term Liquidity

          We employ a centralized cash management program that essentially concentrates the cash assets of our operating partnerships and their subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. Our centralized cash management program provides that funds in excess of the daily needs of our operating partnerships and their subsidiaries are concentrated, consolidated, or otherwise made available for use by other entities within our consolidated group. We place no restrictions on the ability to move cash between entities, payment of inter-company balances or the ability to upstream dividends to parent companies other than restrictions that may be contained in agreements governing the indebtedness of those entities. However, our cash and the cash of our subsidiaries is not concentrated into accounts of Knight or any company not in our consolidated group of companies, and Knight has no rights with respect to our cash except as permitted pursuant to our partnership agreement.

          Furthermore, certain of our operating subsidiaries are subject to FERC enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.

          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 December 31, 2007. As of December 31, 2007, we had $589.1 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 $723.1 million as of December 31, 2007. As of December 31, 2007, our outstanding short-term debt was $610.2 million. Currently, we believe our liquidity to be adequate. For more information on our commercial paper program and our credit facility, see Note 9 to our consolidated financial statements included elsewhere in this report.

          Long-term Financing

          In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through issuing long-term notes or additional common units, or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.

          We are subject, however, to changes in the equity and debt markets for our limited partner units and long-term notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited

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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.

          Equity Issuances

          On May 17, 2007, KMR issued 5,700,000 of its shares in a public offering at a price of $52.26 per share. 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.

          On December 5, 2007, we completed a public offering of 7,130,000 of our common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $48.09 per unit, less commissions and underwriting expenses. We received net proceeds of $342.9 million for the issuance of these 7,130,000 common units.

          We used the proceeds from each of these two equity issuances to reduce the borrowings under our commercial paper program. In addition, pursuant to our purchase and sale agreement with Trans-Global Solutions, Inc., we issued 266,813 common units in May 2007 to TGS to settle a purchase price liability related to our acquisition of bulk terminal operations from TGS in April 2005. As agreed between TGS and us, the units were valued at $15.0 million.

          On February 12, 2008, we completed an additional offering of 1,080,000 of our common units at a price of $55.65 per unit in a privately negotiated transaction with two investors. We received net proceeds of $60.1 million for the issuance of these 1,080,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

          Debt Issuances

          From time to time we issue long-term debt securities. All of our long-term debt securities issued to date, other than those issued under our long-term revolving credit facility or those issued by our subsidiaries and operating partnerships, generally have the same terms except for interest rates, maturity dates and prepayment premiums. All of our outstanding debt securities are unsecured obligations that rank equally with all of our other senior debt obligations; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. Our fixed rate notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.

          During 2007, we completed three separate public offerings of senior notes. We received proceeds, net of underwriting discounts and commissions, as follows:

• $992.8 million from a January 30, 2007 public offering of a total of $1.0 billion in principal amount of senior notes, consisting of $600 million of 6.00% notes due February 1, 2017, and $400 million of 6.50% notes due February 1, 2037;

• $543.9 million from a June 21, 2007 public offering of $550 million in principal amount of 6.95% senior notes due January 15, 2038; and

• $497.8 million from an August 28, 2007 public offering of $500 million in principal amount of 5.85% senior notes due September 15, 2012.

          We used the proceeds from each of these three debt 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. As of December 31, 2007, our total liability balance due on the various series of our senior notes was $6,288.8 million, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $188.2 million. For additional information regarding our debt securities, see Note 9 to our consolidated financial statements included elsewhere in this report.

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          On February 12, 2008, we completed a public offering of senior notes. We issued a total of $900 million in principal amount of senior notes, consisting of $600 million of 5.95% notes due February 15, 2018, and $300 million of 6.95% notes due January 15, 2038. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $894.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program.

          Capital Requirements for Recent Transactions

          During 2007, our cash outlays for the acquisition of assets and investments totaled $713.3 million. We utilized our commercial paper program to fund our 2007 acquisitions. We then reduced our short-term borrowings with the proceeds from our issuances of additional limited partnership units and senior notes, as described above. We intend to refinance the remainder of our current short-term debt and any additional short-term debt incurred during 2008 through a combination of long-term debt, equity and the issuance of additional commercial paper to replace maturing commercial paper borrowings.

          We are committed to maintaining a cost effective capital structure and we intend to finance new acquisitions using a mix of approximately 50% equity financing and 50% debt financing. For more information on our capital requirements during 2007 in regard to our acquisition expenditures, see Note 3 to our consolidated financial statements included elsewhere in this report.

          Off Balance Sheet Arrangements

          We have invested in entities that are not consolidated in our financial statements. As of December 31, 2007, our obligations with respect to these investments, as well as our obligations with respect to a letter of credit, are summarized below (dollars in millions):

Entity	Investment Type		Our Ownership Interest		Remaining Interest(s) Ownership		Total Entity Assets(5)			Total Entity Debt			Our Contingent Share of Entity Debt(6)
Cortez Pipeline Company		General Partner	50	%		(1)		$	79.9		$	157.3		$	78.7	(2)
West2East Pipeline LLC(3)		Limited Liability	51	%		ConocoPhillips and Sempra Energy		$	2,730.2		$	2,225.4		$	1,135.0
Nassau County, Florida Ocean Highway And Port Authority (4)		N/A	N/A			Nassau County, Florida Ocean Highway and Port Authority			N/A			N/A		$	22.5

(1)	The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated.
(2)	We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt. As of December 31, 2007, Shell Oil Company shares our several guaranty obligations jointly and severally for $64.3 million of Cortez’s debt balance; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty. Accordingly, as of December 31, 2007 we have a letter of credit in the amount of $37.5 million issued by JP Morgan Chase, in order to secure our indemnification obligations to Shell for 50% of the Cortez debt balance of $64.3 million.
	Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation. The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement.

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(3)	West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. As of December 31, 2007, the remaining limited liability member interests in West2East Pipeline LLC are owned by ConocoPhillips (24%) and Sempra Energy (25%). We owned a 66 2/3% ownership interest in West2East Pipeline LLC from October 21, 2005 until June 30, 2006, and we included its results in our consolidated financial statements until June 30, 2006. On June 30, 2006, our ownership interest was reduced to 51%, West2East Pipeline LLC was deconsolidated, and we subsequently accounted for our investment under the equity method of accounting. Upon completion of the pipeline, our ownership percentage is expected to be reduced to 50%.
(4)	Arose from our Vopak terminal acquisition in July 2001. Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals LLC, the operator of the port facilities. In July 2002, we acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement. In December 2002, we issued a $28 million letter of credit under our credit facilities and the former letter of credit guarantee was terminated. As of December 31, 2007, the face amount of this letter of credit outstanding under our credit facility was $22.5 million. Principal payments on the bonds are made on the first of December each year and reductions are made to the letter of credit.
(5)	Principally property, plant and equipment.
(6)	Represents the portion of the entity’s debt that we may be responsible for if the entity cannot satisfy the obligation.

          We account for our investments in Cortez Pipeline Company and West2East Pipeline LLC under the equity method of accounting. For the year ended December 31, 2007, our share of earnings, based on our ownership percentage and before amortization of excess investment cost was $19.2 million from Cortez Pipeline Company and a loss of $12.4 million from West2East Pipeline LLC. Additional information regarding the nature and business purpose of these investments is included in Notes 7 and 9 to our consolidated financial statements included elsewhere in this report.

          Summary of Certain Contractual Obligations

	Amount of Commitment Expiration per Period
	Total		1 Year or Less		2-3 Years			4-5 Years			After 5 Years
					(In millions)
Contractual Obligations:
Commercial paper outstanding	$	589.1	$	589.1		$	—		$	—	$	—
Other debt borrowings-principal payments		6,488.2		21.1			537.0			1,681.4		4,248.7
Interest payments(a)		5,947.2		443.7			788.0			633.9		4,081.6
Lease obligations(b)		130.7		31.7			42.7			28.1		28.2
Pension and post-retirement welfare plans(c)		62.1		4.6			9.7			10.9		36.9
Other obligations(d)		146.1		44.9			84.1			17.1		—
Total	$	13,363.4	$	1,135.1		$	1,461.5		$	2,371.4	$	8,395.4
Other commercial commitments:
Standby letters of credit(e)	$	672.4	$	634.9		$	—		$	—	$	37.5
Capital expenditures(f)	$	250.5	$	250.5			—			—		—

(a)	Interest payment obligations exclude adjustments for interest rate swap agreements.
(b)	Represents commitments for capital leases, including interest, and operating leases.
(c)	Represents expected benefit payments from pension and post-retirement welfare plans as of December 31, 2007.
(d)	Consist of payments due under carbon dioxide take-or-pay contracts.
(e)	The $672.4 million in letters of credit outstanding as of December 31 2007 consisted of the following: (i) a combined $298.0 million in three letters of credit supporting our hedging of energy commodity price risks; (ii) a $100 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges

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	on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (iii) a combined $58.3 million in ten letters of credit supporting our Trans Mountain pipeline system operations; (iv) a $37.5 million letter of credit supporting our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; (v) our $30.3 million guarantee under letters of credit totaling $45.5 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (vi) a $25.3 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $24.1 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (viii) a $22.5 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; (ix) a $19.9 million letter of credit supporting the construction of our Kinder Morgan Louisiana Pipeline; (x) a $15.5 million letter of credit supporting our pipeline and terminal operations in Canada; (xi) a $5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois Development Revenue Bonds; and (xii) a combined $20.4 million in eight letters of credit supporting environmental and other obligations of us and our subsidiaries.
(f)	Represents commitments for the purchase of plant, property and equipment as of December 31, 2007.
	Operating Activities

          Net cash provided by operating activities was $1,741.8 million in 2007, versus $1,363.9 million in 2006. The overall year-to-year increase of $377.9 million (28%) in cash flow from operations principally consisted of:

• a $159.1 million increase in cash attributable to changes in the reserves related to the legal fees, transportation rate cases and other litigation liabilities of our pipeline and terminal operations (consisting of an incremental $140.0 million non-cash operating expense accrued in 2007, and payments of $19.1 million made in June 2006 to certain shippers on our Pacific operations’ pipelines). The expense was associated with a liability adjustment made in December 2007, and the payments related to a settlement agreement reached in May 2006 that resolved certain challenges by complainants with regard to delivery tariffs and gathering enhancement fees at our Pacific operations’ Watson Station, located in Carson, California;

• a $139.1 million increase in cash inflows relative to changes in (i) other non-current assets and liabilities, including, among other things, incremental transportation and dock prepayments received from pipeline customers (due primarily to timing differences); and (ii) other incremental non-cash expenses, including higher non-cash operating expenses in 2007 associated with environmental liability adjustments, and higher non-cash general and administrative expenses related to the activities required to complete KMI’s going-private transaction (with regard to the going-private transaction expenses, we were required to recognize the full amounts allocated to us from Knight as expense on our income statement; 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);

• a $95.1 million increase in cash inflows relative to net changes in working capital items, mainly due to timing differences that resulted in higher 2007 net cash inflows from the collection and payment of trade and related party receivables and payables, and from lower payments on accrued tax and interest liabilities; and

• a $51.6 million decrease in cash from overall lower partnership income—net of the following non-cash items: (i) depreciation, depletion and amortization expenses; (ii) gains and losses on property sales and casualty indemnifications; (iii) earnings from equity investees; and (iv) a $377.1 million goodwill impairment charge recognized in the first quarter of 2007. The increases and decreases in our partnership income in 2007 compared to 2006 are discussed above in “—Results of Operations.”

          Investing Activities

          Net cash used in investing activities was $2,428.5 million for the year ended December 31, 2007, compared to $1,501.9 million for the prior year. The $926.6 million (62%) overall increase in funds utilized in investing activities was primarily attributable to the following:

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• a $326.1 million increase due to higher expenditures made for strategic business acquisitions. In 2007, our acquisition outlays for assets and investments totaled $713.3 million, primarily consisting of $549.1 million for net payments made to Knight for our acquisition of the Trans Mountain pipeline system, $100.3 million for the acquisition of bulk terminal assets from Marine Terminals, Inc., and $38.8 million for the purchase of the Vancouver Wharves bulk marine terminal. In 2006, our acquisition outlays totaled $387.2 million, primarily consisting of $244.6 million for the acquisition of Entrega Gas Pipeline LLC and $89.1 million for the acquisition of bulk, liquids and refined products terminal operations and related assets. Both our 2007 and 2006 acquisition expenditures are discussed more fully in Note 3 to our consolidated financial statements included elsewhere in this report;

• a $509.5 million increase from higher capital expenditures—largely due to increased investments undertaken to expand and improve our bulk and liquids terminalling operations, and our Trans Mountain pipeline system. Our sustaining capital expenditures, defined as capital expenditures that do not increase the capacity of an asset, totaled $152.6 million in 2007 and $125.5 million in 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. Additionally, our forecasted expenditures for sustaining capital expenditures for 2008 are approximately $196.2 million. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary;

• a $273.6 million increase from incremental contributions to equity investments in 2007, largely driven by incremental investments of $202.7 million and $61.6 million, respectively, for our proportionate share of construction costs of the Rockies Express and Midcontinent Express pipelines; and

• a $231.8 million decrease in cash used due to higher net proceeds received from the sales of property, plant and equipment and other net assets (net of salvage and removal costs). The increase from sales proceeds in 2007 versus 2006 was driven by the approximately $298.6 million we received for the sale of our North System operations in October 2007. In April 2006, we received $42.5 million from Momentum Energy Group, LLC for the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation facility, and in the first half of 2006, we received $27.1 million from the sale of certain oil and gas properties originally acquired from Journey Acquisition – I, L.P. and Journey 2000, L.P.

          Financing Activities

          Net cash provided by financing activities amounted to $735.7 million in 2007; while in the prior year, our financing activities provided net cash of $132.4 million. The $603.3 million (456%) overall increase in cash inflows provided by financing activities was primarily due to:

•	a $334.5 million increase from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The year-to-year increase in cash from financing activities was primarily due to (i) a $1,784.5 million net increase in cash inflows from the issuances and payments of senior notes in 2007; and (ii) a $1,453.6 million decrease in cash from lower overall net commercial paper borrowings in 2007, relative to 2006.
	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 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 was associated with public debt offerings completed on January 30, 2007, June 21, 2007 and August 28, 2007. On these dates, we

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	completed offerings of $1.0 billion, $550 million and $500 million, respectively, in principal amount of senior notes in four separate series: (i) $600 million of 6.00% notes due February 1, 2017; (ii) $400 million of 6.50% notes due February 1, 2037; (iii) $550 million of 6.95% notes due January 15, 2038; and (iv) $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;
•	a $392.4 million increase from overall equity financing activities—which include our issuances of limited partner units. In May 2007, we received proceeds of $297.9 million, after commissions and underwriting expenses, for our issuance of 5,700,000 i-units to KMR, and in December 2007, we received net proceeds of $342.9 million from a public offering of 7,130,000 common units. In 2006, we received proceeds of $248.4 million from the issuance of additional common units, primarily related to our August 2006 public offering of 5,750,000 of our common units at a price of $44.80, less commissions and underwriting expenses. We used the proceeds from each of these equity issuances to reduce the borrowings under our commercial paper program; and
•	a $100.9 million decrease from lower contributions from minority interests—principally due to contributions of $104.2 million received in 2006 from Sempra Energy with regard to their ownership interest in Rockies Express. The contributions from Sempra included an $80.0 million contribution for its 33 1/3% share of the purchase price of Entrega Gas Pipeline LLC, discussed above in “—Investing Activities.”

          Partnership Distributions

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

          Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. For 2007, 2006 and 2005, we distributed approximately 100%, 103% and 101%, respectively, of the total of cash receipts less cash disbursements (calculations assume that KMR unitholders received cash). The difference between these numbers and 100% of distributable cash flow reflects net changes in reserves.

          Our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units. We do not distribute cash to i-unit owners but instead retain the cash for use in our business. However, the cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to our general partner. Each time we make a distribution, the number of i-units owned by KMR and the percentage of our total units owned by KMR increase automatically under the provisions of our partnership agreement.

          Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets.

          Available cash for each quarter is distributed:

• first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;

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• second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;

• third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and

• fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, and 50% to our general partner.

          Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. Our general partner’s incentive distribution that we declared for 2007 was $611.9 million, while the incentive distribution paid to our general partner during 2007 was $559.6 million. The difference between declared and paid distributions is due to the fact that our distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year. In addition, our general partner waived $20.1 million of its 2006 incentive distribution for the fourth quarter of 2006, which was paid in the first quarter of 2007, in order to fund the annual bonus for employees.

          On February 14, 2008, we paid a quarterly distribution of $0.92 per unit for the fourth quarter of 2007. This distribution was 11% greater than the $0.83 distribution per unit we paid for both the fourth quarter of 2006 and the first quarter of 2007. We paid this distribution in cash to our common unitholders and to our Class B unitholders. KMR, our sole i-unitholder, received additional i-units based on the $0.92 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.

          Litigation and Environmental

          As of December 31, 2007, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $92.0 million. In addition, we have recorded a receivable of $37.8 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. As of December 31, 2006, our total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, amounted to $64.2 million.

          Additionally, as of December 31, 2007, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $247.9 million. The reserve is primarily related to various claims from lawsuits arising from our Pacific operations, 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, and in December 2007, we recorded a non-cash increase in operating expense of $140.0 million related to our litigation matters. As of December 31, 2006, our total reserve for legal fees, transportation rate cases and other litigation liabilities amounted to $112.0 million.

          Though no assurance can be given, 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.

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          Pursuant to our continuing commitment to operational excellence and our focus on safe, reliable operations, we have implemented, and intend to implement in the future, enhancements to certain of our operational practices in order to strengthen our environmental and asset integrity performance. These enhancements have resulted and may result in higher operating costs and sustaining capital expenditures; however, we believe these enhancements will provide us the greater long term benefits of improved environmental and asset integrity performance.

          Please refer to Notes 16 and 17 of our consolidated financial statements included elsewhere in this report for additional information regarding pending litigation and environmental matters, respectively.

          Regulation

          The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of December 17, 2002, the date of enactment, and must perform subsequent integrity tests on a seven year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing will consist of hydrostatic testing, internal electronic testing, or direct assessment of the piping. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001. All baseline assessments for products pipelines must be completed by March 31, 2008 and we expect to meet this deadline. We have included all incremental expenditures estimated to occur during 2008 associated with the Pipeline Safety Improvement Act of 2002 and the integrity management of our products pipelines in our 2008 budget and capital expenditure plan.

          Please refer to Note 17 to our consolidated financial statements included elsewhere in this report for additional information regarding regulatory matters.

          Recent Accounting Pronouncements

          Please refer to Note 18 to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements.

          Information Regarding Forward-Looking Statements

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

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

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

• changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission;

• our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to make expansions to our facilities;

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• difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;

• our ability to successfully identify and close acquisitions and make cost-saving changes in operations;

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

• crude oil and natural gas production from exploration and production areas that we serve, including, among others, the Permian Basin area of West Texas;

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

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

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

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

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

• our ability to obtain insurance coverage without significant levels of self-retention of risk;

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

• capital markets conditions;

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

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

• the ability to achieve cost savings and revenue growth;

• inflation;

• interest rates;

• the pace of deregulation of retail natural gas and electricity;

• foreign exchange fluctuations;

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

• the extent of our success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;

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• engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells;

• the uncertainty inherent in estimating future oil and natural gas production or reserves;

• the ability to complete expansion projects on time and on budget;

• the timing and success of business development efforts; and

• unfavorable results of litigation and the fruition of contingencies referred to in Note 16 to our consolidated financial statements included elsewhere in this report.

          There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.

          See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, 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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

          Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in commodity prices or interest rates and the timing of transactions.

Energy Commodity Market Risk

          We are exposed to commodity market risk and other external risks, such as weather-related risk, in the ordinary course of business. However, we take steps to hedge, or limit our exposure to, these risks in order to maintain a more stable and predictable earnings stream. Stated another way, we execute a hedging strategy that seeks to protect our financial position against adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil. The derivative contracts we use include energy products traded on the New York Mercantile Exchange and over-the-counter markets, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps.

          Fundamentally, our hedging strategy involves taking a simultaneous position in the futures market that is equal and opposite to our position in the cash market (or physical product) in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil and natural gas, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby directly offsetting any change in prices, either positive or negative. A hedge is successful when gains or losses in the cash market are neutralized by losses or gains in the futures transaction.

Our risk management policies prohibit us from engaging in speculative trading and we are not a party to leveraged derivatives. Furthermore, our policies require that we only enter into derivative contracts with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we

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maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future. The credit ratings of the primary parties from whom we purchase energy commodity derivative contracts are as follows (credit ratings per Standard & Poor’s Rating Services):

	Credit Rating
BNP Paribas	AA+
J. Aron & Company / Goldman Sachs	AA–
Morgan Stanley	AA–

          We account for our energy commodity risk management derivative contracts according to the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (after amendment by SFAS No. 137, SFAS No. 138, and SFAS No. 149). According to the provisions of SFAS No. 133, derivatives are measured at fair value and recognized on the balance sheet as either assets or liabilities, and in general, gains and losses on derivatives are reported on the income statement.

          However, as discussed above, our principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids and crude oil. Using derivative contracts for this purpose helps provide us increased certainty with regard to our operating cash flows and helps us undertake further capital improvement projects, attain budget results and meet distribution targets to our partners. SFAS No. 133 categorizes such use of energy commodity derivative contracts as cash flow hedges, because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain. Cash flow hedges are defined as hedges made with the intention of decreasing the variability in cash flows related to future transactions, as opposed to the value of an asset, liability or firm commitment, and SFAS No. 133 prescribes special hedge accounting treatment for such derivatives.

          In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, outside “Net Income” reported in our consolidated statements of income, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts’ gains and losses are recorded in other comprehensive income, pending occurrence of the expected transaction. Other comprehensive income consists of those financial items that are included in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings.

          All remaining gains and losses on the derivative contracts (the ineffective portion) are included in current net income. The ineffective portion of the gain or loss on the derivative contracts is the difference between the gain or loss from the change in value of the derivative contract and the effective portion of that gain or loss. In addition, when the hedged forecasted transaction does take place and affects earnings, the effective part of the hedge is also recognized in the income statement, and the earlier recognized effective amounts are removed from “Accumulated other comprehensive loss.” If the forecasted transaction results in an asset or liability, amounts in “Accumulated other comprehensive loss” should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc.

          Under current accounting rules, the accumulated components of other comprehensive income are to be reported separately as accumulated other comprehensive income or loss in the stockholders’ equity section of the balance sheet. For us, the gains and losses that are included in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets are primarily related to the derivative contracts associated with our hedging of anticipated future cash flows from the sales and purchases of natural gas, natural gas liquids and crude oil and represent the effective portion of the gain or loss on these derivative contacts. Accordingly, the total “Accumulated other comprehensive loss” included within the Partners’ Capital section of our accompanying balance sheets as of December 31, 2007 and December 31, 2006, included amounts associated with the commodity price risk management activities of $1,377.2 million and $838.7 million, respectively.

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          In future periods, as the hedged cash flows from our actual purchases and sales of energy commodities affect our net income, the related gains and losses included in our accumulated other comprehensive loss as a result of our hedging are transferred to the income statement as well, effectively offsetting the changes in cash flows stemming from the hedged risk.

          We measure the risk of price changes in the natural gas, natural gas liquids and crude oil markets utilizing a value-at-risk model. Value-at-risk is a statistical measure of how much the mark-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We utilize a closed form model to evaluate risk on a daily basis. The value-at-risk computations utilize a confidence level of 97.7% for the resultant price movement and a holding period of one day is chosen for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the value-at-risk number presented. Derivative contracts evaluated by the model include commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options.

          For each of the years ended December 31, 2007 and 2006, our value-at-risk reached a high of $1.6 million and $2.6 million, respectively, and a low of $0.7 million and $0.5 million, respectively. Value-at-risk as of December 31, 2007, was $1.6 million and averaged $1.2 million for 2007. Value-at-risk as of December 31, 2006, was $0.6 million and averaged $1.1 million for 2006.

          Our calculated value-at-risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivative contracts assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. In addition, as discussed above, we enter into these derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, the change in the market value of our portfolio of derivative contracts, with the exception of a minor amount of hedging inefficiency, is offset by changes in the value of the underlying physical transactions. For more information on our risk management activities, see Note 14 to our consolidated financial statements included elsewhere in this report.

Interest Rate Risk

          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. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

          For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. We do not have an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on our fixed rate debt until we would be required to refinance such debt.

          As of December 31, 2007 and 2006, the carrying values of our fixed rate debt were approximately $6,382.9 million and $4,551.2 million, respectively. These amounts compare to, as of December 31, 2007 and 2006, fair values of $6,518.7 million and $4,672.7 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change (approximately 64 basis points) in the average interest rates applicable to such debt for 2007 and 2006, would result in changes of approximately $259.9 million and $183.4 million, respectively, in the fair values of these instruments.

          The carrying value and fair value of our variable rate debt, including associated accrued interest and excluding the value of interest rate swap agreements (discussed below), was $684.5 million as of December 31, 2007 and $1,195.6 million as of December 31, 2006. A hypothetical 10% change in the weighted average interest rate on all of our borrowings, when applied to our outstanding balance of variable rate debt as of December 31, 2007 and 2006,

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including adjustments for notional swap amounts, would result in changes of approximately $19.1 million and $20.3 million, respectively, in our 2007 and 2006 annual pre-tax earnings.

          As of December 31, 2007 and 2006, we were a party to interest rate swap agreements with notional principal amounts of $2.3 billion and $2.1 billion, respectively. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal.

          We entered into our interest rate swap agreements for the purposes of (i) hedging the interest rate risk associated with our fixed rate debt obligations and (ii) transforming a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Since the fair value of our fixed rate debt varies with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest. Such swap agreements result in future cash flows that vary with the market rate of interest, and therefore hedge against changes in the fair value of our fixed rate debt due to market rate changes.

          As of both December 31, 2007 and 2006, all of our interest rate swap agreements represented fixed-for-variable rate swaps, where we agreed to pay our counterparties a variable rate of interest on a notional principal amount, comprised of principal amounts from various series of our long-term fixed rate senior notes. In exchange, our counterparties agreed to pay us a fixed rate of interest, thereby allowing us to transform our fixed rate liabilities into variable rate obligations without the incurrence of additional loan origination or conversion costs.

          We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. In general, we attempt to maintain an overall target mix of approximately 50% fixed rate debt and 50% variable rate debt.

          As of December 31, 2007, our cash and investment portfolio did not include fixed-income securities. Due to the short-term nature of our investment portfolio, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.

          See Note 9 to our consolidated financial statements included elsewhere in this report for additional information related to our debt instruments; for more information on our interest rate swap agreements, see Note 14.

Item 8. Financial Statements and Supplementary Data.

          The information required in this Item 8 is included in this report as set forth in the “Index to Financial Statements” on page 114.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

          None.

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Item 9A. Controls and Procedures.

          Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

          As of December 31, 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.

          Management’s Report on Internal Control Over Financial Reporting

          Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.

          The effectiveness of our internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

          Certain businesses we acquired during 2007 were excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007. The excluded businesses consisted of the following:

• the Vancouver Wharves bulk marine terminal, acquired May 30, 2007; and

• the terminal assets and operations acquired from Marine Terminals, Inc., effective September 1, 2007.

          These businesses, in the aggregate, constituted 0.6% of our total operating revenues for 2007 and 1.2% of our total assets as of December 31, 2007.

          Changes in Internal Control Over Financial Reporting

          There has been no change in our internal control over financial reporting during the fourth quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

          None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

          Directors and Executive Officers of our General Partner and its Delegate

          Set forth below is certain information concerning the directors and executive officers of our general partner and KMR, the delegate of our general partner. All directors of our general partner are elected annually by, and may be removed by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of KMR are elected annually by, and may be removed by, our general partner as the sole holder of KMR’s voting shares. Kinder Morgan (Delaware), Inc. is a wholly owned subsidiary of Knight. All officers of our general partner and all officers of KMR serve at the discretion of the board of directors of our general partner.

Name	Age	Position with our General Partner and KMR
Richard D. Kinder	63	Director, Chairman and Chief Executive Officer
C. Park Shaper	39	Director and President
Steven J. Kean	46	Executive Vice President and Chief Operating Officer
Edward O. Gaylord	76	Director
Gary L. Hultquist	64	Director
Perry M. Waughtal	72	Director
Kimberly A. Dang	38	Vice President, Investor Relations and Chief Financial Officer
Jeffrey R. Armstrong	39	Vice President (President, Terminals)
Thomas A. Bannigan	54	Vice President (President, Products Pipelines)
Richard T. Bradley	52	Vice President (President, CO2)
David D. Kinder	33	Vice President, Corporate Development and Treasurer
Joseph Listengart	39	Vice President, General Counsel and Secretary
Scott E. Parker	47	Vice President (President, Natural Gas Pipelines)
James E. Street	51	Vice President, Human Resources and Administration

          Richard D. Kinder is Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc. and Knight. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of KMR since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Knight in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected President of KMR, Kinder Morgan G.P., Inc. and Knight in July 2004 and served as President until May 2005. He has also served as Chief Manager, and as a member of the Board of Managers of Knight Holdco LLC since May 2007. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc. and Knight.

          C. Park Shaper is Director and President of KMR, Kinder Morgan G.P., Inc. and Knight. Mr. Shaper was elected President of KMR, Kinder Morgan G.P., Inc. and Knight in May 2005. He served as Executive Vice President of KMR, Kinder Morgan G.P., Inc. and Knight from July 2004 until May 2005. Mr. Shaper was elected Director of KMR and Kinder Morgan G.P., Inc. in January 2003 and of Knight in May of 2007. He was elected Vice President, Treasurer and Chief Financial Officer of KMR upon its formation in February 2001, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. He was elected Vice President, Treasurer and Chief Financial Officer of Knight in January 2000, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as its Treasurer until January 2004 and its Chief Financial Officer until May 2005. He has also served as President, and as a member of the Board of Managers, of Knight Holdco LLC since May 2007. He received a Masters of Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University. Mr. Shaper is also a trust manager of Weingarten Realty Investors.

          Steven J. Kean is Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and Knight. Mr. Kean was elected Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and Knight in January 2006. He served as Executive Vice President, Operations of KMR, Kinder Morgan G.P., Inc. and Knight from May 2005 to January 2006. He served as President, Texas Intrastate Pipeline Group from June

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2002 until May 2005. He served as Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. He has also served as Chief Operating Officer, and as a member of the Board of Managers, of Knight Holdco LLC since May 2007. Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State University in May 1982.

          Edward O. Gaylord is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of KMR upon its formation in February 2001. Mr. Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997. Since 1989, Mr. Gaylord has been the Chairman of the board of directors of Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship channel.

          Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of KMR upon its formation in February 2001. He was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory firm.

          Perry M. Waughtal is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of KMR upon its formation in February 2001. Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal is also a director of HealthTronics, Inc.

          Kimberly A. Dang is Vice President, Investor Relations and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and Knight. Mrs. Dang was elected Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and Knight in May 2005. She served as Treasurer of KMR, Kinder Morgan G.P., Inc. and Knight from January 2004 to May 2005. She was elected Vice President, Investor Relations of KMR, Kinder Morgan G.P., Inc. and Knight in July 2002. From November 2001 to July 2002, she served as Director, Investor Relations of KMR, Kinder Morgan G.P., and Knight. From May 2001 until November 2001, Mrs. Dang was an independent financial consultant. From September 2000 until May 2001, she served as an associate and later a principal at Murphree Venture Partners, a venture capital firm. She has also served as Chief Financial Officer of Knight Holdco LLC since May 2007. Mrs. Dang has received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University and a Bachelor of Business Administration degree in accounting from Texas A&M University.

          Jeffrey R. Armstrong is Vice President (President, Terminals) of KMR and Kinder Morgan G.P., Inc. Mr. Armstrong became Vice President (President, Terminals) in July 2003. He served as President, Kinder Morgan Liquids Terminals LLC from March 1, 2001, when the company was formed via the acquisition of GATX Terminals, through July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX Terminals, where he was General Manager of their East Coast operations. He received his Bachelor’s degree from the United States Merchant Marine Academy and an MBA from the University of Notre Dame.

          Thomas A. Bannigan is Vice President (President, Products Pipelines) of KMR and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of Plantation Pipe Line Company. Mr. Bannigan was elected Vice President (President, Products Pipelines) of KMR upon its formation in February 2001. He was elected Vice President (President, Products Pipelines) of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan has served as President and Chief Executive Officer of Plantation Pipe Line Company since May 1998. Mr. Bannigan received his Juris Doctor, cum laude, from Loyola University in 1980 and received a Bachelors degree from the State University of New York in Buffalo.

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          Richard T. Bradley is Vice President (President, CO₂) of KMR and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO₂ Company, L.P. Mr. Bradley was elected Vice President (President, CO₂) of KMR upon its formation in February 2001 and Vice President (President, CO₂) of Kinder Morgan G.P., Inc. in April 2000. Mr. Bradley has been President of Kinder Morgan CO₂ Company, L.P. (formerly known as Shell CO₂ Company, Ltd.) since March 1998. Mr. Bradley received a Bachelor of Science in Petroleum Engineering from the University of Missouri at Rolla.

          David D. Kinder is Vice President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc. and Knight. Mr. Kinder was elected Treasurer of KMR, Kinder Morgan G.P., Inc. and Knight in May 2005. He was elected Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and Knight in October 2002. He served as manager of corporate development for Knight and Kinder Morgan G.P., Inc. from January 2000 to October 2002. He has also served as Treasurer of Knight Holdco LLC since May 2007. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.

          Joseph Listengart is Vice President, General Counsel and Secretary of KMR, Kinder Morgan G.P., Inc. and Knight. Mr. Listengart was elected Vice President, General Counsel and Secretary of KMR upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of Knight in October 1999. Mr. Listengart was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been an employee of Kinder Morgan G.P., Inc. since March 1998. He has also served as General Counsel and Secretary of Knight Holdco LLC since May 2007. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990.

          Scott E. Parker is Vice President (President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and Knight. He was elected Vice President (President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and Knight in May 2005. Mr. Parker served as President of NGPL from March 2003 to May 2005. Mr. Parker served as Vice President, Business Development of NGPL from January 2001 to March 2003. He held various positions at NGPL from January 1984 to January 2001. Mr. Parker holds a Bachelor’s degree in accounting from Governors State University.

          James E. Street is Vice President, Human Resources and Administration of KMR, Kinder Morgan G.P., Inc. and Knight. Mr. Street was elected Vice President, Human Resources and Administration of KMR upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Knight in August 1999. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.

          Corporate Governance

          We have a separately designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of Messrs. Gaylord, Hultquist and Waughtal. Mr. Gaylord is the chairman of the audit committee and has been determined by the board to be an “audit committee financial expert.” The board has determined that all of the members of the audit committee are independent as described under the relevant standards.

          We have not, nor has our general partner nor KMR, made, within the preceding three years, contributions to any tax-exempt organization in which any of our or KMR’s independent directors serves as an executive officer that in any single fiscal year exceeded the greater of $1.0 million or 2% of such tax-exempt organization’s consolidated gross revenues.

          On April 11, 2007, our chief executive officer certified to the New York Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, that as of April 11, 2007, he was not aware of any violation by us of the New York Stock Exchange’s Corporate Governance listing standards. We have also filed as an exhibit to this report the Sarbanes-Oxley Act Section 302 certifications regarding the quality of our public disclosure.

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          We make available free of charge within the “Investors” information section of our Internet website, at www.kindermorgan.com, and in print to any unitholder who requests, the governance guidelines, the charters of the audit committee, compensation committee and nominating and governance committee, and our code of business conduct and ethics (which applies to senior financial and accounting officers and the chief executive officer, among others). Requests for copies may be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We intend to disclose any amendments to our code of business conduct and ethics that would otherwise be disclosed on Form 8-K and any waiver from a provision of that code granted to our executive officers or directors that would otherwise be disclosed on Form 8-K on our Internet website within four business days following such amendment or waiver. The information contained on or connected to our Internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

          Interested parties may contact our lead director, the chairpersons of any of the board’s committees, the independent directors as a group or the full board by mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, Attention: General Counsel, or by e-mail within the “Contact Us” section of our Internet website, at www.kindermorgan.com. Any communication should specify the intended recipient.

          Section 16(a) Beneficial Ownership Reporting Compliance

          Section 16 of the Securities Exchange Act of 1934 requires our directors and officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the Securities and Exchange Commission. Such persons are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file.

          Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2007.

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Item 11. Executive Compensation.

As is commonly the case for publicly traded limited partnerships, we have no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as our general partner, is to direct, control and manage all of our activities. Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has delegated to KMR the management and control of our business and affairs to the maximum extent permitted by our partnership agreement and Delaware law, subject to our general partner’s right to approve certain actions by KMR. The executive officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities for KMR. Certain of those executive officers also serve as executive officers of Knight, formerly KMI, and of Knight Holdco LLC, Knight's privately owned parent company. Except as indicated otherwise, all information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for services rendered to us, our subsidiaries and our affiliates, including Knight and Knight Holdco LLC. In this Item 11, “we,” “our” or “us” refers to Kinder Morgan Energy Partners, L.P. and, where appropriate, Kinder Morgan G.P., Inc., KMR and Knight.

Compensation Discussion and Analysis

Program Objectives

We are a publicly traded master limited partnership, and our businesses consist of a diversified portfolio of energy transportation, storage and production assets. We seek to attract and retain executives who will help us achieve our primary business strategy objective of growing the value of our portfolio of businesses for the benefit of our unitholders. To help accomplish this goal, we have designed an executive compensation program that rewards individuals with competitive compensation that consists of a mix of cash, benefit plans and long-term compensation, with a majority of executive compensation tied to the “at risk” portions of the annual cash bonus.

The key objectives of our executive compensation program are to attract, motivate and retain executives who will advance our overall business strategies and objectives to create and return value to our unitholders. We believe that an effective executive compensation program should link total compensation to financial performance and to the attainment of short- and long-term strategic, operational, and financial objectives. We also believe it should provide competitive total compensation opportunities at a reasonable cost. In designing our executive compensation program, we have recognized that our executives have a much greater portion of their overall compensation at-risk than do our other employees; consequently, we have tried to establish the at-risk portions of our executive total compensation at levels that recognize their much increased level of responsibility and their ability to influence business results.

Currently, our executive compensation program is principally comprised of the following two elements: (i) base cash salary; and (ii) possible annual cash bonus (reflected in the Summary Compensation Table below as Non-Equity Incentive Plan Compensation). It has been our philosophy to pay our executive officers a base salary not to exceed $200,000, which we believe is below annual base salaries for comparable positions in the marketplace. At its January 2008 meeting, KMR’s compensation committee (discussed more fully below) agreed to raise the cap for our executive officers’ base salaries to an annual amount not to exceed $300,000. No increases above $200,000 have been implemented at this time. If this increase was implemented, we believe the base salaries paid to our executive officers would continue to be below the industry average for similarly positioned executives. While not awarded by us, KMR’ compensation committee was aware of the units awarded by Knight Holdco LLC (as discussed more fully below) and took these awards into account as components of the total compensation received by our executive officers.

In addition, we believe that the compensation of our Chief Executive Officer, Chief Financial Officer and the executives named below, collectively referred to in this Item 11 as our named executive officers, should be directly and materially tied to the financial performance of Knight and us, and should be aligned with the interests of our unitholders. Therefore, the majority of our named executive officers’ compensation is allocated to the “at risk” portion of our compensation program—the annual cash bonus. Accordingly, for 2007, our executive compensation was weighted toward the cash bonus, payable on the basis of achieving (i) an earnings before interest, taxes, depreciation, depletion and amortization (referred to as EBITDA) less capital spending target by Knight; and (ii) a cash distribution per common unit target by us.

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We periodically compare our executive compensation components with market information. The purpose of this comparison is to ensure that our total compensation package operates effectively, remains both reasonable and competitive with the energy industry, and is generally comparable to the compensation offered by companies of similar size and scope as us. We also keep abreast of current trends, developments, and emerging issues in executive compensation, and if appropriate, will obtain advice and assistance from outside legal, compensation or other advisors.

We have endeavored to design our executive compensation program and practices with appropriate consideration of all tax, accounting, legal and regulatory requirements. Section 162(m) of the Internal Revenue Code limits the deductibility of certain compensation for our executive officers to $1,000,000 of compensation per year; however, if specified conditions are met, certain compensation may be excluded from consideration of the $1,000,000 limit. Since the bonuses paid to our executive officers are paid under Knight’s Annual Incentive Plan as a result of reaching designated financial targets established by KMR’s and Knight’s compensation committees, we expect that all compensation paid to our executives would qualify for deductibility under federal income tax rules. Though we are advised that we and private companies, such as Knight, are not subject to section 162(m), we and Knight have chosen to generally operate as if this code section does apply to us and Knight as a measure of appropriate governance.

Prior to 2006, long-term equity awards comprised a third element of our executive compensation program. These awards primarily consisted of grants of restricted KMI stock and grants of non-qualified options to acquire shares of KMI common stock, both pursuant to the provisions of KMI’s Amended and Restated 1999 Stock Plan, referred to in this report as the KMI stock plan. Prior to 2003, we used both KMI stock options and restricted KMI stock as the principal components of long-term executive compensation, and beginning in 2003, we used grants of restricted stock exclusively as the principal component of long-term executive compensation. For each of the years ended December 31, 2006 and 2007, no restricted stock or options to purchase shares of KMI, KMP or KMR were granted to any of our named executive officers.

Additionally, in connection with KMI’s going-private transaction, Knight Holdco LLC awarded members of Knight’s management Class A-1 and Class B units of Knight Holdco LLC. In accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units. As a subsidiary of Knight Holdco LLC, we are, under accounting rules, allocated a portion of this compensation expense, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units. For more information concerning the Knight Holdco LLC units, see Item 13. “Certain Relationships and Related Transactions, and Director Independence—Related Transactions—KMI Going-Private Transaction”.

Behaviors Designed to Reward

Our executive compensation program is designed to reward individuals for advancing our business strategies and the interests of our stakeholders, and we prohibit engaging in any detrimental activities, such as performing services for a competitor, disclosing confidential information or violating appropriate business conduct standards. Each executive is held accountable to uphold and comply with company guidelines, which require the individual to maintain a discrimination-free workplace, to comply with orders of regulatory bodies, and to maintain high standards of operating safety and environmental protection.

Unlike many companies, we have no executive perquisites and, with respect to our United States-based executives, we have no supplemental executive retirement, non-qualified supplemental defined benefit/contribution, deferred compensation or split dollar life insurance programs. Additionally, we do not have employment agreements (other than with our Chairman and Chief Executive Officer, Richard D. Kinder), special severance agreements or change of control agreements for our U.S. executives. Our executives are eligible for the same severance policy as our workforce, which caps severance payments to an amount equal to six months of salary. We have no executive company cars or executive car allowances nor do we offer or pay for financial planning services. Additionally, we do not own any corporate aircraft and we do not pay for executives to fly first class. We believe that we are currently below competitive levels for comparable companies in this area of our overall compensation package; however, we have no current plans to change our policy of not offering such executive benefits, perquisite programs or special executive severance arrangements.

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At his request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, receives $1 of base salary per year. Additionally, Mr. Kinder has requested that he receive no annual bonus, unit grants, or other compensation from us. Mr. Kinder does not have any deferred compensation, supplemental retirement or any other special benefit, compensation or perquisite arrangement with us. Each year Mr. Kinder reimburses us for his portion of health care premiums and parking expenses. Mr. Kinder was awarded Class B units by and in Knight Holdco LLC in connection with KMI’s going-private transaction, and while we are, under accounting rules, allocated compensation expense attributable to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.

Elements of Compensation

As outlined above, our executive compensation program currently is principally comprised of the following two elements: (i) a base cash salary; and (ii) a possible annual cash bonus. With regard to our named executive officers other than our Chief Executive Officer, KMR’s compensation committee reviews and approves annually the financial goals and objectives of both Knight and us that are relevant to the compensation of our named executive officers. Generally following the regularly scheduled fourth quarter board meeting in each year, the committee solicits information from other directors, the Chief Executive Officer and other relevant members of senior management regarding the performance of our named executive officers other than our Chief Executive Officer during that year. Our Chief Executive Officer makes compensation recommendations to the committee with respect to our named executive officers, other than himself. The committee obtains the information and the recommendations prior to the regularly scheduled first quarter board meeting.

Annually, at KMR’s regularly scheduled first quarter board meeting, the committee evaluates the performance of our named executive officers other than our Chief Executive Officer and makes determinations regarding the terms of their continued employment and compensation for that year. If the committee deems it advisable, it may, rather than determine the terms of continued employment and compensation for the named executive officers (other than the Chief Executive Officer), make a recommendation with respect thereto to the independent members of the board, who make the determination at the first quarter board meeting. The committee also determines bonuses for the prior year based on the performance targets set therefor, and sets performance targets for the present year for bonus and other relevant purposes.

If any of KMR’s or our general partner’s executive officers is also an executive officer of Knight, the committee’s compensation determination or recommendation (i) may be with respect to the aggregate compensation to be received by such officer from Knight, KMR, and our general partner that is to be allocated among them in accordance with procedures approved by the committee, if such aggregate compensation set by the committee and that set by the committee or the board of KMR are the same, or alternatively (ii) may be with respect to the compensation to be received by such executive officers from Knight, KMR or our general partner, as the case may be, in which case such compensation will not be allocated among Knight, on the one hand, and KMR, our general partner and us, on the other. Thereafter, the committee or the Chief Executive Officer will discuss the committee’s evaluation and the determination as to compensation with the named executive officers.

In addition, the compensation committee has the sole authority to retain (and terminate as necessary) and compensate any compensation consultants, counsel and other firms of experts to advise it as it determines necessary or appropriate. The committee has the sole authority to approve any such firm’s fees and other retention terms, and we and Knight, as applicable, will make adequate provision for the payment of all fees and other compensation, approved by the committee, to any such firm employed by the committee. The committee also has sole authority to determine if any compensation consultant is to be used to assist in the evaluation of director, Chief Executive Officer or senior executive compensation and will have sole authority to retain and terminate any such compensation consultant and to approve the consultant’s fees and other retention terms.

Base Salary

Base salary is paid in cash. For each of the years 2007 and 2006, all of our named executive officers, with the exception of our Chairman and Chief Executive Officer who receives $1 of base salary per year as described above, were paid a base salary of $200,000 per year. At KMR’s first quarter 2008 board meeting, the compensation committee agreed to raise the base salary cap for our executive officers, beginning in 2008, to an annual amount not

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to exceed $300,000. No increases above $200,000 have been implemented at this time. Generally, we believe that our executive officers’ base salaries are (and will continue to be following any implementation of the previously described increase) below base salaries for executives in similar positions and with similar responsibilities at companies of comparable size and scope.

Possible Annual Cash Bonus (Non-Equity Cash Incentive)

Our possible annual cash bonuses are provided for under Knight’s Annual Incentive Plan, which became effective January 18, 2005. The overall purpose of the Knight Annual Incentive Plan is to increase our executive officers’ and our employees’ personal stake in the continued success of Knight and us by providing them additional incentives through the possible payment of annual cash bonuses. Under the plan, annual cash bonuses may be paid to our executive officers and other employees depending on a variety of factors, including their individual performance, Knight’s financial performance, the financial performance of Knight’s subsidiaries (including us), safety and environmental goals and regulatory compliance.

The plan is administered by the compensation committee of Knight’s board of directors. The compensation committee is authorized to grant awards under the plan, interpret the plan, adopt rules and regulations for carrying out the plan, and make all determinations necessary or advisable for the administration of the plan.

All of the employees of Knight and its subsidiaries, including KMGP Services Company, Inc., are eligible to participate in the plan, except employees who are included in a unit of employees covered by a collective bargaining agreement unless such agreement expressly provides for eligibility under the plan. However, only eligible employees who are selected by the KMR and Knight compensation committees will actually participate in the plan and receive bonuses.

The plan consists of two components: the executive plan component and the non-executive plan component. Our Chairman and Chief Executive Officer and all employees who report directly to the Chairman are eligible for the executive plan component; however, as stated elsewhere in this report, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, has elected to not participate under the plan. As of January 31, 2008, excluding Mr. Richard D. Kinder, eleven of our current executive officers were eligible to participate in the executive plan component. All other U.S. eligible employees were eligible for the non-executive plan component.

The KMR compensation committee determines which of our eligible employees will be eligible to participate under the executive plan component of the plan. At or before the start of each calendar year (or later, to the extent allowed under Internal Revenue Code regulations), performance objectives for that year are identified. The performance objectives are based on one or more of the criteria set forth in the plan. The KMR compensation committee establishes a bonus opportunity for each executive officer, which is our portion of the amount of the bonus the executive officer will earn if the performance objectives are fully satisfied. The compensation committee may specify a minimum acceptable level of achievement of each performance objective below which no bonus is payable with respect to that objective. The compensation committee may set additional levels above the minimum (which may also be above the targeted performance objective), with a formula to determine the percentage of the bonus opportunity to be earned at each level of achievement above the minimum. Performance at a level above the targeted performance objective may entitle the executive officer to earn a bonus in excess of 100% of the bonus opportunity. However, the maximum payout to any individual under the plan for any year is $2.0 million, and the KMR compensation committee has the discretion to reduce the bonus amount payable by us in any performance period.

Performance objectives may be based on one or more of the following criteria:

• Knight’s EBITDA less capital spending, or the EBITDA less capital spending of one of its subsidiaries or business units;

• Knight’s net income or the net income of one of its subsidiaries or business units;

• Knight’s revenues or the revenues of one of its subsidiaries or business units;

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• Knight’s unit revenues minus unit variable costs or the unit revenues minus unit variable costs of one of its subsidiaries or business units;

• Knight’s return on capital, return on equity, return on assets, or return on invested capital, or the return on capital, return on equity, return on assets, or return on invested capital of one of its subsidiaries or business units;

• Knight’s cash flow return on assets or cash flows from operating activities, or the cash flow return on assets or cash flows from operating activities of one of its subsidiaries or business units;

• Knight’s capital expenditures or the capital expenditures of one of its subsidiaries or business units;

• Knight’s operations and maintenance expense or general and administrative expense, or the operations and maintenance expense or general and administrative expense of one of its subsidiaries or business units; or

• Knight’s debt-equity ratios and key profitability ratios, or the debt-equity ratios and key profitability ratios of one of its subsidiaries or business units.

The KMR compensation committee set two performance objectives for 2007 under both the executive plan component and the non-executive plan component. The 2007 performance objectives were $3.44 in cash distributions per common unit at KMP, and $1,089.5 million of EBITDA less capital spending at Knight. These targets were the same as our and Knight’s previously disclosed 2007 budget expectations. At the end of 2007, the KMR compensation committee determined and certified in writing the extent to which the performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by the KMR compensation committee. In 2007, both we and Knight exceeded our established targets.

The table below sets forth the bonus opportunities that could have been payable by us and Knight to our executive officers if the performance objectives established by the KMR compensation committee for 2007 had been 100% achieved. The KMR compensation committee may, at its sole discretion, reduce the amount of the portion of the bonus actually paid by us to any executive officer under the plan from the amount of any bonus opportunity open to such executive officer; and, because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established by the compensation committee each year for eligible executive officers chosen to participate for that year, it is not possible to accurately predict any amounts that will actually be paid under the executive plan portion of the plan over the life of the plan. The compensation committee set bonus opportunities under the plan for 2007 for the executive officers at dollar amounts in excess of that which were expected to actually be paid under the plan. The actual payout amounts under the Non-Equity Incentive Plan Awards made in 2007 are set forth in the Summary Compensation Table in this report in the column entitled “Non-Equity Incentive Plan Compensation.”

Knight Annual Incentive Plan

Bonus Opportunities for 2007

Name and Principal Position	Dollar Value
Richard D. Kinder, Chairman and Chief Executive Officer..................		$	—	(1)
Kimberly A. Dang, Vice President and Chief Financial Officer.............			1,000,000	(2)
Steven J. Kean, Executive Vice President and Chief Operating Officer....			1,500,000	(3)
Scott E. Parker, Vice President (President, Natural Gas Pipelines)..........			1,500,000	(3)
C. Park Shaper, Director and President..........................................			1,500,000	(3)

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_______________

(1) Declined to participate.

(2) Under the plan, for 2007, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $500,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $1,500,000 in bonus opportunities would have been available. The KMR compensation committee may, in its sole discretion, reduce the award payable by us to any participant for any reason.

(3) Under the plan, for 2007, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $750,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $2,000,000 in bonus opportunities would have been available. The KMR compensation committee may, in its sole discretion, reduce the award payable by us to any participant for any reason.

Knight may amend the plan from time to time without shareholder approval except as required to satisfy the Internal Revenue Code or any applicable securities exchange rules. Awards may be granted under the plan for calendar years 2008 through 2009, unless the plan is terminated earlier by Knight. However, the plan will remain in effect until payment has been completed with respect to all awards granted under the plan prior to its termination.

Other Compensation

Knight Inc. Savings Plan. The Knight Inc. Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of Knight and KMGP Services Company, Inc., including the named executive officers, to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, our general partner may make special discretionary contributions. Certain employees’ contributions are based on collective bargaining agreements. The mandatory contributions are made each pay period on behalf of each eligible employee. Participants may direct the investment of both their contributions and employer contributions into a variety of investments at the employee’s discretion. Plan assets are held and distributed pursuant to a trust agreement.

Employer contributions for employees vest on the second anniversary of the date of hire. Effective October 1, 2005, for new employees of our Terminals business segment, a tiered employer contribution schedule was implemented. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for service between two and five years, and 4% for service of five years or more. All employer contributions for employees of our Terminals business segment hired after October 1, 2005 vest on the fifth anniversary of the date of hire (effective January 1, 2008, this five year anniversary date for Terminals employees was changed to three years to comply with changes in federal regulations).

At its July 2007 meeting, the compensation committee of the KMR and Knight boards of directors approved a special contribution of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2007 and continuing through the last pay period of July 2008. The additional 1% contribution does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest according to the same vesting schedule described in the preceding paragraph. Since this additional 1% company contribution is discretionary, KMR and Knight compensation committee approvals will be required annually for each additional contribution. During the first quarter of 2008, excluding our portion of the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2007.

Additionally, in 2006, an option to make after-tax “Roth” contributions (Roth 401(k) option) to a separate participant account was added to the Savings Plan as an additional benefit to all participants. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option, and (ii) attainment of age 59 ½, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.

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Knight Inc. Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and Knight, including our named executive officers, are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, “grandfathered” according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement.

The following table sets forth the estimated actuarial present value of each named executive officer’s accumulated pension benefit as of December 31, 2007, under the provisions of the Cash Balance Retirement Plan. With respect to our named executive officers, the benefits were computed using the same assumptions used for financial statement purposes, assuming current remuneration levels without any salary projection, and assuming participation until normal retirement at age sixty-five. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.

Pension Benefits
		Current		Present Value of
		Credited Yrs		Accumulated	Contributions
Name	Plan Name	of Service		Benefit(1)	During 2007
Richard D. Kinder	Cash Balance	7	$	—	$	—
Kimberly A. Dang	Cash Balance	6		31,408		7,294
Steven J. Kean	Cash Balance	6		41,724		7,767
Scott E. Parker	Cash Balance	9		71,515		9,130
C. Park Shaper	Cash Balance	7		51,079		8,194

__________

(1) The present values in the Pension Benefits table are based on certain assumptions-including a 5.75% discount rate, RP 2000 mortality (post-retirement only), 5% cash balance interest crediting rate, and lump sums calculated using a 5% interest rate and IRS mortality. We assumed benefits would commence at normal retirement date or unreduced retirement date, if earlier. No death or turnover was assumed prior to retirement date.

Other Potential Post-Employment Benefits. On October 7, 1999, Mr. Richard D. Kinder entered into an employment agreement with Knight pursuant to which he agreed to serve as its Chairman and Chief Executive Officer. His employment agreement provides for a term of three years and one year extensions on each anniversary of October 7^th. Mr. Kinder, at his initiative, accepted an annual salary of $1 to demonstrate his belief in our and Knight’s long term viability. Mr. Kinder continues to accept an annual salary of $1, and he receives no other compensation from us. Mr. Kinder was awarded Class B units by and in Knight Holdco LLC in connection with Knight’s going-private transaction, and while we, as a subsidiary of Knight Holdco LLC, are allocated compensation expense attributable to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.

Knight believes that Mr. Kinder’s employment agreement contains provisions that are beneficial to Knight and its subsidiaries and accordingly, Mr. Kinder’s employment agreement is extended annually at the request of Knight and KMR’s Board of Directors. For example, with limited exceptions, Mr. Kinder is prevented from competing in any manner with Knight or any of its subsidiaries, while he is employed by Knight and for 12 months following the termination of his employment with Knight. The agreement contains provisions that address termination with and without cause, termination as a result of change in duties or disability, and death. At his current compensation level, the maximum amount that would be paid to Mr. Kinder or his estate in the event of his termination is three times $750,000, or $2.25 million. This payment would be made if Mr. Kinder were terminated by Knight without cause or if Mr. Kinder terminated his employment with Knight as a result of a change in duties

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(as defined in the employment agreement). There are no employment agreements or change-in-control arrangements with any of our other executive officers.

Mr. Scott E. Parker elected to not participate in the going-private transaction. As a result, we offered Mr. Parker a retention agreement. The agreement was effective May 30, 2007, and lasts for three years. Mr. Parker is eligible for quarterly cash payments of $65,000, a one-time relocation payment of $100,000, and the right to participate in both the annual incentive plan and employee benefit plans. Under the terms of the agreement, Mr. Parker will also receive payments of $500,000 on May 30, 2008, $500,000 on May 30, 2009, and $2,000,000 on May 30, 2010, respectively, provided he is an active employee on each respective date. The agreement also contains confidential information, non-solicitation of employees and non-compete provisions.

Common Unit Option Plan. Pursuant to our Common Unit Option Plan, key personnel are eligible to receive grants of options to acquire common units. The total number of common units authorized under the option plan is 500,000. None of the options granted under the option plan may be “incentive stock options” under Section 422 of the Internal Revenue Code. If an option expires without being exercised, the number of common units covered by such option will be available for a future award. The exercise price for an option may not be less than the fair market value of a common unit on the date of grant. KMR’s compensation committee determines the duration and vesting of the options to employees at the time of grant, and no individual employee may be granted options for more than 20,000 common units in any year. As of December 31, 2007, no options to purchase common units were outstanding under the plan. KMR’s compensation committee administers the option plan, and the plan has a termination date of March 5, 2008.

For the year ended December 31, 2007, no options to purchase common units were granted to or exercised by any of our executive officers, and as of December 31, 2007, none of our executive officers owned unexercised common unit options. The plan may also grant, to each of our non-employee directors, options to purchase common units at an exercise price equal to the fair market value of the common units at the end of the trading day on such date. For the year ended December 31, 2007, no options to purchase common units were granted to our non-employee directors.

Summary Compensation Table

The following table shows compensation paid or otherwise awarded to (i) our principal executive officer; (ii) our principal financial officer; and (iii) our three most highly compensated executive officers (other than our principal executive officer and principal financial officer) serving at fiscal year end 2007 (collectively referred to as the “named executive officers”) for services rendered to us, our subsidiaries or our affiliates, including Knight and Knight Holdco LLC (collectively referred to as the “Knight affiliated entities”), during fiscal years 2007 and 2006. The amounts in the columns below, except the column entitled “Unit Awards by Knight Holdco LLC”, represent the total compensation paid or awarded to the named executive officers by all the Knight affiliated entities, and as a result the amounts are in excess of the compensation expense allocated to and recognized by us for services rendered to us. The amounts in the column entitled “Unit Awards by Knight Holdco LLC” consist of accounting expense calculated in accordance with SFAS No. 123R and allocated to us for the Knight Holdco LLC Class A-1 and Class B units awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units and none of the named executive officers has received any payments in respect of such units.

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							(1)		(2)		(3)		(4)		(5)		(6)
											Non-Equity						Unit Awards
							Stock		Option		Incentive		Change				by Knight
Name and							Awards		Awards		Plan		in Pension		All Other		Holdco
Principal Position	Year		Salary		Bonus		by KMI		by KMI		Compensation		Value		Compensation		LLC		Total
Richard D. Kinder	2007	$	1	$	—	$	—	$	—	$	—	$	—	$	—	$	1,016,000	$	1,016,001
Director, Chairman and	2006		1		—		—		—		—		—		—		—		1
Chief Executive Officer
Kimberly A. Dang	2007		200,000		—		338,095		—		400,000		7,294		32,253		73,800		1,051,442
Vice President and	2006		200,000		—		139,296		37,023		270,000		6,968		46,253		—		699,540
Chief Financial Officer
Steven J. Kean	2007		200,000		—		4,397,080		—		1,100,000		7,767		147,130		295,010		6,146,987
Executive Vice President	2006		200,000		—		1,591,192		147,943		—		7,422		284,919		—		2,231,476
And
Chief Operating Officer
Scott E. Parker	2007		200,000		—		2,340,080		—		1,100,000		9,130		307,688		—		3,956,898
Vice President (President,	2006		200,000		350,000		881,317		29,490		500,000		8,735		164,630		—		2,134,172
Natural Gas Pipelines)
C. Park Shaper	2007		200,000		—		1,950,300		—		1,200,000		8,194		155,953		466,110		3,980,557
Director and President	2006		200,000		—		1,134,283		24,952		—		7,835		348,542		—		1,715,612

_______________

(1) Consists of expense calculated in accordance with SFAS No. 123R attributable to restricted KMI stock awarded in 2003, 2004 and 2005 according to the provisions of the KMI Stock Plan. No restricted stock was awarded in 2007 or 2006. For grants of restricted stock, we take the value of the award at time of grant and accrue the expense over the vesting period according to SFAS No. 123R. For grants made July 16, 2003—KMI closing price was $53.80, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. For grants made July 20, 2004—KMI closing price was $60.79, fifty percent of the shares vest on the third anniversary after the date of grant and the remaining fifty percent of the shares vest on the fifth anniversary after the date of grant. For grants made July 20, 2005—KMI closing price was $89.48, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. As a result of the KMI going-private transaction, all outstanding restricted shares vested in 2007 and therefore all remaining compensation expense with respect to restricted stock was recognized in 2007 in accordance with SFAS No. 123R. However, Knight bore all of the costs associated with this acceleration.

(2) Consists of expense calculated in accordance with SFAS No. 123R attributable to options to purchase KMI shares awarded in 2002 and 2003 according to the provisions of the KMI Stock Plan. No options were granted in 2007 or 2006. For options granted in 2002—volatility of 0.3912 using a 6 year term, 4.01% five year risk free interest rate return, and a 0.71% expected annual dividend rate. For options granted in 2003—volatility of 0.3853 using a 6.25 year term, 3.37% treasury strip quote at time of grant, and a 2.973% expected annual dividend rate. As a result of the KMI going-private transaction, all outstanding options vested in 2007 and therefore all remaining compensation expense with respect to options was recognized in 2007 in accordance with SFAS No. 123R. As a condition to their being permitted to participate in the KMI going-private transaction, Messrs. Kean and Shaper agreed to the cancellation of 10,467 and 22,031 options, respectively. These cancelled options had weighted average exercise prices of $39.12 and $24.75 per share, respectively. However, Knight bore all of the costs associated with this acceleration.

(3) Represents amounts paid according to the provisions of the Knight Annual Incentive Plan. In the case of Mr. Parker, for the year 2006, an additional $350,000 was paid outside of the plan, as reflected in the Bonus column. Amounts were earned in

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the fiscal year indicated but were paid in the next fiscal year. Messrs. Kean and Shaper refused to accept a bonus for 2006. The committee agreed that this was not a reflection of performance on either person.

(4) Represents the 2007 and 2006, as applicable, change in the actuarial present value of accumulated defined pension benefit (including unvested benefits) according to the provisions of Knight’s Cash Balance Retirement Plan.

(5) Amounts represent value of contributions to the Knight Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000, taxable parking subsidy and dividends paid on unvested restricted stock awards. Amounts each year include $10,000 representing the value of contributions to the Knight Savings Plan. Amounts representing the value of dividends paid on unvested restricted stock awards are as follows: for 2007—Mrs. Dang $21,875; Mr. Kean $136,500; Mr. Parker $77,000; and Mr. Shaper $144,375; for 2006—Mrs. Dang $35,875; Mr. Kean $273,000; Mr. Parker $154,000; and Mr. Shaper $336,875. Mr. Parker’s 2007 amount also includes amounts for imputed income for company provided cellphone, a $100,000 relocation allowance, and a $130,000 payment to compensate for loss of dividends associated with the KMI going-private transaction.

(6) Such amounts represent the amount of the non-cash compensation expense calculated in accordance with SFAS No. 123R attributable to the Class A-1 and Class B units of Knight Holdco LLC and allocated to us for financial reporting purposes but does not include any such expense allocated to Knight or any of its other subsidiaries. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated, nor do we expect, to pay any amounts in respect of such units. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Related Transactions—KMI Going-Private Transaction” for further discussion of these units.

KMI Stock Options and Restricted Stock

Effective with the completion of the KMI going-private transaction on May 30, 2007, all of KMI’s equity compensation awards (including awards held by our named executive officers) were subject to the following treatment:

• each option or other award to purchase shares of KMI common stock granted under any Kinder Morgan employee or director equity plan, whether vested or unvested, that was outstanding immediately prior to the effective time of the buyout, vested as of the effective time of the buyout, and was cancelled and converted into the right to receive a cash payment equal to the number of shares of KMI common stock underlying such options multiplied by the amount (if any) by which the $107.50 per share merger consideration issued in the going-private transaction exceeded the option exercise price, without interest and less any applicable withholding tax; and

• each share of restricted stock or restricted stock unit under any Kinder Morgan stock plan or benefit plan vested as of the effective time of the buyout and was cancelled and converted into the right to receive a cash payment equal to the number of outstanding shares of restricted stock or restricted stock units, multiplied by the $107.50 per share merger consideration, without interest and less any applicable withholding tax.

The following table sets forth, for each of our named executive officers (i) the number of KMI stock options (all of which were vested) held by such persons; (ii) the cash value realized with respect to such stock options upon consummation of the going-private transaction; (iii) the number of shares of restricted KMI stock held by such persons; and (iv) the aggregate cash value realized with respect to such shares of restricted stock upon consummation of the going-private transaction. A portion of the consideration received by the named executive officers with respect to their options to acquire shares of KMI common stock and their restricted shares of KMI common stock was reinvested in exchange for ownership interests in Knight Holdco LLC, and certain executive officers, as a condition to their being permitted to participate as investors in Knight Holdco LLC, agreed to the cancellation of certain of their options prior to the going-private transaction.

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	Option Awards			Stock Awards
	Stock		Value	Shares of		Value
Name	Options		Realized (1)	Restricted Stock		Realized (2)
Richard D. Kinder	—	$	—	—	$	—
Kimberly A. Dang	24,750		1,443,178	8,000		860,000
Steven J. Kean(3)	25,533		1,375,772	78,000		8,385,000
Scott E. Parker	10,000		537,000	44,000		4,730,000
C. Park Shaper(4)	197,969		12,529,810	82,500		8,868,750

_______

(1) Calculated based on the actual exercise prices underlying the related options, as opposed to the weighted average exercise price per share of options.

(2) Calculated as $107.50 multiplied by the number of shares of restricted stock.

(3) Mr. Kean, as a condition to his being permitted to participate as an investor in Knight, agreed to the cancellation of 10,467 of his options shown above, with a weighted average exercise price of $39.12 per share, prior to the going-private transaction.

(4) Mr. Shaper, as a condition to his being permitted to participate as an investor in Knight, agreed to the cancellation of 22,031 of his options shown above, with a weighted average exercise price of $24.75 per share, prior to the going-private transaction.

Grants of Plan-Based Awards

The following supplemental compensation table shows compensation details on the value of all non-guaranteed and non-discretionary incentive awards granted during 2007 to our named executive officers, as well as awards of Knight Holdco LLC units received in 2007 by each named executive officer. The table includes the Knight Holdco LLC Class A-1 and Class B units awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation to pay any amounts in respect of such units. The table includes awards made during or for 2007. The information in the table under the caption “Estimated Possible Payments Under Non-Equity Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the Knight Annual Incentive Plan for performance in 2007. Amounts actually paid under that plan for 2007 are set forth in the Summary Compensation Table under the caption “Non-Equity Incentive Plan Compensation.” There will not be any additional payouts under the Annual Incentive Plan for 2007.

		Estimated Possible Payouts Under			All other stock
		Non-Equity Incentive Plan Awards1			awards2	Grant date
					Number	fair value
Name	Grant date	Threshold	Target	Maximum	of units	of stock awards3
Richard D. Kinder	May 30, 2007				791,405,452	$    9,200,000
Kimberly A. Dang	January 17, 2007	$     500,000	$  1,000,000	$    1,500,000
	May 30, 2007				49,893,032	674,887
Steven J. Kean	January 17, 2007	750,000	1,500,000	2,000,000
	May 30, 2007				162,114,878	2,720,252
Scott E. Parker	January 17, 2007	500,000	1,500,000	2,000,000
C. Park Shaper	January 17, 2007	750,000	1,500,000	2,000,000
	May 30, 2007				225,436,274	4,315,475

__________

 

¹ Represents grants under the Knight Annual Incentive Plan for performance in 2007. See “Elements of Compensation—

 

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Possible Annual Cash Bonus (Non-Equity Cash Incentive)” for a discussion of these awards.

 

² Represents the sum of the number of Class A-1 units and the number of Class B units of Knight Holdco LLC awarded to the named executive officers in connection with the going-private transaction. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Related Transactions—KMI Going-Private Transaction” for detail regarding these awards.

   

³ Amounts represent the fair value calculated in accordance with SFAS No. 123R attributable to Class A-1 and Class B units of Knight Holdco LLC awarded by Knight Holdco LLC to the named executive officers in connection with the going-private transaction. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated to pay any amounts in respect of such units. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Related Transactions—KMI Going-Private Transaction” for further discussion of these units.

 

Outstanding Equity Awards at Fiscal Year-End

The only unvested equity awards outstanding at the end of fiscal 2007 were the Class B units of Knight Holdco LLC awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units.

	Stock awards:
			Market value of
		Number of units that	units of stock that
Name	Type of units:	have not vested	have not vested1
Richard D. Kinder	Class B units	791,405,452	N/A
Kimberly A. Dang	Class B units	49,462,841	N/A
Steven J. Kean	Class B units	158,281,090	N/A
C. Park Shaper	Class B units	217,636,499	N/A

__________

 

¹ Because the Class B units are equity interests of Knight Holdco LLC, a private limited liability company, the market value of such interests is not readily determinable. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated, nor do we expect, to pay any amounts in respect of such units. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Related Transactions—KMI Going-Private Transaction” for further discussion of these units.

 

Director Compensation

Compensation Committee Interlocks and Insider Participation. The compensation committee of KMR functions as our compensation committee. KMR’s compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding the executive officers of our general partner and its delegate, KMR. Mr. Richard D. Kinder, Mr. James E. Street, and Messrs. Shaper and Kean, who are executive officers of KMR, participate in the deliberations of the KMR compensation committee concerning executive officer compensation. None of the members of KMR’s compensation committee is or has been one of our officers or employees, and none of our executive officers served during 2007 on a board of directors of another entity which has employed any of the members of KMR’s compensation committee.

Directors Fees. Beginning in 2005, awards under our Common Unit Compensation Plan for Non-Employee Directors served as compensation for each of KMR’s three non-employee directors. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. Directors of KMR who are also employees of Knight (Messrs. Richard D. Kinder and C. Park Shaper) do not receive compensation in their capacity as directors.

Kinder Morgan Energy Partners, L.P. Common Unit Compensation Planfor Non-Employee Directors. On January 18, 2005, KMR’s compensation committee established the Kinder Morgan Energy Partners, L.P. Common

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Unit Compensation Plan for Non-Employee Directors. The plan is administered by KMR’s compensation committee and KMR’s board has sole discretion to terminate the plan at any time. The primary purpose of this plan was to promote our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders’ interests. Further, since KMR’s success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR’s shareholders.

The plan recognizes that the compensation to be paid to each non-employee director is fixed by the KMR board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. Each election will be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. The election for 2006 was made effective January 17, 2006; the election for 2007 was made effective January 17, 2007; and the election for 2008 was made effective January 16, 2008. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000.

Each annual election will be evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement will contain the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the director’s service as a director of KMR is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director will, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have lapsed will cease to be subject to any forfeiture restrictions, and we will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director will have the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions.

The number of common units to be issued to a non-employee director electing to receive the cash compensation in the form of common units will equal the amount of such cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the cash compensation in the form of common units will receive cash equal to the difference between (i) the cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment will be payable in four equal installments generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded.

On January 17, 2007, each of KMR’s three non-employee directors was awarded cash compensation of $160,000 for board service during 2007. Effective January 17, 2007, each non-employee director elected to receive certain amounts of that compensation in the form of our common units and each was issued common units pursuant to the plan and its agreements (based on the $48.44 closing market price of our common units on January 17, 2007, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive compensation of $95,911.20 in the form of our common units and was issued 1,980 common units; Mr. Waughtal elected to receive compensation of $159,852.00 in the form of our common units and was issued 3,300 common units; and Mr. Hultquist elected to receive cash compensation of $96,880.00 in the form of our common units and was issued 2,000 common units. All remaining compensation ($64,088.80 to Mr. Gaylord; $148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) will be paid in cash to each of the non-employee directors as described above, and no other compensation will be paid to the non-employee directors during 2007.

On January 16, 2008, each of KMR’s three non-employee directors was awarded cash compensation of $160,000 for board service during 2008; however, during a plan audit it was determined that each director was inadvertently paid an additional dividend in 2007. As a result, each director’s cash compensation for service during 2008 was adjusted downward to reflect this error. The correction results in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr. Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal.

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Effective January 16, 2008, two of the three non-employee directors elected to receive certain amounts of that compensation in the form of our common units and each was issued common units pursuant to the plan and its agreements (based on the $55.81 closing market price of our common units on January 16, 2008, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive compensation of $84,831.20 in the form of our common units and was issued 1,520 common units; and Mr. Waughtal elected to receive compensation of $157,272.58 in the form of our common units and was issued 2,818 common units. All remaining compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00 to Mr. Hultquist) will be paid in cash to each of the non-employee directors as described above, and no other compensation will be paid to the non-employee directors during 2008.

Directors’ Unit Appreciation Rights Plan. On April 1, 2003, KMR’s compensation committee established our Directors’ Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR’s three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement.

All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised.

On April 1, 2003, the date of adoption of the plan, each of KMR’s three non-employee directors was granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of KMR’s three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors; however, all unexercised awards made under the plan remain outstanding. No unit appreciation rights were exercised during 2006. In 2007, Mr. Hultquist exercised 7,500 unit appreciation rights and received a cash amount of $116,250. As of December 31, 2007, 45,000 unit appreciation rights had been granted, vested and remained outstanding.

The following table discloses the compensation earned by each of KMR’s three non-employee directors for board service during fiscal year 2007. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. Directors of KMR who are also employees of Knight do not receive compensation in their capacity as directors.

	Fees Earned or		Common Unit		All Other
Name	Paid in Cash		Awards(1)		Compensation(2)		Total
Edward O. Gaylord	$	64,089	$	95,911	$	111,466	$	271,466
Gary L. Hultquist		63,120		96,880		65,840		225,840
Perry M. Waughtal		148		159,852		114,726		274,726

__________

 

(1) Represents the value of cash compensation received in the form of our common units according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors. Value computed as the number of common units elected to be received in lieu of cash times the closing price on date of election. For Mr. Gaylord, 1,980 units elected on January 17, 2007 times the closing price of $48.44; for Mr. Hultquist, 2,000 units elected times the closing price of $48.44; and for Mr. Waughtal, 3,300 units elected times the closing price of $48.44.

 

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(2) For each, represents (i) the value of common unit appreciation rights earned according to the provisions of our Directors’ Unit Appreciation Rights Plan for Non-Employee Directors, determined according to the provisions of SFAS No. 123R—for each common unit appreciation right, equal to the increase in value of a corresponding common unit from December 31, 2006 to December 31, 2007; and (ii) distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors.

For 2007, for Mr. Gaylord, includes (i) value of $106,575 computed as the number of common unit appreciation rights held during 2007 (17,500) times the increase in common unit closing price from December 31, 2006 to December 31, 2007 ($6.09; equal to $53.99 at December 31, 2007 less $47.90 at December 31, 2006); and (ii) $4,891 for distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors; for Mr. Hultquist, includes (i) value of $60,900 computed as the number of common unit appreciation rights held during 2007 (10,000) times the increase in common unit closing price from December 31, 2006 to December 31, 2007 ($6.09; equal to $53.99 at December 31, 2007 less $47.90 at December 31, 2006); and (ii) $4,940 for distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors; for Mr. Waughtal, includes (i) value of $106,575 computed as the number of common unit appreciation rights held during 2007 (17,500) times the increase in common unit closing price from December 31, 2006 to December 31, 2007 ($6.09; equal to $53.99 at December 31, 2007 less $47.90 at December 31, 2006); and (ii) $8,151 for distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors.

Compensation Committee Report

Throughout fiscal 2007, the compensation committee of KMR’s board of directors was comprised of three directors, each of which the KMR board of directors has determined meets the criteria for independence under KMR’s governance guidelines and the New York Stock Exchange rules.

The KMR compensation committee has discussed and reviewed the above Compensation Discussion and Analysis for fiscal year 2007 with management. Based on this review and discussion, the KMR compensation committee recommended to its board of directors, that this Compensation Discussion and Analysis be included in this annual report on Form 10-K for the fiscal year 2007.

KMR Compensation Committee:

Edward O. Gaylord

Gary L. Hultquist

Perry M. Waughtal

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

          The following table sets forth information as of January 31, 2008, regarding (i) the beneficial ownership of (a) our common and Class B units and (b) KMR shares by all directors of our general partner and KMR, its delegate, by each of the named executive officers identified in Item 11 “Executive Compensation” and by all directors and executive officers as a group; and (ii) the beneficial ownership of our common and Class B units or shares of KMR by all persons known by our general partner to own beneficially at least 5% of our common and Class B units and KMR shares. For information regarding the beneficial ownership of Knight Holdco LLC’s units by our named executive officers (and our executive officers who are also officers of Knight) and directors, see Item 13. “Certain Relationships and Related Transactions, and Director Independence—Related Transactions—KMI Going-Private Transaction.” Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002.

Amount and Nature of Beneficial Ownership(1)

	Common Units					Class B Units					Kinder Morgan Management Shares
	Number of Units(2)		Percent of Class			Number of Units(3)		Percent of Class			Number of Shares(4)		Percent of Class
Richard D. Kinder(5)		315,979		*			—		—			84,663		*
C. Park Shaper		4,000		*			—		—			23,793		*
Edward O. Gaylord(6)		40,000		*			—		—			—		—
Gary L. Hultquist		11,500		*			—		—			—		—
Perry M. Waughtal(7)		46,918		*			—		—			46,180		*
Steven J. Kean		—		—			—		—			—		—
Scott E. Parker		—		—			—		—			—		—
Kimberly A. Dang		121		*			—		—			440		*
Directors and Executive Officers as a group (14 persons)(8)		435,995		*			—		—			175,027		*
Knight Inc.(9)		14,355,735		8.43	%		5,313,400		100.00	%		10,334,746		14.27	%
Kayne Anderson Capital Advisors,L.P. and Richard A. Kayne(10)		—		—			—		—			7,869,016		10.86	%
Tortoise Capital Advisors, L.L.C.(11)		—		—			—		—			4,314,123		5.96	%
Janus Capital Management LLC(12)		—		—			—		—			3,647,958		5.04	%

* Less than 1%.

(1)	Except as noted otherwise, all units and KMR shares involve sole voting power and sole investment power. For KMR, see note (4). On January 18, 2005, KMR’s board of directors initiated a rule requiring each director to own a minimum of 10,000 common units, KMR shares, or a combination thereof.
(2)	As of January 31, 2008, we had 170,224,734 common units issued and outstanding.
(3)	As of January 31, 2008, we had 5,313,400 Class B units issued and outstanding.
(4)	Represent the limited liability company shares of KMR. As of January 31, 2008, there were 72,432,482 issued and outstanding KMR shares, including two voting shares owned by our general partner. In all cases, our i-units will be voted in proportion to the affirmative and negative votes, abstentions and non-votes of owners of KMR shares. Through the provisions in our partnership agreement and KMR’s limited liability company agreement, the number of outstanding KMR shares, including voting shares owned by our general partner, and the number of our i-units will at all times be equal.
(5)	Includes 7,879 common units owned by Mr. Kinder’s spouse. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units.
(6)	Includes 1,520 restricted common units.
(7)	Includes 2,818 restricted common units.
(8)	Includes 4,338 restricted common units. Also includes 671 KMR shares purchased by one of our executives for his children. The executive disclaims any beneficial ownership in such KMR shares.
(9)	Includes common units owned by Knight Inc. and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(10)	As reported on the Schedule 13G/A filed February 13, 2008 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors, L.P. reported that in regard to KMR shares, it had sole voting power over 0

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	shares, shared voting power over 7,867,883 shares, sole disposition power over 0 shares and shared disposition power over 7,867,883 shares. Mr. Kayne reports that in regard to KMR shares, he had sole voting power over 1,133 shares, shared voting power over 7,867,883 shares, sole disposition power over 1,133 shares and shared disposition power over 7,867,883 shares. Kayne Anderson Capital Advisors, L.P.’s and Richard A. Kayne’s address is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067.
(11)	As reported on the Schedule 13G/A filed February 12, 2008 by Tortoise Capital Advisors, L.L.C. Tortoise Capital Advisors, L.L.C. reported that in regard to KMR shares, it had sole voting power over 0 shares, shared voting power over 4,202,836 shares, sole disposition power over 0 shares and shared disposition power over 4,314,123 shares. Tortoise Capital Advisors, L.L.C.’s address is 10801 Mastin Blvd., Suite 222, Overland Park, Kansas 66210.
(12)	As reported on the Schedule 13G filed February 14, 2008 by Janus Capital Management LLC. Janus Capital Management LLC reported that in regard to KMR shares, it had sole voting power over 3,647,958 shares, shared voting power over 0 shares, sole disposition power over 3,647,958 shares and shared disposition power over 0 shares. Janus Capital Management LLC’s address is 151 Detroit Street, Denver, Colorado 80206.

Equity Compensation Plan Information

          The following table sets forth information regarding our equity compensation plans as of December 31, 2007. Specifically, the table provides information regarding our Common Unit Option Plan and our Common Unit Compensation Plan for Non-Employee Directors, both described in Item 11, “Executive Compensation.—Compensation Discussion and Analysis—Elements of Compensation—Other Compensation—Common Unit Option Plan,” Item 11 “Executive Compensation—Director Compensation—Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors,” and Note 13 of the notes to our consolidated financial statements included elsewhere in this report.

Plan category	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders	—
Equity compensation plans not approved by security holders	141,820
Total	141,820

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

Related Transactions

KMI Going-Private Transaction

On May 30, 2007, KMI completed the going-private transaction, whereby pursuant to a merger agreement, generally each share of KMI common stock was converted into the right to receive $107.50 in cash without interest. See Item 11. “Executive Compensation—KMI Stock Options and Restricted Stock” for a discussion of the disposition of options to purchase KMI common stock and shares of restricted KMI stock in the going-private transaction. For further information regarding this transaction, see “(a) General Development of Business” within Items 1 and 2 of this report.

In connection with the going-private transaction, some of our executive officers became investors in Knight Holdco LLC, Knight's parent company. None of our independent directors, Messrs. Gaylord, Hultquist and Waughtal, are investors in Knight Holdco LLC. Each of the investors in Knight Holdco LLC entered into an amended and restated limited liability company agreement of Knight Holdco LLC which governs the rights and obligations of the investors with respect to Knight Holdco LLC and Knight. Pursuant to the limited liability company agreement, Knight Holdco LLC is a “manager managed” limited liability company governed by an 11 member board of managers and initially by a “chief manager.” Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, is Knight Holdco LLC's initial chief manager. Mr. Kinder is also a member of the board of managers and has the right to appoint an additional four members of the board of managers. The chief manager has control over most of the operations of Knight Holdco LLC, subject to rights of the board of managers (and in some cases, the members of Knight Holdco LLC, acting in their capacity as such) to approve significant actions proposed to be taken by Knight Holdco LLC or its subsidiaries (generally other than us, KMR and our respective subsidiaries), including, among other things, liquidations, issuances of equity securities, distributions (other than identified tax related distributions), transactions with affiliates, settlement of litigation or entry into agreements with a value in excess of $50 million, entry into new lines of business and approval of the annual budget. Additionally, the members of Knight Holdco LLC (and in some cases, just certain members) have the ability to compel restructuring and liquidity events, including an initial public offering of Knight Holdco LLC or any of its subsidiaries or businesses, a sale or disposition of Knight Holdco LLC or any of its material subsidiaries or its businesses, or distributions of excess cash to the members of Knight Holdco LLC, although in some cases such actions may only be so compelled after specified time periods.

Generally, Knight Holdco LLC has three classes of units—Class A units, Class A-1 units, and Class B units. The Class A units were issued to investors, including members of senior management who directly or indirectly reinvested all or a portion of their KMI equity and/or cash, in respect of their capital contributions to Knight Holdco LLC. Generally, the holders of Class A units will share ratably in all distributions, subject to amounts allocated to the Class A-1 units and the Class B units as set forth below.

The Class B units were awarded by Knight Holdco LLC to members of Knight's management in consideration of their services to or for the benefit of Knight Holdco LLC. The Class B units represent interests in the profits of Knight Holdco LLC following the return of capital for the holders of Class A units and the achievement of predetermined performance targets over time. The Class B units will performance vest in increments of 5% of profits distributions up to a maximum of 20% of all profits distributions that would otherwise be payable with respect to the Class A units and Class A-1 units, based on the achievement of predetermined performance targets. The Class B units are subject to time based vesting, and with respect to any holder thereof, will vest 33 1/3% on each of the 3^rd, 4^th and 5^th year anniversary of the issuance of such Class B units to such holder. The amended and restated limited liability company agreement also includes provisions with respect to forfeiture of Class B units upon termination for cause, Knight Holdco LLC's call rights upon termination and other related provisions relating to an employee's tenure. The allocation of the Class B units among Knight's management was determined prior to closing by Mr. Kinder, and approved by other, non-management investors.

The Class A-1 units were awarded by Knight Holdco LLC to members of Knight's management (other than Mr. Richard D. Kinder) who reinvested their equity interests in Knight Holdco LLC in connection with the going-private transaction in consideration of their services to or for the benefit of Knight Holdco LLC. Class A-1 units

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entitle a holder thereof to receive distributions from Knight Holdco LLC in an amount equal to distributions paid on Class A units (other than distributions on the Class A units that represent a return of the capital contributed in respect of such Class A units), but only after the Class A units have received aggregate distributions in an amount equal to the amount of capital contributed in respect of the Class A units.

The table below sets forth the beneficial ownership (as defined in Rule 13(d)(3) of the Exchange Act) of Knight Holdco LLC's units by each of our directors and named executive officers (and executive officers of ours who are also executive officers of Knight), detailing the contributions made by each in respect of their Class A units and the grant date fair value, as calculated in accordance with SFAS No. 123R, of the Class A-1 and Class B units received by each. In accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units. As a subsidiary of Knight Holdco LLC, we are allocated a portion of this compensation expense, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units. Please see Item 11. “Executive Compensation” for disclosure regarding the Class A-1 and Class B units received by each of the named executive officers and the expense as calculated in accordance with SFAS No. 123R allocated to us for 2007 in respect of each officer's units. Except as noted otherwise, each individual has sole voting power and sole disposition power over the units listed.

				% of Class
		% of Class	Class A-1	A-1		% of Class
	Class A Units	A Units(1)	Units	Units(2)	Class B Units	B Units(3)
Richard D. Kinder(4)	2,424,000,000	30.6	–	–	791,405,452	40.0
Edward O. Gaylord	–	–	–	–	–	–
Gary L. Hultquist	–	–	–	–	–	–
Perry M. Waughtal	–	–	–	–	–	–
C. Park Shaper(5)	13,598,785	*	7,799,775	28.3	217,636,499	11.0
Steven J. Kean(6)	6,684,149	*	3,833,788	13.9	158,281,090	8.0
Kimberly A. Dang(7)	750,032	*	430,191	1.6	49,462,841	2.5
David D. Kinder(8)	1,075,981	*	617,144	2.3	55,398,382	2.8
Joseph Listengart(9)	6,059,449	*	3,475,483	12.6	79,140,545	4.0
Scott E. Parker	–	–	–	–	–	–
James E. Street(10)	3,813,005	*	2,187,003	7.9	49,462,841	2.5
Executive officers and directors as a group (14 persons)	2,460,763,539	31.1	21,086,247	76.5	1,626,338,205	82.2

____________________________________

* Less than 1%.

(1) As of January 31, 2008, Knight Holdco LLC had 7,914,367,913 Class A Units issued and outstanding.

(2) As of January 31, 2008, Knight Holdco LLC had 27,225,694 Class A-1 Units issued and outstanding and 345,042 phantom Class A-1 Units issued and outstanding. The phantom Class A-1 Units were issued to Canadian management employees.

(3) As of January 31, 2008, Knight Holdco LLC had 1,922,620,621 Class B Units issued and outstanding and 55,893,008 phantom Class B Units issued and outstanding. The phantom Class B Units were issued to Canadian management employees.

(4) Includes 522,372 Class A units owned by Mr. Kinder's wife. Mr. Kinder disclaims any and all beneficial or pecuniary interest in the Class A units held by his wife. Also includes 263,801,817 Class B Units that Mr. Kinder transferred to a limited partnership. Mr. Kinder may be deemed to be the beneficial owner of these transferred Class B Units, because Mr. Kinder controls the voting and disposition power of these Class B Units, but he disclaims ninety-nine percent of any beneficial and pecuniary interest in them. Mr. Kinder contributed 23,994,827 shares of KMI common stock and his wife contributed 5,173 shares of KMI common stock to Knight Holdco LLC that were valued for purposes of Knight Holdco LLC's limited liability agreement at $2,423,477,628 and $522,372, respectively, in exchange for their respective Class A units. The Class B units received by Mr. Kinder had a grant date fair value as calculated in accordance with SFAS No. 123R of $9,200,000.

(5) Includes 217,636,499 Class B Units that Mr. Shaper transferred to a limited partnership. Mr. Shaper may be deemed to be the beneficial owner of these transferred Class B Units, because Mr. Shaper controls the voting and disposition power of these Class B Units, but he disclaims approximately twenty-two percent of any beneficial and pecuniary interest in them. Mr. Shaper made a cash investment of $13,598,785 of his after-tax proceeds from the conversion in the going-private transaction of 82,500 shares of KMI restricted stock and options to acquire 197,969 shares of KMI common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Shaper had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $4,315,475.

(6) Mr. Kean made a cash investment of $6,684,149 of his after-tax proceeds from the conversion in the going-private transaction of 78,000 shares of KMI restricted stock and options to acquire 25,533 shares of KMI common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Kean had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $2,720,252.

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(7) Includes 49,462,841 Class B Units that Ms. Dang transferred to a limited partnership. Ms. Dang may be deemed to be the beneficial owner of these transferred Class B Units, because Ms. Dang has voting and disposition power of these Class B Units, but she disclaims ten percent of any beneficial and pecuniary interest in them. Ms. Dang made a cash investment of $750,032 of her after-tax proceeds from the conversion in the going-private transaction of 8,000 shares of KMI restricted stock and options to acquire 24,750 shares of KMI common stock in exchange for her Class A units. The Class A-1 units and Class B units received by Ms. Dang had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $674,887.

(8) Includes 55,398,382 Class B Units that Mr. Kinder transferred to a limited partnership. Mr. Kinder may be deemed to be the benficial owner of these transferred Class B Units, because Mr. Kinder controls the voting and disposition power of these Class B Units, but he disclaims eight percent of any benficial and pecuniary interest in them. Mr. Kinder made a cash investment of $1,075,981 of his after-tax proceeds from the conversion in the going-private transaction of 15,750 shares of KMI restricted stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Kinder had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $787,587.

(9) Mr. Listengart made a cash investment of $6,059,449 of his after-tax proceeds from the conversion in the going-private transaction of 52,500 shares of KMI restricted stock and options to acquire 48,459 shares of KMI common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Listengart had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $1,712,851.

(10) Mr. Street made a cash investment of $3,813,005 of his after-tax proceeds from the conversion in the going-private transaction of 30,000 shares of KMI restricted stock and options to acquire 34,588 shares of KMI common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Street had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $1,074,434.

Other

Our policy is that (i) employees must obtain authorization from the appropriate business unit president of the relevant company or head of corporate function, and (ii) directors, business unit presidents, executive officers and heads of corporate functions must obtain authorization from the non-interested members of the audit committee of the applicable board of directors, for any business relationship or proposed business transaction in which they or an immediate family member has a direct or indirect interest, or from which they or an immediate family member may derive a personal benefit (a “related party transaction”). The maximum dollar amount of related party transactions that may be approved as described above in this paragraph in any calendar year is $1.0 million. Any related party transactions that would bring the total value of such transactions to greater than $1.0 million must be referred to the audit committee of the appropriate board of directors for approval or to determine the procedure for approval.

For information regarding other related transactions, see Note 12 of the notes to our consolidated financial statements included elsewhere in this report.

Director Independence

Our limited partnership agreement provides for us to have a general partner rather than a board of directors. Pursuant to a delegation of control agreement, our general partner 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, except that KMR cannot take certain specified actions without the approval of our general partner. Through the operation of that agreement and our partnership agreement, KMR manages and controls our business and affairs, and the board of directors of KMR performs the functions of and acts as our board of directors. Similarly, the standing committees of KMR’s board of directors function as standing committees of our board. KMR’s board of directors is comprised of the same persons who comprise our general partner’s board of directors. References in this report to the board mean KMR’s board, acting as our board of directors, and references to committees mean KMR’s committees, acting as committees of our board of directors.

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The board has adopted governance guidelines for the board and charters for the audit committee, nominating and governance committee and compensation committee. The governance guidelines and the rules of the New York Stock Exchange require that a majority of the directors be independent, as described in those guidelines, the committee charters and rules, respectively. Copies of the guidelines and committee charters are available on our internet website at www.kindermorgan.com. To assist in making determinations of independence, the board has determined that the following categories of relationships are not material relationships that would cause the affected director not to be independent:

• if the director was an employee, or had an immediate family member who was an executive officer, of KMR or us or any of its or our affiliates, but the employment relationship ended more than three years prior to the date of determination (or, in the case of employment of a director as an interim chairman, interim chief executive officer or interim executive officer, such employment relationship ended by the date of determination);

• if during any twelve month period within the three years prior to the determination the director received no more than, and has no immediate family member that received more than, $100,000 in direct compensation from us or our affiliates, other than (i) director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), (ii) compensation received by a director for former service as an interim chairman, interim chief executive officer or interim executive officer, and (iii) compensation received by an immediate family member for service as an employee (other than an executive officer);

• if the director is at the date of determination a current employee, or has an immediate family member that is at the date of determination a current executive officer, of another company that has made payments to, or received payments from, us and our affiliates for property or services in an amount which, in each of the three fiscal years prior to the date of determination, was less than the greater of $1.0 million or 2% of such other company’s annual consolidated gross revenues. Contributions to tax-exempt organizations are not considered payments for purposes of this determination;

• if the director is also a director, but is not an employee or executive officer, of our general partner or another affiliate or affiliates of KMR or us, so long as such director is otherwise independent; and

• if the director beneficially owns less than 10% of each class of voting securities of us, our general partner, or KMR.

The board has affirmatively determined that Messrs. Gaylord, Hultquist and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the New York Stock Exchange rules. Each of them meets the standards above and has no other relationship with us. In conjunction with all regular quarterly and certain special board meetings, these three non-management directors also meet in executive session without members of management. In January 2008, Mr. Waughtal was elected for a one year term to serve as lead director to develop the agendas for and preside at these executive sessions of independent directors.

The governance guidelines and our audit committee charter, as well as the rules of the New York Stock Exchange and the Securities and Exchange Commission, require that members of the audit committee satisfy independence requirements in addition to those above. The board has determined that all of the members of the audit committee are independent as described under the relevant standards.

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Item 14. Principal Accounting Fees and Services

          The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2007 and 2006 (in dollars):

	Year Ended December 31,
	2007		2006
Audit fees(1)	$	2,070,205	$	2,038,215
Tax fees(2)		2,563,793		1,470,466
Total	$	4,633,998	$	3,508,681

(1)

Includes fees for integrated audit of annual financial statements and internal control over financial reporting, reviews of the related quarterly financial statements, and reviews of documents filed with the Securities and Exchange Commission.

(2)

For 2007 and 2006, amounts include fees of $2,352,533 and $1,356,399, respectively, billed for professional services rendered for tax processing and preparation of Forms K-1 for our unitholders. Amounts also include fees of $211,260 and $114,067, respectively, billed for professional services rendered for tax return review services and for general state, local and foreign tax compliance and consulting services.

          All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and were pre-approved by the audit committee of KMR and our general partner. Pursuant to the charter of the audit committee of KMR, the delegate of our general partner, the committee’s primary purposes include the following: (i) to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; (ii) to pre-approve all audit and non-audit services, including tax services, to be provided, consistent with all applicable laws, to us by our external auditors; and (iii) to establish the fees and other compensation to be paid to our external auditors. The audit committee has reviewed the external auditors’ fees for audit and non audit services for fiscal year 2007. The audit committee has also considered whether such non audit services are compatible with maintaining the external auditors’ independence and has concluded that they are compatible at this time.

          Furthermore, the audit committee will review the external auditors’ proposed audit scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, will regularly review with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and will, at least annually, use its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items): (i) the auditors’ internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors; (iii) the independence of the external auditors; and (iv) the aggregate fees billed by our external auditors for each of the previous two fiscal years.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) and (2) Financial Statements and Financial Statement Schedules

See “Index to Financial Statements” set forth on page 114.

(a)(3) Exhibits

*3.1 —	Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended June 30, 2001, filed on August 9, 2001).
*3.2 —	Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed November 22, 2004).
*3.3 —	Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed May 5, 2005).
*4.1 —	Specimen Certificate evidencing Common Units representing Limited Partner Interests (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4, File No. 333-44519, filed on February 4, 1998).
*4.2 —	Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed February 16, 1999, File No. 1-11234 (the “February 16, 1999 Form 8-K”)).
*4.3 —	First Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the subsidiary guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.2 to the February 16, 1999 Form 8-K (File No. 1-11234)).
*4.4 —	Second Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee, relating to release of subsidiary guarantors under the $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.4 to the Partnership’s Form 10-Q (File No. 1-11234) for the quarter ended September 30, 1999 (the “1999 Third Quarter Form 10-Q”)).
*4.5 —	Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2001 (File No. 1-11234)).
*4.6 —	Form of 7.50% Notes due November 1, 2010 (contained in the Indenture filed as Exhibit 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2001).
*4.7 —	Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2000).
*4.8 —	Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Subordinated Debt Securities (including form of Subordinated Debt Securities) (filed as Exhibit 4.12 to Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2000).
*4.9 —	Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).
*4.10 —	Specimen of 6.75% Notes due March 15, 2011 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).
*4.11 —	Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).

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*4.12 —	Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended March 31, 2002, filed on May 10, 2002).
*4.13 —	Specimen of 7.125% Notes due March 15, 2012 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended March 31, 2002, filed on May 10, 2002).
*4.14 —	Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended March 31, 2002, filed on May 10, 2002).
*4.15 —	Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (File No. 333-100346) filed on October 4, 2002 (the “October 4, 2002 Form S-4”)).
*4.16 —	First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to the October 4, 2002 Form S-4).
*4.17 —	Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the October 4, 2002 Form S-4).
*4.18 —	Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 (File No. 333-102961) filed on February 4, 2003 (the “February 4, 2003 Form S-3”)).
*4.19 —	Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the February 4, 2003 Form S-3).
*4.20 —	Subordinated Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.4 to the February 4, 2003 Form S-3).
*4.21 —	Form of Subordinated Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Subordinated Indenture filed as Exhibit 4.4 to the February 4, 2003 Form S-3).
*4.22 —	Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary 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 5.00% Notes due December 15, 2013 (filed as Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*4.23 —	Certificate of Executive Vice President and Chief Financial Officer and Vice President, General Counsel and Secretary 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 5.125% Notes due November 15, 2014 (filed as Exhibit 4.27 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2004 filed March 4, 2005).
*4.24 —	Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary 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 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2005, filed on May 6, 2005).
*4.25 —	Certificate of 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 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2006 filed March 1, 2007).
*4.26 —	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 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2007 filed August 8, 2007).
*4.27 —	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 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended September 30, 2007 filed November 9, 2007).

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4.28 —	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 5.95% Senior Notes due 2018.
4.29 —	Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
*10.1 —	Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. 1997 Form 10-K, File No. 1-11234).
*10.2 —	Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001).
*10.3 —	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).
*10.4 —	Kinder Morgan Energy Partners, L.P. Directors’ Unit Appreciation Rights Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*10.5 —	Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors’ Unit Appreciation Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*10.6 —	Resignation and Non-Compete agreement dated July 21, 2004 between KMGP Services, Inc. and Michael C. Morgan, President of Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2004, filed on August 5, 2004).
*10.7 —	Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005).
*10.8 —	Form of Common Unit Compensation Agreement entered into with Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005).
*10.9 —	Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K, filed on August 11, 2005).
*10.10 —	First Amendment, dated October 28, 2005, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Form 10-Q for the quarter ended September 30, 2006).
*10.11 —	Second Amendment, dated April 13, 2006, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P.’s Form 10-Q for the quarter ended September 30, 2006).
*10.12 —	Third Amendment, dated October 6, 2006, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.3 to Kinder Morgan Energy Partners, L.P.’s Form 10-Q for the quarter ended September 30, 2006).
11.1 —	Statement re: computation of per share earnings.
12.1 —	Statement re: computation of ratio of earnings to fixed charges.
21.1 —	List of Subsidiaries.
23.1 —	Consent of PricewaterhouseCoopers LLP.
23.2 —	Consent of Netherland, Sewell and Associates, Inc.
31.1 —	Certification by CEO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 —	Certification by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

112

32.1 —	Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 —	Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.

113

INDEX TO FINANCIAL STATEMENTS

	Page Number
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm	115
Consolidated Statements of Income for the years ended December 31, 2007, 2006, and 2005	117
Consolidated Statements of Comprehensive Income for the years ended December 31, 2007, 2006, and 2005	118
Consolidated Balance Sheets as of December 31, 2007 and 2006	119
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006, and 2005	120
Consolidated Statements of Partners’ Capital for the years ended December 31, 2007, 2006, and 2005	122
Notes to Consolidated Financial Statements	123

114

Report of Independent Registered Public Accounting Firm

To the Partners of
Kinder Morgan Energy Partners, L.P.:

In our opinion, the accompanying consolidated balance sheets and the related statements of income and comprehensive income, of partners’ capital and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. (the “Partnership”) and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing in item 9A. Our responsibility is to express opinions on these financial statements and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded:

• The Vancouver Wharves bulk marine terminal, acquired May 30, 2007; and

• The terminal assets and operations acquired from Marine Terminals, Inc., effective September 30, 2007,

(the “Acquired Businesses”) from its assessment of internal control over financial reporting as of December 31, 2007 because these businesses were each acquired by the Partnership in a purchase business combination during 2007. We have also excluded the Acquired Businesses from our audit of internal control over financial reporting. These Acquired Businesses are wholly-owned subsidiaries whose total assets and total revenues, in the aggregate,

115

represent 0.6% and 1.2%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2007.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2008

116

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2007			2006			2005
	(In millions except per unit amounts)
Revenues
Natural gas sales	$	5,834.7		$	6,039.9		$	7,198.5
Services		2,449.2			2,177.6			1,810.5
Product sales and other		933.8			831.2			736.9
		9,217.7			9,048.7			9,745.9
Costs, Expenses and Other
Gas purchases and other costs of sales		5,809.8			5,990.9			7,167.3
Operations and maintenance		1,024.6			777.0			719.5
Fuel and power		237.5			223.7			178.5
Depreciation, depletion and amortization		540.0			423.9			341.6
General and administrative		278.7			238.4			216.7
Taxes, other than income taxes		153.8			134.4			106.5
Goodwill impairment expense		377.1			—			—
Other expense (income)		(11.5	)		(31.2	)		—
		8,410.0			7,757.1			8,730.1
Operating Income		807.7			1,291.6			1,015.8
Other Income (Expense)
Earnings from equity investments		69.7			74.0			89.6
Amortization of excess cost of equity investments		(5.8	)		(5.6	)		(5.5	)
Interest, net		(391.4	)		(337.8	)		(259.0	)
Other, net		14.2			12.0			3.3
Minority Interest		(7.0	)		(15.4	)		(7.3	)
Income from Continuing Operations Before Income Taxes		487.4			1,018.8			836.9
Income Taxes		(71.0	)		(29.0	)		(24.5	)
Income from Continuing Operations		416.4			989.8			812.4
Discontinued Operations:
Income (loss) from operations of North System		21.1			14.3			(0.2	)
Gain on disposal of North System		152.8			—			—
Income (loss) from Discontinued Operations		173.9			14.3			(0.2	)
Net Income	$	590.3		$	1,004.1		$	812.2
Calculation of Limited Partners’ interest in Net Income (loss):
Income from Continuing Operations	$	416.4		$	989.8		$	812.4
Less: General Partner’s interest		(609.9	)		(513.2	)		(477.3	)
Limited Partners’ interest		(193.5	)		476.6			335.1
Add: Limited Partners’ interest in Discontinued Operations		172.2			14.2			(0.2	)
Limited Partners’ interest in Net Income (loss)	$	(21.3	)	$	490.8		$	334.9
Basic Limited Partners’ Net Income (loss) per Unit:
Income (loss) from Continuing Operations	$	(0.82	)	$	2.12		$	1.58
Income from Discontinued Operations		0.73			0.07			—
Net Income (loss)	$	(0.09	)	$	2.19		$	1.58
Weighted average number of units outstanding		236.9			224.6			212.2
Diluted Limited Partners’ Net Income (loss) per Unit:
Income (loss) from Continuing Operations	$	(0.82	)	$	2.12		$	1.58
Income from Discontinued Operations		0.73			0.06			—
Net Income (loss)	$	(0.09	)	$	2.18		$	1.58
Weighted average number of units outstanding		236.9			224.9			212.4
Per unit cash distribution declared	$	3.48		$	3.26		$	3.13

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

117

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2007			2006			2005
	(In millions)
Net Income	$	590.3		$	1,004.1		$	812.2
Change in fair value of derivatives used for hedging purposes		(974.2	)		(187.5	)		(1,045.6	)
Reclassification of change in fair value of derivatives to net income		433.2			428.1			424.0
Foreign currency translation adjustments		132.5			(19.6	)		(0.7	)
Minimum pension liability adjustments, pension and other post-retirement benefit plan actuarial gains/losses, and reclassification of pension and other post-retirement benefit plan actuarial gains/losses and prior service costs/credits to net income		(3.5	)		(1.8	)		—
Total other comprehensive income		(412.0	)		219.2			(622.3	)
Comprehensive Income	$	178.3		$	1,223.3		$	189.9

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007				2006
	(Dollars in millions)
ASSETS
Current Assets
Cash and cash equivalents		$	58.9			$	6.7
Restricted deposits			67.9				—
Accounts, notes and interest receivable, net Trade			960.2				854.7
Related parties			3.6				7.9
Inventories
Products			19.5				20.4
Materials and supplies			18.3				16.6
Gas imbalances
Trade			21.2				7.8
Related parties			5.7				11.6
Other current assets			54.4				111.1
			1,209.7				1,036.8
Property, Plant and Equipment, net			11,591.3				10,106.1
Investments			655.4				426.3
Notes receivable
Trade			0.1				1.2
Related parties			87.9				96.2
Goodwill			1,077.8				1,421.0
Other intangibles, net			238.6				213.2
Deferred charges and other assets			317.0				241.4
Total Assets		$	15,177.8			$	13,542.2
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts		$	19.0			$	46.2
Trade			926.7				784.1
Related parties			22.6				203.3
Current portion of long-term debt			610.2				1,359.1
Accrued interest			131.2				83.7
Accrued taxes			73.8				35.4
Deferred revenues			22.8				20.0
Gas imbalances
Trade			23.7				15.9
Related parties			—				—
Accrued other current liabilities			728.3				589.6
			2,558.3				3,137.3
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding			6,455.9				4,384.3
Value of interest rate swaps			152.2				42.6
			6,608.1				4,426.9
Deferred revenues			14.2				18.8
Deferred income taxes			202.4				185.2
Asset retirement obligations			50.8				48.9
Other long-term liabilities and deferred credits			1,254.1				716.6
			8,129.6				5,396.4
Commitments and Contingencies (Notes 13 and 16)
Minority Interest			54.2				60.2
Partners’ Capital
Common Units (170,220,396 and 162,816,303 units issued and outstanding as of December 31, 2007 and 2006, respectively)			3,048.4				3,414.9
Class B Units (5,313,400 and 5,313,400 units issued and outstanding as of December 31, 2007 and 2006, respectively)			102.0				126.1
i-Units (72,432,482 and 62,301,676 units issued and outstanding as of December 31, 2007 and 2006, respectively)			2,400.8				2,154.2
General Partner			161.1				119.2
Accumulated other comprehensive loss			(1,276.6	)			(866.1	)
			4,435.7				4,948.3
Total Liabilities and Partners’ Capital		$	15,177.8			$	13,542.2

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

119

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007				2006				2005
	(In millions)
Cash Flows From Operating Activities
Net income		$	590.3			$	1,004.1			$	812.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			547.0				432.8				349.8
Amortization of excess cost of equity investments			5.8				5.7				5.6
Impairment of goodwill			377.1				—				—
Gains and other non-cash income from the sale of property, plant and equipment			(162.5	)			(15.2	)			(0.5	)
Gains from property casualty indemnifications			(1.8	)			(15.2	)			—
Earnings from equity investments			(71.5	)			(76.2	)			(91.7	)
Distributions from equity investments			104.1				67.9				63.1
Changes in components of working capital:
Accounts receivable			92.6				15.8				(240.7	)
Other current assets			3.9				13.8				(14.1	)
Inventories			(6.9	)			0.9				(13.5	)
Accounts payable			(79.7	)			(48.8	)			294.9
Accrued interest			47.3				8.0				17.9
Accrued liabilities			(9.5	)			(10.6	)			4.5
Accrued taxes			40.7				14.2				(2.3	)
Rate reparations, refunds and other litigation reserve adjustments			140.0				(19.1	)			105.0
Other, net			124.9				(14.2	)			(0.8	)
Net Cash Provided by Operating Activities			1,741.8				1,363.9				1,289.4
Cash Flows From Investing Activities
Acquisitions of assets and equity investments			(713.3	)			(387.2	)			(307.8	)
Additions to property, plant and equip. for expansion and maintenance projects			(1,691.6	)			(1,182.1	)			(863.1	)
Sale of property, plant and equipment, and other net assets net of removal costs			302.6				70.8				9.9
Property casualty indemnifications			8.0				13.1				—
Net proceeds from (Investments in) margin deposits			(70.2	)			2.3				—
Contributions to equity investments			(276.1	)			(2.5	)			(1.2	)
Natural gas stored underground and natural gas liquids line-fill			12.3				(12.9	)			(18.7	)
Other			(0.2	)			(3.4	)			(0.2	)
Net Cash Used in Investing Activities			(2,428.5	)			(1,501.9	)			(1,181.1	)
Cash Flows From Financing Activities
Issuance of debt			7,686.1				4,632.5				4,900.9
Payment of debt			(6,409.3	)			(3,698.7	)			(4,463.2	)
Repayments from (Loans to) related party			4.4				1.1				2.1
Debt issue costs			(13.8	)			(2.0	)			(6.0	)
Increase (Decrease) in cash book overdrafts			(27.2	)			15.8				0.6
Proceeds from issuance of common units			342.9				248.4				415.6
Proceeds from issuance of i-units			297.9				—				—
Contributions from minority interest			8.9				109.8				7.8
Distributions to partners:
Common units			(552.6	)			(512.1	)			(460.6	)
Class B units			(18.0	)			(17.2	)			(16.3	)
General Partner			(567.7	)			(523.2	)			(460.9	)
Minority interest			(16.0	)			(119.0	)			(12.1	)
Other, net			0.1				(3.0	)			(3.9	)
Net Cash Provided by (Used in) Financing Activities			735.7				132.4				(96.0	)
Effect of exchange rate changes on cash and cash equivalents			3.2				0.2				(0.2	)
Increase (Decrease) in Cash and Cash Equivalents			52.2				(5.4	)			12.1
Cash and Cash Equivalents, beginning of year			6.7				12.1				—
Cash and Cash Equivalents, end of year		$	58.9			$	6.7			$	12.1

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

120

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

	Year Ended December 31,
	2007			2006			2005
	(In millions)
Noncash Investing and Financing Activities:
Contribution of net assets to partnership investments		$	—		$	17.0		$	—
Assets acquired by the issuance of units			15.0			1.6			49.6
Assets acquired by the assumption or incurrence of liabilities			19.7			6.1			76.6
Assets acquired by the transfer of Trans Mountain			—			1,199.5			—
Liabilities assumed by the transfer of Trans Mountain			—			282.5			—
Related party asset settlements with Knight			276.2			—			—
Related party liability settlements with Knight			556.6			—			—
Supplemental disclosures of cash flow information:
Cash paid during the year for interest (net of capitalized interest)			336.0			329.2			245.6
Cash paid during the year for income taxes			6.2			25.6			7.3

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

121

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	2007					2006					2005
		Units		Amount			Units		Amount			Units		Amount
						(Dollars in millions)
Common Units:
Beginning Balance		162,816,303	$	3,414.9			157,005,326	$	2,680.4			147,537,908	$	2,438.0
Net income (loss)		—		(20.4	)		—		347.8			—		237.8
Units issued as consideration pursuant to common unit compensation plan for non-employee directors		7,280		0.4			5,250		0.3			5,250		0.3
Units issued as consideration in the acquisition of assets		266,813		15.0			34,627		1.6			1,022,068		49.6
Units issued for cash		7,130,000		342.5			5,771,100		248.2			8,440,100		415.3
Trans Mountain Acquisition		—		(166.8	)		—		648.7			—		—
Knight Inc. going-private transaction exp.		—		15.4			—		—			—		—
Distributions		—		(552.6	)		—		(512.1	)		—		(460.6	)
Ending Balance		170,220,396		3,048.4			162,816,303		3,414.9			157,005,326		2,680.4
Class B Units:
Beginning Balance		5,313,400		126.1			5,313,400		109.6			5,313,400		117.4
Net income (loss)		—		(0.6	)		—		11.6			—		8.5
Trans Mountain Acquisition		—		(6.0	)		—		22.1			—		—
Knight Inc. going-private transaction exp.		—		0.5			—		—			—		—
Distributions		—		(18.0	)		—		(17.2	)		—		(16.3	)
Ending Balance		5,313,400		102.0			5,313,400		126.1			5,313,400		109.6
i-Units:
Beginning Balance		62,301,676		2,154.2			57,918,373		1,783.6			54,157,641		1,695.0
Net income (loss)		—		(0.3	)		—		131.4			—		88.7
Units issued for cash		5,700,000		297.6			—		—			—		(0.1	)
Trans Mountain Acquisition		—		(57.4	)		—		239.2			—		—
Knight Inc. going-private transaction exp.		—		6.7			—		—			—		—
Distributions		4,430,806		—			4,383,303		—			3,760,732		—
Ending Balance		72,432,482		2,400.8			62,301,676		2,154.2			57,918,373		1,783.6
General Partner:
Beginning Balance		—		119.2			—		119.9			—		103.5
Net income		—		611.6			—		513.3			—		477.3
Trans Mountain Acquisition		—		(2.2	)		—		9.2			—		—
Knight Inc. going-private transaction exp.		—		0.2			—		—			—		—
Distributions		—		(567.7	)		—		(523.2	)		—		(460.9	)
Ending Balance		—		161.1			—		119.2			—		119.9
Accum. other comprehensive income (loss):
Beginning Balance		—		(866.1	)		—		(1,079.7	)		—		(457.4	)
Change in fair value of derivatives used for hedging purposes		—		(974.2	)		—		(187.5	)		—		(1,045.6	)
Reclassification of change in fair value of derivatives to net income		—		433.2			—		428.1			—		424.0
Foreign currency translation adjustments		—		132.5			—		(19.6	)		—		(0.7	)
Pension and other post-retirement benefit liability changes		—		(3.5	)		—		(1.8	)		—		—
Adj. to initially apply SFAS No. 158-pension and other post-retirement benefit acctg. changes		—		1.5			—		(5.6	)		—		—
Ending Balance		—		(1,276.6	)		—		(866.1	)		—		(1,079.7	)
Total Partners’ Capital		247,966,278	$	4,435.7			230,431,379	$	4,948.3			220,237,099	$	3,613.8

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

122

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

          General

          Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August 1992. 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 own and manage a diversified portfolio of energy transportation and storage assets and presently conduct our business through five reportable business segments. These segments and the activities performed to provide services to our customers and create value for our unitholders are as follows:

• Products Pipelines - transporting, storing and processing refined petroleum products;

• Natural Gas Pipelines - transporting, storing, selling, gathering, treating and processing natural gas;

• CO₂ ^- producing, transporting and selling carbon dioxide, commonly called CO₂, for use in, and selling crude oil, natural gas and natural gas liquids produced from, enhanced oil recovery operations;

• Terminals - transloading, storing and delivering a wide variety of bulk, petroleum, petrochemical and other liquid products at terminal facilities located across North America; and

• Trans Mountain – transporting crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington.

          We focus on providing fee-based services to customers, generally avoiding near-term commodity price risks and taking advantage of the tax benefits of a limited partnership structure. We trade on the New York Stock Exchange under the symbol “KMP,” and we conduct our operations through the following five limited partnerships:

• Kinder Morgan Operating L.P. “A” (OLP-A);

• Kinder Morgan Operating L.P. “B” (OLP-B);

• Kinder Morgan Operating L.P. “C” (OLP-C);

• Kinder Morgan Operating L.P. “D” (OLP-D); and

• Kinder Morgan CO₂ Company (KMCO2).

          Combined, the five limited partnerships are referred to as our operating partnerships, and we are the 98.9899% limited partner and our general partner is the 1.0101% general partner in each. Both we and our operating partnerships are governed by Amended and Restated Agreements of Limited Partnership, as amended and certain other agreements that are collectively referred to in this report as the partnership agreements.

          Knight Inc. and Kinder Morgan G.P., Inc.

          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 generally each share of KMI common stock would be converted into the right to receive $107.50 in cash without interest. KMI in turn would merge with a wholly owned subsidiary of Knight Holdco LLC, a privately owned company in which Richard D. Kinder, Chairman and Chief Executive Officer of KMI, would be a major investor. On May 30, 2007, the merger closed, with KMI continuing as the surviving legal entity and subsequently renamed “Knight Inc.,” referred to as “Knight” in this report. Additional investors in Knight Holdco LLC include the following: other senior members of Knight 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); KMI 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. This transaction is referred to in this report as the “going-private transaction.”

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          Knight is privately owned, and remains the sole indirect common stockholder of 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. At December 31, 2007, Knight and its consolidated subsidiaries owned, through its general and limited partner interests, an approximate 13.9% interest in us.

          Kinder Morgan Management, LLC

          Kinder Morgan Management, LLC, a Delaware limited liability company, was formed on February 14, 2001. Its shares represent limited liability company interests and are traded on the New York Stock Exchange under the symbol “KMR.” Kinder Morgan Management, LLC is referred to as “KMR” in this report. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, our general partner 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, except that KMR cannot take certain specified actions without the approval of our general partner.

          Under the delegation of control agreement, KMR manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR’s activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries. As of December 31, 2007, KMR owned approximately 29.2% of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR).

2. Summary of Significant Accounting Policies

          Basis of Presentation

          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. Canadian dollars are designated as C$. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform to the current presentation.

          Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. We believe, however, that certain accounting policies are of more significance in our financial statement preparation process than others. Also, certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared.

          These estimates and assumptions affect the amounts we report for 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 evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

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          Cash Equivalents

          We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

          Accounts Receivables

          Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. An allowance for doubtful accounts is charged to expense monthly, generally using a percentage of revenue or receivables, based on a historical analysis of uncollected amounts, adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2007, 2006 and 2005 (in millions):

	Valuation and Qualifying Accounts
Allowance for Doubtful Accounts	Balance at beginning of Period		Additions charged to costs and expenses		Additions charged to other accounts(1)		Deductions(2)			Balance at end of period
Year ended December 31, 2007	$	6.8	$	0.4	$	—	$	(0.2	)	$	7.0
Year ended December 31, 2006	$	6.5	$	0.3	$	0.3	$	(0.3	)	$	6.8
Year ended December 31, 2005	$	8.6	$	0.2	$	—	$	(2.3	)	$	6.5

(1)	Amount for 2006 represents the allowance recognized when we acquired Devco USA L.L.C. ($0.2) and Transload Services, LLC ($0.1).
(2)	Deductions represent the write-off of receivables.

          In addition, the balances of “Accrued other current liabilities” in our accompanying consolidated balance sheets include amounts related to customer prepayments of approximately $6.5 million as of December 31, 2007 and $10.8 million as of December 31, 2006.

          Inventories

          Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market. We report materials and supplies at the lower of cost or market. As of December 31, 2007, we owed certain customers a total of $8.3 million for the value of natural gas inventory stored in our underground storage facilities, and we reported this amount within “Accounts Payable—Trade” in our accompanying consolidated balance sheet. As of December 31, 2006, the value of natural gas in our underground storage facilities under the weighted-average cost method was $8.4 million, and we reported this amount within “Other current assets” in our accompanying consolidated balance sheet. We also maintain gas in our underground storage facilities on behalf of certain third parties. We receive a fee from our storage service customers but do not reflect the value of their gas stored in our facilities in our accompanying consolidated balance sheets.

          Property, Plant and Equipment

          Capitalization, Depreciation and Depletion and Disposals

          We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated

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depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.

          We compute depreciation using the straight-line method based on estimated economic lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 2.0% to 12.5%, excluding certain short-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates included changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

          Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.

          A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the maket value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset.

          In addition, we engage in enhanced recovery techniques in which carbon dioxide is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the carbon dioxide associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost associated with pressure maintenance operations for reservoir management is expensed when it is injected. When carbon dioxide is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production rate is determined by field.

          As discussed in “—Inventories” above, we maintain natural gas in underground storage as part of our inventory. This component of our inventory represents the portion of gas stored in an underground storage facility generally known as “working gas,” and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal to meet demand. In addition to this working gas, underground gas storage reservoirs contain injected gas which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as “cushion gas,” is divided into the categories of “recoverable cushion gas” and “unrecoverable cushion gas,” based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of the cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself (thus, part of our “Property, Plant and Equipment, net” balance in our accompanying consolidated balance sheets), and this unrecoverable portion is depreciated over the facility’s estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

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          Impairments

          We evaluate the impairment of our long-lived assets in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell. We review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.

          We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.

          Equity Method of Accounting

          We account for investments greater than 20% in affiliates, which we do not control, by the equity method of accounting. Under this method, an investment is carried at our acquisition cost, plus our equity in undistributed earnings or losses since acquisition, and less distributions received.

          Excess of Cost Over Fair Value

          We account for our business acquisitions and intangible assets in accordance with the provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” Accounting standards require that goodwill not be amortized, but instead should be tested, at least on an annual basis, for impairment. Pursuant to this SFAS No. 142, goodwill and other intangible assets with indefinite useful lives cannot be amortized until their useful life becomes determinable. Instead, such assets must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We have selected an impairment measurement test date of January 1 of each year and we have determined that our goodwill was not impaired as of January 1, 2008; however, our consolidated income statement for the year ended December 31, 2007 included a goodwill impairment expense of $377.1 million, due to the inclusion of Knight’s first quarter 2007 impairment of goodwill that resulted from a determination of the fair values of Trans Mountain pipeline assets prior to our acquisition of these assets on April 30, 2007. For more information on this acquisition and this impairment expense, see Notes 3 and 8, respectively.

          Our total unamortized excess cost over fair value of net assets in consolidated affiliates was $1,077.8 million as of December 31, 2007 and $1,421.0 million as of December 31, 2006. Such amounts are reported as “Goodwill” on our accompanying consolidated balance sheets. Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was$138.2 million as of both December 31, 2007 and December 31, 2006. Pursuant to SFAS No. 142, this amount, referred to as equity method goodwill, should continue to be recognized in accordance with Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Accordingly, we included this amount within “Investments” on our accompanying consolidated balance sheets.

          In almost all cases, the price we paid to acquire our share of the net assets of our equity investees differed from the underlying book value of such net assets. This differential consists of two pieces. First, an amount related to the difference between the investee’s recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (representing equity method goodwill as described above) we paid to acquire the investment. The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at the date of acquisition totaled $174.7 million and $177.1 million as of December 31, 2007 and 2006, respectively, and similar to our treatment of equity method goodwill, we included these amounts within “Investments” on our

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accompanying consolidated balance sheets. As of December 31, 2007, this excess investment cost is being amortized over a weighted average life of approximately 30.9 years.

          In addition to our annual impairment test of goodwill, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives in accordance with APB Opinion No. 18. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. As of December 31, 2007, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted. For more information on our investments, see Note 7.

          Revenue Recognition Policies

          We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We generally sell natural gas under long-term agreements, with periodic price adjustments. In some cases, we sell natural gas under short-term agreements at prevailing market prices. In all cases, we recognize natural gas sales revenues when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies. We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and generally, our natural gas marketing revenues are recorded gross, not net of cost of gas sold.

          We provide various types of natural gas storage and transportation services to customers. The natural gas remains the property of these customers at all times. In many cases (generally described as “firm service”), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as “interruptible service”), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to our “firm” and “interruptible” transportation services, we also provide natural gas park and loan service to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized based on the terms negotiated under these contracts.

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

          We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. Liquids terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product.

          Revenues from the sale of oil, natural gas liquids and natural gas production are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer. As a result, we maintain a minimum amount of product inventory in storage.

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          Allowance For Funds Used During Construction

          Included in the cost of our qualifying property, plant and equipment is an allowance for funds used during construction or upgrade, often referred to as AFUDC. AFUDC represents the estimated cost of capital, from borrowed funds, during the construction period. Total AFUDC resulting from the capitalization of interest expense in 2007, 2006 and 2005 was $31.4 million, $20.3 million and $9.8 million, respectively. Approximately $6.1 million and $2.2 million of AFUDC on equity, related to our Trans Mountain pipeline system assets, was also capitalized in the twelve months ended December 31, 2007 and 2006, respectively.

          Unit-Based Compensation

          We account for common unit options granted under our common unit option plan according to the provisions of SFAS No. 123R (revised 2004), “Share-Based Payment,” which became effective for us January 1, 2006. However, we have not granted common unit options or made any other share-based payment awards since May 2000, and as of December 31, 2005, all outstanding options to purchase our common units were fully vested. Therefore, the adoption of this Statement did not have an effect on the accounting for these common unit options in our consolidated financial statements, as we had reached the end of the requisite service period for any compensation cost resulting from share-based payments made under our common unit option plan.

          Environmental Matters

          We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

          We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. For more information on our environmental disclosures, see Note 16.

          Legal

          We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for such amounts. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. In general, we expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. For more information on our legal disclosures, see Note 16.

          Pensions and Other Post-retirement Benefits

          We account for pension and other post-retirement benefit plans according to the provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R).” This Statement requires us to fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and post-retirement benefit plans as either assets or

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liabilities on our balance sheet. For more information on our pension and post-retirement benefit disclosures, see Note 10.

          Gas Imbalances

          We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominations and actual gas receipts from, and gas deliveries to, our interconnecting pipelines and shippers under various operational balancing and shipper imbalance agreements. Natural gas imbalances are either settled in cash or made up in-kind subject to the pipelines’ various tariff provisions.

          Minority Interest

          Minority interest, sometimes referred to as noncontrolling interest, represents the outstanding ownership interests in our five operating limited partnerships and their consolidated subsidiaries that are not owned by us. In our consolidated income statements, the minority interest in the income (or loss) of a consolidated subsidiary is shown as a deduction from (or an addition to) our consolidated net income. In our consolidated balance sheets, minority interest represents the noncontrolling ownership interest in our consolidated net assets and is presented separately between liabilities and Partners’ Capital.

          As of December 31, 2007, minority interest consisted of the following:

• the 1.0101% general partner interest in each of our five operating partnerships;

• the 0.5% special limited partner interest in SFPP, L.P.;

• the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;

• the 33 1/3% interest in International Marine Terminals Partnership, a Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P. “C”;

• the approximate 31% interest in the Pecos Carbon Dioxide Company, a Texas general partnership owned approximately 69% and controlled by Kinder Morgan CO₂ Company, L.P. and its consolidated subsidiaries;

• the 1% interest in River Terminals Properties, L.P., a Tennessee partnership owned 99% and controlled by Kinder Morgan River Terminals LLC; and

• the 30% interest in Guilford County Terminal Company, LLC, a limited liability company owned 70% and controlled by Kinder Morgan Southeast Terminals LLC.

          Income Taxes

          We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner’s tax attributes in us.

          Some of our corporate subsidiaries and corporations in which we have an equity investment do pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized.

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          Foreign Currency Transactions and Translation

          We account for foreign currency transactions and the foreign currency translation of our consolidating foreign subsidiaries in accordance with the provisions of SFAS No. 52, “Foreign Currency Translation.” Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which our foreign subsidiary operates, also referred to as its functional currency. Transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary; and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary.

          We translate the assets and liabilities of each of our consolidating foreign subsidiaries to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders’ equity accounts are translated by using historical exchange rates. Translation adjustments result from translating all assets and liabilities at current year-end rates, while stockholders’ equity is translated by using historical and weighted-average rates. The cumulative translation adjustments balance is reported as a component of accumulated other comprehensive income/(loss) within Partners’ Capital on our accompanying consolidated balance sheet.

          Comprehensive Income

          Statement of Financial Accounting Standards No. 130, “Accounting for Comprehensive Income,” requires that enterprises report a total for comprehensive income. The difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivatives utilized for hedging our exposure to fluctuating expected future cash flows produced by price or interest rate risk; (ii) foreign currency translation adjustments; and (iii) unrealized periodic benefit costs from minimum pension liability adjustments and the reclassification of post-retirement benefit and pension plan actuarial gains/losses and prior service costs/credits to net income. For more information on our risk management activities, see Note 14.

          Cumulative revenues, expenses, gains and losses that under generally accepted accounting principals are included within our comprehensive income but excluded from our earnings are reported as accumulated other comprehensive income/(loss) within Partners’ Capital in our consolidated balance sheets. The following table summarizes changes in the amount of our “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets for each of the two years ended December 31, 2006 and 2007 (in millions):

	Net unrealized gains/(losses) on cash flow hedge derivatives				Foreign currency translation adjustments				Pension and Other Post-retirement liability adjs.				Total Accumulated other comprehensive income/(loss)
December 31, 2005		$	(1,079.3	)		$	(0.4	)		$	—			$	(1,079.7	)
Change for period			240.6				(19.6	)			(7.4	)			213.6
December 31, 2006			(838.7	)			(20.0	)			(7.4	)			(866.1	)
Change for period			(541.0	)			132.5				(2.0	)			(410.5	)
December 31, 2007		$	(1,379.7	)		$	112.5			$	(9.4	)		$	(1,276.6	)

          Net Income Per Unit

          We compute Basic Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period. Diluted Limited Partners’ Net Income per Unit reflects the maximum potential dilution that could occur if units whose issuance depends on the market price of the units at a future date were considered outstanding, or if, by application of the treasury stock method, options to issue units were exercised, both of which would result in the issuance of additional units that would then share in our net income.

          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

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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.

          Asset Retirement Obligations

          We account for asset retirement obligations pursuant to SFAS No. 143, “Accounting for Asset Retirement Obligations.” For more information on our asset retirement obligations, see Note 4.

          Risk Management Activities

          We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations.

          Our derivative contracts are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities – Deferral of the Effective Date of FASB Statement No.133” and No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities.”SFAS No. 133 established accounting and reporting standards requiring that every derivative contract (including certain derivative contracts embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative contract’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative contract meets those criteria, SFAS No. 133 allows a derivative contract’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative contract as a hedge and document and assess the effectiveness of derivative contracts associated with transactions that receive hedge accounting.

          Furthermore, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements of SFAS No. 133 and is accounted for using traditional accrual accounting. Our derivative contracts that hedge our commodity price risks involve our normal business activities, which include the sale of natural gas, natural gas liquids and crude oil, and these derivative contracts have been designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivative contracts that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative contract’s gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. See Note 14 for more information on our risk management activities.

          Accounting for Regulatory Activities

          Our regulated utility operations are accounted for in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which prescribes the circumstances in which the application of generally accepted accounting principles is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process.

          The following regulatory assets and liabilities are reflected within “Deferred charges and other assets” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets as of December 31, 2007 and December 31, 2006 (in millions):

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	As of December 31,
	2007			2006
Regulated Assets:
Employee benefit costs		$	0.6		$	0.4
Fuel Tracker			2.4			1.6
Deferred regulatory expenses			3.4			3.2
Total regulatory assets			6.4			5.2
Regulated Liabilities:
Deferred income taxes			—			0.9
Total regulatory liabilities			—			0.9
Net regulatory assets		$	6.4		$	4.3

          As of December 31, 2007, all of our regulatory assets and regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from one to five years.

3. Acquisitions, Joint Ventures and Divestitures

          Acquisitions and Joint Ventures Involving Unrelated Entities

          During 2007, 2006 and 2005, we completed the following acquisitions, and except for our acquisition of the Trans Mountain pipeline system (discussed below), these acquisitions were accounted for as business combinations 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 are included in our consolidated financial statements from the acquisition date.

			Allocation of Purchase Price
			(in millions)
Ref.	Date	Acquisition	Purchase Price			Current Assets			Property Plant & Equipment			Deferred Charges & Other			Goodwill			Minority Interest
(1)	1/05	Claytonville Oil Field Unit		$	6.5		$	—		$	6.5		$	—		$	—		$	—
(2)	4/05	Texas Petcoke Terminal Region			247.2			—			72.5			161.4			13.3			—
(3)	7/05	Terminal Assets			36.2			0.5			35.7			—			—			—
(4)	7/05	General Stevedores, L.P.			10.4			0.6			5.2			0.2			4.4			—
(5)	8/05	North Dayton Natural Gas Storage Facility			109.4			—			71.7			11.7			26.0			—
(6)	8-9/05	Terminal Assets			4.3			0.4			3.9			—			—			—
(7)	11/05	Allied Terminal Assets			13.3			0.2			12.6			0.5			—			—
(8)	2/06	Entrega Gas Pipeline LLC			244.6			—			244.6			—			—			—
(9)	4/06	Oil and Gas Properties			63.6			0.1			63.5			—			—			—
(10)	4/06	Terminal Assets			61.9			0.5			43.6			—			17.8			—
(11)	11/06	Transload Services, LLC			16.6			1.6			6.6			—			8.4			—
(12)	12/06	Devco USA L.L.C.			7.3			0.8			—			6.5			—			—
(13)	12/06	Roanoke, Virginia Products Terminal			6.4			—			6.4			—			—			—
(14)	1/07	Interest in Cochin Pipeline			47.8			—			47.8			—			—			—
(15)	5/07	Vancouver Wharves Terminal.			57.2			6.5			50.7			—			—			—
(16)	9/07	Marine Terminals, Inc. Assets			101.5			0.2			60.8			40.5			—			—

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          (1) Claytonville Oil Field Unit

          Effective January 31, 2005, we acquired an approximate 64.5% gross working interest in the Claytonville oil field unit located in Fisher County, Texas from Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in the Permian Basin of West Texas. Our purchase price was approximately $6.5 million, consisting of $6.2 million in cash and the assumption of $0.3 million of liabilities. Following our acquisition, we became the operator of the field, which at the time of acquisition was producing approximately 200 barrels of oil per day. The acquisition of this ownership interest complemented our existing carbon dioxide assets in the Permian Basin and we include the acquired operations as part of our CO₂ business segment.

          (2) Texas Petcoke Terminal Region

          Effective April 29, 2005, we acquired seven bulk terminal operations from Trans-Global Solutions, Inc. for an aggregate consideration of approximately $247.2 million, consisting of $186.0 million in cash, $46.2 million in common units, and an obligation to pay an additional $15 million on April 29, 2007, two years after the closing. We settled the $15 million liability by issuing additional common units. All of the acquired assets are located in the state of Texas, and include facilities at the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship Channel. We combined the acquired operations into a new terminal region called the Texas Petcoke region, as certain of the terminals have contracts in place to provide petroleum coke handling services for major Texas oil refineries. The acquisition complemented our existing Gulf Coast terminal facilities and expanded our pre-existing petroleum coke handling operations. The acquired operations are included as part of our Terminals business segment.

          Our allocation of the purchase price to assets acquired and liabilities assumed was based on an appraisal of fair market values, which was completed in the fourth quarter of 2005. A total of $13.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. We believe this acquisition resulted in the recognition of goodwill primarily due to the fact that certain advantageous factors and conditions existed that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities —in the aggregate, these factors represented goodwill. The $161.4 million of deferred charges and other assets in the table above represents the fair value of intangible customer relationships, which encompass both the contractual life of customer contracts plus any future customer relationship value beyond the contract life. In connection with the transaction, Trans-Global Solutions, Inc. agreed to indemnify Kinder Morgan G.P., Inc. for any losses relating to our failure to repay $50.9 million of indebtedness incurred to fund the acquisition, and we agreed to indemnify Trans-Global Solutions, Inc. for any taxes of Trans-Global Solutions, Inc. that may arise from the sale of any acquired assets. We have no current intention to sell any of the assets acquired in this transaction.

          (3) July 2005 Terminal Assets

          In July 2005, we acquired three terminal facilities in separate transactions for an aggregate consideration of approximately $36.2 million in cash. The largest of the transactions was the purchase of a refined petroleum products terminal in New York Harbor from ExxonMobil Oil Corporation. The second acquisition involved a dry-bulk river terminal located in the state of Kentucky, and the third involved a liquids/dry-bulk facility located in Blytheville, Arkansas. The operations of all three facilities are included in our Terminals business segment.

          The New York Harbor terminal, located on Staten Island and referred to as the Kinder Morgan Staten Island terminal, complements our existing Northeast liquids terminal facilities located in Carteret and Perth Amboy, New Jersey. At the time of acquisition, the terminal had storage capacity of 2.3 million barrels for gasoline, diesel and fuel oil, and we expected to bring several idle tanks back into service that would add another 550,000 barrels of capacity. As part of the transaction, ExxonMobil entered into a long-term storage capacity agreement with us and has continued to utilize a portion of the terminal. Since our acquisition, we have invested approximately $25 million in terminal improvements, including funds used to rebuild a ship berth with the ability to accommodate tanker vessels. All expansion projects should be complete by the end of the first quarter of 2008.

          The dry-bulk terminal, located along the Ohio River in Hawesville, Kentucky, primarily handles wood chips and finished paper products. The acquisition complemented our existing terminal assets located in the Ohio River

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Valley and further expanded our wood-chip handling businesses. As part of the transaction, we assumed a long-term handling agreement with Weyerhauser Company, an international forest products company.

          The assets acquired at the liquids/dry-bulk facility in Blytheville, Arkansas consisted of storage and supporting infrastructure for 40,000 tons of anhydrous ammonia, 9,500 tons of urea ammonium nitrate solutions and 40,000 tons of urea. As part of the transaction, we have entered into a long-term agreement to sublease all of the existing anhydrous ammonia and urea ammonium nitrate terminal assets to Terra Nitrogen Company, L.P. The terminal is one of only two facilities in the United States that can handle imported fertilizer and provide shipment west on railcars, and the acquisition of the facility positioned us to take advantage of the increase in fertilizer imports that has resulted from the recent decrease in domestic production.

          (4) General Stevedores, L.P.

          Effective July 31, 2005, we acquired all of the partnership interests in General Stevedores, L.P. for an aggregate consideration of approximately $10.4 million, consisting of $2.0 million in cash, $3.4 million in common units, and $5.0 million in assumed liabilities, including debt of $3.0 million. In August 2005, we paid the $3.0 million outstanding debt balance.

          General Stevedores, L.P. owns, operates and leases barge unloading facilities located along the Houston, Texas ship channel. Its operations primarily consist of receiving, storing and transferring semi-finished steel products, including coils, pipe and billets. The acquisition complemented and further expanded our existing Texas Gulf Coast terminal facilities, and its operations are included as part of our Terminals business segment. A total of $4.4 million of goodwill was assigned to our Terminals business segment, and the entire amount is expected to be deductible for tax purposes. We believe this acquisition resulted in the recognition of goodwill primarily due to the fact that certain advantageous factors and conditions existed that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities —in the aggregate, these factors represented goodwill.

          (5) North Dayton Natural Gas Storage Facility

          Effective August 1, 2005, we acquired a natural gas storage facility in Liberty County, Texas, from Texas Genco LLC for an aggregate consideration of approximately $109.4 million, consisting of $52.9 million in cash and $56.5 million in assumed debt. The facility, referred to as our North Dayton storage facility, has approximately 6.3 billion cubic feet of total capacity, consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of pad (cushion) gas. The acquisition complemented our existing Texas intrastate natural gas pipeline group assets and positioned us to pursue expansions at the facility that will provide or offer needed services to utilities, the growing liquefied natural gas industry along the Texas Gulf Coast, and other natural gas storage users. Additionally, as part of the transaction, we entered into a long-term storage capacity and transportation agreement with NRG, one of the largest wholesale electric power generating companies in the United States, with over 13,000 megawatts of generation capacity. The agreement covers storage services for approximately 2.0 billion cubic feet of natural gas capacity and expires on March 1, 2017. The North Dayton storage facility’s operations are included in our Natural Gas Pipelines business segment.

          Our allocation of the purchase price to assets acquired and liabilities assumed was based on an appraisal of fair market values, which was completed in the fourth quarter of 2005. A total of $26.0 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes. We believe our acquisition of the North Dayton natural gas storage facility resulted in the recognition of goodwill primarily due to the fact that the favorable location and the favorable association with our pre-existing assets contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities —in the aggregate, these factors represented goodwill. The $11.7 million of deferred charges and other assets in the table above represents the fair value of the intangible long-term natural gas storage capacity and transportation agreement.

          (6) August and September 2005 Terminal Assets

          In August and September 2005, we acquired certain terminal facilities and assets, including both real and personal property, in two separate transactions for an aggregate consideration of approximately $4.3 million in cash.

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In August 2005, we spent $1.9 million to acquire the Kinder Morgan Blackhawk terminal from White Material Handling, Inc., and in September 2005, we spent $2.4 million to acquire a repair shop and related assets from Trans-Global Solutions, Inc.

          The Kinder Morgan Blackhawk terminal consists of approximately 46 acres of land, storage buildings, and related equipment located in Black Hawk County, Iowa. The terminal primarily stores and transfers fertilizer and salt and further expanded our Midwest region bulk terminal operations. The acquisition of the repair shop, located in Jefferson County, Texas, near Beaumont, consists of real and personal property, including parts inventory. The acquisition facilitated and expanded the earlier acquisition of our Texas Petcoke terminals from Trans-Global Solutions in April 2005. The operations of both acquisitions are included in our Terminals business segment.

          (7) Allied Terminal Assets

          Effective November 4, 2005, we acquired certain terminal assets from Allied Terminals, Inc. for an aggregate consideration of approximately $13.3 million, consisting of $12.1 million in cash and $1.2 million in assumed liabilities. The assets primarily consisted of storage tanks, loading docks, truck racks, land and other equipment and personal property located adjacent to our Shipyard River bulk terminal in Charleston, South Carolina. The acquisition complemented an ongoing capital expansion project at our Shipyard River terminal that together, will add infrastructure in order to increase the terminal’s ability to handle increasing supplies of imported coal. The acquired assets are counted as an external addition to our Shipyard River terminal and are included as part of our Terminals business segment.

          (8) Entrega Gas Pipeline LLC

          Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. We contributed 66 2/3% of the consideration for this purchase, which corresponded to our percentage ownership of West2East Pipeline LLC at that time. At the time of acquisition, Sempra Energy held the remaining 33 1/3% ownership interest and contributed this same proportional amount of the total consideration.

          On the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that, when fully constructed, consisted of two segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming and (ii) a 191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado. In the first quarter of 2006, EnCana Corporation completed construction of the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and interim service began on that portion of the pipeline on February 24, 2006. Under the terms of the purchase and sale agreement, Rockies Express Pipeline LLC constructed the segment that extends from the Wamsutter Hub to the Cheyenne Hub. Construction on this pipeline segment began in the second quarter of 2006, and both pipeline segments were placed into service on February 14, 2007. The acquired assets are included in our Natural Gas Pipelines business segment.

          In April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline LLC. Going forward, the entire pipeline system (including lines currently being developed by Rockies Express Pipeline LLC) will be known as the Rockies Express Pipeline. The combined 1,679-mile pipeline system will be one of the largest natural gas pipelines ever constructed in North America. The approximately $4.9 billion project will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for all of the pipeline capacity.

          On June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership interest in West2East Pipeline LLC. On that date, a 24% ownership interest was transferred to ConocoPhillips, and an additional 1% interest will be transferred once construction of the entire project is completed. Through our subsidiary Kinder Morgan W2E Pipeline LLC, we will continue to operate the project but our ownership interest decreased to 51% of the equity in the project (down from 66 2/3%). Sempra’s ownership interest in West2East Pipeline LLC decreased to 25% (down from 33 1/3%). When construction of the entire project is completed, our ownership interest will be reduced to 50% at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect our 50%

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economics in the project. We do not anticipate any additional changes in the ownership structure of the Rockies Express Pipeline project.

          West2East Pipeline LLC qualifies as a variable interest entity as defined by Financial Accounting Standards Board Interpretation No. 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities-an interpretation of ARB No. 51,” due to the fact that the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including equity holders. Furthermore, following ConocoPhillips’ acquisition of its ownership interest in West2East Pipeline LLC on June 30, 2006, we receive 50% of the economics of the Rockies Express project on an ongoing basis, and thus, effective June 30, 2006, we were no longer considered the primary beneficiary of this entity as defined by FIN 46R. Accordingly, on that date, we made the change in accounting for our investment in West2East Pipeline LLC from full consolidation to the equity method following the decrease in our ownership percentage.

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

          In addition, we have guaranteed our proportionate share of West2East Pipeline LLC’s debt borrowings under a $2 billion credit facility entered into by Rockies Express Pipeline LLC. For more information on our contingent debt, see Note 9.

          (9) April 2006 Oil and Gas Properties

          On April 5, 2006, Kinder Morgan Production Company L.P. purchased various oil and gas properties from Journey Acquisition – I, L.P. and Journey 2000, L.P. for an aggregate consideration of approximately $63.6 million, consisting of $60.0 million in cash and $3.6 million in assumed liabilities. The acquisition was effective March 1, 2006. However, we divested certain acquired properties that are not considered candidates for carbon dioxide enhanced oil recovery, thus reducing our total investment. We received proceeds of approximately $27.1 million from the sale of these properties.

          The properties are primarily located in the Permian Basin area of West Texas, produce approximately 400 barrels of oil equivalent per day, and include some fields with potential for enhanced oil recovery development near our current carbon dioxide operations. The acquired operations are included as part of our CO₂ business segment.

          (10) April 2006 Terminal Assets

          In April 2006, we acquired terminal assets and operations from A&L Trucking, L.P. and U.S. Development Group in three separate transactions for an aggregate consideration of approximately $61.9 million, consisting of $61.6 million in cash and $0.3 million in assumed liabilities.

          The first transaction included the acquisition of equipment and infrastructure on the Houston Ship Channel that loads and stores steel products. The acquired assets complement our nearby bulk terminal facility purchased from General Stevedores, L.P. in July 2005. The second acquisition included the purchase of a rail terminal at the Port of Houston that handles both bulk and liquids products. The rail terminal complements our existing Texas petroleum coke terminal operations and maximizes the value of our existing deepwater terminal by providing customers with both rail and vessel transportation options for bulk products. Thirdly, we acquired the entire membership interest of Lomita Rail Terminal LLC, a limited liability company that owns a high-volume rail ethanol terminal in Carson, California. The terminal serves approximately 80% of the Southern California demand for reformulated fuel blend ethanol with expandable offloading/distribution capacity, and the acquisition expanded our existing rail transloading operations. All of the acquired assets are included in our Terminals business segment. A total of $17.8 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.

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          (11) Transload Services, LLC

          Effective November 20, 2006, we acquired all of the membership interests of Transload Services, LLC from Lanigan Holdings, LLC for an aggregate consideration of approximately $16.6 million, consisting of $15.8 million in cash and $0.8 million of assumed liabilities. Transload Services, LLC is a leading provider of innovative, high quality material handling and steel processing services, operating 14 steel-related terminal facilities located in the Chicago metropolitan area and various cities in the United States. Its operations include transloading services, steel fabricating and processing, warehousing and distribution, and project staging. Specializing in steel processing and handling, Transload Services can inventory product, schedule shipments and provide customers cost-effective modes of transportation. The combined operations include over 92 acres of outside storage and 445,000 square feet of covered storage that offers customers environmentally controlled warehouses with indoor rail and truck loading facilities for handling temperature and humidity sensitive products. The acquired assets are included in our Terminals business segment, and the acquisition further expanded and diversified our existing terminals’ materials services (rail transloading) operations.

          A total of $8.4 million of goodwill was assigned to our Terminals business segment, and the entire amount is expected to be deductible for tax purposes. We believe this acquisition resulted in the recognition of goodwill primarily due to the fact that it establishes a business presence in several key markets, taking advantage of the non-residential and highway construction demand for steel that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities —in the aggregate, these factors represented goodwill.

          (12) Devco USA L.L.C.

          Effective December 1, 2006, we acquired all of the membership interests in Devco USA L.L.C., an Oklahoma limited liability company, for an aggregate consideration of approximately $7.3 million, consisting of $4.8 million in cash, $1.6 million in common units, and $0.9 million of assumed liabilities. The primary asset acquired was a technology based identifiable intangible asset, a proprietary process that transforms molten sulfur into premium solid formed pellets that are environmentally friendly, easy to handle and store, and safe to transport. The process was developed internally by Devco’s engineers and employees. Devco, a Tulsa, Oklahoma based company, has more than 20 years of sulfur handling expertise and we believe the acquisition and subsequent application of this acquired technology complements our existing dry-bulk terminal operations. We allocated $6.5 million of our total purchase price to the value of this intangible asset, and we have included the acquisition as part of our Terminals business segment.

          (13) Roanoke, Virginia Products Terminal

          Effective December 15, 2006, we acquired a refined petroleum products terminal located in Roanoke, Virginia from Motiva Enterprises, LLC for approximately $6.4 million in cash. The terminal has storage capacity of approximately 180,000 barrels per day for refined petroleum products like gasoline and diesel fuel. The terminal is served exclusively by the Plantation Pipeline and Motiva has entered into a long-term contract to use the terminal. The acquisition complemented the other refined products terminals we own in the southeast region of the United States, and the acquired terminal is included as part our Products Pipelines business segment.

          (14) Interest in Cochin Pipeline

          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.

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          As of December 31, 2007, our allocation of the purchase price was preliminary, pending final determination of deferred income tax balances at the time of acquisition. We expect these final purchase price adjustments to be in the first quarter of 2008.

          (15) Vancouver Wharves Terminal

          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 $57.2 million, consisting of $38.8 million in cash and $18.4 million in assumed liabilities. 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.

          (16) Marine Terminals, Inc. Assets

          Effective September 1, 2007, we acquired certain bulk terminals assets from Marine Terminals, Inc. for an aggregate consideration of approximately $101.5 million, consisting of $100.3 million in cash and an assumed liability of $1.2 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.

          As of December 31, 2007, we have preliminarily allocated $60.8 million of our combined purchase price to “Property, Plant and Equipment, net”. The $40.5 million allocated to deferred charges and other assets included $39.7 million of intangible assets, representing the fair value of intangible customer relationships which encompass both the contractual life of customer contracts plus any future customer relationship value beyond the contract life. We expect to make further purchase price adjustments to the acquired assets in the first half of 2008, based on further analysis of fair market values. 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.

          Pro Forma Information

          Pro forma 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 January 1, 2006, is not materially different from the information presented in our accompanying consolidated statements of income.

          Trans Mountain Pipeline System

          On April 30, 2007, we acquired the Trans Mountain pipeline system from Knight for $549.1 million in cash. The transaction was approved by the independent directors of both Knight 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, according to 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

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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 similar 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, all income statements presented be combined as of the date of common control. 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. 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 November 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.

          Divestitures

          Douglas Gas Gathering and Painter Gas Fractionation

          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 year ended December 31, 2006. For more information on our accounting for derivative contracts, see Note 14.

          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.

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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.

          North System Natural Gas Liquids Pipeline System – Discontinued Operations

          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 $298.6 million in cash. Our investment in net assets, including all transaction related accruals, was approximately $145.8 million, most of which represented property, plant and equipment, and we recognized approximately $152.8 million of gain on the sale of these net assets.

          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 were 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. Prior to the sale, all of the assets were 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 the financial results of the North System have been reclassified to discontinued operations in our accompanying consolidated statements of income for all periods presented in this report. We reported the net amount of the gain, $152.8 million, with the caption “Gain on disposal of North System” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2007.

           Summarized financial information of the North System is as follows (in millions):

	Year Ended December 31,
	2007			2006			2005
Operating revenues	$	41.1		$	43.7		$	41.2
Operating expenses		(14.8	)		(22.7	)		(35.2	)
Depreciation and amortization		(7.0	)		(8.9	)		(8.2	)
Earnings from equity investments		1.8			2.2			2.1
Amortization of excess cost of equity investments		—			(0.1	)		(0.1	)
Other, net – income (expense)		—			0.1			—
Income (loss) from operations		21.1			14.3			(0.2	)
Income from disposal		152.8			—			—
Total earnings from discontinued operations	$	173.9		$	14.3		$	(0.2	)

          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 does 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.

4. Asset Retirement Obligations

          We account for our legal obligations associated with the retirement of long-lived assets pursuant to Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

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          SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. Under SFAS No. 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

          In our CO₂ business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of December 31, 2007 and 2006, we have recognized asset retirement obligations relating to these requirements at existing sites within our CO₂ segment in the aggregate amounts of $49.2 million and $47.2 million, respectively.

          In our Natural Gas Pipelines business segment, if we were to cease providing utility services, we would be required to remove surface facilities from land belonging to our customers and others. We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities. As of December 31, 2007 and 2006, we have recognized asset retirement obligations relating to the businesses within our Natural Gas Pipelines segment in the aggregate amounts of $3.0 million and $3.1 million, respectively.

          We have included $1.4 million of our total asset retirement obligations as of both December 31, 2007 and December 31, 2006 within “Accrued other current liabilities” in our accompanying consolidated balance sheets. The remaining $50.8 million obligation as of December 31, 2007 and $48.9 million obligation as of December 31, 2006 are reported separately as non-current liabilities in our accompanying consolidated balance sheets. No assets are legally restricted for purposes of settling our asset retirement obligations. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the years ended December 31, 2007 and 2006 is as follows (in millions):

	Year Ended December 31,
	2007			2006
Balance at beginning of period	$	50.3		$	43.2
Liabilities incurred		0.4			6.8
Liabilities settled		(1.1	)		(2.2	)
Accretion expense		2.6			2.5
Revisions in estimated cash flows		—			—
Balance at end of period	$	52.2		$	50.3

          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.

5. Income Taxes

          Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in millions):

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	Year Ended December 31,
	2007			2006			2005
Taxes currently payable:
Federal	$	12.7		$	12.8		$	9.6
State		8.2			2.3			2.1
Foreign		31.5			11.2			0.4
Total		52.4			26.3			12.1
Taxes deferred:
Federal		11.8			1.6			8.1
State		6.2			0.2			0.8
Foreign		0.6			0.9			3.5
Total		18.6			2.7			12.4
Total tax provision	$	71.0		$	29.0		$	24.5
Effective tax rate		14.6	%		2.8	%		2.9	%

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

	Year Ended December 31,
	2007			2006			2005
Federal income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) as a result of:
Partnership earnings not subject to tax		(35.0	)%		(35.0	)%		(35.0	)%
Corporate subsidiary earnings subject to tax		3.0	%		1.0	%		1.1	%
Income tax expense attributable to corporate equity earnings		2.3	%		0.5	%		1.1	%
Income tax expense attributable to foreign corporate earnings		6.6	%		1.1	%		0.5	%
State taxes		2.7	%		0.2	%		0.2	%
Effective tax rate		14.6	%		2.8	%		2.9	%

          Our deferred tax assets and liabilities as of December 31, 2007 and 2006 result from the following (in millions):

	December 31,
	2007		2006
Deferred tax assets:
Book accruals	$	13.1	$	1.4
Net Operating Loss/Alternative minimum tax credits		1.2		3.0
Other		1.7		1.3
Total deferred tax assets		16.0		5.7
Deferred tax liabilities:
Property, plant and equipment		189.9		106.9
Other		28.5		84.0
Total deferred tax liabilities		218.4		190.9
Net deferred tax liabilities	$	202.4	$	185.2

          We had available, at December 31, 2007, approximately $0.13 million of foreign minimum tax credit carryforwards, which will expire between the years 2013 and 2016, and $1.1 million of state net operating loss carryforwards, which will expire between the years 2008 and 2025. We believe it is more likely than not that the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary.

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6. Property, Plant and Equipment

          Classes and Depreciation

          As of December 31, 2007 and 2006, our property, plant and equipment consisted of the following (in millions):

	December 31,
	2007			2006
Natural gas, liquids, crude oil and carbon dioxide pipelines	$	5,498.4		$	4,795.9
Natural gas, liquids, carbon dioxide pipeline, and terminals station equipment		5,076.2			4,549.3
Natural gas, liquids (including linefill), and transmix processing		168.3			172.7
Other		1,060.4			844.9
Accumulated depreciation and depletion		(2,044.0	)		(1,641.2	)
		9,759.3			8,721.6
Land and land right-of-way		551.5			532.9
Construction work in process		1,280.5			851.6
Property, Plant and Equipment, net	$	11,591.3		$	10,106.1

          Depreciation and depletion expense charged against property, plant and equipment consisted of $529.3 million in 2007, $416.6 million in 2006 and $339.6 million in 2005.

          Casualty Gain

          On August 29, 2005, Hurricane Katrina made landfall in the United States Gulf Coast causing widespread damage to residential and commercial real and personal property. In addition, on September 23, 2005, Hurricane Rita struck the Texas-Louisiana Gulf Coast causing additional damage to insured interests. The primary assets we operate that were impacted by these storms included several bulk and liquids terminal facilities located in the states of Louisiana and Mississippi, and certain of our Gulf Coast liquids terminals facilities, which are located along the Houston Ship Channel. Specifically, with regard to physical property damage, our International Marine Terminals facility suffered extensive property damage and a general loss of business due to the effects of Hurricane Katrina. IMT is a Louisiana partnership owned 66 2/3% by us. It operates a multi-purpose bulk commodity transfer terminal facility located in Port Sulphur, Louisiana.

          All of our terminal facilities affected by these storms are currently open, and all of the facilities are covered by property casualty insurance. Some of the facilities are also covered by business interruption insurance. To account for our property casualty damage, we recognized repair expense related to hurricane damage as incurred. We also transferred off our books the net book value of the assets that were damaged or destroyed, and we offset the book value of all damaged and destroyed assets with indemnity proceeds received (and receivable in the future) according to the provisions of the insurance policies in force. We also incurred capital expenditures related to the repair and replacement of damaged assets.

          When an insured asset is damaged or destroyed, the relevant accounts must be adjusted to the date of the casualty, and settlement with the insurance companies must be completed. The maximum amount recoverable from property damage is the fair market value of the property at the date of loss (the replacement value), or the amount stipulated in the insurance contract. Although net book values are irrelevant in determining indemnifications from insurers, under current accounting provisions, asset book values are used for accounting purposes to measure the gain or loss resulting from casualty settlements. Also, because indemnifications under insurance policies are based upon fair market values, indemnifications often exceed the book value of the assets destroyed or damaged, and any excess of insurance indemnifications over the book value of damaged assets represents a book casualty gain.

          In the fourth quarter of 2006, we reached settlements with our insurance carriers on all of our property damage claims related to the 2005 hurricane season, including IMT’s claims. As a result of these settlements, we recognized a property casualty gain of $15.2 million, excluding all hurricane repair and clean-up expenses. This casualty gain represented the excess of indemnity proceeds received or recoverable over the book value of damaged or destroyed assets. We also collected, in 2006, property insurance indemnities of $13.1 million, and we disclosed these cash receipts separately as “Property casualty indemnifications” within investing activities on our accompanying consolidated statement of cash flows. In addition, as of December 31, 2006, we signed proofs of loss totaling $8.0 million for expected future property damage proceeds, and we received these indemnity proceeds in January 2007.

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With the settlement of these claims, we released all remaining estimated property insurance receivables and estimated property insurance-related damage claim amounts, as these hurricane property damage claims are now closed; however, we did recognize additional casualty gains of approximately $1.8 million in the first quarter of 2007 (before minority interest allocations), based upon our final determination of the book value of the fixed assets destroyed or damaged, and indemnities pursuant to flood insurance coverage.

          In addition to this casualty gain, 2006 income and expense items related to hurricane activity included the following: (i) a $2.8 million increase in operating and maintenance expenses from hurricane repair and clean-up activities, (ii) a $1.1 million increase in income tax expense associated with overall hurricane income and expense items, (iii) a $0.4 million decrease in general and administrative expenses from the allocation of overhead expenses to hurricane related capital projects, and (iv) a $3.1 million increase in minority interest expense related to the allocation of IMT’s earnings from hurricane income and expense items to minority interest. Combined, the hurricane income and expense items, including the casualty gain, resulted in a total increase in net income of $8.6 million in 2006. For the year 2006, we spent approximately $12.2 million for hurricane repair and replacement costs and including accruals, sustaining capital expenditures for hurricane repair and replacement costs totaled $14.2 million.

7. Investments

          Our significant equity investments as of December 31, 2007 consisted of:

• Plantation Pipe Line Company (51%);

• West2East Pipeline LLC (51%);

• Red Cedar Gathering Company (49%);

• Midcontinent Express Pipeline LLC (50%);

• Thunder Creek Gas Services, LLC (25%); and

• Cortez Pipeline Company (50%).

          We operate and own an approximate 51% ownership interest in Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49% interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered participating rights. Therefore, we do not control Plantation Pipe Line Company, and we account for our investment under the equity method of accounting.

          Similarly, 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. As discussed in Note 3, 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. Prior to June 30, 2006, we owned a 66 2/3% ownership interest in West2East Pipeline LLC and we accounted for our investment under the full consolidation method. Following the decrease in our ownership interest to 51% effective June 30, 2006, we deconsolidated this entity and began to account for our investment under the equity method. As of December 31, 2006, we had no material investment in the net assets of West2East Pipeline LLC due to the fact that the amount of its assets, primarily property, plant and equipment, was largely offset by the amount of its liabilities, primarily debt.

          We also own a 50% interest in Midcontinent Express Pipeline LLC, which filed an application with the FERC in October 2007 requesting a certificate of public convenience and necessity that would authorize construction and

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operation of an approximate 500-mile natural gas transmission system. Energy Transfer Partners, L.P. owns the remaining 50% interest. The Midcontinent Express Pipeline will create long-haul, firm natural gas transportation takeaway capacity, either directly or indirectly, from natural gas producing regions located in Texas, Oklahoma and Arkansas. The total project is expected to cost approximately $1.3 billion, and will have an initial transportation capacity of approximately 1.4 billion cubic feet per day of natural gas. Furthermore, in January 2008, Midcontinent Express and MarkWest Pioneer, L.L.C., a subsidiary of MarkWest Energy Partners, L.P., entered into an option agreement which provides MarkWest a one-time right to purchase a 10% ownership interest in Midcontinent Express after the pipeline is fully constructed and placed into service. If the option is exercised, we and Energy Transfer Partners will each own 45% of Midcontinent Express, while MarkWest will own the remaining 10%.

          Our total investments consisted of the following (in millions):

	December 31,
	2007		2006
Plantation Pipe Line Company	$	195.4	$	199.6
West2East Pipeline LLC		191.9		—
Red Cedar Gathering Company		135.6		160.6
Midcontinent Express Pipeline LLC		63.0		—
Thunder Creek Gas Services, LLC		37.0		37.2
Cortez Pipeline Company		14.2		16.2
All Others		18.3		12.7
Total Equity Investments	$	655.4	$	426.3

          Our earnings (losses) from equity investments were as follows (in millions):

	Year Ended December 31,
	2007			2006			2005
Red Cedar Gathering Company	$	28.0		$	36.3		$	32.0
Cortez Pipeline Company		19.2			19.2			26.3
Plantation Pipe Line Company		29.4			12.8			24.9
Thunder Creek Gas Services, LLC		2.2			2.4			2.8
Midcontinent Express Pipeline LLC		1.4			—			—
West2East Pipeline LLC		(12.4	)		—			—
All Others		1.9			3.3			3.6
Total	$	69.7		$	74.0		$	89.6
Amortization of excess costs	$	(5.8	)	$	(5.6	)	$	(5.5	)

          Summarized combined unaudited financial information for our significant equity investments (listed above) is reported below (in millions; amounts represent 100% of investee financial information):

	Year Ended December 31,
Income Statement	2007		2006		2005
Revenues	$	473.0	$	441.9	$	440.7
Costs and expenses		355.1		299.5		279.6
Earnings before extraordinary items and cumulative effect of a change in accounting principle		117.9		142.4		161.1
Net income	$	117.9	$	142.4	$	161.1

	December 31,
Balance Sheet	2007		2006
Current assets	$	138.3	$	95.5
Non-current assets		3,519.5		1,506.0
Current liabilities		319.5		213.2
Non-current liabilities		2,624.1		1,127.3
Partners’/owners’ equity		714.2		261.0

8. Intangibles

          Our intangible assets include goodwill, lease value, contracts, customer relationships, technology-based assets and agreements.

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          Goodwill and Excess Investment Cost

          As an investor, the price we pay to acquire an ownership interest in an investee will most likely differ from the underlying interest in book value, with book value representing the investee’s net assets per its financial statements. This differential relates to both discrepancies between the investee’s recognized net assets at book value and at current fair values and to any premium we pay to acquire the investment. Under ABP No. 18, any such premium paid by an investor, which is analogous to goodwill, must be identified.

          For our investments in affiliated entities that are included in our consolidation, the excess cost over underlying fair value of net assets is referred to as goodwill and reported separately as “Goodwill” in our accompanying consolidated balance sheets. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires goodwill to be assigned 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.

          Changes in the carrying amount of our goodwill for each of the two years ended December 31, 2006 and 2007 are summarized as follows (in millions):

	Products Pipelines			Natural Gas Pipelines			CO2			Terminals				Trans Mountain(a)				Total
Balance as of December 31, 2005		$	263.2		$	288.4		$	46.1		$	201.3			$	—			$	799.0
Acquisitions and purchase price adjs.			—			—			—			30.0				593.2				623.2
Disposals			—			—			—			—				—				—
Impairments			—			—			—			—				—				—
Currency translation adjustments			—			—			—			—				(1.2	)			(1.2	)
Balance as of December 31, 2006		$	263.2		$	288.4		$	46.1		$	231.3			$	592.0			$	1,421.0
Acquisitions and purchase price adjs.			—			—			—			(2.2	)			—				(2.2	)
Disposals			—			—			—			—				—				—
Impairments			—			—			—			—				(377.1	)			(377.1	)
Currency translation adjustments			—			—			—			—				36.1				36.1
Balance as of December 31, 2007		$	263.2		$	288.4		$	46.1		$	229.1			$	251.0			$	1,077.8

(a)	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 (discussed in Note 3). Following the provisions of generally accepted accounting principles, 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. Knight recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007.
For our investments in entities that are not fully consolidated but instead are included in our financial statements under the equity method of accounting, the premium we pay that represents excess cost over underlying fair value of net assets is referred to as equity method goodwill, and under SFAS No. 142, this excess cost is not subject to amortization but rather to impairment testing pursuant to APB No. 18. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, in addition to our annual impairment test of goodwill, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives in accordance with APB Opinion No. 18. As of both December 31, 2007 and 2006, we have reported $138.2 million in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.
We also periodically reevaluate the difference between the fair value of net assets accounted for under the equity method and our proportionate share of the underlying book value (that is, the investee’s net assets per its financial statements) of the investee at date of acquisition. In almost all instances, this differential, relating to the discrepancy between our share of the investee’s recognized net assets at book values and at current fair values, represents our share of undervalued depreciable assets, and since those assets (other than land) are subject to depreciation, we amortize this portion of our investment cost against our share of investee earnings. We reevaluate this differential, as well as the amortization period for such undervalued depreciable assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives in accordance with

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APB Opinion No. 18. The caption “Investments” in our accompanying consolidated balance sheets includes excess fair value of net assets over book value costs of $174.7 million as of December 31, 2007 and $177.1 million as of December 31, 2006.
	Other Intangibles
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):

	December 31, 2007				December 31, 2006
Customer relationships, contracts and agreements
Gross carrying amount		$	264.1			$	224.4
Accumulated amortization			(36.9	)			(23.1	)
Net carrying amount			227.2				201.3
Technology-based assets, lease value and other
Gross carrying amount			13.3				13.3
Accumulated amortization			(1.9	)			(1.4	)
Net carrying amount			11.4				11.9
Total Other intangibles, net		$	238.6			$	213.2

          The increase in the carrying amount of customer relationships, contracts and agreements since December 31, 2006 was primarily due to the acquisition of intangible customer relationships included in our purchase of certain assets from Marine Terminals, Inc. effective September 1, 2007. As of the acquisition date, we preliminarily allocated $39.8 million of our combined purchase price for Marine Terminals, Inc.’s assets to intangible customer relationships, and we estimated the expected useful life of these intangibles to be 20 years. For more information on this acquisition, see Note 3.

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

	Year Ended December 31,
	2007		2006		2005
Customer relationships, contracts and agreements	$	13.8	$	13.5	$	8.6
Technology-based assets, lease value and other		0.5		0.2		0.1
Total amortization	$	14.3	$	13.7	$	8.7

          As of December 31, 2007, our weighted average amortization period for our intangible assets was approximately 18.25 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $15.5 million, $14.4 million, $14.2 million, $14.1 million and $14.1 million, respectively.

9. Debt

          Short-Term Debt

          Our outstanding short-term debt as of December 31, 2007 and 2006 consisted of the following (in millions):

	December 31, 2007			December 31, 2006
Commercial paper borrowings		$	589.1		$	1,098.2
Short-term portion of:
5.35% senior notes due August 15, 2007			—			250.0
5.40% note due March 31, 2012(a)			9.9			—
5.23% senior notes due January 2, 2014(b)			6.2			5.9
7.84% senior notes due July 23, 2008(c)			5.0			5.0
Total short-term debt		$	610.2		$	1,359.1

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(a)      Our subsidiaries, Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company, are the obligors on            the note.

(b)      Our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes.

(c)      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 6.40% during 2007 and 6.18% during 2006.

          Credit Facilities

          On February 22, 2006, we entered into a second unsecured bank credit facility, a nine-month credit facility in the amount of $250 million, expiring on November 21, 2006. This facility contained borrowing rates and restrictive financial covenants that were similar to the borrowing rates and covenants under our pre-existing five-year unsecured $1.6 billion bank facility due August 18, 2010.

          Effective August 28, 2006, we terminated our $250 million nine-month facility and we increased our five-year bank credit facility from $1.6 billion to $1.85 billion. The five-year unsecured bank credit facility remains due August 18, 2010; however, the bank facility can be amended to allow for borrowings up to $2.1 billion. There were no borrowings under our five-year credit facility as of December 31, 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 December 31, 2007, the amount available for borrowing under our credit facility was reduced by an aggregate amount of $1,126.9 million, consisting of (i) our outstanding commercial paper borrowings ($589.1 million as of December 31, 2007); (ii) a combined $298 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 $46.6 million in two letters of credit that support tax-exempt bonds; (v) a $19.9 million letter of credit that supports 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 $35.8 million in other letters of credit supporting other obligations of us and our subsidiaries.

          Our five-year credit facility permits us to obtain bids for fixed rate loans from members of the lending syndicate. Interest on our credit facility accrues at our option at a floating rate equal to either (i) the administrative agent’s base rate (but not less than the Federal Funds Rate, plus 0.5%); or (ii) LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.

          Our credit facility included the following restrictive covenants as of December 31, 2007:

• total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed:

• 5.5, in the case of any such period ended on the last day of (i) a fiscal quarter in which we make any Specified Acquisition, or (ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or

• 5.0, in the case of any such period ended on the last day of any other fiscal quarter;

• certain limitations on entering into mergers, consolidations and sales of assets;

• limitations on granting liens; and

• prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.

          In addition to normal repayment covenants, under the terms of our credit facility, the occurrence at any time of any of the following would constitute an event of default (i) our failure to make required payments of any item of

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indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million; (ii) our general partner’s failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million; (iii) adverse judgments rendered against us for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed; and (iv) voluntary or involuntary commencements of any proceedings or petitions seeking our liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.

          Excluding the relatively non-restrictive specified negative covenants and events of defaults, our credit facility does not contain any provisions designed to protect against a situation where a party to an agreement is unable to find a basis to terminate that agreement while its counterparty’s impending financial collapse is revealed and perhaps hastened through the default structure of some other agreement. The credit facility also does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin we will pay with respect to borrowings and the facility fee that we will pay on the total commitment will vary based on our senior debt investment rating. None of our debt is subject to payment acceleration as a result of any change to our credit ratings.

          Commercial Paper Program

          In April 2006, we increased our commercial paper program by $250 million to provide for the issuance of up to $1.85 billion. 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 December 31, 2007, we had $589.1 million of commercial paper outstanding with a weighted average interest rate of 5.58%. As of December 31, 2006, we had $1,098.2 million of commercial paper outstanding with an average interest rate of 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.

          Long-Term Debt

          Our outstanding long-term debt, excluding the value of interest rate swaps, as of December 31, 2007 and 2006 was $6,455.9 million and $4,384.3 million, respectively. The balances consisted of the following (in millions):

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	December 31,
	2007				2006
Kinder Morgan Energy Partners, L.P. borrowings:
5.35% senior notes due August 15, 2007		$	—			$	250.0
6.30% senior notes due February 1, 2009			250.0				250.0
7.50% senior notes due November 1, 2010			250.0				250.0
6.75% senior notes due March 15, 2011			700.0				700.0
7.125% senior notes due March 15, 2012			450.0				450.0
5.85% senior notes due September 15, 2012			500.0				—
5.00% senior notes due December 15, 2013			500.0				500.0
5.125% senior notes due November 15, 2014			500.0				500.0
6.00% senior notes due February 1, 2017			600.0				—
7.400% senior notes due March 15, 2031			300.0				300.0
7.75% senior notes due March 15, 2032			300.0				300.0
7.30% senior notes due August 15, 2033			500.0				500.0
5.80% senior notes due March 15, 2035			500.0				500.0
6.50% senior notes due February 1, 2037			400.0				—
6.95% senior notes due January 15, 2038			550.0				—
Commercial paper borrowings			589.1				1,098.2
Subsidiary borrowings:
Central Florida Pipe Line LLC-7.840% senior notes due July 23, 2008			5.0				10.0
Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010			5.3				5.3
Kinder Morgan Operating L.P. “A”-5.40% BP note, due March 31, 2012			23.6				—
Kinder Morgan Canada Company-5.40% BP note, due March 31, 2012			21.0				—
Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014			43.2				49.1
Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018			25.0				25.0
Kinder Morgan Operating L.P. “B”-Jackson-Union Cos. IL Revenue Bonds due April 1, 2024			23.7				23.7
International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025			40.0				40.0
Other miscellaneous subsidiary debt			1.4				1.4
Unamortized debt discount on senior notes			(11.2	)			(9.3	)
Current portion of long-term debt			(610.2	)			(1,359.1	)
Total Long-term debt		$	6,455.9			$	4,384.3

          Senior Notes

          During 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:

• $992.8 million from a January 30, 2007 public offering of a total of $1.0 billion in principal amount of senior notes, consisting of $600 million of 6.00% notes due February 1, 2017, and $400 million of 6.50% notes due February 1, 2037;

• $543.9 million from a June 21, 2007 public offering of $550 million in principal amount of 6.95% senior notes due January 15, 2038; and

• $497.8 million from an August 28, 2007 public offering of $500 million in principal amount of 5.85% senior notes due September 15, 2012.

          We used the proceeds from each of these offerings to reduce the borrowings under our commercial paper program. As of December 31, 2007 and 2006, the outstanding balance on the various series of our senior notes (excluding unamortized debt discount) was $6,288.8 million and $4,490.7 million, respectively. For a listing of the various outstanding series of our senior notes, see the table above included in “—Long-Term Debt.”

          On February 12, 2008, we completed an additional public offering of senior notes. We issued a total of $900 million in principal amount of senior notes, consisting of $600 million of 5.95% notes due February 15, 2018, and

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$300 million of 6.95% notes due January 15, 2038. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $894.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program. The notes due in 2038 constitute a further issuance of the $550 million aggregate principal amount of 6.95% notes issued on June 21, 2007 (referred to above) and will form a single series with those notes.

          Interest Rate Swaps

          Information on our interest rate swaps is contained in Note 14.

          Subsidiary Debt

          Our subsidiaries are obligors on the following debt. The agreements governing these obligations contain various affirmative and negative covenants and events of default. We do not believe that these provisions will materially affect distributions to our partners.

          Central Florida Pipeline LLC Debt

          Central Florida Pipeline LLC is an obligor on an aggregate principal amount of $40 million of senior notes originally issued to a syndicate of eight insurance companies. The senior notes have a fixed annual interest rate of 7.84% with repayments in annual installments of $5 million beginning July 23, 2001. The final payment is due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of each year. In both July 2007 and July 2006, we made an annual repayment of $5.0 million and as of December 31, 2007, Central Florida’s outstanding balance under the senior notes was $5.0 million.

          Arrow Terminals L.P.

          Arrow Terminals L.P. is an obligor on a $5.3 million principal amount of Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority. The bonds have a maturity date of January 1, 2010, and interest on these bonds is paid and computed quarterly at the Bond Market Association Municipal Swap Index. The bonds are collateralized by a first mortgage on assets of Arrow’s Chicago operations and a third mortgage on assets of Arrow’s Pennsylvania operations. As of December 31, 2007, the interest rate was 3.595%. The bonds are also backed by a $5.4 million letter of credit issued by JP Morgan Chase that backs-up the $5.3 million principal amount of the bonds and $0.1 million of interest on the bonds for up to 45 days computed at 12% per annum on the principal amount thereof.

          Kinder Morgan Texas Pipeline, L.P. Debt

          Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes with a fixed annual stated interest rate as of August 1, 2005, of 8.85%. The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million. The final payment is due January 2, 2014. As of December 31, 2007, KMTP’s outstanding balance under the senior notes was $43.2 million.

          Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million and at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid.

          Kinder Morgan Liquids Terminals LLC Debt

          Kinder Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. These bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2007, the interest rate was 3.57%. We have an outstanding letter of credit issued by Citibank in the amount of $25.3 million that

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backs-up the $25.0 million principal amount of the bonds and $0.3 million of interest on the bonds for up to 42 days computed at 12% on a per annum basis on the principal thereof.

          Kinder Morgan Operating L.P. “B” Debt

          This $23.7 million principal amount of tax-exempt bonds due April 1, 2024 was issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. As of December 31, 2007, the interest rate on these bonds was 3.33%. Also, as of December 31, 2007, we had an outstanding letter of credit issued by Wachovia in the amount of $24.1 million that backs-up the $23.7 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 55 days computed at 12% per annum on the principal amount thereof.

          International Marine Terminals Debt

          We own a 66 2/3% interest in International Marine Terminals partnership. The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40.0 million Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. As of December 31, 2007, the interest rate on these bonds was 3.65%.

          On March 15, 2005, these bonds were refunded and the maturity date was extended from March 15, 2006 to March 15, 2025. No other changes were made under the bond provisions. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees.

          Kinder Morgan Operating L.P. “A” Debt

          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 3). 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 December 31, 2007, the outstanding balance under the note was $44.6 million.

          Maturities of Debt

          The scheduled maturities of our outstanding debt, excluding value of interest rate swaps, as of December 31, 2007, are summarized as follows (in millions):

Year	Commitment
2008		$	610.2
2009			265.8
2010			270.7
2011			715.1
2012			964.3
Thereafter			4,240.0
Total		$	7,066.1

          Contingent Debt

          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

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performance under such guarantee is remote. The following is a description of our contingent debt agreements as of December 31, 2007.

          Cortez Pipeline Company Debt

          Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO₂ Company, L.P. – 50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and Cortez Vickers Pipeline Company – 13% partner) are required, on a several, 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 December 31, 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 December 31, 2007, Cortez Capital Corporation had $93.0 million of commercial paper outstanding with an average interest rate of approximately 5.66%, 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.

          Red Cedar Gathering Company Debt

          Red Cedar Gathering Company was the obligor on $55 million in aggregate principal amount of Senior Notes due October 31, 2010. The Senior Notes were collateralized by a first priority lien on the ownership interests, including our 49% ownership interest, in Red Cedar Gathering Company. The Senior Notes were also guaranteed by us and the other owner of Red Cedar Gathering Company jointly and severally. As of December 31, 2006, $31.4 million in principal amount of notes were outstanding.

          In March 2007, Red Cedar refinanced the outstanding balance of its existing Senior Notes through a private placement of $100 million in principal amount of ten year fixed rate notes. As a result of Red Cedar Gathering Company’s retirement of the remaining $31.4 million outstanding principal amount of its Senior Notes, we are no longer contingently liable for any Red Cedar Gathering Company debt.

          Nassau County, Florida Ocean Highway and Port Authority Debt

          We have posted a letter of credit 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. Our subsidiary, 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 December 31, 2007, this letter of credit had a face amount of $22.5 million.

          Rockies Express Pipeline LLC Debt

          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,

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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 December 31, 2007, Rockies Express Pipeline LLC had $1,625.4 million of commercial paper outstanding with a weighted average interest rate of approximately 5.50%, and there were no borrowings under its five-year credit facility. Accordingly, as of December 31, 2007, our contingent share of Rockies Express’ debt was $1,135.0 million (51% of total borrowings).

          Fair Value of Financial Instruments

          Fair value as used in SFAS No. 107, “Disclosures About Fair Value of Financial Instruments,” represents the amount at which an instrument could be exchanged in a current transaction between willing parties. The estimated fair value of our long-term debt, including its current portion and excluding the value of interest rate swaps, is based upon prevailing interest rates available to us as of December 31, 2007 and December 31, 2006 and is disclosed below (in millions).

	December 31, 2007				December 31, 2006
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Total Debt		$ 7,066.1		$ 7,201.8		$ 5,743.4		$ 5,865.0

10. Pensions and Other Post-Retirement Benefits

          Pension and Post-Retirement Benefit Plans

          Due to our acquisition of Trans Mountain (see Note 3), Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline L.P.) are sponsors 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 2007 and 2006 was approximately $3.2 million and $3.5 million, respectively, recognized ratably over each year. As of December 31, 2007, we estimate our overall net periodic pension and post-retirement benefit costs for these plans for the year 2008 will be approximately $3.1 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 $2.6 million to these benefit plans in 2008.

          Additionally, in connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk Terminals, Inc. in 1998, we acquired certain liabilities for pension and post-retirement benefits. We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. We also provide the same benefits to former salaried employees of SFPP. Additionally, we will continue to fund these costs for those employees currently in the plan during their retirement years. SFPP’s post-retirement benefit plan is frozen and no additional participants may join the plan. The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Knight Inc. Retirement

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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.

          Our net periodic benefit cost for the SFPP post-retirement benefit plan were credits of $0.2 million in 2007, $0.3 million in 2006, and $0.3 million in 2005. The credits resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost. As of December 31, 2007, we estimate no overall net periodic post-retirement benefit cost for the SFPP post-retirement benefit plan for the year 2008; however, this estimate could change if a future significant event would require a remeasurement of liabilities. In addition, we expect to contribute approximately $0.4 million to this post-retirement benefit plan in 2008.

          On September 29, 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R).” One of the provisions of this Statement requires an employer with publicly traded equity securities to recognize the overfunded or underfunded status of a defined benefit pension plan or post-retirement benefit plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Following adoption of SFAS No. 158, entities will report as part of the net benefit liability on their balance sheets amounts that have not yet been recognized as a component of benefit expense (for example, unrecognized prior service costs or credits, net (actuarial) gain or loss, and transition obligation or asset) with a corresponding adjustment to accumulated other comprehensive income.

          We adopted SFAS No. 158 on December 31, 2006, and the primary impact on us from adopting this Statement was to require us to fully recognize, in our consolidated balance sheet, both the funded status of our pension and post-retirement benefit plan obligations, and previously unrecognized prior service costs and credits and actuarial gains and losses. As of December 31, 2006, the recorded value of our pension and post-retirement benefit obligations for both the Trans Mountain pension and post-retirement benefit plans and the SFPP post-retirement benefit plan was a combined $28.4 million.

          The following table discloses the incremental effect on our consolidated balance sheet of applying SFAS No. 158 on December 31, 2006 (in millions):

	Before Application			Adjustments			After Application
Prepaid benefit cost		$    —			$    —			$    —
Accrued benefit liability		30.3			(1.9	)		28.4
Intangible asset		—			—			—
Deferred income tax liability		(6.4	)		(1.2	)		(7.6	)
Minority interest		—			—			—
Accumulated other comprehensive income		—			3.1			3.1

          As of December 31, 2007, the recorded value of our pension and post-retirement benefit obligations for these plans was a combined $37.5 million. We consider our overall pension and post-retirement benefit liability exposure to be minimal in relation to the value of our total consolidated assets and net income.

          Multiemployer Plans

          As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $6.7 million for the year ended December 31, 2007, and $6.3 million for each of the years ended December 31, 2006 and 2005.

          Kinder Morgan Savings Plan

          The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of Knight, Inc. and KMGP Services Company, Inc. to contribute between 1% and 50% of base

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compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, our general partner may make special discretionary contributions. Certain employees’ contributions are based on collective bargaining agreements. The mandatory contributions are made each pay period on behalf of each eligible employee. Participants may direct the investment of their contributions and all employer contributions, including discretionary contributions, into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. The total amount charged to expense for our Savings Plan was $11.7 million during 2007, $10.2 million during 2006, and $7.9 million during 2005.

           Employer contributions for employees vest on the second anniversary of the date of hire. Effective October 1, 2005, for new employees of our Terminals segment, a tiered employer contribution schedule was implemented. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for services between two and five years, and 4% for service of five years or more. All employer contributions for Terminals employees hired after October 1, 2005 vest on the fifth anniversary of the date of hire (effective January 1, 2008, this five year anniversary date for Terminals employees was changed to three years to comply with changes in federal regulations).

          At its July 2007 meeting, the compensation committee of the KMR board of directors approved a special contribution of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2007 and continuing through the last pay period of July 2008. The additional 1% contribution does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive and it will vest according to the same vesting schedule described in the preceding paragraph. Since this additional 1% company contribution is discretionary, compensation committee approval will be required annually for each additional contribution. During the first quarter of 2008, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2007.

          Additionally, in 2006, an option to make after-tax “Roth” contributions (Roth 401(k) option) to a separate participant account was added to the Savings Plan as an additional benefit to all participants. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option, and (ii) attainment of age 59 ½, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.

          Cash Balance Retirement Plan

          Employees of KMGP Services Company, Inc. and Knight are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, “grandfathered” according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement.

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11. Partners’ Capital

          Limited Partner Units

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

	December 31, 2007		December 31, 2006
Common units		170,220,396		162,816,303
Class B units		5,313,400		5,313,400
i-units		72,432,482		62,301,676
Total limited partner units		247,966,278		230,431,379

          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 December 31, 2007, our common unit total consisted of 155,864,661 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 common unit total 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 December 31, 2007 and December 31, 2006, all of our 5,313,400 Class B units were held entirely 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 December 31, 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. In accordance with its limited liability company agreement, KMR’s activities are restricted to being a limited partner in us, and to controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR’s limited liability company agreement, the number of outstanding KMR shares and the number of i-units will at all times be equal.

          Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common unit.

          The cash equivalent of distributions of i-units will be treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We will not distribute the cash to the holders of our i-units but will instead retain the cash for use in our business. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, KMR received a distribution of 1,258,778 i-units on November 14, 2007. These additional i-units distributed were based on the $0.88 per unit distributed to our common unitholders on that date. During the year ended December 31, 2007, KMR received distributions of 4,430,806 i-units. These additional i-units distributed were based on the $3.39 per unit distributed to our common unitholders during 2007. During 2006, KMR received distributions of 4,383,303 i-units, based on the $3.23 per unit distributed to our common unitholders during 2006.

          Equity Issuances

          In August 2006, we issued, in a public offering, 5,750,000 of our common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $44.80 per unit, less commissions and underwriting

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expenses. We received net proceeds of approximately $248.0 million for the issuance of these 5,750,000 common units.

          On May 17, 2007, KMR issued 5,700,000 of its shares in a public offering at a price of $52.26 per share. 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.

          On December 5, 2007, we issued, in a public offering, 7,130,000 of our common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $48.09 per unit, less commissions and underwriting expenses. We received net proceeds of $342.9 million for the issuance of these 7,130,000 common units.

          We used the proceeds from each of these three issuances to reduce the borrowings under our commercial paper program. In addition, pursuant to our purchase and sale agreement with Trans-Global Solutions, Inc., we issued 266,813 common units in May 2007 to TGS to settle a purchase price liability related to our acquisition of bulk terminal operations from TGS in April 2005. As agreed between TGS and us, the units were issued equal to a value of $15.0 million.

          In addition, on February 12, 2008, we completed an offering of 1,080,000 of our common units at a price of $55.65 per unit in a privately negotiated transaction. We received net proceeds of $60.1 million for the issuance of these 1,080,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

          Income Allocation and Declared Distributions

          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, according to the provisions of our partnership agreement. For the years ended December 31, 2007, 2006 and 2005, we declared distributions of $3.48, $3.26 and $3.13 per unit, respectively. Under the terms of our partnership agreement, our total distributions to unitholders for 2007, 2006 and 2005 required incentive distributions to our general partner in the amount of $611.9 million, $528.4 million and $473.9 million, respectively. The increased incentive distributions paid for 2007 over 2006, and 2006 over 2005 reflect the increases in amounts distributed per unit as well as the issuance of additional units. Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.

          Fourth Quarter 2006 Incentive Distribution Waiver

          According to the provisions of the Knight Annual Incentive Plan, in order for the executive officers of our general partner and KMR, and for the employees of KMGP Services Company, Inc. and Knight who operate our business to earn a non-equity cash incentive (bonus) for 2006, both we and Knight were required to meet pre-established financial performance targets. The target for us was $3.28 in cash distributions per common unit for 2006. Due to the fact that we did not meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan; however, at its January 17, 2007 board meeting, the board of directors of KMI (now Knight) determined that it was in KMI’s long-term interest to fund a partial payout of our bonuses through a reduction in our general partner’s incentive distribution.

          Accordingly, our general partner, with the approval of the compensation committees and boards of KMI and KMR, waived $20.1 million of its 2006 incentive distribution for the fourth quarter of 2006. The waived amount approximated an amount equal to our actual bonus payout for 2006, which was approximately 75% of our budgeted full bonus payout for 2006 of $26.5 million. Including the effect of this waiver, our distributions to unitholders for

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2006 resulted in payments of incentive distributions to our general partner in the amount of $508.3 million. The waiver of $20.1 million of incentive payment in the fourth quarter of 2006 reduced our general partner’s equity earnings by $19.9 million.

          Fourth Quarter 2007 Incentive Distribution

          On January 16, 2008, we declared a cash distribution of $0.92 per unit for the quarterly period ended December 31, 2007. This distribution was paid on February 14, 2008, to unitholders of record as of January 31, 2008. Our common unitholders and Class B unitholders received cash. KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $0.92 distribution per common unit. The number of i-units distributed was 1,253,951. For each outstanding i-unit that KMR held, a fraction of an i-unit (0.017312) was issued. The fraction was determined by dividing:

	•	$0.92, the cash amount distributed per common unit
by
	•	$53.143, the average of KMR’s limited liability shares’ closing market prices from January 14-28, 2008, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.

          This February 14, 2008 distribution included an incentive distribution to our general partner in the amount of $170.3 million. Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2007 balance sheet as a distribution payable.

12. Related Party Transactions

          General and Administrative Expenses

          KMGP Services Company, Inc., a subsidiary of our general partner, provides employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides centralized payroll and employee benefits services to (i) us; (ii) our operating partnerships and subsidiaries; (iii) our general partner; and (iv) KMR (collectively, the “Group”). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of Knight, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to our limited partnership agreement, we provide reimbursement for our share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, we reimburse KMR with respect to costs incurred or allocated to KMR in accordance with our limited partnership agreement, the delegation of control agreement among our general partner, KMR, us and others, and KMR’s limited liability company agreement.

          The named executive officers of our general partner and KMR and other employees that provide management or services to both Knight and the Group are employed by Knight. Additionally, other Knight employees assist in the operation of our Natural Gas Pipeline assets. These Knight employees’ expenses are allocated without a profit component between Knight and the appropriate members of the Group.

          Additionally, in accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize compensation expense in connection with their Class A-1 and Class B units over the expected life of such units. As a subsidiary of Knight Holdco LLC, we are allocated a portion of this compensation expense, although we have no obligation nor do we expect to pay any of these costs.

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          Partnership Interests and Distributions

          Kinder Morgan G.P., Inc.

          Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to our partnership agreement, our general partner’s interests represent a 1% ownership interest in us, and a direct 1.0101% ownership interest in each of our five operating partnerships. Collectively, our general partner owns an effective 2% interest in our operating partnerships, excluding incentive distributions rights as follows:

• its 1.0101% direct general partner ownership interest (accounted for as minority interest in our consolidated financial statements); and

• its 0.9899% ownership interest indirectly owned via its 1% ownership interest in us.

          As of December 31, 2007, our general partner owned 1,724,000 common units, representing approximately 0.70% of our outstanding limited partner units.

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

          Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

          Our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units. We do not distribute cash to i-unit owners but retain the cash for use in our business. However, the cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to our general partner. Each time we make a distribution, the number of i-units owned by KMR and the percentage of our total units owned by KMR increase automatically under the provisions of our partnership agreement.

          Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets.

          Available cash for each quarter is distributed:

• first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;

• second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;

• third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and

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• fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, and 50% to our general partner.

          For more information on incentive distributions paid to our general partner, see Note 11 “—Income Allocation and Declared Distributions.”

          Knight Inc.

          Knight Inc. remains the sole indirect stockholder of our general partner. Also, as of December 31, 2007, Knight directly owned 8,838,095 common units, indirectly owned 5,313,400 Class B units and 5,517,640 common units through its consolidated affiliates, including our general partner, and owned 10,334,746 KMR shares, representing an indirect ownership interest of 10,334,746 i-units. Together, these units represented approximately 12.1% of our outstanding limited partner units. Including both its general and limited partner interests in us, at the 2007 distribution level, Knight received approximately 49% of all quarterly distributions from us, of which approximately 43% was attributable to its general partner interest and the remaining 6% was attributable to its limited partner interest. The actual level of distributions Knight will receive in the future will vary with the level of distributions to our limited partners determined in accordance with our partnership agreement.

          Kinder Morgan Management, LLC

          As of December 31, 2007, KMR, our general partner’s delegate, remained the sole owner of our 72,432,482 i-units.

          Asset Acquisitions and Sales

          From time to time in the ordinary course of business, we buy and sell pipeline and related services from Knight and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with our policies governing such transactions. 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 ownership interest in TransColorado Gas Transmission Company LLC from two wholly-owned subsidiaries of Knight on November 1, 2004, Knight agreed to indemnify us and our general partner 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.

          Operations

          Natural Gas Pipelines Business Segment

          Knight or its subsidiaries operate and maintain for us the assets comprising our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of Knight, operates Trailblazer Pipeline Company LLC’s assets under a long-term contract pursuant to which Trailblazer Pipeline Company LLC incurs the costs and expenses related to NGPL’s operating and maintaining the assets. Trailblazer Pipeline Company LLC provides the funds for its own capital expenditures. NGPL does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company LLC’s assets.

          The remaining assets comprising our Natural Gas Pipelines business segment as well as our Cypress Pipeline (and our North System until its sale in October 2007, described in Note 3), which is part of our Products Pipelines business segment, are operated under other agreements between Knight and us. Pursuant to the applicable underlying agreements, we pay Knight either a fixed amount or actual costs incurred as reimbursement for the corporate general and administrative expenses incurred in connection with the operation of these assets. The amounts paid to Knight for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company LLC, were $1.0 million of fixed costs and $48.1 million of actual costs incurred for 2007, $1.0 million of fixed costs and $37.9 million of actual costs incurred for 2006, and $5.5 million of fixed costs and $24.2 million of actual costs incurred for 2005.

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          We believe the amounts paid to Knight for the services they provided each year fairly reflect the value of the services performed. However, due to the nature of the allocations, these reimbursements may not exactly match the actual time and overhead spent. We believe the fixed amounts that were agreed upon at the time the contracts were entered into were reasonable estimates of the corporate general and administrative expenses to be incurred by Knight and its subsidiaries in performing such services. We also reimburse Knight and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to our assets.

          CO₂ Business Segment

          Knight or its subsidiaries operate and maintain for us the power plant we constructed at the SACROC oil field unit, located in the Permian Basin area of West Texas. The power plant provides approximately half of SACROC’s current electricity needs. Kinder Morgan Power Company, a subsidiary of Knight, operates and maintains the power plant under a five-year contract expiring in June 2010. Pursuant to the contract, Knight incurs the costs and expenses related to operating and maintaining the power plant for the production of electrical energy at the SACROC field. Such costs include supervisory personnel and qualified operating and maintenance personnel in sufficient numbers to accomplish the services provided in accordance with good engineering, operating and maintenance practices. Kinder Morgan Production Company fully reimburses Knight’s expenses, including all agreed-upon labor costs, and also pays to Knight an operating fee of $20,000 per month.

          In addition, Kinder Morgan Production Company is responsible for processing and directly paying invoices for fuels utilized by the plant. Other materials, including but not limited to lubrication oil, hydraulic oils, chemicals, ammonia and any catalyst are purchased by Knight and invoiced monthly as provided by the contract, if not paid directly by Kinder Morgan Production Company. The amounts paid to Knight in 2007 and 2006 for operating and maintaining the power plant were $3.1 million and $2.9 million, respectively. Furthermore, we believe the amounts paid to Knight for the services they provide each year fairly reflect the value of the services performed.

          Risk Management

          Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. We also have exposure to interest rate risk as a result of the issuance of our fixed rate debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to these risks and protect our profit margins, and we are prohibited from engaging in speculative trading.

          Our commodity-related risk management activities are monitored by our risk management committee, which is a separately designated standing committee whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Our risk management committee is charged with the review and enforcement of our management’s risk management policy. The committee is comprised of 19 executive-level employees of Knight or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of our businesses. The committee is chaired by our President and is charged with the following three responsibilities: (i) establish and review risk limits consistent with our risk tolerance philosophy; (ii) recommend to the audit committee of our general partner’s delegate any changes, modifications, or amendments to our risk management policy; and (iii) address and resolve any other high-level risk management issues.

          In addition, 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 also 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

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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 December 31, 2007 (in millions):

Derivatives-net asset/(liability)
Accrued other current liabilities	$ (239.8)
Other long-term liabilities and deferred credits	$ (386.5)

          For more information on our risk management activities see Note 14.

          KM Insurance, Ltd.

          KM Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and wholly-owned subsidiary of Knight. KMIL was formed during the second quarter of 2005 as a Class 2 Bermuda insurance company, the sole business of which is to issue policies for Knight and us to secure the deductible portion of our workers compensation, automobile liability, and general liability policies placed in the commercial insurance market. We accrue for the cost of insurance, which is included in the related party general and administrative expenses and which totaled approximately $3.6 million in 2007 and $5.8 million in 2006.

          Notes Receivable

          Plantation Pipe Line Company

          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 $89.7 million and $93.1 million as of December 31, 2007 and December 31, 2006, respectively. Of these amounts, $2.4 million and $3.4 million were included within “Accounts, notes and interest receivable, net—Related parties” as of December 31, 2007 and December 31, 2006, respectively, and the remainder was included within “Notes receivable—Related parties” at each reporting date.

          Knight Inc.

          As of December 31, 2007, an affiliate of Knight owed to us a long-term note with a principal amount of $0.6 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 which became an affiliate of ours in 2007), 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 within the caption “Changes in components of working capital: Accounts Receivable” in the operating section of our accompanying consolidated statement of cash flows.

          Coyote Gas Treating, LLC

          Coyote Gas Treating, LLC is a joint venture that was organized in December 1996. It is referred to as Coyote Gulch in this report. The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. Prior to the contribution of our ownership interest in Coyote Gulch to

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Red Cedar Gathering on September 1, 2006, we were the managing partner and owned a 50% equity interest in Coyote Gulch.

          As of January 1, 2006, we had a $17.0 million note receivable from Coyote Gulch. The term of the note was month-to-month. In March 2006, the owners of Coyote Gulch agreed to transfer Coyote Gulch’s notes payable to members’ equity. Accordingly, we contributed the principal amount of $17.0 million related to our note receivable to our equity investment in Coyote Gulch.

          On September 1, 2006, we and the Southern Ute Tribe (owners of the remaining 50% interest in Coyote Gulch) agreed to transfer all of the members’ equity in Coyote Gulch to the members’ equity of Red Cedar Gathering Company, a joint venture organized in August 1994. Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado, and is owned 49% by us and 51% by the Southern Ute Tribe. Under the terms of a five-year operating lease agreement that became effective January 1, 2002, Red Cedar also operates the gas treating facility owned by Coyote Gulch and is responsible for all operating and maintenance expenses and capital costs.

          Accordingly, on September 1, 2006, we and the Southern Ute Tribe contributed the value of our respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a result, Coyote Gulch became a wholly owned subsidiary of Red Cedar. The value of our 50% equity contribution from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7 million, and this amount remains included within “Investments” on our consolidated balance sheet as of December 31, 2007.

          Other

          Generally, KMR makes all decisions relating to the management and control of our business. Our general partner owns all of KMR’s voting securities and is its sole managing member. Knight, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner. Certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, Knight and us. The officers of Knight have fiduciary duties to manage Knight, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to themselves. In general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders. The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

          The partnership agreements provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. The duty of the officers of Knight may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The audit committee of KMR’s board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between Knight or its subsidiaries, on the one hand, and us, on the other hand.

13. Leases and Commitments

          Capital Leases

          We acquired certain leases classified as capital leases as part of our acquisition of Kinder Morgan River Terminals LLC in October 2004. We lease our Memphis, Tennessee port facility under an agreement accounted for as a capital lease. The lease is for 24 years and expires in 2017.

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          Amortization of assets recorded under capital leases is included with depreciation expense. The components of property, plant and equipment recorded under capital leases are as follows (in millions):

	December 31, 2007				December 31, 2006
Leasehold improvements		$	2.2			$	2.2
Less: Accumulated amortization			(0.3	)			(0.2	)
Total		$	1.9			$	2.0

          Future commitments under capital lease obligations as of December 31, 2007 are as follows (in millions):

Year	Commitment
2008		$	0.2
2009			0.2
2010			0.2
2011			0.2
2012			0.2
Thereafter			0.6
Subtotal			1.6
Less: Amount representing interest			(0.6	)
Present value of minimum capital lease payments		$	1.0

          Operating Leases

          Including probable elections to exercise renewal options, the remaining terms on our operating leases range from one to 61 years. Future commitments related to these leases as of December 31, 2007 are as follows (in millions):

Year	Commitment
2008		$	31.5
2009			22.8
2010			19.5
2011			15.6
2012			12.1
Thereafter			27.6
Total minimum payments		$	129.1

          The largest of these lease commitments, in terms of total obligations payable by December 31, 2008, include commitments supporting: (i) crude oil drilling rig operations for the oil and gas activities of our CO₂ business segment; (ii) marine port terminal operations at our Nassau bulk product terminal, located in Fernandina Beach, Florida; and (iii) natural gas storage in underground salt dome caverns for our Texas intrastate natural gas pipeline group.

          We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $2.0 million. Total lease and rental expenses were $49.2 million for 2007, $54.2 million for 2006 and $47.3 million for 2005.

          Common Unit Option Plan

          During 1998, we established a common unit option plan, which provides that key personnel of KMGP Services Company, Inc. and Knight are eligible to receive grants of options to acquire common units. The number of common units authorized under the option plan is 500,000. The option plan terminates in March 2008. The options granted generally have a term of seven years, vest 40% on the first anniversary of the date of grant and 20% on each of the next three anniversaries, and have exercise prices equal to the market price of the common units at the grant date.

          As of January 1, 2006, outstanding options to purchase 15,300 common units were held by employees of Knight or KMGP Services Company, Inc. at an average exercise price of $17.82 per unit. Outstanding options to purchase 10,000 common units were held by one of our general partner’s three non-employee directors at an average exercise

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price of $21.44 per unit. All 25,300 outstanding options were fully vested. During 2006, 4,200 options to purchase common units were cancelled or forfeited, and 21,100 options to purchase common units were exercised at an

average price of $19.67 per unit. The common units underlying these options had an average fair market value of $46.43 per unit. Accordingly, as of December 31, 2006 and 2007, there were no outstanding options.

          We account for common unit options granted under our common unit option plan according to the provisions of SFAS No. 123R (revised 2004), “Share-Based Payment,” which became effective for us January 1, 2006. This Statement amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and requires companies to expense the value of employee stock options and similar awards. According to the provisions of SFAS No. 123R, share-based payment awards result in a cost that will be measured at fair value on the awards’ grant date, based on the estimated number of awards that are expected to vest. Companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects, and compensation cost for awards that vest would not be reversed if the awards expire without being exercised.

          However, we have not granted common unit options or made any other share-based payment awards since May 2000, and as described above, all outstanding options to purchase our common units were fully vested as of January 1, 2006. Therefore, the adoption of this Statement did not have an effect on our consolidated financial statements due to the fact that we had reached the end of the requisite service period for any compensation cost resulting from share-based payments made under our common unit option plan.

          Directors’ Unit Appreciation Rights Plan

           On April 1, 2003, KMR’s compensation committee established our Directors’ Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR’s three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement.

          All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised.

          On April 1, 2003, the date of adoption of the plan, each of KMR’s three non-employee directors were granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of KMR’s three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors. All unexercised awards made under our Directors’ Unit Appreciation Rights Plan remain outstanding.

          No unit appreciation rights were exercised during 2006. During 2007, 7,500 unit appreciation rights were exercised by one director at an aggregate fair value of $53.00 per unit. As of December 31, 2007, 45,000 unit appreciation rights had been granted, vested and remained outstanding.

          Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors

           On January 18, 2005, KMR’s compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan. The plan is administered by KMR’s compensation committee and KMR’s board has sole discretion to terminate the plan at any time. The primary purpose of this plan was to promote our interests

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and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders’ interests. Further, since KMR’s success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR’s shareholders.

          The plan recognizes that the compensation to be paid to each non-employee director is fixed by the KMR board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. Each election is made generally at or around the first board meeting in January of each calendar year and is effective for the entire calendar year. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000.

          The initial election under this plan for service in 2005 was made effective January 20, 2005. The elections for 2006, 2007 and 2008 were made effective January 17, 2006, January 17, 2007 and January 16, 2008, respectively. Each annual election is evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement contains the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the director’s service as a director of KMR is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director will, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have lapsed cease to be subject to any forfeiture restrictions, and we will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director has the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions.

          The number of common units to be issued to a non-employee director electing to receive the cash compensation in the form of common units will equal the amount of such cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the cash compensation in the form of common units will receive cash equal to the difference between (i) the cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment is payable in four equal installments generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded.

          On January 18, 2005, the date of adoption of the plan, each of KMR’s three non-employee directors was awarded cash compensation of $119,750 for board service during 2005. Effective January 20, 2005, each non-employee director elected to receive compensation of $79,750 in the form of our common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $45.55 closing market price of our common units on January 18, 2005, as reported on the New York Stock Exchange). Also, consistent with the plan, the remaining $40,000 cash compensation and the $37.50 of cash compensation that did not equate to a whole common unit, based on the January 18, 2005 $45.55 closing price, was paid to each of the non-employee directors as described above. No other compensation was paid to the non-employee directors during 2005.

          On January 17, 2006, each of KMR’s three non-employee directors was awarded cash compensation of $160,000 for board service during 2006. Effective January 17, 2006, each non-employee director elected to receive compensation of $87,780 in the form of our common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $50.16 closing market price of our common units on January 17, 2006, as reported on the New York Stock Exchange). The remaining $72,220 cash compensation was paid to each of the non-employee directors as described above. No other compensation was paid to the non-employee directors during 2006.

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          On January 17, 2007, each of KMR’s three non-employee directors was awarded cash compensation of $160,000 for board service during 2007. Effective January 17, 2007, each non-employee director elected to receive certain amounts of compensation in the form of our common units and each were issued common units pursuant to the plan and its agreements (based on the $48.44 closing market price of our common units on January 17, 2007, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive compensation of $95,911.20 in the form of our common units and was issued 1,980 common units; Mr. Waughtal elected to receive compensation of $159,852.00 in the form of our common units and was issued 3,300 common units; and Mr. Hultquist elected to receive compensation of $96,880.00 in the form of our common units and was issued 2,000 common units. All remaining cash compensation ($64,088.80 to Mr. Gaylord; $148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) was paid to each of the non-employee directors as described above, and no other compensation was paid to the non-employee directors during 2007.

          On January 16, 2008, each of KMR’s three non-employee directors was awarded cash compensation of $160,000 for board service during 2008; however, during a plan audit it was determined that each director was inadvertently paid an additional dividend in 2007. As a result, each director’s cash compensation for service during 2008 was adjusted downward to reflect this error. The correction results in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr. Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal. Effective January 16, 2008, two of the three non-employee directors elected to receive certain amounts of compensation in the form of our common units and each was issued common units pursuant to the plan and its agreements (based on the $55.81 closing market price of our common units on January 16, 2008, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive compensation of $84,831.20 in the form of our common units and was issued 1,520 common units; and Mr. Waughtal elected to receive compensation of $157,272.58 in the form of our common units and was issued 2,818 common units. All remaining cash compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00 to Mr. Hultquist) will be paid to each of the non-employee directors as described above, and no other compensation will be paid to the non-employee directors during 2008.

14. Risk Management

          Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil. We also have exposure to interest rate risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks, and we account for these hedging transactions according to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and associated amendments, collectively, SFAS No. 133.

          Energy Commodity Price Risk Management

          We are exposed to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil as a result of the forecasted purchase or sale of these products. Specifically, these risks are associated with unfavorable price volatility related to (i) pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas purchases; and (iii) natural gas system use and storage.

          Given our portfolio of businesses as of December 31, 2007, our principal use of energy commodity derivative contracts was to mitigate the risk associated with market movements in the price of energy commodities. The unfavorable price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations. Our energy commodity derivative contracts act as a hedging (offset) mechanism against the volatility of energy commodity prices by allowing us to transfer this price risk to counterparties who are able and willing to bear it.

          Hedging effectiveness and ineffectiveness

          Pursuant to SFAS No. 133, our energy commodity derivative contracts are designated as cash flow hedges and for cash flow hedges, the portion of the change in the value of derivative contracts that is effective in offsetting undesired changes in expected cash flows (the effective portion) is reported as a component of other comprehensive

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income (outside current earnings, net income), but only to the extent that they can later offset the undesired changes in expected cash flows during the period in which the hedged cash flows affect earnings. To the contrary, the portion of the change in the value of derivative contracts that is not effective in offsetting undesired changes in expected cash flows (the ineffective portion), as well as any component excluded from the computation of the effectiveness of the derivative contracts, is required to be recognized currently in earnings. 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 during 2007, a loss of $1.3 million during 2006 and a loss of $0.6 million during 2005, respectively. These recognized 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 years ended 2007, 2006 and 2005, we did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness.

          During the years 2007, 2006 and 2005, we reclassified $433.2 million, $428.1 million and $424.0 million, respectively, of “Accumulated other comprehensive loss” into earnings. With the exception of (i) an approximate $0.1 million loss reclassified in the first quarter of 2007; and (ii) a $2.9 million loss resulting from the discontinuance of cash flow hedges related to the sale of our Douglas gathering assets in 2006 (described in Note 3), none of the reclassification of “Accumulated other comprehensive loss” into earnings during 2007, 2006 or 2005 resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred).

          Our consolidated “Accumulated other comprehensive loss” balance was $1,276.6 million as of December 31, 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 $1,377.2 million as of December 31, 2007 and $838.7 million as of December 31, 2006. Approximately $553.3 million of this total accumulated loss associated with our commodity price risk management activities as of December 31, 2007 is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur).

          Fair Value of Energy Commodity Derivative Contracts

          The fair values of the energy commodity derivative contracts we use, including commodity futures and options contracts, fixed price swaps, and basis swaps 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 December 31, 2007 and December 31, 2006 (in millions):

	December 31, 2007				December 31, 2006
Derivatives-net asset/(liability)
Other current assets		$	37.0			$	91.9
Deferred charges and other assets			4.4				12.7
Accrued other current liabilities			(593.9	)			(431.4	)
Other long-term liabilities and deferred credits		$	(836.8	)		$	(510.2	)

          As of December 31, 2007, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with commodity price risk is through December 2012.

          Credit Risks

          We have counterparty credit risk as a result of our use of energy commodity derivative contracts. Our over-the-counter swaps and options are contracts we entered into with counterparties outside centralized trading facilities such as a futures, options or stock exchange. These contracts are with a number of parties, all of which had investment grade credit ratings as of December 31, 2007. We both owe money and are owed money under these

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derivative contracts. While we enter into derivative contracts principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

          Additionally, 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 December 31, 2007 and December 31, 2006, we had three outstanding letters of credit totaling $298.0 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.

          As of December 31, 2007, we had cash margin deposits associated with our commodity contract positions and over-the-counter swap partners totaling $67.9 million, and we reported this amount as “Restricted deposits” in our accompanying consolidated balance sheet as of December 31, 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.

          Interest Rate Risk Management

          In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. 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 December 31, 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. In February 2007, we entered into additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $600 million. These swap agreements were related to the $600 million of 5.95% senior notes we issued on February 12, 2008, and have a maturity date of February 15, 2018.

          All of our interest rate swap agreements have a termination date that corresponds to the maturity date of one of our series of senior notes and, as of December 31, 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. In addition, certain of our swap agreements contain mutual cash-out provisions that allow us or our counterparties to settle the agreement at certain future dates before maturity based on the then-economic value of the swap agreement.

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          Hedging effectiveness and ineffectiveness

          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.

          Fair Value of Interest Rate Swap Agreements

          The fair values of our interest rate swap agreements 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 December 31, 2007, this unamortized premium totaled $14.2 million, representing the unamortized proceeds we received from the swap agreement we terminated in the first quarter of 2007.

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

	December 31, 2007			December 31, 2006
Derivatives-net asset/(liability)
Deferred charges and other assets		$	138.0		$	65.2
Other long-term liabilities and deferred credits			—			(22.6	)
Net fair value of interest rate swaps		$	138.0		$	42.6

          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 December 31, 2007, all of our interest rate swap agreements were with counterparties with investment grade credit ratings.

          Other

          Certain of our business activities expose us to foreign currency fluctuations. However, due to the limited size of this exposure, we do not believe the risks associated with changes in foreign currency will have a material adverse effect on our business, financial position, results of operations or cash flows. As a result, we do not significantly hedge our exposure to fluctuations in foreign currency.

15. Reportable Segments

          We divide our operations into five reportable business segments:

• Products Pipelines;

• Natural Gas Pipelines;

• CO₂;

• Terminals; and

• Trans Mountain.

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          Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2). We evaluate performance principally based on each segments’ earnings before depreciation, depletion and amortization, which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income and income tax expense, and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies.

          Our Products Pipelines segment derives its revenues primarily from the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the sale, transport, processing, treating, 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 3, due to the sale of our North System, an approximate 1,600-mile interstate common carrier pipeline system whose operating results were 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 results 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.

          Financial information by segment follows (in millions):

	2007			2006			2005
Revenues
Products Pipelines
Revenues from external customers	$	844.4		$	776.3		$	711.8
Intersegment revenues		—			—			—
Natural Gas Pipelines
Revenues from external customers		6,466.5			6,577.7			7,718.4
Intersegment revenues		—			—			—
CO2
Revenues from external customers		824.1			736.5			657.6
Intersegment revenues		—			—			—
Terminals
Revenues from external customers		963.0			864.1			699.3
Intersegment revenues		0.7			0.7			—
Trans Mountain
Revenues from external customers		160.8			137.8			—
Intersegment revenues		—			—			—
Total segment revenues		9,259.5			9,093.1			9,787.1
Less: Total intersegment revenues		(0.7	)		(0.7	)		—
		9,258.8			9,092.4			9,787.1
Less: Discontinued operations		(41.1	)		(43.7	)		(41.2	)
Total consolidated revenues	$	9,217.7		$	9,048.7		$	9,745.9

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	2007			2006			2005
Operating expenses(a)
Products Pipelines	$	451.8		$	308.3		$	366.0
Natural Gas Pipelines		5,882.9			6,057.8			7,255.0
CO2		304.2			268.1			212.6
Terminals		536.4			461.9			373.4
Trans Mountain		65.9			53.3			—
Total segment operating expenses		7,241.2			7,149.4			8,207.0
Less: Total intersegment operating expenses		(0.7	)		(0.7	)		—
		7,240.5			7,148.7			8,207.0
Less: Discontinued operations		(14.8	)		(22.7	)		(35.2	)
Total consolidated operating expenses	$	7,225.7		$	7,126.0		$	8,171.8
Other expense (income)
Products Pipelines	$	(154.8	)	$	—		$	—
Natural Gas Pipelines		(3.2	)		(15.1	)		—
CO2		—			—			—
Terminals		(6.3	)		(15.2	)		—
Trans Mountain(b)		377.1			(0.9	)		—
Total segment Other expense (income)		212.8			(31.2	)		—
Less: Discontinued operations		152.8			—			—
Total consolidated Other expense (income)	$	365.6		$	(31.2	)	$	—
Depreciation, depletion and amortization
Products Pipelines	$	89.2		$	82.9		$	79.1
Natural Gas Pipelines		64.8			65.4			61.7
CO2		282.2			190.9			149.9
Terminals		89.3			74.6			59.1
Trans Mountain		21.5			19.0			—
Total segment depreciation, depletion and amortiz.		547.0			432.8			349.8
Less: Discontinued operations		(7.0	)		(8.9	)		(8.2	)
Total consol. depreciation, depletion and amortiz.	$	540.0		$	423.9		$	341.6
Earnings from equity investments
Products Pipelines	$	32.5		$	16.3		$	28.5
Natural Gas Pipelines		19.2			40.5			36.8
CO2		19.2			19.2			26.3
Terminals		0.6			0.2			0.1
Trans Mountain		—			—			—
Total segment earnings from equity investments		71.5			76.2			91.7
Less: Discontinued operations		(1.8	)		(2.2	)		(2.1	)
Total consolidated equity earnings	$	69.7		$	74.0		$	89.6
Amortization of excess cost of equity investments
Products Pipelines	$	3.4		$	3.4		$	3.4
Natural Gas Pipelines		0.4			0.3			0.2
CO2		2.0			2.0			2.0
Terminals		—			—			—
Trans Mountain		—			—			—
Total segment amortization of excess cost of invests.		5.8			5.7			5.6
Less: Discontinued operations		—			(0.1	)		(0.1	)
Total consol. amortization of excess cost of invests.	$	5.8		$	5.6		$	5.5
Interest income
Products Pipelines	$	4.4		$	4.5		$	4.6
Natural Gas Pipelines		—			0.1			0.7
CO2		—			—			—
Terminals		—			—			—
Trans Mountain		—			—			—
Total segment interest income		4.4			4.6			5.3
Unallocated interest income		1.3			3.1			4.1
Total consolidated interest income	$	5.7		$	7.7		$	9.4

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	2007			2006			2005
Other, net-income (expense)
Products Pipelines	$	5.0		$	7.6		$	1.5
Natural Gas Pipelines		0.2			0.6			2.0
CO2		—			0.8			—
Terminals		1.0			2.1			(0.2	)
Trans Mountain		8.0			1.0			—
Total segment other, net-income (expense)		14.2			12.1			3.3
Less: Discontinued operations		—			(0.1	)		—
Total consolidated other, net-income (expense)	$	14.2		$	12.0		$	3.3
Income tax benefit (expense)
Products Pipelines	$	(19.7	)	$	(5.2	)	$	(10.3	)
Natural Gas Pipelines		(6.0	)		(1.4	)		(2.6	)
CO2		(2.1	)		(0.2	)		(0.4	)
Terminals		(19.2	)		(12.3	)		(11.2	)
Trans Mountain		(19.4	)		(9.9	)		—
Total segment income tax benefit (expense)		(66.4	)		(29.0	)		(24.5	)
Unallocated income tax benefit (expense)		(4.6	)		—			—
Total consolidated income tax benefit (expense)	$	(71.0	)	$	(29.0	)	$	(24.5	)
Segment earnings(c)
Products Pipelines	$	477.0		$	404.9		$	287.6
Natural Gas Pipelines		535.0			509.1			438.4
CO2		252.8			295.3			319.0
Terminals		326.7			333.5			255.5
Trans Mountain		(315.1	)		57.5			—
Total segment earnings		1,276.4			1,600.3			1,300.5
Interest and corporate administrative expenses(d)		(686.1	)		(596.2	)		(488.3	)
Total consolidated net income	$	590.3		$	1,004.1		$	812.2
Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(e)
Products Pipelines	$	569.6		$	491.2		$	370.1
Natural Gas Pipelines		600.2			574.8			500.3
CO2		537.0			488.2			470.9
Terminals		416.0			408.1			314.6
Trans Mountain		(293.6	)		76.5			—
Total segment earnings before DD&A		1,829.2			2,038.8			1,655.9
Total segment depreciation, depletion and amortiz.		(547.0	)		(432.8	)		(349.8	)
Total segment amortization of excess cost of invests.		(5.8	)		(5.7	)		(5.6	)
Interest and corporate administrative expenses		(686.1	)		(596.2	)		(488.3	)
Total consolidated net income	$	590.3		$	1,004.1		$	812.2
Capital expenditures(f)
Products Pipelines	$	259.4		$	196.0		$	271.5
Natural Gas Pipelines		264.0			271.6			102.9
CO2		382.5			283.0			302.1
Terminals		480.0			307.7			186.6
Trans Mountain		305.7			123.8			—
Total consolidated capital expenditures	$	1,691.6		$	1,182.1		$	863.1
Investments at December 31
Products Pipelines	$	202.3		$	211.1		$	223.7
Natural Gas Pipelines		427.5			197.9			177.1
CO2		14.2			16.1			17.9
Terminals		10.6			0.5			0.6
Trans Mountain		0.8			0.7			—
Total consolidated investments	$	655.4		$	426.3		$	419.3

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	2007		2006		2005
Assets at December 31
Products Pipelines	$	4,045.0	$	3,910.5	$	3,873.9
Natural Gas Pipelines		4,347.3		3,946.6		4,140.0
CO2		2,004.5		1,870.8		1,772.8
Terminals		3,036.4		2,397.5		2,052.5
Trans Mountain		1,440.8		1,314.0		—
Total segment assets		14,874.0		13,439.4		11,839.2
Corporate assets(g)		303.8		102.8		84.3
Total consolidated assets	$	15,177.8	$	13,542.2	$	11,923.5

(a)	Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes.
(b)	2007 amount represents an expense of $377.1 million attributable to a goodwill impairment charge recognized by Knight, as discussed in Notes 3 and 8.
(c)	Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, other expense (income), depreciation, depletion and amortization, and amortization of excess cost of equity investments.
(d)	Includes unallocated interest income and income tax expense, interest and debt expense, general and administrative expenses, and minority interest expense.
(e)	Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(f)	Includes sustaining capital expenditures of $152.6 million in 2007 (not including Trans Mountain for periods prior to our acquisition date of April 30, 2007), $125.5 million in 2006 (not including Trans Mountain) and $140.8 million in 2005. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.
(g)	Includes cash and cash equivalents, margin and restricted deposits, certain unallocable deferred charges, and risk management assets related to the fair value of interest rate swaps.

          We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2007, 2006 and 2005, we reported (in millions) total consolidated interest expense of $397.1 million, $345.5 million and $268.4 million, respectively.

          Our total operating revenues are derived from a wide customer base. For each of the three years ended December 31, 2007, 2006 and 2005, no revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues.

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

	2007		2006		2005
Revenues from external customers
United States	$	8,986.3	$	8,889.9	$	9,715.1
Canada		211.9		139.3		11.8
Mexico and other(a)		19.5		19.5		19.0
Total consol. revenues from external customers	$	9,217.7	$	9,048.7	$	9,745.9
Long-lived assets at December 31(b)
United States	$	11,054.3	$	9,917.2	$	9,442.8
Canada		1,420.0		766.4		48.2
Mexico and other		89.5		91.4		92.3
Total consolidated long-lived assets	$	12,563.8	$	10,775.0	$	9,583.3

(a)	Includes operations in Mexico and the Netherlands.
(b)	Long-lived assets exclude (i) goodwill; (ii) other intangibles, net; and (iii) long-term note receivables from related parties.

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16. Litigation, Environmental and Other Contingencies

          Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during 2007. This note also contains a description of any material legal proceeding initiated during 2007 in which we are involved.

          Federal Energy Regulatory Commission Proceedings

          Our SFPP, L.P. and CALNEV Pipe Line LLC subsidiaries are involved in proceedings before the Federal Energy Regulatory Commission. SFPP is the subsidiary limited partnership that owns our Pacific operations. CALNEV Pipe Line LLC and related terminals was acquired from GATX Corporation and is not part of the Pacific Operations. The tariffs and rates charged by SFPP and CALNEV 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 these pipeline systems. In general, these complaints allege the rates and tariffs charged by SFPP and CALNEV are not just and reasonable.

          As to SFPP, 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) whether indexed rate increases may become effective without investigation; (iv) the capital structure to be used in computing the “starting rate base” of our Pacific operations; (v) the level of income tax allowance we may include in our rates; and (vi) 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, and the decision is now final.

          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.

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

•	FERC Docket No. OR92-8, et al.—Complainants/Protestants: Chevron; Navajo; ARCO; BP WCP; Western Refining; ExxonMobil; Tosco; and Texaco (Ultramar is an intervenor)—Defendant: SFPP Consolidated proceeding involving shipper complaints against certain East Line and West Line rates. All five issues (and others) described four paragraphs above are involved in these proceedings. Portions of this proceeding were appealed (and re-appealed) to the D.C. Court and remanded to the FERC. BP WCP, Chevron, and ExxonMobil requested a hearing before the FERC on remanded grandfathering and income tax allowance issues. The FERC issued an Order on Rehearing, Remand, Compliance, and Tariff Filings on December 26, 2007, which denied the requests for a hearing, affirmed the income tax allowance policy and further clarified the implementation of that policy, and required SFPP to file a compliance filing;
•	FERC Docket Nos. OR92-8-028, et al.—Complainants/Protestants: BP WCP; ExxonMobil; Chevron;
	ConocoPhillips; and Ultramar—Defendant: 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.—Complainants/Protestants: All Shippers except Chevron (which is an intervenor)—Defendant: SFPP Consolidated proceeding involving shipper complaints against all SFPP rates. All five issues (and others) described four paragraphs above are involved in these proceedings. Portions of this proceeding were appealed (and re-appealed) to the D.C. Court and remanded to the FERC. The FERC issued an Order on Rehearing, Remand, Compliance, and Tariff Filings on December 26, 2007, which denied the requests for a hearing, affirmed the income tax allowance policy and further clarified the implementation of that policy, and required SFPP to file a compliance filing;
•	FERC Docket Nos. OR02-4 and OR03-5—Complainant/Protestant: Chevron—Defendant: SFPP
	Chevron initiated proceeding to permit Chevron to become complainant in OR96-2. Appealed to the D.C. Court and held in abeyance pending final disposition of the OR96-2 proceedings;
•	FERC Docket No. OR04-3—Complainants/Protestants: America West Airlines; Southwest Airlines; Northwest Airlines; and Continental Airlines—Defendant: 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. The FERC has set the complaints against the West Line rates for hearing but denied the request to consolidate the dockets with the ongoing proceedings involving SFPP’s North and Oregon Line rates;
•	FERC Docket Nos. OR03-5, OR05-4 and OR05-5—Complainants/Protestants: BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)—Defendant: SFPP Complaints allege that SFPP’s interstate rates are not just and reasonable. The FERC has set the complaints against the West and East Line rates for hearing, but denied the request to consolidate the dockets with the ongoing proceedings involving SFPP’s North and Oregon Line rates;
•	FERC Docket No. OR03-5-001—Complainants/Protestants: BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)—Defendant: 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, which has been set for hearing;
•	FERC Docket No. OR07-1—Complainant/Protestant: Tesoro—Defendant: 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;

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•	FERC Docket No. OR07-2—Complainant/Protestant: Tesoro—Defendant: 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—Complainants/Protestants: BP WCP; Chevron; ExxonMobil; Tesoro; and Valero Marketing—Defendant: SFPP Complaint alleges that SFPP’s North Line indexed rate increase was not just and reasonable. The FERC has dismissed the complaint and denied rehearing the dismissal. Petitions for review filed by BP WCP and ExxonMobil at the D.C. Court;
•	FERC Docket No. OR07-4—Complainants/Protestants: BP WCP; Chevron; and ExxonMobil—Defendants: SFPP; Kinder Morgan G.P., Inc.; and Knight 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)—Complainants/Protestants: ExxonMobil and Tesoro—Defendants: Calnev; Kinder Morgan G.P., Inc.; and Knight 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, among other things, dismissed with prejudice the complaints against Kinder Morgan GP Inc. and Knight, Inc. and allowed complainants to file amended complaints. ExxonMobil filed a request for rehearing of the dismissal of the complaints against Kinder Morgan GP, Inc. and Knight Inc., which is currently pending before the FERC. The FERC has not acted on the amended complaints;
•	FERC Docket No. OR07-6—Complainant/Protestant: ConocoPhillips—Defendant: SFPP
	Complaint alleges that SFPP’s North Line indexed rate increase was not just and reasonable. The FERC has dismissed the complaint and denied rehearing of the dismissal. The FERC had consolidated this case with OR07-3 and issued orders that applied to both OR07-3 and OR07-6. Although the FERC orders in these dockets have been appealed by certain of the complainants in OR07-3, they have not been appealed by ConocoPhillips in OR07-6;
•	FERC Docket No. OR07-8 (consolidated with Docket No. OR07-11)—Complainant/Protestant: BP WCP—Defendant: 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, which the FERC denied. On February 13, 2008, the FERC set this complaint for hearing, but referred it to settlement negotiations;
•	FERC Docket No. OR07-9—Complainant/Protestant: BP WCP—Defendant: 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 unreasonable. On July 6, 2007, the FERC dismissed the complaint. BP WCP requested rehearing, which the FERC denied. A petition for review was filed by BP WCP. The FERC’s motion to dismiss or hold the case in abeyance is pending;
•	FERC Docket No. OR07-10—Complainants/Protestants: BP WCP; ConocoPhillips; Valero; and ExxonMobil—Defendant: 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;

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•	FERC Docket No. OR07-11 (consolidated with Docket No. OR07-8)—Complainant/Protestant: ExxonMobil—Defendant: SFPP Complaint alleges that SFPP’s 2005 indexed rate increase was not just and reasonable. On February 13, 2008, the FERC set this complaint for hearing, but referred it to settlement negotiations. It is consolidated with the complaint in Docket No. OR07-8;
•	FERC Docket No. OR07-14—Complainants/Protestants: BP WCP and Chevron—Defendants: SFPP; Calnev; Operating Limited Partnership “D”; Kinder Morgan Energy Partners, L.P.; Kinder Morgan Management LLC; Kinder Morgan General Partner, Inc.; Knight 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 dismissed the complaints;
•	FERC Docket No. OR07-16—Complainant/Protestant: Tesoro—Defendant: Calnev
	Complaint challenges Calnev’s 2005, 2006, and 2007 indexing adjustments. The FERC dismissed the complaint. A petition for review was filed by Tesoro. A scheduling order for briefs and oral argument has not yet been issued by the D.C. Court;
•	FERC Docket No. OR07-18—Complainants/Protestants: Airline Complainants; Chevron; and Valero Marketing—Defendant: Calnev Complaint alleges that Calnev’s rates are unjust and unreasonable and that none of Calnev’s rates are grandfathered under EPAct 1992. In December 2007, the FERC issued an order accepting and holding in abeyance the portion of the complaint against the non-grandfathered portion of Calnev’s rates. The order also gave complainants 45 days to amend their complaint against the grandfathered portion of Calnev’s rates in light of clarifications provided in the FERC’s order;
•	FERC Docket No. OR07-19—Complainant/Protestant: ConocoPhillips—Defendant: Calnev
	Complaint alleges that Calnev’s rates are unjust and unreasonable and that none of Calnev’s rates are grandfathered under EPAct 1992. In December 2007, the FERC issued an order accepting and holding in abeyance the portion of the complaint against the non-grandfathered portion of Calnev’s rates. The order also gave complainants 45 days to amend their complaint against the grandfathered portion of Calnev’s rates in light of clarifications provided in the FERC’s order;
•	FERC Docket No. OR07-20—Complainant/Protestant: BP WCP—Defendant: SFPP
	Complaint alleges that SFPP’s 2007 indexed rate increase was not just and reasonable. In December 2007, the FERC dismissed the complaint. Complainant filed a request for rehearing which is currently pending before the FERC. In February 2008, the FERC accepted a joint offer of settlement that dismisses, with prejudice, the East Line index rate portion of the complaint in OR07-20;
•	FERC Docket No. OR07-22—Complainant/Protestant: BP WCP—Defendant: Calnev
	Complaint alleges that Calnev’s rates are unjust and unreasonable and that none of Calnev’s rates are grandfathered under EPAct 1992. In December 2007, the FERC issued an order giving complainant 45 days to amend its complaint in light of guidance provided by the FERC;
•	FERC Docket No. IS05-230 (North Line rate case)—Complainants/Protestants: Shippers—Defendant: 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 on September 18, 2007. The FERC has yet to issue an order on shipper’s motion;
•	FERC Docket No. IS05-327—Complainants/Protestants: Shippers—Defendant: 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;

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•	FERC Docket No. IS06-283 (East Line rate case)—Complainants/Protestants: Shippers—Defendant: 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. In November 2007, the parties submitted a joint offer of settlement which was certified to the FERC in December 2007. In February 2008, the FERC accepted the joint offer of settlement which, among other things, resolved all protests and complaints related to the East Line Phase I Expansion Tariff;
•	FERC Docket No. IS06-296—Complainant/Protestant: ExxonMobil—Defendant: 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 or, to hold the investigation in abeyance, which is pending before the FERC. Calnev and ExxonMobil have reached an agreement in principle to settle this and other dockets;
•	FERC Docket No. IS06-356—Complainants/Protestants: Shippers—Defendant: 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 the FERC. On September 20, 2007, the FERC denied SFPP’s request for rehearing. In November 2007, all parties submitted a joint offer of settlement. In February 2008, the FERC accepted the joint offer of settlement which, among other things, resolved all protests and complaints related to the East Line 2006 Index Tariff;
•	FERC Docket No. IS07-137 (ULSD surcharge)—Complainants/Protestants: Shippers—Defendant: 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 related to ULSD recovery fee accepted subject to refund and proceeding is being held in abeyance pending resolution of other proceedings involving SFPP. SFPP rescinded the ULSD litigation surcharge in compliance with FERC order. Request for rehearing filed by Chevron and Tesoro. The FERC ultimately denied rehearing in an order issued on November 13, 2007;
•	FERC Docket No. IS07-229—Complainants/Protestants: BP WCP and ExxonMobil—Defendant: SFPP SFPP filed to increase certain rates on its pipelines pursuant to FERC’s indexing methodology. Two shippers filed protests. The FERC found the tariff filings consistent with its regulations but suspended the increased rates subject to refund pending challenges to SFPP’s underlying rates. In November 2007, all parties submitted a joint offer of settlement. In February 2008, the FERC accepted the joint offer of settlement which, among other things, resolved all protests and complaints related to the East Line 2007 Index Tariff;
•	FERC Docket No. IS07-234—Complainants/Protestants: BP WCP and ExxonMobil—Defendant: Calnev Calnev filed to increase certain rates on its pipeline pursuant to FERC’s indexing methodology. Two shippers protested. The FERC found the tariff filings consistent with its regulations but suspended the increased rates subject to refund pending challenges to SFPP’s underlying rates. Calnev and ExxonMobil have reached an agreement in principle to settle this and other dockets;
•	FERC Docket No. IS08-28—Complainants/Protestants: ConocoPhillips; Chevron; BP WCP; ExxonMobil; Southwest Airlines; Western; and Valero—Defendant: SFPP SFPP filed to increase its East Line rates based on costs incurred related to an expansion. Various shippers filed protests, which SFPP answered. The FERC issued an order on November 29, 2007 accepting and suspending the tariff subject to refund. The proceeding is being held in abeyance pursuant to ongoing settlement negotiations; and
•	Motions to compel payment of interim damages (various dockets)—Complainants/Protestants: Shippers—Defendants: SFPP; Kinder Morgan G.P., Inc.; and Knight Inc. Motions seek payment of interim refunds or escrow of funds pending resolution of various complaints and protests involving SFPP. The FERC denied shippers’ refund requests in an order issued on December 26, 2007 in Docket Nos. OR92-8, et al.

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          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 December 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it to submit compliance filings and revised tariffs. In accordance with the FERC’s December 2005 order and its February 2006 order on rehearing, SFPP submitted a compliance filing to the FERC in March 2006, and rate reductions were implemented on May 1, 2006. We estimate the impact of the rate reductions in 2007 was approximately $25 million, and we estimate that the actual, partial year impact on 2006 distributable cash flow was approximately $15.7 million. In addition, in December 2005, we recorded accruals of $105.0 million for expenses attributable to an increase in our reserves related to our rate case liability.

          In December 2007, as a follow-up to the March 2006 compliance filing, SFPP received a FERC order that directed us to submit revised compliance filings and revised tariffs. In conjunction with this order, our other FERC and CPUC rate cases, and other unrelated litigation matters, we increased our litigation reserves by $140.0 million in the fourth quarter of 2007. We assume that, with respect to our SFPP litigation reserves, any additional reparations and accrued interest thereon will be paid no earlier than the fourth quarter of 2008. We expect to file the revised compliance filings on February 26, 2008, and to implement new rates on March 1, 2008. We estimate that the impact of the new rates on our 2008 budget will be less than $3.0 million.

          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 $290 million in reparation and refund payments and approximately $45 million in additional annual rate reductions.

          California Public Utilities Commission Proceedings

          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.

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          Carbon Dioxide Litigation

          Shores and First State Bank of Denton Lawsuits

          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).

          Armor/Reddy Lawsuit

          On May 13, 2004, William Armor filed a case alleging the same claims for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit against Kinder Morgan CO₂, Kinder Morgan G.P., Inc., and Cortez Pipeline Company among others. Armor v. Shell Oil Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas filed May 13, 2004).

          On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd. filed a case in Dallas state district court alleging the same claims for underpayment of royalties. Reddy and Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial District Court, Dallas County, Texas filed May 20, 2005). The defendants included Kinder Morgan CO₂ and Kinder Morgan Energy Partners, L.P. On June 23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the court in the Armor lawsuit ordered that the Reddy lawsuit be transferred and consolidated into the Armor lawsuit.

          Effective March 5, 2007, the parties executed a final settlement agreement which providesfor the dismissal of the lawsuit and the plaintiffs’ claims with prejudice to being refiled. On June 12, 2007, the Dallas state district court signed its order dismissing the case and all claims with prejudice.

          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.

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          Ptasynski Colorado Federal District Court Lawsuit

          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.

          Bridwell Oil Company Wichita County Lawsuit

          On March 1, 2004, Bridwell Oil Company, one of the named plaintiffs in the above described Bailey action, filed a new matter in which it asserted claims that are virtually identical to the claims it asserted in the Bailey lawsuit. Bridwell Oil Co. v. Shell Oil Co. et al., No. 160,199-B (78^th Judicial District Court, Wichita County, Texas filed March 1, 2004). The defendants in this action include, among others, Kinder Morgan CO₂, Kinder Morgan Energy Partners, L.P., and Cortez Pipeline Company. This case was abated pending resolution of the Bailey action discussed above.

          Effective March 5, 2007, the parties executed a final settlement agreement which provides for the dismissal of the lawsuit and the plaintiffs’ claims with prejudice to being refiled. On June 14, 2007, the Wichita County state district court signed its order dismissing the case and all claims with prejudice.

          CO₂ Claims Arbitration

          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 CO₂Company, 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. In November 2007, the plaintiff in the arbitration moved to dismiss the defendants’ Complaint on the grounds that the issues

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presented should be decided by a panel in a second arbitration. In December 2007, the defendants in the arbitration filed a motion seeking summary judgment on their Complaint and dismissal of the second arbitration. No hearing date has been set.

          MMS Notice of Noncompliance and Civil Penalty

          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 CO₂has 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 was originally set for December 10, 2007. In November 2007, the MMS and Kinder Morgan CO₂ filed a joint motion to vacate the hearing date and stay the accrual of additional penalties to allow the parties to discuss settlement. In November 2007, the administrative law judge granted the joint motion, stayed accrual of additional penalties for the period from November 6, 2007 to February 18, 2008, and reset the hearing date to March 24, 2008. The parties conducted settlement conferences on February 4, 2008 and February 12, 2008.

          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 MorganCO₂’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.

          MMS Order to Report and Pay

          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

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“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.

          The MMS and Kinder Morgan CO₂ have agreed to stay the March 2007 and August 2007 Order to Report and Pay proceedings to allow the parties to discuss settlement. The parties conducted settlement conferences on February 4, 2008 and February 12, 2008.

          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 (8^th 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 during 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

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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. The Petition was denied in December 2007. The case is now proceeding in the trial court as a certified class action and the case is set for trial in September 2008.

          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 and Bravo Dome Units are currently ongoing. These audits and inquiries involve federal agencies and the States of Colorado and New Mexico.

          Commercial Litigation Matters

          Union Pacific Railroad Company Easements

          SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company and referred to in this 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 second quarter of 2008.

          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,

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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 before the Court of Appeals will be completed in the spring of 2008. The oral argument is expected to take place in September 2008.

          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 is still pending on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees.

          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. On February 14, 2008, the Arkansas Supreme Court clarified its previously issued order and mandated that the trial court dismiss the lawsuit in its entirety. Based on the information available to date and our preliminary investigation, the Kinder Morgan defendants believe that the claims against them are without merit and intend to defend against them vigorously.

          Federal Investigation at Cora and Grand Rivers Coal Facilities

          On June 22, 2005, we announced that the Federal Bureau of Investigation was conducting an investigation related to our coal terminal facilities located in Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involved 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 conducted an internal investigation of the allegations and discovered no evidence of wrongdoing or improper activities at these two terminals.

          In the fourth quarter of 2007, we reached a civil settlement with the U.S. Attorney’s office for the Southern District of Illinois pursuant to which we paid approximately $25 million, in aggregate, to the Tennessee Valley Authority and other customers of the Cora and Grand Rivers terminals from 1997 through 1999. We made no admission or acknowledgment of improper conduct as part of the 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. The settlement has been finalized, and we recorded a $25 million increase in expense in the third quarter of 2007 associated with the settlement of this liability.

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          Queen City Railcar Litigation

          On August 28, 2005, a railcar containing the chemical styrene began leaking styrene gas in Cincinnati, Ohio while en route to our Queen City Terminal. The railcar was sent by the Westlake Chemical Corporation from Louisiana, transported by Indiana & Ohio Railway, and consigned to Westlake at its dedicated storage tank at Queen City Terminals, Inc., a subsidiary of Kinder Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation 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. Without admitting fault or liability, the parties have reached a settlement in principle of the Dameron suit.

          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.

          Leukemia Cluster Litigation

          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 25, 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.

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          Pipeline Integrity and Releases

          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. 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. 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.

          Kleberg County, Texas Gas Pipeline Rupture

          On February 12, 2008, Kinder Morgan Texas Pipeline incurred a failure on its 16-inch diameter natural gas pipeline in a remote area in Kleberg County, Texas, which resulted in an explosion and fire. The incident caused some property damage, however no serious physical injuries have been reported to date. Kinder Morgan Texas Pipeline notified appropriate regulatory agencies and is currently investigating the cause of the rupture.

          Walnut Creek, California Pipeline Rupture

          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

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final by order of the court or are awaiting court approval. The only civil cases which remain pending at present are: (i) a cross-claim for contribution and indemnity by an engineering company defendant against the Kinder Morgan defendants in which the court has entered summary judgment in favor of the Kinder Morgan defendants; and (ii) a challenge to the court-ordered allocation of settlement proceeds in one of the court-approved wrongful death settlements filed by a nonresident sibling in which the court has also granted summary judgment in favor of the Kinder Morgan defendants. Both of these judgments in favor of the Kinder Morgan defendants are subject to potential appeal.

          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.

          EPA Notice of Proposed Debarment

          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. Based upon our discussions to date, we do not believe that this matter will result in the debarment or suspension of SFPP.

          Baker, California

          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

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California Department of Fish & Game has alleged a small natural resource damage claim that is currently under review. CALNEV expects to work cooperatively with the Department of Fish & Game to resolve this claim.

          Henrico County, Virginia

          On April 17, 2006, Plantation 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.

          Dublin, California

          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.

          Soda Springs, California

          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. On January 30, 2008, we entered into a settlement agreement with Nevada County and the state of California to resolve any outstanding civil penalties claims related to this release for $75,000.

          Rockies Express Pipeline LLC Wyoming Construction Incident

          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 U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as 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

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insurers. The parties are currently engaged in discovery. We do not expect the cost of any settlement or eventual judgment, if any, to be material.

          Charlotte, North Carolina

          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. Plantation has reached an agreement in principle with the Department of Justice and the EPA for all four releases for approximately $0.7 million, plus some additional work to be performed to prevent future releases. The parties are negotiating a consent decree. Although it is not possible to predict the ultimate outcome, 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 historical 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 an historical 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.

          Barstow, California

          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.

          Oil Spill Near Westridge Terminal, Burnaby, British Columbia

          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 do not expect this matter to have a material adverse impact on our results of operations or cash flows.

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          On December 20, 2007 we initiated a lawsuit entitled Trans Mountain Pipeline LP, Trans Mountain Pipeline Inc. and Kinder Morgan Canada Inc. v. The City of Burnaby, et al., Supreme Court of British Columbia, Vancouver Registry No. S078716. The suit alleges that the City of Burnaby and its agents are liable in damages including, but not limited to, all costs and expenses incurred by us as a result of the rupture of the pipeline and subsequent release of crude oil.

          Although no assurance can be given, we believe that we have meritorious defenses to all pending pipeline integrity actions set forth in this note and, 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 it is not possible to predict the ultimate outcomes, 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 December 31, 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 $247.9 million and $112.0 million, respectively. The reserve is primarily related to various claims from lawsuits arising from our Pacific operations’ pipeline transportation rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

          Environmental Matters

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

          On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County. We filed our answer to the complaint on June 27, 2003, in which we denied ExxonMobil’s claims and allegations as well as included counterclaims against ExxonMobil. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, 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.

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

          We 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. In the fourth quarter of 2007, we finalized the settlement terms, filed with the court for final approval, and paid the $3.2 million in satisfaction of all past and future rent obligations.

          Mission Valley Terminal Lawsuit

          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.

          Portland Harbor DOJ/EPA Investigation

          The United States Department of Justice and the United States Environmental Protection Agency are continuing to investigate potential criminal charges relating to 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 and are engaged in ongoing discussions with the office of the United States Attorney for the District of Oregon and the Department of Justice in an attempt to resolve this matter.

          Louisiana Department of Environmental Quality Settlement

          After conducting a voluntary compliance self-audit, in April 2006, we voluntarily disclosed certain findings from the audit related to compliance with environmental regulations and permits at our Harvey and St. Gabriel Terminals to the Louisiana Department of Environmental Quality, referred to in this report as the LDEQ. Following further discussion between the LDEQ and us, in August 2007, the LDEQ issued a Consolidated Compliance Order and Notice of Potential Penalty for each of the two facilities. We and the LDEQ have reached agreement on a proposed settlement agreement under which we agree to finalize certain work, which we have already undertaken to ensure compliance with the environmental regulations at these two facilities, and to pay a penalty of $0.3 million. The proposed settlement agreement is undergoing public comment pursuant to LDEQ regulations, and then will be finalized.

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          Other Environmental

          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 it is not possible to predict the ultimate outcomes, we believe that the 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 December 31, 2007, we have accrued an environmental reserve of$92.0 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. As of December 31, 2006, our environmental reserve totaled $64.2 million. 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.

          Other

          We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

17. Regulatory Matters

          The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expanded the circumstances under which interstate petroleum products pipelines may employ cost-of-

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service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2007, 2006 and 2005, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines.

          FERC Order No. 2004/690

          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 Standards of Conduct apply only to the relationship between interstate gas transmission pipelines and their marketing affiliates, not their energy affiliates;

• all risk management personnel can be shared;

• the requirement to post discretionary tariff actions was eliminated (but interstate gas pipelines must still maintain a log of discretionary tariff waivers);

• lawyers providing legal advice may be shared employees; and

• new interstate gas transmission pipelines are not subject to the Standards of Conduct until they commence service.

          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.

          Notice of Inquiry – Financial Reporting

          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.

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          On September 20, 2007, the 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: (i) submit additional revenue information, including revenue from shipper-supplied gas; (ii) identify the costs associated with affiliate transactions; and (iii) provide additional information on incremental facilities and on discounted and negotiated rates. The 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 were filed by numerous parties on November 13, 2007.

          Notice of Inquiry – Fuel Retention Practices

          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 were filed by numerous parties on November 30, 2007.

          Notice of Proposed Rulemaking – Promotion of a More Efficient Capacity Release Market

          On November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket No. RM 08-1-000 regarding proposed modifications to its Part 284 regulations concerning the release of firm capacity by shippers on interstate natural gas pipelines. The FERC proposes to remove, on a permanent basis, the rate ceiling on capacity release transactions of one year or less. Additionally, the FERC proposes to exempt capacity releases made as part of an asset management arrangement from the prohibition on tying and from the bidding requirements of section 284.8. Initial comments were filed by numerous parties on January 25, 2008.

          Notice of Proposed Rulemaking – Natural Gas Price Transparency

          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 proposed 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 were filed on August 23, 2007. In addition, the FERC conducted 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.

          On December 26, 2007, the FERC issued Order No. 704 in this docket implementing only the annual reporting provisions of the NOPR with minimal changes to the original proposal. The order becomes effective February 4, 2008. The initial report is due May 1, 2009 for calendar year 2008. Subsequent reports are due by May 1 of each year for the previous calendar year. Order 704 will require most, if not all Kinder Morgan natural gas pipelines to report annual volumes of relevant transactions to the FERC.

          In addition, on December 21, 2007, the FERC issued a new notice of proposed rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that were contained in Docket Nos. RM07-10-000 and AD06-11-000. The new NOPR proposes to exempt from the daily posting requirements those non-interstate pipelines that (i) flow less than 10 million MMBtus of natural gas per year, (ii) fall entirely upstream of a processing plant, and (iii) deliver more than ninety-five percent (95%) of the natural gas volumes they flow directly to end-users. However, the new NOPR expands the proposal to require that both interstate and non-exempt non-interstate pipelines post daily the capacities of, volumes scheduled at, and actual volumes flowing through, their major receipt and delivery points and

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mainline segments. Initial comments are due March 13, 2008 and reply comments are due April 14, 2008. A Technical Conference is scheduled for April 3, 2008.

          Notice of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids Pipelines

          On September 6, 2006, the PHMSA published a notice of proposed rulemaking (PHMSA 71 FR 52504) that proposed to extend certain threat-focused pipeline safety regulations to rural onshore low-stress hazardous liquid pipelines within a prescribed buffer of previously defined U.S. states. Low-stress hazardous liquid pipelines, except those in populated areas or that cross commercially navigable waterways, have not been subject to the safety regulations in PHMSA 49 CFR Part 195.1. According to the PHMSA, unusually sensitive areas are areas requiring extra protection because of the presence of sole-source drinking water resources, endangered species, or other ecological resources that could be adversely affected by accidents or leaks occurring on hazardous liquid pipelines.

          The notice proposed to define a category of “regulated rural onshore low-stress lines” (rural lines operating at or below 20% of specified minimum yield strength, with a diameter of eight and five-eighths inches or greater, located in or within a quarter-mile of a U.S. state) and to require operators of these lines to comply with a threat-focused set of requirements in Part 195 that already apply to other hazardous liquid pipelines. The proposed safety requirements addressed the most common threats—corrosion and third party damage—to the integrity of these rural lines. The proposal intended to provide additional integrity protection, to avoid significant adverse environmental consequences, and to improve public confidence in the safety of unregulated low-stress lines.

          Since the new notice is a proposed rulemaking in which the PHMSA 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.

          Natural Gas Pipeline Expansion Filings

          Rockies Express Pipeline-Currently Certificated Facilities

          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 went into service in January 2008. Construction of the Big Hole compressor station is planned to commence in the second quarter of 2008, in order to meet an expected in-service date of June 30, 2009.

          Rockies Express Pipeline-West Project

          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

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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 entered interim service to upstream delivery points on January 12, 2008. This project is expected to be fully operational in March 2008.

          Rockies Express Pipeline-East Project

          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, referred to as the posted schedule. Rockies Express has requested that the FERC issue an updated scheduling order to modify the posted schedule for earlier resolution. Without a modification of the posted 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 meet a revised schedule that was developed in consultation with the FERC staff at a public meeting convened on September 21, 2007. On November 23, 2007, the FERC issued a draft environmental impact statement for the project, in advance of the posted schedule. Comments on the environmental impact statement were submitted January 14, 2008, also in advance of the posted schedule. 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.

          TransColorado Pipeline

          On April 19, 2007, the FERC issued an order approving TransColorado Gas Transmission Company LLC’s application for authorization to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” This project provides for 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 was completed and entered service January 1, 2008.

          Kinder Morgan Interstate Gas Transmission Pipeline

          On August 6, 2007, KMIGT filed, in FERC Docket CP07-430, for regulatory approval to construct and operate a 41-mile, $29 million natural gas pipeline from the Cheyenne Hub to markets in and around Greeley, Colorado. When completed, the Colorado Lateral will provide firm transportation of up to 55 million cubic feet per day to a local utility under long-term contract. The FERC issued a draft environmental assessment on the project on January 11, 2008, and comments on the project were received February 11, 2008. Public Service Company of Colorado, a competitor to serving markets off the Colorado Lateral, reported that it had filed a complaint before the State of Colorado Public Utilities Commission against Atmos, the anchor shipper on the project. The Colorado Public Utilities Commission has set a hearing for April 8, 2008 on the complaint. Public Service Company of Colorado has requested the FERC delay the issuance of approvals to KMIGT, pending the outcome of the complaint proceeding.

          On December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its system in Nebraska to serve incremental ethanol and industrial load. The application is pending before the FERC until March 10, 2008, at which time the project will be approved if no protests are filed.

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          Kinder Morgan Louisiana Pipeline

          On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application with the FERC requesting approval to construct and operate our Kinder Morgan Louisiana Pipeline. The 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 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 project cost is approximately $510 million project and it 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.

          Midcontinent Express Pipeline

          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. On February 8, 2008, the FERC issued a draft environmental impact statement which stated that the building and operation of the proposed 504-mile Midcontinent Express Pipeline would result in limited adverse environmental impact. A final environmental impact statement must be released before the FERC can issue a certificate authorizing construction. 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 terminate close to the Alabama border, 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 1.4 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.

18. Recent Accounting Pronouncements

          SFAS No. 123R

          On December 16, 2004, the Financial Accounting Standards Board issued SFAS No. 123R (revised 2004), “Share-Based Payment.” This Statement amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following: (i) share-based payment awards result in a cost that will be measured at fair value on the awards’ grant date, based on the estimated number of awards that are expected to vest (compensation cost for awards that vest would not be reversed if the awards expire without being exercised); (ii) when measuring fair value, companies can choose an option-pricing model that appropriately reflects their specific circumstances and the economics of their transactions; and (iii) companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects. Upon settlement of share-based payment awards, the tax effects will be recognized in the income statement or additional paid-in capital.

          For us, this Statement became effective January 1, 2006. However, we have not granted common unit options or made any other share-based payment awards since May 2000, and as of December 31, 2005, all outstanding options

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to purchase our common units were fully vested. Therefore, the adoption of this Statement did not have an effect on our consolidated financial statements due to the fact that we have reached the end of the requisite service period for any compensation cost resulting from share-based payments made under our common unit option plan.

          SFAS No. 154

          On June 1, 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This Statement replaces Accounting Principles Board Opinion No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. In contrast, APB No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle.

          The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (January 1, 2006 for us). The Statement does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of this Statement. Adoption of this Statement did not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively.

          EITF 04-5

          In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” EITF 04-5 provides guidance for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership.

          For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an effect on our consolidated financial statements.

          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.

          SFAS No. 155

          On February 16, 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments.” This Statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” 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.

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          SFAS No. 156

          On March 17, 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This Statement amends SFAS No. 140 and 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.

          EITF 06-3

          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). The adoption of EITF 06-3 had no effect on our consolidated financial statements.

          FIN 48

          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 not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% 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. A reconciliation of our beginning and ending gross unrecognized tax benefits for 2007 is as follows (in millions):

	2007
Balance at beginning of period	$	3.2
Additions based on current year tax positions		4.7
Additions based on prior year tax positions		0.1
Reductions based on settlements with taxing authority		—
Reductions due to lapse in statute of limitations		(1.7	)
Balance at end of period	$	6.3

          Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of January 1, 2007, we had $1.1 million of accrued interest and no accrued penalties. As of December 31, 2007 (i) we had $0.6 million of accrued interest and no accrued penalties; (ii) we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $1.2 million during the next twelve months; and (iii) we believe approximately $5.4 million of the total $6.3 million of unrecognized tax benefits on our consolidated balance sheet as of December 31, 2007 would affect our effective

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income tax rate in future periods in the event those unrecognized tax benefits were recognized. In addition, we have U.S. and state tax years open to examination for the periods 2003 through 2007.

          SAB 108

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

          SFAS No. 157

          On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This Statement establishes a single definition of fair value and a framework for measuring fair value in generally accepted accounting principles that should result in increased consistency and comparability in fair value measurements. SFAS No. 157 also expands disclosures about fair value measurements, improving the quality of information provided to users of financial statements. The provisions of this Statement apply 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.

          On February 12, 2008, the FASB issued Financial Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157.” This Staff Position delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The delay is intended to allow the Board and constituents additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS No. 157.

          The remainder of SFAS No. 157 was adopted by us effective January 1, 2008. The adoption of this Statement did not have an impact on our balance sheet, statement of income, or statement of cash flows since we already apply its basic concepts in measuring fair values.

          SFAS No. 158

          On September 29, 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R).” This Statement requires an employer to: (i) recognize the overfunded or underfunded status of a defined benefit pension plan or postretirement benefit plan (other than a multiemployer plan) as an asset or liability in its statement of financial position; (ii) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and to disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations; and (iii) recognize changes in the funded status of a plan in the year in which the changes occur through comprehensive income.

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

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          According to the provisions of this Statement, an employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit pension plan or postretirement benefit plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006 (December 31, 2006 for us). For us, the adoption of this part of SFAS No. 158 did not have a material effect on our statement of financial position as of December 31, 2006.

          In addition, the requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008 (December 31, 2008 for us). In the year that the measurement date provisions of this Statement are initially applied, a business entity is required to disclose the separate adjustments of retained earnings (“Partners’ Capital” for us) and “Accumulated other comprehensive income/loss” from applying this Statement. While earlier application of the recognition of measurement date provisions is allowed, we have opted not to adopt this part of the Statement early. For more information on our pensions and other post-retirement benefit plans, and our disclosures regarding the provisions of this Statement, please see Note 10.

          SFAS No. 159

          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 was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of this Statement did not have any impact on our financial statements.

          SFAS 141(R)

          On December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), “Business Combinations.” Although this statement amends and replaces SFAS No. 141, it retains the fundamental requirements in SFAS No. 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. SFAS No. 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control.

          Significant provisions of SFAS No. 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

          This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for us). Early adoption is not permitted. We are currently reviewing the effects of this Statement.

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          SFAS No. 160

          On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” This Statement changes the accounting and reporting for noncontrolling interests in consolidated financial statements. A noncontrolling interest, sometimes referred to as a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent.

          Specifically, SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheet within equity, but separate from the parent’s equity; (ii) the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement (consolidated net income and comprehensive income will be determined without deducting minority interest, however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent’s shareholders); and (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly—as equity transactions.

          This Statement is effective for fiscal years, and interim period within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for us). Early adoption is not permitted. SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except for its presentation and disclosure requirements, which shall be applied retrospectively for all periods presented. We are currently reviewing the effects of this Statement.

19. Quarterly Financial Data (Unaudited)

	Operating Revenues			Operating Income				Income from Continuing Operations				Income from Discontinued Operations			Net Income
	(In millions)
2007
First Quarter(a)		$	2,171.7		$	(75.5	)		$	(156.6	)		$	7.1		$	(149.5	)
Second Quarter			2,366.4			314.6				227.3				5.4			232.7
Third Quarter			2,230.8			311.4				205.2				8.6			213.8
Fourth Quarter			2,448.8			257.2				140.5				152.8			293.3
2006
First Quarter		$	2,413.3		$	314.0			$	249.9			$	3.0		$	252.9
Second Quarter			2,216.1			317.7				251.0				3.4			254.4
Third Quarter			2,296.8			311.4				227.1				2.4			229.5
Fourth Quarter			2,122.5			348.5				261.8				5.5			267.3

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	Income (loss) from Continuing Operations				Income (loss) from Discontinued Operations			Net Income
Basic Limited Partners’ income (loss) per Unit:
2007
First Quarter(a)		$	(1.27	)		$	0.03		$	(1.24	)
Second Quarter			0.34				0.02			0.36
Third Quarter			0.21				0.03			0.24
Fourth Quarter			(0.12	)			0.62			0.50
2006
First Quarter		$	0.54			$	0.02		$	0.56
Second Quarter			0.55				0.01			0.56
Third Quarter			0.41				0.01			0.42
Fourth Quarter			0.62				0.02			0.64
Diluted Limited Partners’ income (loss) per Unit:
2007
First Quarter(a)		$	(1.27	)		$	0.04		$	(1.23	)
Second Quarter			0.34				0.02			0.36
Third Quarter			0.21				0.03			0.24
Fourth Quarter			(0.12	)			0.62			0.50
2006
First Quarter		$	0.54			$	0.02		$	0.56
Second Quarter			0.54				0.02			0.56
Third Quarter			0.41				0.01			0.42
Fourth Quarter			0.62				0.02			0.64

(a) 2007 first quarter includes an expense of $377.1 million attributable to a goodwill impairment charge recognized by Knight, as discussed in Notes 3 and 8.

20. Supplemental Information on Oil and Gas Producing Activities (Unaudited)

          The Supplementary Information on Oil and Gas Producing Activities is presented as required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities, exploration and development activities; and the results of operations from oil and gas producing activities.

          Supplemental information is also provided for per unit production costs; oil and gas production and average sales prices; the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

          Our capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing Activities
	December 31,
	2007			2006			2005
Consolidated Companies(a)
Wells and equipment, facilities and other	$	1,612.5		$	1,369.5		$	1,097.9
Leasehold		348.1			347.4			320.7
Total proved oil and gas properties		1,960.6			1,716.9			1,418.6
Accumulated depreciation and depletion		(725.5	)		(470.2	)		(303.3	)
Net capitalized costs	$	1,235.1		$	1,246.7		$	1,115.3

(a) Amounts relate to Kinder Morgan CO₂ Company, L.P. and its consolidated subsidaries. Includes capitalized asset retirement costs and associated accumulated depreciation. There are no capitalized costs associated with unproved oil and gas properties for the periods reported.

          Our costs incurred for property acquisition, exploration and development were as follows (in millions):

Costs Incurred in Exploration, Property Acquisitions and Development
	Year Ended December 31,
	2007		2006		2005
Consolidated Companies(a)
Property Acquisition
Proved oil and gas properties	$	—	$	36.6	$	6.4
Development		244.4		261.8		281.7

(a) Amounts relate to Kinder Morgan CO₂ Company, L.P. and its consolidated subsidaries. There are no capitalized costs associated with unproved oil and gas properties for the periods reported. All capital expenditures were made to develop our proved oil and gas properties and no exploration costs were incurred for the periods reported.

207

          Our results of operations from oil and gas producing activities for each of the years 2007, 2006 and 2005 are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing Activities
	Year Ended December 31,
	2007		2006		2005
Consolidated Companies(a)
Revenues(b)	$	589.7	$	524.7	$	469.1
Expenses:
Production costs		243.9		208.9		159.6
Other operating expenses(c)		56.9		66.4		59.0
Depreciation, depletion and amortization expenses		258.5		169.4		130.5
Total expenses		559.3		444.7		349.1
Results of operations for oil and gas producing activities	$	30.4	$	80.0	$	120.0

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Revenues include losses attributable to our hedging contracts of $434.2 million, $441.7 million and $374.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.
(c)	Consists primarily of carbon dioxide expense.

          The table below represents estimates, as of December 31, 2007, of proved crude oil, natural gas liquids and natural gas reserves prepared by Netherland, Sewell and Associates, Inc. (independent oil and gas consultants) of Kinder Morgan CO₂ Company, L.P. and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the state of Texas. This data has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this document. The estimates of reserves and future revenue in this document conforms to the guidelines of the United States Securities and Exchange Commission.

          We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change.

          Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations or declines based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.

          During 2007, we filed estimates of our oil and gas reserves for the year 2006 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil reserves reported on Form EIA-23 and those reported in this report exceeds 5%.

208

Reserve Quantity Information
	Consolidated Companies(a)
	Crude Oil (MBbls)			NGLs (MBbls)			Nat. Gas (MMcf)(b)
Proved developed and undeveloped reserves:
As of December 31, 2004		123,731			20,245			1,590
Revisions of previous estimates(c)		9,807			(4,278	)		1,608
Improved Recovery(d)		21,715			4,847			242
Production		(13,815	)		(1,920	)		(1,335	)
Purchases of reserves in place		513			89			48
As of December 31, 2005		141,951			18,983			2,153
Revisions of previous estimates(e)		(4,615	)		(6,858	)		(1,408	)
Production		(13,811	)		(1,817	)		(461	)
Purchases of reserves in place		453			25			7
As of December 31, 2006		123,978			10,333			291
Revisions of previous estimates(f)		10,361			2,784			1,077
Production		(12,984	)		(2,005	)		(290	)
As of December 31, 2007		121,355			11,112			1,078
Proved developed reserves:
As of December 31, 2004		71,307			8,873			1,357
As of December 31, 2005		78,755			9,918			1,650
As of December 31, 2006		69,073			5,877			291
As of December 31, 2007		70,868			5,517			1,078

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.

(b) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees fahrenheit.

(c) Crude oil revisions are based on better than expected recoveries on the SACROC unit carbon dioxide flood project. Natural gas liquids revisions are based on a lower than expected natural gas liquid yield at the SACROC unit carbon dioxide flood project.

(d) Improved recovery is due to significant additional areas of the SACROC unit being added to the future carbon dioxide flood project.

(e) Based on lower than expected recoveries of a section of the SACROC unit carbon dioxide flood project.

(f) Associated with an expansion of the carbon dioxide flood project area of the SACROC unit.

          The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with SFAS No. 69. The assumptions that underly the computation of the standardized measure of discounted cash flows may be summarized as follows:

• the standardized measure includes our estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions;

• pricing is applied based upon year-end market prices adjusted for fixed or determinable contracts that are in existence at year-end;

• future development and production costs are determined based upon actual cost at year-end;

• the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and

• a discount factor of 10% per year is applied annually to the future net cash flows.

209

          Our standardized measure of discounted future net cash flows from proved reserves were as follows (in millions):

Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves

	As of December 31,
	2007			2006			2005
Consolidated Companies(a)
Future cash inflows from production	$	12,099.5		$	7,534.7		$	9,150.6
Future production costs		(3,536.2	)		(2,617.9	)		(2,756.6	)
Future development costs(b)		(1,919.2	)		(1,256.8	)		(869.0	)
Undiscounted future net cash flows		6,644.1			3,660.0			5,525.0
10% annual discount		(2,565.7	)		(1,452.2	)		(2,450.0	)
Standardized measure of discounted future net cash flows	$	4,078.4		$	2,207.8		$	3,075.0

(a) Amounts relate to Kinder Morgan CO₂ Company, L.P. and its consolidated subsidaries.

(b) Includes abandonment costs.

          The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in millions):

Changes in the Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves

	2007			2006			2005
Consolidated Companies(a)
Present value as of January 1	$	2,207.8		$	3,075.0		$	2,045.0
Changes during the year:
Revenues less production and other costs(b)		(722.1	)		(690.0	)		(624.4	)
Net changes in prices, production and other costs(b)		2,153.2			(123.0	)		1,013.4
Development costs incurred		244.5			261.8			281.7
Net changes in future development costs		(547.8	)		(446.0	)		(492.3	)
Purchases of reserves in place		—			3.2			9.4
Revisions of previous quantity estimates(c)		510.8			(179.5	)		51.1
Improved Recovery(d)		—			—			587.5
Accretion of discount		198.1			307.4			204.4
Timing differences and other		33.9			(1.1	)		(0.8	)
Net change for the year		1,870.6			(867.2	)		1,030.0
Present value as of December 31	$	4,078.4		$	2,207.8		$	3,075.0

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.

(b) Excludes the effect of losses attributable to our hedging contracts of $434.2 million, $441.7 million and $374.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.

(c) 2007 revisions are associated with an expansion of the carbon dioxide flood project area for the SACROC unit. 2006 revisions are based on lower than expected recoveries from a section of the SACROC unit carbon dioxide flood project. 2005 revisions are based on better than expected crude oil recoveries on the SACROC unit carbon dioxide flood project, partially offset by a lower than expected natural gas liquids yield at the SACROC unit carbon dioxide flood project.

(d) Improved recovery is due to significant additional areas of the SACROC unit being added to the future carbon dioxide flood project.

210

SIGNATURES

          Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware Limited Partnership)

By: KINDER MORGAN G.P., INC.,
its sole General Partner

By: KINDER MORGAN MANAGEMENT, LLC,
the Delegate of Kinder Morgan G.P., Inc.

By: /s/ KIMBERLY A. DANG

Kimberly A. Dang,
Vice President and Chief Financial Officer

Date: February 25, 2008

          Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ KIMBERLY A. DANG	Vice President and Chief Financial	February 25, 2008
	Officer of Kinder Morgan
Kimberly A. Dang	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc. (principal
	financial officer and principal
	accounting officer)
/s/ RICHARD D. KINDER	Chairman of the Board and Chief	February 25, 2008
	Executive Officer of Kinder Morgan
Richard D. Kinder	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc. (principal
	executive officer)
/s/ EDWARD O. GAYLORD	Director of Kinder Morgan	February 25, 2008
	Management, LLC, Delegate of
Edward O. Gaylord	Kinder Morgan G.P., Inc.
/s/ GARY L. HULTQUIST	Director of Kinder Morgan	February 25, 2008
	Management, LLC, Delegate of
Gary L. Hultquist	Kinder Morgan G.P., Inc.
/s/ PERRY M. WAUGHTAL	Director of Kinder Morgan	February 25, 2008
	Management, LLC, Delegate of
Perry M. Waughtal	Kinder Morgan G.P., Inc.
/s/ C. PARK SHAPER	Director and President of	February 25, 2008
	Kinder Morgan Management, LLC,
C. Park Shaper	Delegate of Kinder Morgan G.P., Inc.

211

EX-4

KINDER MORGAN MANAGEMENT, LLC

KINDER MORGAN G.P., INC.

OFFICERS’ CERTIFICATE

PURSUANT TO SECTION 301 OF INDENTURE

Each of the undersigned, Kimberly A. Dang and David D. Kinder, the Vice President and Chief Financial Officer and the Vice President and Treasurer, respectively, of (i) Kinder Morgan Management, LLC (the “Company”), a Delaware limited liability company and the delegate of Kinder Morgan G.P., Inc. and (ii) Kinder Morgan G.P., Inc., a Delaware corporation and the general partner of Kinder Morgan Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), on behalf of the Partnership, does hereby establish the terms of a series of senior debt Securities of the Partnership under the Indenture relating to senior debt Securities, dated as of January 31, 2003 (the “Indenture”), between the Partnership and U.S. Bank National Association, as successor trustee to Wachovia Bank, National Association (the “Trustee”), pursuant to resolutions adopted by the Board of Directors of the Company, or a committee thereof, on February 28, 2007, February 4, 2008 and February 5, 2008 and in accordance with Section 301 of the Indenture, as follows:

1.The title of the Securities shall be “5.95% Senior Notes due 2018” (the “Notes”);

2.         The aggregate principal amount of the Notes which initially may be authenticated and delivered under the Indenture shall be limited to a maximum of $600,000,000, except for Notes authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Notes pursuant to the terms of the Indenture, and except that any additional principal amount of the Notes may be issued in the future without the consent of Holders of the Notes so long as such additional principal amount of Notes are authenticated as required by the Indenture;

3.         The Notes shall be issued on February 12, 2008, and the principal of the Notes shall be payable on February 15, 2018; the Notes will not be entitled to the benefit of a sinking fund;

4.         The Notes shall bear interest at the rate of 5.95% per annum, which interest shall accrue from February 12, 2008, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, which dates shall be February 15 and August 15 of each year, and such interest shall be payable semi-annually in arrears on February 15 and August 15 of each year, commencing August 15, 2008, to holders of record at the close of business on the February 1 or August 1, respectively, next preceding each such Interest Payment Date;

5.         The principal of, premium, if any, and interest on, the Notes shall be payable at the office or agency of the Partnership maintained for that purpose in the Borough of Manhattan, New York, New York; provided, however, that at the option of the Partnership, payment of interest may be made from such office in the Borough of Manhattan, New York, New York by check mailed to the address of the person entitled thereto as such address shall appear in the Security Register. If at any time there shall be no such office or agency in the Borough of Manhattan, New York, New York, where the Notes may be presented or surrendered for

payment, the Partnership shall forthwith designate and maintain such an office or agency in the Borough of Manhattan, New York, New York, in order that the Notes shall at all times be payable in the Borough of Manhattan, New York, New York. The Partnership hereby initially designates the Corporate Trust Office of the Trustee in the Borough of Manhattan, New York, New York, as one such office or agency;

6.         U.S. Bank National Association, successor trustee to Wachovia Bank, National Association, is appointed as the Trustee for the Notes, and U.S. Bank National Association, and any other banking institution hereafter selected by the officers of the Company, on behalf of the Partnership, are appointed agents of the Partnership (a) where the Notes may be presented for registration of transfer or exchange, (b) where notices and demands to or upon the Partnership in respect of the Notes or the Indenture may be made or served and (c) where the Notes may be presented for payment of principal and interest;

7.         The Notes will be redeemable, at the Partnership’s option, at any time in whole, or from time to time in part, upon not less than 30 and not more than 60 days notice mailed to each Holder of the Notes to be redeemed at the Holder’s address appearing in the Security Register, at a price equal to 100% of the principal amount of the Notes to be redeemed plus accrued interest to the Redemption Date, subject to the right of Holders of record on the relevant Record Date to receive interest due on an Interest Payment Date that is on or prior to the Redemption Date, plus a make-whole premium, if any. In no event will the Redemption Price ever be less than 100% of the principal amount of the Notes being redeemed plus accrued interest to the Redemption Date.

The amount of the make-whole premium on any Note, or portion of a Note, to be redeemed will be equal to the excess, if any, of:

(1) the sum of the present values, calculated as of the Redemption Date, of:

• each interest payment that, but for the redemption, would have been payable on the Note, or portion of a Note, being redeemed on each interest payment date occurring after the Redemption Date, excluding any accrued interest for the period prior to the Redemption Date; and

• the principal amount that, but for the redemption, would have been payable at the stated maturity of the Note, or portion of a Note, being redeemed;

over

(2) the principal amount of the Note, or portion of a Note, being redeemed.

The present value of interest and principal payments referred to in clause (1) above will be determined in accordance with generally accepted principles of financial analysis. The present values will be calculated by discounting the amount of each payment of interest or principal from the date that each such payment would have been payable, but for the redemption, to the Redemption Date at a discount rate equal to the Treasury Yield, as defined below, plus 0.40%.

The make-whole premium will be calculated by an independent investment banking institution of national standing appointed by the Partnership. If the Partnership fails to make that

-2-

appointment at least 30 business days prior to the redemption date, or if the institution so appointed is unwilling or unable to make the calculation, the financial institution named in the Notes will make the calculation. If the financial institution named in the Notes is unwilling or unable to make the calculation, an independent investment banking institution of national standing appointed by the Trustee will make the calculation.

For purposes of determining the make-whole premium, Treasury Yield refers to an annual rate of interest equal to the weekly average yield to maturity of United States Treasury Notes that have a constant maturity that corresponds to the remaining term to maturity of the Notes to be redeemed, calculated to the nearer 1/12 of a year (the “Remaining Term”). The Treasury Yield will be determined as of the third business day immediately preceding the applicable redemption date.

The weekly average yields of United States Treasury Notes will be determined by reference to the most recent statistical release published by the Federal Reserve Bank of New York and designated “H.15(519) Selected Interest Rates” or any successor release (the “H.15 Statistical Release”). If the H.15 Statistical Release sets forth a weekly average yield for United States Treasury Notes having a constant maturity that is the same as the Remaining Term of the Notes to be redeemed, then the Treasury Yield will be equal to that weekly average yield. In all other cases, the Treasury Yield will be calculated by interpolation, on a straight-line basis, between the weekly average yields on the United States Treasury Notes that have a constant maturity closest to and greater than the Remaining Term of the Notes to be redeemed and the United States Treasury Notes that have a constant maturity closest to and less than the Remaining Term, in each case as set forth in the H.15 Statistical Release. Any weekly average yields so calculated by interpolation will be rounded to the nearer 0.01%, with any figure of 0.0050% or more being rounded upward. If weekly average yields for United States Treasury Notes are not available in the H.15 Statistical Release or otherwise, then the Treasury Yield will be calculated by interpolation of comparable rates selected by the independent investment banking institution.

If less than all of the Notes are to be redeemed, the Trustee will select the Notes to be redeemed by a method that the Trustee deems fair and appropriate. The Trustee may select for redemption Notes and portions of Notes in amounts of $1,000 or whole multiples of $1,000.

8.         Payment of principal of, and interest on, the Notes shall be without deduction for taxes, assessments or governmental charges paid by Holders of the Notes;

9.         The Notes are approved in the form attached hereto as Exhibit A, shall be issued upon original issuance in whole in the form of one or more book-entry Global Securities, and the Depositary shall be The Depository Trust Company; and

10.       The Notes shall be entitled to the benefits of the Indenture, including the covenants and agreements of the Partnership set forth therein, except to the extent expressly otherwise provided herein or in the Notes.

Any initially capitalized terms not otherwise defined herein shall have the meanings ascribed to such terms in the Indenture.

-3-

IN WITNESS WHEREOF, each of the undersigned has hereunto signed his or her name this 5^th day of February, 2008.

/s/ Kimberly A. Dang

Kimberly A. Dang

Vice President and Chief Financial Officer

/s/ David D. Kinder

David D. Kinder

Vice President and Treasurer

[Signature Page to Officers' Certificate Establishing Series]

EXHIBIT A

Form of Global Note attached.

EX-11

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

EXHIBIT 11 – STATEMENT RE: COMPUTATION OF PER SHARE EARNINGS

(Units in millions; Dollars in millions except per unit amounts)

	Year Ended December 31,
	2007			2006			2005
Weighted average number of limited partners’ units on which limited partners’ net income per unit is based:
Basic		236.9			224.6			212.2
Add: Incremental units under common unit option plan and under contracts to issue units depending on the market price of the units at a future date		—			0.3			0.2
Assuming dilution		236.9			224.9			212.4
Calculation of Limited Partners’ interest in Net Income:
Income from Continuing Operations	$	416.4		$	989.8		$	812.4
Less: General Partner’s interest in Income from Continuing Operations		(609.9	)		(513.2	)		(477.3	)
Limited Partners’ interest in Income from Continuing Operations		(193.5	)		476.6			335.1
Add: Limited Partners’ interest in Income from Discontinued Operations		172.2			14.2			(0.2	)
Limited Partners’ interest in Net Income	$	(21.3	)	$	490.8		$	334.9
Basic Limited Partners’ Net Income per unit:
Income from Continuing Operations	$	(0.82	)	$	2.12		$	1.58
Income from Discontinued Operations	$	0.73		$	0.07		$	—
Net Income	$	(0.09	)	$	2.19		$	1.58
Diluted Limited Partners’ Net Income per unit:
Income from Continuing Operations	$	(0.82	)	$	2.12		$	1.58
Income from Discontinued Operations	$	0.73		$	0.06		$	—
Net Income	$	(0.09	)	$	2.18		$	1.58

EX-12

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

EXHIBIT 12 – STATEMENT RE: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(Dollars In millions except ratio amounts)

	Year Ended December 31,
	2007			2006			2005			2004			2003
Earnings:
Pre-tax income from continuing operations before cumulative effect of a change in accounting principle and before adjustment for minority interest and equity earnings (including amortization of excess cost of equity investments) per statements of income	$	430.5		$	965.8		$	760.1		$	769.6		$	616.1
Add:
Fixed charges		444.8			383.7			293.8			215.5			188.5
Amortization of capitalized interest		2.0			1.3			0.8			0.6			0.4
Distributed income of equity investees		101.6			66.3			61.1			63.9			81.7
Less:
Interest capitalized from continuing operations		(31.4	)		(20.3	)		(9.8	)		(6.3	)		(5.3	)
Minority interest in pre-tax income of subsidiaries with no fixed charges		(0.5	)		(0.5	)		(0.4	)		(0.1	)		—
Income as adjusted	$	947.0		$	1,396.3		$	1,105.6		$	1,043.2		$	881.4
Fixed charges:
Interest and debt expense, net per statements of income (includes amortization of debt discount, premium, and debt issuance costs; excludes capitalized interest)	$	428.5		$	365.8		$	278.2		$	202.5		$	188.1
Add:
Portion of rents representative of the interest factor		16.3			17.9			15.6			13.0			0.4
Fixed charges	$	444.8		$	383.7		$	293.8		$	215.5		$	188.5
Ratio of earnings to fixed charges		2.13			3.64			3.76			4.84			4.68

EX-21

KINDER MORGAN ENERGY PARTNERS, L.P.

Kinder Morgan Canada Company – Nova Scotia

Kinder Morgan North Texas Pipeline, L.P. - DE

Kinder Morgan Texas Gas Services LLC - DE

Kinder Morgan Transmix Company, LLC - DE

Kinder Morgan Interstate Gas Transmission LLC - CO

Kinder Morgan Trailblazer, LLC - DE

CGT Trailblazer, LLC - DE

Kinder Morgan Texas Pipeline, L.P. - DE

Kinder Morgan Operating L.P. “A” - DE

Kinder Morgan Operating L.P. “B” - DE

Kinder Morgan CO2 Company, L.P. - DE

Trailblazer Pipeline Company - IL

Kinder Morgan Bulk Terminals, Inc. - LA

Western Plant Services, Inc. - CA

Dakota Bulk Terminal, Inc. - WI

Delta Terminal Services LLC - DE

RCI Holdings, Inc. - LA

HBM Environmental, Inc. - LA

Milwaukee Bulk Terminals LLC - WI

Queen City Terminals, Inc. - DE

Kinder Morgan Port Terminals USA LLC - DE

Elizabeth River Terminals LLC - DE

Nassau Terminals LLC - DE

Fernandina Marine Construction Management LLC - DE

Kinder Morgan Port Manatee Terminal LLC - DE

Kinder Morgan Port Sutton Terminal LLC - DE

Pinney Dock & Transport LLC - OH

Kinder Morgan Operating L.P. “C” - DE

Kinder Morgan Operating L.P. “D” - DE

SFPP, L.P. - DE

Kinder Morgan Liquids Terminals LLC - DE

Kinder Morgan Pipeline LLC - DE

Kinder Morgan Tank Storage Terminals LLC - DE

Kinder Morgan 2-Mile LLC - DE

Rahway River Land LLC - DE

Central Florida Pipeline LLC - DE

Southwest Florida Pipeline LLC - DE

Calnev Pipe Line LLC - DE

Kinder Morgan Las Vegas LLC - DE

Globalplex Partners, Joint Venture - LA

Colton Processing Facility - CA

Kinder Morgan Materials Services, LLC - PA

CIG Trailblazer Gas Company, L.L.C. - DE

KM Trailblazer, LLC - DE

Kinder Morgan Border Pipeline, L.P. - DE

Tejas Gas, LLC - DE

Gulf Energy Gas, LLC - DE

Gulf Energy Gathering & Processing, LLC - DE

Gulf Energy Marketing, LLC - DE

Hydrocarbon Development, LLC - DE

Kinder Morgan Tejas Pipeline, L.P. - DE

Stellman Transportation, LLC - DE

Kinder Morgan Tejas Pipeline GP LLC - DE

Tejas Energy Partner, LLC - DE

Tejas Gas Systems, LLC - DE

Tejas-Gulf, LLC - DE

Tejas Natural Gas, LLC - DE

Kinder Morgan Pipeline Services of Mexico S. de R.L. de C.V. - Mexico

Valley Gas Transmission, LLC - DE

TransColorado LLC - DE

Silver Canyon Pipeline LLC - DE

Kinder Morgan Liquids Terminals St. Gabriel LLC - LA

Kinder Morgan Gas Natural de Mexico S. de R.L. de C.V. - Mexico

KM Production Company GP LLC - DE

Kinder Morgan Production Company LP - DE

Emory B Crane, LLC- LA

Frank L. Crane, LLC - LA

Paddy Ryan Crane, LLC - LA

Agnes B Crane, LLC - LA

KMBT LLC - DE

KM Production Company LP LLC - DE

KM Crane LLC - MD

MJR Operating LLC - MD

Kinder Morgan West Texas Pipeline, L.P. - DE

Kinder Morgan Southeast Terminals LLC - DE

International Marine Terminals - LA

I.M.T. Land Corp. - LA

ICPT, L.L.C. - LA

KM Crude Oil Pipelines GP LLC - DE

KM Crude Oil Pipelines LP LLC - DE

Kinder Morgan Crude Oil Pipelines, L.P. - DE

Kinder Morgan Carbon Dioxide Transportation Company - DE

Pecos Carbon Dioxide Transportation Company - TX

River Consulting, LLC – LA

KM Liquids Partners GP LLC - DE

KM Liquids Terminals, L.P. - DE

KM Liquids Holdings LLC - DE

Kinder Morgan Wink Pipeline, L.P. - DE

Kinder Morgan River Terminals LLC formerly Global Materials Services LLC- TN

Arrow Terminals B.V. - Dutch

Arrow Terminals Canada B. V. - Netherlands

Arrow Terminals Canada Company - NSULC

Kinder Morgan Arrow Terminals, L.P. LP - DE

Global American Terminals LLC - DE

Kinder Morgan Amory LLC - MS

Kinder Morgan Arrow Terminals Holdings, Inc. - DE

KM Decatur, Inc. - AL

Mid-South Port Transportation LLC

River Terminals Properties, LP - TN

Tajon Holdings, Inc. - PA

River Terminals Properties GP LLC - DE

Guilford County Terminal Company, LLC -NC

Johnston County Terminal, LLC

TransColorado Gas Transmission Company - CO

KM Upstream LLC -DE

Kinder Morgan Petcoke LP LLC - DE

Kinder Morgan Petcoke GP LLC - DE

Kinder Morgan Petcoke, L.P. - DE

Stevedore Holdings, L.P. - DE

Kinder Morgan NatGas Operator LLC - DE

General Stevedores Holdings LLC - DE

General Stevedores GP, LLC - TX

SRT Vessels LLC - DE

Carbon Exchange LLC - DE

Kinder Morgan Louisiana Pipeline Holding LLC - DE

Kinder Morgan Louisiana Pipeline LLC - DE

Kinder Morgan Pecos LLC - DE

Kinder Morgan W2E Pipeline LLC - DE

West2East Pipeline LLC - DE

Rockies Express Pipeline LLC formerly Entrega Gas Pipeline LLC- DE

Kinder Morgan Texas Terminals, L.P. - DE

Kinder Morgan Cameron Prairie Pipeline LLC - DE

Kinder Morgan Canada Terminals ULC - Alberta

Midcontinent Express Pipeline LLC - DE

Lomita Rail Terminal LLC - DE

Transload Services, LLC - IL

Devco USA, L.L.C. - OK

Kinder Morgan Cochin ULC - Alberta

Kinder Morgan Cochin LLC - DE

Kinder Morgan Seven Oaks LLC - DE

Kinder Morgan Columbus LLC - DE

KM Liquids Terminals LLC - DE

Kinder Morgan Production Company LLC - DE

Kinder Morgan Crude Oil Pipelines LLC - DE

Kinder Morgan Tejas Pipeline LLC - DE

Kinder Morgan Texas Pipeline LLC - DE

Kinder Morgan Wink Pipeline LLC - DE

Kinder Morgan North Texas Pipeline LLC - DE

Kinder Morgan Border Pipeline LLC - DE

Kinder Morgan Marine Services LLC - DE

Kinder Morgan Mid Atlantic Marine Services LLC - DE

TransColorado Gas Transmission Company LLC - DE

Trailblazer Pipeline Company LLC - DE

EX-23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-3 (Nos. 333-25995, 333-62155, 333-33726, 333-54616, 333-60912-01, 333-55866-01, 333-91316-01, 333-102961, 333-102962-01, 333-122424, 333-124471, 333-141491 and 333-142584) and (ii) Form S-8 (Nos. 333-56343 and 333-122168) of Kinder Morgan Energy Partners, L.P. of our report dated February 25, 2008 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, Texas

February 25, 2008

EX-23

CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.

As oil and gas consultants, we hereby consent to the use of our name and our report dated January 18, 2008, in this Form 10-K, incorporated by reference into Kinder Morgan Energy Partners, L.P.’s previously filed Registration Statement File Nos. 333-122424, 333-25995, 333-62155, 333-33726, 333-54616, 333-60912-01, 333-55866-01, 333-91316-01, 333-102961, 333-102962-01 333-124471, 333-141491 and 333-142584 on Form S-3, and 333-122168 and 333-56343 on Form S-8.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Danny D. Simmons
	Danny D. Simmons, P.E.
	President and Chief Operating Officer

Houston, Texas

February 13, 2008

EX-31

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

EXHIBIT 31.1 – CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Richard D. Kinder, certify that:

1. I have reviewed this annual report on Form 10-K of Kinder Morgan Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial information.

Date: February 25, 2008

/s/ Richard D. Kinder

Richard D. Kinder

Chairman and Chief Executive Officer

EX-31

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

EXHIBIT 31.2 – CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly A. Dang certify that:

1. I have reviewed this annual report on Form 10-K of Kinder Morgan Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial information.

Date: February 25, 2008

/s/ Kimberly A. Dang

Kimberly A. Dang

Vice President and Chief Financial Officer

EX-32

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

EXHIBIT 32.1 – CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. (the “Company”) for the yearly period ending December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Dated: February 25, 2008	/s/ Richard D. Kinder
	Richard D. Kinder,
	Chairman and Chief Executive Officer of Kinder Morgan
	Management, LLC, the delegate of Kinder Morgan G.P., Inc.,
	the General Partner of Kinder Morgan Energy Partners, L.P.

EX-32

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

EXHIBIT 32.2 – CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. (the “Company”) for the yearly period ending December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Dated: February 25, 2008	/s/ Kimberly A. Dang
	Kimberly A. Dang
	Vice President and Chief Financial Officer of Kinder Morgan
	Management, LLC, the delegate of Kinder Morgan G.P., Inc.,
	the General Partner of Kinder Morgan Energy Partners, L.P.