Kinder Morgan Energy Partners L P 10K 2008 Annual report


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, 2008

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 Noo

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. Yeso Nox

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. Yesx Noo

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 filerx Accelerated filero Non-accelerated filero Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yeso Nox

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 30, 2008 was approximately $9,043,981,544. As of January 31, 2009, the registrant had 183,169,827 Common Units outstanding.

KINDER MORGAN ENERGY PARTNERS, L.P.

TABLE OF CONTENTS


		Page Number

	PART I
Items 1 and 2.	Business and Properties	3
	General Development of Business	3
	Organizational Structure	3
	Recent Developments	4
	Financial Information about Segments	9
	Narrative Description of Business	9
	Business Strategy	9
	Business Segments	9
	Products Pipelines	10
	Natural Gas Pipelines	15
	CO₂	23
	Terminals	27
	Kinder Morgan Canada	29
	Major Customers	31
	Regulation	32
	Environmental Matters	35
	Other	37
	Financial Information about Geographic Areas	38
	Available Information	38
Item 1A.	Risk Factors	38
Item 1B.	Unresolved Staff Comments	51
Item 3.	Legal Proceedings	51
Item 4.	Submission of Matters to a Vote of Security Holders	51

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52
Item 6.	Selected Financial Data	53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
	Critical Accounting Policies and Estimates	57
	Results of Operations	60
	Liquidity and Capital Resources	77
	Recent Accounting Pronouncements	91
	Information Regarding Forward-Looking Statements	91
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	93
	Energy Commodity Market Risk	93
	Interest Rate Risk	95
Item 8.	Financial Statements and Supplementary Data	96
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	96
Item 9A.	Controls and Procedures	96
Item 9B.	Other Information	97

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	98
	Directors and Executive Officers of our General Partner and its Delegate	98
	Corporate Governance	100
	Section 16(a) Beneficial Ownership Reporting Compliance	101
Item 11.	Executive Compensation	101
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113
Item 13.	Certain Relationships and Related Transactions, and Director Independence	116
Item 14.	Principal Accounting Fees and Services	117

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	119
	Index to Financial Statements	123
Signatures		216

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 26,000 miles of pipelines and approximately 170 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 over $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. This transaction is referred to in this report as the “going-private transaction.”

As of December 31, 2008, Knight and its consolidated subsidiaries owned, through its general and limited partner interests, an approximate 14.1% 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. Including both its general and limited partner interests in us, at the 2008 distribution level, Knight received approximately 51% of all quarterly “Available Cash” distributions (as defined in our partnership agreement) from us, with approximately 44% and 7% of all quarterly distributions from us attributable to Knight’s general partner and limited partner interests, respectively.

Kinder Morgan Management, LLC, referred to as “KMR” in this report, is a Delaware limited liability company formed in February 2001. KMR’s shares represent limited liability company interests and trade on the New York Stock Exchange under the symbol “KMR.” 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.

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, 2008, KMR, through its ownership of our i-units, owned approximately 29.3% of all of our outstanding limited partner units.

Recent Developments

The following is a brief listing of significant developments since December 31, 2007. We begin with developments pertaining to our five reportable business segments, described more fully below in “—(c) Narrative Description of Business—Business Segments.” Additional information regarding most of these items may be found elsewhere in this report. All dollars in this report are United States dollars, except where stated otherwise. Canadian dollars are designated as C$.

Products Pipelines


	•	In October 2008, we successfully completed a series of tests demonstrating the commercial feasibility of transporting batched denatured ethanol on our 16-inch diameter gasoline pipeline that extends between Tampa and Orlando, Florida. After making certain mechanical modifications to the pipeline in late November, we began batching denatured ethanol shipments along with gasoline shipments for our customers, making our Central Florida Pipeline the first gasoline pipeline in the U.S. capable of also handling ethanol in commercial movements.

		In addition to the Central Florida Pipeline ethanol project, we have approved over $90 million in ethanol and biofuel related capital expenditure projects, including modifications to tanks, truck racks and related infrastructure for new or expanded ethanol and biodiesel service at various owned, operated, and/or third party terminal facilities located in the Southeast and the Pacific Northwest. We plan on offering ethanol blending capabilities in twelve of fifteen markets served by our Southeast terminals by the end of 2009.

	•	In October 2008, Plantation Pipe Line Company successfully shipped a 20,000 barrel batch of blended biodiesel (a 5% blend commonly referred to as B5). The shipment originated at Collins, Mississippi and was delivered to a customer terminal located in Spartanburg, South Carolina. Plantation is currently developing plans to expand its capability to deliver biodiesel to at least ten markets served by its pipeline system in the Southeast. Assuming sufficient commercial support, Plantation expects to be moving forward with investments to provide this service during the second quarter of 2009.

	•	In November 2008, our West Coast Products operations completed an approximate $25 million expansion project that included the construction of four 80,000 barrel tanks and ancillary facilities that provide military jet fuel and marine diesel fuel service to the U.S. Marine Corps Naval Air Station in Miramar, California and the Naval Air Station in Point Loma, California.

	•	On December 10, 2008, our West Coast Products operations purchased a 200,000 barrel refined petroleum products terminal located in Phoenix, Arizona from ConocoPhillips for approximately $27.5 million in cash.

	Natural Gas Pipelines

	•	Effective April 1, 2008, we sold our 25% equity ownership interest in Thunder Creek Gas Services, LLC to PVR Midstream LLC, a subsidiary of Penn Virginia Corporation, for approximately $50.7 million in cash. Our investment in net assets, including all transaction related accruals, was approximately $37.7 million, and we recognized $13.0 million of gain on the sale of our investment. We reported the gain within the caption


		“Other, net” on our accompanying consolidated statements of income. For additional information regarding this divestiture, see Note 3 to our consolidated financial statements.

	•	On May 20, 2008, transportation service on the final 210 miles of the Rockies Express-West pipeline segment commenced. Interim service for up to 1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles of pipe began on January 12, 2008. The Rockies Express-West pipeline segment is the second phase of the Rockies Express Pipeline and consists of a 713-mile, 42-inch diameter pipeline that extends from the Cheyenne Hub in Weld County, Colorado to an interconnect with Panhandle Eastern Pipeline Company in Audrain County, Missouri. Now fully operational, Rockies Express-West has the capacity to transport up to 1.5 billion cubic feet of natural gas per day and can make deliveries to interconnects with our Kinder Morgan Interstate Gas Transmission Pipeline, Northern Natural Gas Company, Natural Gas Pipeline Company of America LLC, ANR and Panhandle Eastern Pipeline Company.

	•	On May 30, 2008, the Federal Energy Regulatory Commission, referred to in this report as the FERC, issued an order authorizing construction of the Rockies Express-East pipeline segment, the third phase of the Rockies Express Pipeline. Rockies Express-East is a 639-mile, 42-inch diameter pipeline that will extend from Audrain County, Missouri to Clarington, Ohio. When fully completed, the 1,679-mile Rockies Express Pipeline will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments from creditworthy shippers have been secured for all of the pipeline capacity. We are a 51% owner in Rockies Express, and we currently estimate the total project cost for the entire Rockies Express Pipeline to be approximately $6.2 billion.

		Construction on Rockies Express-East is in progress and, subject to the receipt of regulatory approvals, initial service on the pipeline is projected to commence April 1, 2009. The initial service will provide for capacity of up to 1.6 billion cubic feet per day to interconnects upstream of Lebanon, Ohio, followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15, 2009. Final pipeline completions and fully powered deliveries to Clarington, Ohio are expected to commence by November 1, 2009.

	•	In June 2008, our Texas intrastate group began gas injections into a fifth cavern at its salt dome storage facility located near Markham, Texas as part of an $84 million expansion. After final developments were completed in January 2009, the project added 7.5 billion cubic feet of natural gas working storage capacity, and gas injection capacity will increase by approximately 110 million cubic feet per day upon completion of compression installation in spring 2009. In addition, our intrastate group’s approximately $13 million Texas Hill Country natural gas compression project was completed in January 2009, resulting in 45 million cubic feet of incremental pipeline capacity out of West Texas, primarily serving the Austin, Texas market.

	•	On July 25, 2008, the FERC approved the application made by Midcontinent Express Pipeline LLC to construct and operate the approximately 500-mile Midcontinent Express Pipeline natural gas transmission system along with the lease of 272 million cubic feet of capacity on the Oklahoma intrastate system of Enogex Inc. We own a 50% interest in Midcontinent Express Pipeline LLC, the sole owner of the Midcontinent Express Pipeline. Energy Transfer Partners L.P. owns the remaining interest.

		The project is expected to cost approximately $2.2 billion, including previously announced expansions. This is an increase from the $1.9 billion previous forecast. Much of the increase is attributable to increased construction cost. Midcontinent Express is currently finalizing negotiations with contractors for construction of the final segment. Those contracts will fix the per unit prices, providing greater cost certainty on that portion of the project and those construction costs are incorporated into the current forecast.

		Interim service on the first portion of the pipeline from Bryan County, Oklahoma to an interconnection with Columbia Gulf Transmission Corporation near Perryville, Louisiana is expected to be available in April of 2009. The second construction phase—to the Transco Pipeline—is expected to be completed by August 1, 2009. The Midcontinent Express’ capacity is fully subscribed with long-term binding commitments from creditworthy shippers.

	•	In September 2008, we completed construction on an approximately $75 million natural gas pipeline that transports additional East Texas natural gas supplies to markets in the Houston and Beaumont, Texas areas. It connects our Kinder Morgan Tejas system in Houston County, Texas to our Kinder Morgan Texas Pipeline system in Polk County near Goodrich, Texas. 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 consists of approximately 225 million cubic feet per day of natural gas.

	•	On October 1, 2008, we and Energy Transfer Partners, L.P. announced that we have entered into a joint venture to build and develop the Fayetteville Express Pipeline, a new $1.2 billion natural gas pipeline that will provide shippers in the Arkansas Fayetteville Shale area with takeaway natural gas capacity and further access to growing markets. This project is expected to be in service in 2010 or early 2011 and has secured binding 10-year commitments totaling 1.85 billion cubic feet per day.

	•	In October 2008, we completed construction on an approximately $22 million expansion project on our Kinder Morgan Interstate Gas Transmission pipeline system that provides for the delivery of natural gas to five separate industrial plants (four of which produce ethanol) located near Grand Island, Nebraska. The project is fully subscribed with long-term customer contracts.

	•	On November 24, 2008, our Kinder Morgan Interstate Gas Transmission system completed construction and placed into service its previously announced Colorado Lateral Pipeline. The approximately $39 million expansion project that extends from the Cheyenne Hub to interconnects with Atmos Energy’s pipeline near Greeley, Colorado. The pipeline provides firm natural gas transportation of up to 74 million cubic feet per day to local distribution companies and to industrial end users.

	CO₂

	•	As of February 1, 2009, our CO₂ business segment was nearing completion of its previously announced southwest Colorado carbon dioxide expansion project. Combined, the expansion will cost its owners approximately $290 million and includes developing a new carbon dioxide source field (named the Doe Canyon Deep Unit), drilling new wells, and expanding infrastructure at both the McElmo Dome Unit and the Cortez Pipeline. The entire expansion increases carbon dioxide supplies by approximately 300 million cubic feet per day to our customers.

		The Doe Canyon source field began operations in January 2008 and is currently delivering 120 million cubic feet per day of carbon dioxide. The first compression train of the Goodman Point expansion at the McElmo Dome source field was placed in service in June 2008 at a rate of 108 million cubic feet per day of carbon dioxide. The second compression train was brought on in October 2008 (after the activation of the Blanco pump station on the Cortez Pipeline) and increased the production rate to 207 million cubic feet per day of carbon dioxide. In 2009, the Goodman Point plant has averaged 232 million cubic feet per day of carbon dioxide. In October of 2008, we activated the Blanco pump station on the Cortez Pipeline utilizing power from diesel generators, and in January 2009, we began construction on a new power line that will connect the Blanco pumps to the power grid. The new power line is expected to be in service by the end of the third quarter of 2009. We own a 50% interest in the Cortez Pipeline, which currently delivers approximately 1.3 billion cubic feet per day of carbon dioxide.

	Terminals

	•	On January 16, 2008, we announced plans 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 March 20, 2008, we announced the completion of several expansion projects representing a total investment of more than $500 million at various bulk and liquids terminal facilities. The primary investment projects included (i) an approximately $195 million expansion for additional tankage at our combined Galena Park/Pasadena, Texas liquids terminal facilities located on the Houston, Texas Ship Channel; (ii) an approximately C$170 million investment to construct our Kinder Morgan North 40 terminal, a crude oil tank farm situated on approximately 24 acres near Edmonton, Alberta, Canada; (iii) an approximately $70 million capital improvement project at our Pier IX bulk terminal located in Newport News, Virginia; and (iv)


		approximately $68 million for the construction of nine new liquid storage tanks at our Perth Amboy, New Jersey liquids terminal located on the New York Harbor.

		The storage expansion at our Galena Park/Pasadena terminals brings total capacity of the combined complex to approximately 25 million barrels. As previously announced, the building of our Kinder Morgan North 40 terminal included the construction of nine storage tanks with a combined capacity of approximately 2.15 million barrels for crude oil, all of which is subscribed by shippers under long-term contracts. The Pier IX project involved the construction of a new ship dock and the installation of a new import coal facility that is expected to increase terminal throughput by 30% to about nine million tons a year. The expansion at Perth Amboy included the building of nine new liquid storage tanks, which increased capacity for refined petroleum products and chemicals by 1.4 million barrels, bringing total terminal capacity to approximately 3.7 million barrels.

	•	Effective August 5, 2008, we acquired certain terminal assets from Chemserv, Inc. for an aggregate consideration of approximately $12.7 million, consisting of $11.8 million in cash and $0.9 million in assumed liabilities. The acquired assets are primarily involved in the storage of petroleum products and chemicals.

	•	In December 2008, we began operations at our approximately $47 million terminal at the Rubicon Plant site located in Geismar, Louisiana, which offers liquids storage, transfer and packaging facilities. The newly constructed terminal has liquids storage capacity of approximately 123,500 barrels and has approximately 144,000 square feet of warehouse space.

	Kinder Morgan Canada

	•	Effective August 28, 2008, we acquired a 33 1/3% equity ownership interest in the Express and Platte crude oil pipeline systems from Knight. We also acquired full ownership of an approximate 25-mile Jet Fuel pipeline system that serves the Vancouver (Canada) International Airport. As consideration for these assets, we paid to Knight approximately two million of our common units, valued at $116.0 million. For additional information regarding this acquisition, see Note 3 to our consolidated financial statements.

	•	On October 30, 2008, we completed the construction and commissioning of our approximately C$544 million Anchor Loop project, the second and final phase of a Trans Mountain pipeline system expansion that in total, increased pipeline capacity from approximately 225,000 to 300,000 barrels of crude oil per day. In April 2007, we completed the first phase of the Trans Mountain Pipeline expansion, which included the commissioning of ten new pump stations that boosted pipeline capacity from 225,000 to approximately 260,000 barrels per day.

		The Anchor Loop project involved twinning (or looping) a 158-kilometer section of the existing pipeline system between Hinton, Alberta and Hargreaves, British Columbia, and was completed in two phases: (i) 97-kilometers of 30 and 36-inch diameter pipe and two new pump stations that increased the capacity of the pipeline system by 25,000 barrels per day (the Jasper spread completed on April 28, 2008); and (ii) 61-kilometers of 36-inch diameter pipe that increased the capacity of the pipeline system by an incremental 15,000 barrels per day (the Mount Robson spread in British Columbia completed on October 30, 2008). The pipeline system is currently operating at full capacity, and only final right-of-way restoration on the Mount Robson spread remains for summer 2009.

	Debt and Equity Offerings, Swap Agreements, Cash Distributions and Debt Retirements

	•	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 used the net proceeds to reduce the borrowings under our commercial paper program.

		Also on this date, 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 and we used the net proceeds to reduce the borrowings under our commercial paper program.


	•	In March 2008, we completed a public offering of 5,750,000 of our common units at a price of $57.70 per unit, less commissions and underwriting expenses and we used the net proceeds to reduce the borrowings under our commercial paper program.

	•	On June 6, 2008, we completed a $700 million public offering of senior notes and we used the net proceeds to reduce the borrowings under our commercial paper program.

	•	On November 24, 2008, we announced that we expect to declare cash distributions of $4.20 per unit for 2009, a 4.5% increase over our cash distributions of $4.02 per unit for 2008. Our expected growth in distributions in 2009 assumes an average West Texas Intermediate crude oil price of $68 per barrel in 2009 with some minor adjustments for timing, quality and location differences. Based on actual prices received through the first seven weeks of 2009 and the forward curve, adjusted for the same factors as the budget, our average realized price for 2009 is currently projected to be $43 per barrel. Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO2 business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. We hedge the majority of our crude oil production, but do have exposure to unhedged volumes, the majority of which are natural gas liquids volumes. For 2009, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 segment’s cash flows by approximately $6 million (or approximately 0.2% of our combined business segments’ anticipated distributable cash flow). This sensitivity to the average WTI price is very similar to what we experienced in 2008. Our 2009 cash distribution expectations do not take into account any capital costs associated with financing any payment we may be required to make of reparations sought by shippers on our Pacific operations’ interstate pipelines.

	•	On December 19, 2008, we closed a public offering of $500 million in principal amount of senior notes and we used the proceeds to reduce the borrowings under our five-year unsecured revolving bank credit facility.

	•	On December 22, 2008, we completed a public offering of 3,900,000 of our common units at a price of $46.75 per unit, less commissions and underwriting expenses. We used the net proceeds to reduce the borrowings under our bank credit facility.

	•	In December 2008 and January 2009, we terminated three existing fixed-to-variable interest rate swap agreements in three separate transactions. These swap agreements had a combined notional principal amount of $1.0 billion and we received combined proceeds of $338.7 million from the early termination of these swap agreements;

	•	On February 2, 2009, we paid $250 million to retire the principal amount of our 6.3% senior notes that matured on that date.

Capital Expansion Projects

Our capital expansion program in 2008 was approximately $2.9 billion (for maintenance/sustaining and expansion/discretionary capital spending, and including our equity contributions to the Rockies Express, Midcontinent Express, and Fayetteville Express natural gas pipeline projects). In 2009, we expect our capital expansion program to be approximately $2.8 billion (including our equity contributions to the Rockies Express and Midcontinent Express projects), which will help drive earnings and cash flow growth in 2009 and beyond.

In addition to the ongoing construction of both the Rockies Express-East pipeline segment and the Midcontinent Express Pipeline discussed above in “—Natural Gas Pipelines,” construction and/or expansion plans continue on the following major projects:


	•	Kinder Morgan Louisiana Pipeline. Construction continues on our fully-owned Kinder Morgan Louisiana Pipeline and our current cost estimate for this natural gas transmission system is approximately $950 million. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total, and we anticipate the pipeline to become fully operational in the second quarter of 2009.

	•	Rockies Express Pipeline. Rockies Express is requesting authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne, Wyoming expansion project. The proposed expansion will add additional natural gas compression. The expansion is fully contracted and is expected


		to be operational in April 2010. The total estimated cost for the proposed project is approximately $78 million.

	•	Cora Terminal. Construction continues on an approximately $13 million expansion at our Cora coal terminal, located in Rockwood, Illinois along the upper Mississippi River. The project will increase terminal storage capacity by approximately 250,000 tons (to 1.25 million tons) and will expand maximum throughput at the terminal to approximately 13 million tons annually. We expect the Cora expansion project to be completed in the second quarter of 2009.

	(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.

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.

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.

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 14,300 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;


	•	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 110 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

	•	Kinder Morgan Canada—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. It also includes a one-third interest in an approximately 1,700-mile integrated crude oil pipeline connecting Canadian and United States producers to refineries in the U.S. Rocky Mountain and Midwest regions, and a 25-mile aviation turbine fuel pipeline serving the Vancouver International Airport.

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.

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.

West Coast Products Pipelines

Our West Coast Products Pipelines operations include our SFPP, L.P. operations, our Calnev Pipeline operations and our West Coast 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 SFPP, L.P. operations, also referred to in this report as Pacific operations, serve six western states with approximately 3,100 miles of refined petroleum products pipelines and related terminal facilities that provide refined products to major population centers in the United States, including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. For 2008, the three main product types transported were gasoline (59%), diesel fuel (23%) and jet fuel (18%).

Our Calnev Pipeline 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. The pipeline serves the Mojave Desert through deliveries to a terminal at Barstow California and two nearby major railroad yards. It also serves Nellis Air Force Base, located in Las Vegas, and also includes approximately 55 miles of pipeline serving Edwards Air Force Base.

Our West Coast Products Pipelines operations include 15 truck-loading terminals (13 on SFPP, L.P. and two on Calnev) with an aggregate usable tankage capacity of approximately 14.9 million barrels. The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.

Our West Coast 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 8.4 million barrels of storage for both petroleum products and chemicals.

Markets.Combined, our West Coast Products Pipelines 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 15 military bases. Currently, our West Coast Products Pipelines 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, and generally, in turn the volumes we transport, depends on such factors as prevailing economic conditions, vehicular use and purchase patterns and demographic changes in the markets served. Certain product volumes can also 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 West Coast Product Pipelines operations’ pipeline system come from the major refining centers around Los Angeles, San Francisco, West Texas 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 West Coast Products Pipelines 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 West Coast Products Pipelines operations will be built in the foreseeable future. However, the possibility of individual pipelines such as the Holly pipeline to Las Vegas, Nevada, 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 West Coast Products Pipelines 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 Corporation 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 2008, Plantation delivered an average of 480,341 barrels per day of refined petroleum products. These delivered volumes were comprised of gasoline (61%), diesel/heating oil (25%) and jet fuel (14%). Average delivery volumes for 2008 were 10.3% lower than the 535,672 barrels per day delivered during 2007, and 13.5% lower than the 555,063 barrels per day delivered during 2006. The decrease was predominantly driven by (i) changes in production patterns from Louisiana refineries related to refiners directing higher margin products (such as reformulated gasoline blendstock for oxygenate blending) into markets not directly served by Plantation; (ii) a rapid increase in ethanol blending in the Southeast resulting in lower pipeline-delivered gasoline volumes; and (iii) lower regional demand as a result of high product prices during the first part of the year and a slowing economy.

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 decreased 12% in 2008 compared to 2007, with the majority of this decline 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 (i) a 110-mile, 16-inch diameter pipeline that transports gasoline and beginning in November 2008, ethanol and (ii) 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 2008, the pipeline system transported approximately 106,700 barrels per day of refined products, with the product mix being approximately 68% gasoline, 12% diesel fuel, and 20% jet fuel.

We 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, ethanol, 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 bio-diesel. The Taft terminal contains approximately 0.7 million barrels of storage capacity, for gasoline, ethanol, 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 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 our 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 our 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 2008, the pipeline system transported approximately 30,800 barrels per day of natural gas liquids.

Markets. The pipeline traverses three provinces in Canada and seven states in the United States and can transport 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, 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. In 2008, the pipeline system transported approximately 43,900 barrels per day of refined petroleum products.

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 351,000 barrels of refined products per day during 2008 and approximately 361,000 barrels of refined products per day during 2007.

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. During 2008, KMST expanded its ethanol blending and storage services beyond northern Virginia into several conventional gasoline markets. The new ethanol blending facilities are located in Athens and Doraville, Georgia; North Augusta, South Carolina; Charlotte, Greensboro, and Selma, North Carolina. 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 Colonial pipelines with a number of terminals connected to both 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 both 2008 and 2007.

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 14,300 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

Our Texas intrastate natural gas pipeline group, which operates primarily along the Texas Gulf Coast, consists of the following four natural gas pipeline systems (i) our Kinder Morgan Texas Pipeline; (ii) our Kinder Morgan Tejas Pipeline; (iii) our Mier-Monterrey Mexico Pipeline; and (iv) 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 126 billion cubic feet of on-system natural gas storage capacity. In addition, the combined system, through owned assets and contractual arrangements with third parties, has the capability to process 685 million cubic feet per day of natural gas for liquids extraction and to treat approximately 180 million cubic feet per day of natural gas for carbon dioxide removal.

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/Austin 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 Pipeline 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 in Hidalgo County, Texas, to a point of interconnection with other intrastate pipeline facilities of Kinder Morgan Tejas located at King Ranch, Kleburg County, Texas. The pipeline has a capacity of approximately 300 million cubic feet of natural gas per day and is capable of importing this volume of Mexican gas into the United States or exporting this volume of gas to Mexico.

Our Mier-Monterrey Pipeline consists of a 95-mile natural gas pipeline that stretches from the International Border between the United States and Mexico in Starr County, 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 82-mile pipeline that transports natural gas from an interconnect with the facilities of Natural Gas Pipeline Company of America LLC (a 20% owned equity investee of Knight and 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. The system is bi-directional, permitting deliveries of additional supply from the Barnett Shale area to 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 135 million cubic feet per day of natural gas for liquids extraction, and we have contractual rights to process approximately 550 million cubic feet per day of natural gas at third-party owned facilities. We also share in gas processing margins on gas processed at certain third-party owned facilities. Additionally, we own and operate three natural gas treating plants that provide carbon dioxide and/or hydrogen sulfide removal. We can treat up to 85 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 Energy, Inc. 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, Shell Energy North America (US), 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 additional ten-year periods. The facility was expanded in 2008 and now consists of five salt dome caverns with approximately 24.8 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 Ineos USA, LLC 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 150 million cubic feet per day. In addition to the aforementioned storage facilities, we contract for storage services from third parties, which we then sell to customers on our pipeline system.

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.

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 2008, deliveries through the existing interconnection near Arguellas fluctuated from zero to approximately 295 million cubic feet per day of natural gas, and there were several days of exports to the United States which ranged up to 288 million cubic feet per day. Deliveries to Monterrey also generally ranged from zero to 321 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 liquefied natural gas from the Freeport LNG terminal near Freeport, Texas and from the Golden Pass Terminal currently under development by ExxonMobil south of Beaumont, Texas.

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.

Western Interstate Natural Gas Pipeline Group

Our Western interstate natural gas pipeline 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 (i) our Kinder Morgan Interstate Gas Transmission Pipeline; (ii) our Trailblazer Pipeline; (iii) our Trans Colorado Pipeline; and (iv) 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 powered by 26 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. KMIGT has seen a significant increase in demand from ethanol producers, and has expanded its system to meet the demands from the ethanol producing community. Additionally, in the November 2008, KMIGT completed the construction of the Colorado Lateral, which is a 41-mile, 12-inch pipeline from the Cheyenne Hub southward to the Greeley, Colorado area. Atmos Energy is served by this pipeline under a long-term firm transportation contract, and KMIGT is marketing additional capacity along its route.

Supply. Approximately 11%, by volume, of KMIGT’s firm contracts expire within one year and 57% expire within one to five years. Over 95% of the system’s total firm transport capacity is currently subscribed, with 69% of the total contracted capacity held by KMIGT’s top ten 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, referred to in this report as Trailblazer, 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 manages, maintains and operates Trailblazer for us, for which it is reimbursed at cost. Trailblazer offers its customers firm and interruptible transportation.

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, 2008, approximately 6% of Trailblazer’s firm contracts, by volume, expire before one year and 53%, 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.

Competition. The main competition that Trailblazer currently faces is that the gas supply in the Rocky Mountain area is transported on competing pipelines to the west or east. 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 Rockies Express Pipeline can transport approximately 1.6 billion cubic feet per day of natural gas from the Rocky Mountain area to Midwest markets. These systems compete with Trailblazer for natural gas pipeline transportation demand from the Rocky Mountain area. Additional competition could come from other 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, referred to in this report as TransColorado, 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 40,000 horsepower.

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. 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 placed into service on January 1, 2008. The project increased 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 2008, TransColorado transported an average of approximately 675 million cubic feet per day of natural gas from these supply basins.

Supply. During 2008, 93% of TransColorado’s transport business was with processors or producers or their own marketing affiliates, and 7% was with marketing companies and various gas marketers. Approximately 69% of TransColorado’s transport business in 2008 was conducted with its three largest customers. All of TransColorado’s long-haul southbound pipeline capacity is committed under firm transportation contracts that extend at least through year-end 2009. Of TransColorado’s transportation contracts, 41%, by volume, expire within one to five years, and TransColorado is actively pursuing contract extensions and/or replacement contracts to increase firm subscription levels beyond 2009.

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 and at the north end of its system to accommodate greater natural gas volumes.

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 basin 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 project is expected to cost $6.3 billion, including a previously announced expansion, and will have the capability to transport 1.8 billion cubic feet per day of natural gas. Binding firm commitments have been secured for 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 because 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.

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 included 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 was completed in the fourth quarter of 2008, in order to meet an expected in-service date of April 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) became fully operational on May 20, 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 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 approved the application on May 30, 2008 and construction commenced on the REX-East Project on June 26, 2008. Rockies Express-East is currently projected to commence service on April 1, 2009 to interconnects upstream of Lebanon, followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15, 2009. Final completion and deliveries to Clarington, Ohio are expected to commence by November 1, 2009.

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. In addition, through the pipeline’s Zone 1 facilities, shippers have 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 and Zone 3 facilities into 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 is capable of delivering 1.5 billion cubic feet per day through these interconnects to the Midcontinent market.

The Zone 3 facilities covered by the REX-East project extend eastward from the REX-West facilities and will permit delivery to pipelines and local distribution companies providing service on the southern, midwestern and

eastern seaboards. The interconnecting interstate pipelines include Midwestern Gas Transmission, Trunkline, ANR, Columbia Gas, Dominion Transmission, Tennessee Gas, Texas Eastern, Texas Gas and Dominion East Ohio, and the local distribution companies include Ameren and Vectren.

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 interstate pipelines and local distribution companies with facilities in Ohio and beyond.

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, including Ruby Pipeline which filed in January 2009 for FERC authority to build a pipeline from Opal, Wyoming to Malin, Oregon, with a planned in-service date of March 2011.

Central Interstate Natural Gas Pipeline Group

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 $950 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 20 year take-or-pay 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); 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.

We anticipate the Kinder Morgan Louisiana Pipeline will be fully operational during the third quarter of 2009. We designed and are constructing the Kinder Morgan Louisiana Pipeline in a manner that minimizes environmental impacts, and where possible, existing pipeline corridors are being used to minimize impacts to communities and to the environment. As of December 31, 2008, 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 project is expected to cost approximately $2.2 billion, including previously announced expansions. This is an increase from the $1.9 billion previous forecast. Much of the increase is attributable to increased construction cost. Midcontinent Express is currently finalizing negotiations with contractors for construction of the final segment. Those contracts will fix the per unit prices, providing greater cost certainty on that portion of the project and those construction costs are incorporated into the current forecast.

In January 2008, in conjunction with the signing of additional binding transportation commitments, Midcontinent Express and 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%.

Fayetteville Express Pipeline LLC

The Fayetteville Express Pipeline, when completed, will be a 187-mile, 42-inch diameter pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnect with Trunkline Gas Company’s pipeline in Quitman County, Mississippi. We own a 50% interest in Fayetteville Express Pipeline LLC and Energy Transfer Partners L.P. owns the remaining interest.

The Fayetteville Express Pipeline will also interconnect with Natural Gas Pipeline Company of America LLC’s pipeline in White County, Arkansas, Texas Gas Transmission LLC’s pipeline in Coahoma County, Mississippi, and ANR Pipeline Company’s pipeline in Quitman County, Mississippi. The Fayetteville Express Pipeline will have an initial capacity of 2.0 billion cubic feet of natural gas per day. Pending necessary regulatory approvals, the approximate $1.2 billion pipeline project is expected to be in service by late 2010 or early 2011. Fayetteville Express Pipeline LLC has secured binding 10-year commitments totaling approximately 1.85 billion cubic feet per day, and completed a successful binding open season for shippers on November 7, 2008.

Upstream

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 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 three 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 1,200 producing wells, 85,000 horsepower of compression at 21 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.

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. In 2008, we completed the installation of facilities and drilled eight wells that increased the production capacity from McElmo Dome by over 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 87% of the Doe Canyon Deep unit in Colorado, which contains more than 1.5 trillion cubic feet of carbon dioxide. In 2008, we completed the installation of facilities and drilled six wells to produce over 100 million cubic feet per day of carbon dioxide.

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 PetroSource Energy Company, L.P., a wholly-owned subsidiary of SandRidge Energy, Inc, 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 1.2 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 700 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 carbon dioxide 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.

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, an approximate 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 1.31 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.

In 2008, the average purchased CO₂ injection rate was 259 million cubic feet per day, up from an average of 212 million cubic feet per day in 2007. The average oil production rate for 2008 was approximately 28,000 barrels of oil per day, up from an average of approximately 27,600 barrels of oil per day during 2007. The average natural gas liquids production rate (net of the processing plant share) for 2008 was approximately 5,500 barrels per day, a decrease from an average of approximately 6,300 barrels per day during 2007.

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 during 2008, the Yates unit produced about 27,600 barrels of oil per day, up from an average of approximately 27,000 barrels of oil per day during 2007. 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 the unit produced 235 barrels of oil per day during 2008, up from an average of 218 barrels of oil per day during 2007. 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 during 2008, the field produced 425 barrels of oil per day, up from an average of 408 barrels of oil per day during 2007. 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, 2008. 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:


	Productive Wells (a)				Service Wells (b)				Drilling Wells (c)

	Gross		Net		Gross		Net		Gross		Net

Crude Oil		2,906		2,029		895		700		4		4
Natural Gas		6		3		36		18		—		—

Total Wells		2,912		2,032		931		718		4		4




(a)	Includes active wells and wells temporarily shut-in. As of December 31, 2008, 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, 2008. 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, 2008, 2007 and 2006:


	2008	2007	2006

Productive
Development	47	31	37
Exploratory	—	—	—
Dry
Development	—	—	—
Exploratory	—	—	—

Total Wells	47	31	37




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, 2008:


	Gross	Net

Developed Acres	72,435	67,731
Undeveloped Acres	9,555	8,896

Total	81,990	76,627

Operating Statistics

Operating statistics from our oil and gas producing activities for each of the years 2008, 2007 and 2006 are shown in the following table:


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

	Year Ended December 31,

	2008		2007		2006

Consolidated Companies(a)
Production costs per barrel of oil equivalent(b)(c)(d)	$	20.44	$	16.22	$	13.30

Crude oil production (MBbl/d)		36.2		35.6		37.8

Natural gas liquids production (MBbl/d)(d)		4.8		5.5		5.0
Natural gas liquids production from gas plants(MBbl/d)(e)		3.5		4.1		3.9

Total natural gas liquids production(MBbl/d)		8.3		9.6		8.9

Natural gas production (MMcf/d)(d)(f)		1.4		0.8		1.3
Natural gas production from gas plants(MMcf/d)(e)(f)		0.2		0.3		0.3

Total natural gas production(MMcf/d)(f)		1.6		1.1		1.6

Average sales prices including hedge gains/losses:
Crude oil price per Bbl(g)	$	49.42	$	36.05	$	31.42

Natural gas liquids price per Bbl(g)	$	63.48	$	52.22	$	43.52

Natural gas price per Mcf(h)	$	7.73	$	6.08	$	6.36

Total natural gas liquids price per Bbl(e)	$	63.00	$	52.91	$	43.90

Total natural gas price per Mcf(e)	$	7.63	$	5.89	$	7.02

Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl(g)	$	97.70	$	69.63	$	63.27

Natural gas liquids price per Bbl(g)	$	63.48	$	52.22	$	43.52

Natural gas price per Mcf(h)	$	7.73	$	6.08	$	6.36




(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 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 2008 was approximately 13,900 barrels per day as compared to 15,500 barrels per day as of December 2007.

Crude Oil Pipeline

Our Kinder Morgan Wink Pipeline is 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 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 approximately 118,000 barrels of oil per day in 2008, and approximately 119,000 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 approximately 117 owned or operated liquids and bulk terminal facilities, and more than 32 rail transloading and materials handling facilities located throughout the United States, Canada, and the Netherlands.

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 54.2 million barrels, and in 2008, these terminals handled approximately 596 million barrels of petroleum, chemicals and vegetable oil products.

In the first quarter of 2008, we completed the Phase III expansions at our Pasadena and Galena Park, Texas liquids terminal facilities. The expansions provided additional infrastructure to help meet the growing need for refined petroleum products storage capacity along the Gulf Coast. The investment of approximately $195 million included 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 with ethanol handling infrastructure located at our Pasadena terminal. All of the expansions are supported by long-term customer commitments. With the completion of this expansion, the Pasadena and Galena Park terminal facilities will have a storage capacity of approximately 25 million barrels.

In 2008, we announced additional expansions at our Pasadena and Galena Park terminal facilities. The investment of approximately $114 million includes the construction of the following: (i) 12 new storage tanks at our Pasadena and Galena Park terminals; (ii) a barge dock that will be capable of handling two 300-foot barges with an operating crane for each location; and (iii) a 20-inch, cross-channel line connecting the two facilities. All of the expansions are supported by long-term customer commitments.

In the second quarter of 2008, we completed and put into service approximately 2.15 million barrels of new crude oil capacity at our Kinder Morgan North 40 terminal located near Edmonton, Alberta, Canada. The entire capacity of this terminal is contracted with long-term contracts. The tank farm serves as a premier blending and storage hub for Canadian crude oil. Originally estimated at C$132.6 million, our total investment in this tank farm is now projected to be approximately C$170 million due primarily to additional labor costs. The tank farm has 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 300,000 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.

In the first quarter of 2008, we completed construction and placed into service nine new storage tanks at our Perth Amboy, New Jersey liquids terminal. The tanks have a combined storage 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 for this expansion was approximately $68 million.

In the third quarter of 2008, we completed and put into service approximately 320,000 barrels of additional gasoline capacity at our Shipyard River Terminal located in Charleston, South Carolina. This increase will bring the terminal storage capacity to approximately 1.9 million barrels for petroleum, ethanol and other liquid chemicals.

In September 2008 we purchased the Kinder Morgan Wilmington terminal, located in Wilmington, North Carolina, which has approximately 1.1 million barrels of liquids storage capacity. The facility has significant transportation infrastructure and provides liquid and heated storage and custom tank blending capabilities for agricultural and chemical products.

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 handling, conveying, maintenance and repair, railcar switching and miscellaneous marine services. Combined, our dry-bulk and material transloading facilities handled approximately 99.1 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2008. We own or operate approximately 100 dry-bulk terminals in the United States, Canada and the Netherlands.

In May 2007, we purchased certain buildings and equipment and entered into a 40 year agreement to operate Vancouver Wharves, a bulk marine terminal located at the entrance to the Port of Vancouver, British Columbia. To acquire the terminal assets, we gave an aggregate consideration of $59.5 million, consisting of $38.8 million in cash and $20.7 million in assumed liabilities. 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 our original purchase price, we plan to spend an additional C$57 million at Vancouver Wharves to upgrade and/or relocate certain rail track and transloading systems, buildings and a shiploader. The rail track and transloading relocations are on schedule to be completed in the second quarter of 2009. The shiploader project is expected to be completed in the fourth quarter of 2009.

Effective September 1, 2007, we purchased the assets of Marine Terminals, Inc. for an aggregate consideration of approximately $102.1 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.

In the first quarter of 2008, we completed and put into service a barge unloading terminal located on 30 acres in Columbus, Mississippi. Our Columbus terminal provides for approximately 900,000 tons of capacity, and handles scrap metal, pig iron and hot briquetted iron that is brought in by barge, unloaded, and then trucked to the Severstal Steel Mill which is also located in Columbus.

In the first quarter of 2008, we also completed and put into service our Pier X expansion at our bulk handling facility located in Newport News, Virginia. The expansion involved the construction of a new dock and installation of additional equipment that increased throughput by approximately 30%to approximately nine million tons of bulk products per year. The expansion allows the facility, which primarily handles coal, to now receive product via vessel in addition to rail.

On October 2, 2008, we acquired certain terminal assets from LPC Packaging, a California corporation, for an aggregate consideration of $5.1 million. These acquired assets included state of the art packaging machinery, conveyors and mobile equipment. LPC consists of two facilities located in Stockton, California and a single facility located in San Diego, California. Services provided by these locations include packaging 50 pound bags and super sacks of fertilizer and starch, warehousing and storage of bags and bulk, and inventory management. All three facilities benefit from strong relationships with large customers, having term commitments averaging between three and five years.

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 32 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 2008, our materials services operations handled approximately 348,000 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.

Kinder Morgan Canada

Our Kinder Morgan Canada business segment includes our Trans Mountain pipeline system, our ownership of a one-third interest in the Express pipeline system, and our 25-mile Jet Fuel pipeline system.

Trans Mountain Pipeline System

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 in length. The capacity of the line at Edmonton ranges from 300,000 barrels per day when heavy crude represents 20% of the total throughput (which is a historically normal heavy crude percentage) to 400,000 barrels per day with no heavy crude. As discussed above in “—Recent Developments,” on October 30, 2008, we completed the construction of our Anchor Loop expansion project, which increased pipeline capacity from approximately 260,000 to 300,000 barrels of crude oil per day. The current Trans Mountain pipeline system was already looped with a 30-inch diameter pipe between Darfield and Kamloops, British Columbia and a 30-inch diameter pipe between Edson and Hinton, Alberta.

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 2008, deliveries on Trans Mountain averaged 237,172 barrels per day. This was a decrease of 8% from average 2007 deliveries of 258,540 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. An additional 40,000 barrel per day expansion that increased capacity on the pipeline to approximately 300,000 barrels per day was completed in 2008. Service on the first 25,000 barrels per day of this capacity increase began on May 1, 2008, and the remaining 15,000 barrels per day increase began on November 1, 2008. 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 oil sands development with projects led by firms including Royal Dutch Shell, Suncor Energy and Syncrude Canada. Notwithstanding current economic factors and some announced project delays, further development is expected to continue into the future with expansions to existing oil sands production facilities as well as with new projects. In its moderate growth case, the Canadian Association of Petroleum Producers forecasts Western Canadian crude oil production to increase by over 1.4 million barrels per day by 2015. This increasing supply will likely result in constrained export pipeline capacity from Western Canada, which supports our 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 2008 and 2007, shipments of refined petroleum and iso-octane represented 20% and 25% of throughput, respectively.

CompetitionTrans 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.

Express and Jet Fuel Pipeline Systems

We own a one-third ownership interest in the Express pipeline system and we own a long-term investment in a debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system. We operate the Express pipeline system and we account for our 33 1/3% investment under the equity method of accounting. The Express pipeline system is a batch-mode, common-carrier, crude oil pipeline system comprised of the Express Pipeline and the Platte Pipeline, collectively referred to in this report as the Express pipeline system. The approximate 1,700-mile integrated oil transportation pipeline connects Canadian and United States producers to refineries located in the U.S. Rocky Mountain and Midwest regions.

The Express Pipeline is a 780-mile, 24-inch diameter pipeline that begins at the crude oil pipeline hub at Hardisty, Alberta and terminates at the Casper, Wyoming facilities of the Platte Pipeline.

At the Hardisty, Canada oil hub, the Express Pipeline receives a variety of light, medium and heavy crude oil produced in Western Canada, and makes deliveries to markets in Montana, Wyoming, Utah and Colorado. The Express Pipeline has a design capacity of 280,000 barrels per day. Receipts at Hardisty averaged 196,160 barrels per day during the year ended December 31, 2008, compared with 213,477 barrels per day during the year ended December 31, 2007.

The Platte Pipeline is a 926-mile, 20-inch diameter pipeline that runs from the crude oil pipeline hub at Casper, Wyoming to refineries and interconnecting pipelines in the Wood River, Illinois area, and includes related pumping and storage facilities (including tanks). The Platte Pipeline transports crude oil shipped on the Express Pipeline and crude oil produced from the Rocky Mountain area of the U.S. to markets located in Kansas and Illinois, and to other interconnecting carriers in those areas. The Platte Pipeline has a capacity of 150,000 barrels per day when shipping heavy oil and averaged 133,637 barrels per day east of Casper, Wyoming during the year ended December 31, 2008, as compared to 110,757 barrels per day for the year ended December 31, 2007.

The current Express pipeline system rate structure is a combination of committed rates and uncommitted rates. The committed rates apply to those shippers who have signed long-term (10 or 15 year) contracts with the Express pipeline system to transport crude oil on a ship-or-pay basis. As of December 31, 2008, Express had total firm commitments of approximately 231,000 barrels per day, or 83% of its total capacity. These contracts expire in 2012, 2014 and 2015 in amounts of 40%, 11% and 32% of total capacity, respectively. The remaining contracts provide for committed tolls for transportation on the Express pipeline system, which can be increased each year by up to 2%. The capacity in excess of 231,000 barrels per day is made available to shippers as uncommitted capacity.

We also own and operate the approximate 25-mile aviation turbine fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada (referred to in this report as the Jet Fuel pipeline system). In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in the Port of Vancouver, the aviation turbine fuel operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall volume of 15,000 barrels.

Competition: The Express Pipeline System pipeline to the U.S. Rocky Mountains and Midwest is one of several pipeline alternatives for Western Canadian petroleum production, and throughput on the Express pipeline system may decline if overall petroleum production in Alberta declines, demand in the U.S. Rocky Mountains decreases, new pipelines are built, or if tolls become uncompetitive compared to alternatives. The Express pipeline system competes against other pipeline providers who could be in a position to establish and offer lower tolls.

Major Customers

Our total operating revenues are derived from a wide customer base. For each of the years ended December 31, 2008, 2007 and 2006, 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 2008, 2007 and 2006 accounted for 65.6%, 63.3% and 66.8%, 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. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. 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 Refined Petroleum Products and Oil 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. Those 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 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 systems 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.

Trans Mountain. 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 Trans Mountain’s two expansion projects totaling C$765 million, which were completed during 2007 and 2008. In total, the project added 75,000 barrels per day of incremental capacity to the system, increasing pipeline capacity to approximately 300,000 barrels per day. 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 Refined Petroleum and Oil Pipeline Rate Regulation – U.S. Operations.”

Express Pipeline System. The Canadian segment of the Express Pipeline is regulated by the NEB as a Group 2 pipeline, which results in rates and terms of service being regulated on a complaint basis only. Express committed rates are subject to a 2% inflation adjustment April 1 of each year. The U.S. segment of the Express Pipeline and the Platte Pipeline are regulated by the FERC. See “—Interstate Common Carrier Refined Petroleum and Oil Pipeline Rate Regulation – U.S. Operations.” Additionally, movements on the Platte Pipeline within the State of Wyoming are regulated by the Wyoming Public Service Commission, which regulates the tariffs and terms of service of public utilities that operate in the state of Wyoming. The Wyoming Public Service Commission standards applicable to rates are similar to those of the FERC and the NEB.

Interstate Natural Gas Transportation and Storage Regulation

The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation and storage services under the Natural Gas Act. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under 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:


	• Order No. 436 (1985) which required 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.

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 No. 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 No. 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.

On November 17, 2006, the D.C. 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 No. 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, referred to as a NOPR, soliciting comments on whether or not the interim rule should be made permanent for natural gas transmission providers. On March 21, 2008, the FERC issued a NOPR modifying the approach proposed in the January 18, 2007 NOPR, and on October 16, 2008, the FERC issued a Final Rule in Order 717 revising the FERC Standards of Conduct for natural gas and electric transmission providers by eliminating Order No. 2004’s concept of Energy Affiliates and corporate separation in favor of an employee functional approach as used in Order No. 497. Please refer to Note 17 to our consolidated financial statements included elsewhere in this report for additional information regarding FERC Order No. 2004 and the Standards of Conduct.

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.

Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines. Within that range, each pipeline is permitted to charge discounted rates to meet competition, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination. Apart from discounted rates offered within the range of tariff maximums and minimums, the pipeline is permitted to offer negotiated rates where the pipeline and shippers want rate certainty, irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels. Accordingly, there are a variety of rates that different shippers may pay. For example, some shippers may pay a negotiated rate that is different than the posted tariff rate and some may pay the posted maximum tariff rate or a discounted rate that is limited by the posted maximum and minimum tariff rates. Most of the rates we charge shippers on our greenfield projects, like the Rockies Express or Midcontinent Express pipelines, are pursuant to negotiated rate long-term transportation agreements. As such, negotiated rates provide certainty to the pipeline and the shipper of a fixed rate during the term of the transportation agreement, regardless of changes to the posted tariff rates. While rates may vary by shipper and circumstance, the terms and conditions of pipeline transportation and storage services are not generally negotiable.

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 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 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. The Texas Railroad Commission has the authority to regulate our transportation rates, though it generally has 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.

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. 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 that address employee health and safety.

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, human health and safety.

Environmental Matters

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 hazardous substances 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 damages, 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 business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities.

Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health, and there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased

compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.

In accordance with GAAP, 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, referred to as the U.S. EPA, or similar state agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could increase or mitigate our actual joint and several liability exposures. Although no assurance can be given, we believe that the ultimate resolution of 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 $78.9 million as of December 31, 2008. Our reserve estimates range in value from approximately $78.9 million to approximately $121.4 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.

Hazardous and Non-Hazardous Waste

We generate both hazardous and non-hazardous 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 U.S. EPA 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 our 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 handling and 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, its implementing regulations, and analogous state statutes and regulations. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. The Clean Air Act regulations contain 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. We are unable to fully estimate the effect on earnings or operations or the amount 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.

We are aware of the increasing focus of national and international regulatory bodies on greenhouse gas emissions and climate change issues. We are also aware of legislation, recently proposed by the Canadian legislature, to reduce greenhouse gas emissions.

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.

Climate Change

Studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, which is naturally occurring and also a byproduct of burning of natural gas, are examples of greenhouse gases. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA is separately considering whether it will regulate greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or provinces of Canada or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases, including methane or carbon dioxide, in areas in which we conduct business, could result in changes to the consumption and demand for natural gas and carbon dioxide produced from our source fields and could have adverse effects on our business, financial position, results of operations and prospects. Such changes could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or to our customers, such recovery of costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC, or comparable state regulatory commissions, and the provisions of any final legislation.

Department of Homeland Security

In Section 550 of the Homeland Security Appropriations Act of 2007 (P.L. 109-295) (Act), Congress gave the Department of Homeland Security, referred to in this report as DHS, regulatory authority over security at certain high-risk chemical facilities. Pursuant to its congressional mandate, on April 9, 2007, DHS promulgated the Chemical Facility Anti-Terrorism Standards (“CFATS”), 6 CFR Part 27.

In the CFATS regulation, DHS requires all high-risk chemical and industrial facilities, including oil and gas facilities, to complete security vulnerability assessments, develop site security plans, and implement protective measures necessary to meet DHS-defined risk-based performance standards. DHS has not provided final notice to all facilities that DHS determines to be high risk and subject to the rule. Therefore, neither the extent to which our facilities may subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.

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, 2008, KMGP Services Company, Inc., Knight and Kinder Morgan Canada Inc. had, in the aggregate, approximately 7,800 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 2009 and 2013. 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.

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

Our business is subject to extensive regulation that affects our operations and costs.

Our assets and operations are subject to regulation by federal, state, provincial and local authorities, including regulation by the FERC, and by various authorities under federal, state, provincial and local environmental, human health and safety and pipeline safety laws. Regulation affects almost every aspect of our business, including, among other things, our ability to determine terms and rates for our interstate pipeline services, to make acquisitions or to build extensions of existing facilities. The costs of complying with such laws and regulations are already significant, and additional or more stringent regulation could have a material adverse impact on our business, financial condition and results of operations.

In addition, regulators have taken actions designed to enhance market forces in the gas pipeline industry, which have led to increased competition. In a number of U.S. markets, natural gas interstate pipelines face competitive pressure from a number of new industry participants, such as alternative suppliers, as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material impact on business in our markets and therefore adversely affect our financial condition and results of operations.

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 FERC 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, including unexpected policy changes that sometimes occur following a change of presidential administration, 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.

Environmental laws and regulations could expose us to significant costs and liabilities.

Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly known as CERCLA or Superfund, the Resource Conservation and Recovery Act, commonly known as RCRA, or analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us.

Failure to comply with these laws and regulations may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our results of operations. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or 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 the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.

We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the United States such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

In addition, our oil and gas development and production activities are subject to numerous 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, these activities 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 wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities.

Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

Climate change regulation at the federal, state, provincial, or regional levels and/or new regulations issued by the Department of Homeland Security could result in increased operating and capital costs for us.

carbon dioxide produced from our source fields and could have adverse effects on our business, financial position, results of operations and prospects.

Such changes could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by some of our pipelines or to our customers, such recovery of costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.

The Department of Homeland Security Appropriation Act of 2007 requires the DHS to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS has issued rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these standards. Covered facilities that are determined by the DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping and protection of chemical-terrorism vulnerability information. We have not yet determined the extent of the costs to bring our facilities into compliance, but it is possible that such costs could be substantial.

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 Rockies Express Pipeline which is expected to cost $6.3 billion, the Midcontinent Express Pipeline which is expected to cost $2.2 billion, the Fayetteville Express Pipeline which is expected to cost $1.2 billion, and the Kinder Morgan Louisiana Pipeline which is expected to cost $950 million (the cost estimates for the Rockies Express and Midcontinent Express pipelines include expansions of the base project). 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 return on investment, results of operations and cash flows.

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. 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: (i) demands on management related to the increase in our size after an acquisition, an expansion, or a completed construction project; (ii) the diversion of our management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v) 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 capital markets or more expensive capital would impair our ability to grow.

Part of our business strategy includes acquiring additional businesses and expanding our assets. We may need to raise debt and equity to finance these acquisitions and expansions. Limitations on our access to capital will impair our ability to execute this strategy. We normally fund

acquisitions and expansions 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.

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 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, natural gas liquids and natural gas properties depend to a large degree on prevailing oil and gas prices. Prices for oil, natural gas liquids and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil, natural gas liquids 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, natural gas liquids 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 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. These fluctuations necessarily impact the accuracy of assumptions used in our budgeting process.

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 very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates 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 must either obtain the right from landowners or exercise the power of eminent domain in order to use most 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. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

Whether we have the power of eminent domain for our pipelines, other than interstate natural gas 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 interstate natural gas pipelines have federal eminent domain authority. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. 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.

Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As of December 31, 2008, we had approximately $8.6 billion of consolidated debt (excluding the fair value of interest rate swaps). This level of debt could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions. Each of these factors is to a large extent dependent on economic, financial, competitive and other factors beyond our control.

Our variable rate debt makes us vulnerable to increases in interest rates.

As of December 31, 2008, we had outstanding $8.6 billion of consolidated debt (excluding the fair value of interest rate swaps). Of this amount, approximately $2.9 billion (34%) was subject to variable interest rates, either as short-term or long-term debt of variable rate credit facilities or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps. Should interest rates increase significantly, the amount of cash required to service our debt would increase and 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.”

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.

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 products or 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.

Current levels of market volatility are unprecedented.

The capital and credit markets have been experiencing extreme volatility and disruption for more than 12 months. In some cases, the markets have exerted downward pressure on stock prices and credit capacity for certain issuers. Our plans for growth require regular access to the capital and credit markets. If current levels of market disruption and volatility continue or worsen, access to capital and credit markets could be disrupted making growth through acquisitions and development projects difficult or impractical to pursue until such time as markets stabilize.

Our operating results may be adversely affected by unfavorable economic and market conditions.

Economic conditions worldwide have from time to time contributed to slowdowns in the oil and gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the United States. Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. In addition, decreases in the prices of crude oil and natural gas liquids will have a negative impact on the results of our CO₂ business segment. If global economic and market conditions (including volatility in commodity markets), or economic conditions in the United States or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.

The recent downturn in the credit markets has increased the cost of borrowing and has made financing difficult to obtain, each of which may have a material adverse effect on our results of operations and business.

Recent events in the financial markets have had an adverse impact on the credit markets and, as a result, the availability of credit has become more expensive and difficult to obtain. Some lenders are imposing more stringent restrictions on the terms of credit and there may be a general reduction in the amount of credit available in the markets in which we conduct business. In addition, as a result of the current credit market conditions and the recent downgrade of our short-term credit ratings by Standard & Poor’s Rating Services, we are currently unable to access commercial paper borrowings and instead are meeting our short-term financing and liquidity needs through borrowings under our bank credit facility. The negative impact on the tightening of the credit markets may have a material adverse effect on us resulting from, but not limited to, an inability to expand facilities or finance the

acquisition of assets on favorable terms, if at all, increased financing costs or financing with increasingly restrictive covenants.

The failure of any bank in which we deposit our funds could reduce the amount of cash we have available for operations, to pay distributions and to make additional investments.

We have diversified our cash and cash equivalents between several banking institutions in an attempt to minimize exposure to any one of these entities. However, the Federal Deposit Insurance Corporation, or “FDIC,” only insures amounts up to $250,000 per depositor per insured bank until January 1, 2010 when the standard coverage limit will decrease to $100,000. We currently have cash and cash equivalents and restricted cash deposited in certain financial institutions in excess of federally insured levels. If any of the banking institutions in which we have deposited funds ultimately fails, we may lose our deposits over $250,000. The loss of our deposits could reduce the amount of cash we have available to distribute or invest and could result in a decline in the value of your investment.

There can be no assurance as to the impact on the financial markets of the U.S. government’s plans to purchase large amounts of illiquid, mortgage-backed and other securities from financial institutions.

In response to the financial crises affecting the banking system and financial markets and going concern threats to investment banks and other financial institutions, the U.S. Treasury has announced plans to purchase mortgage-backed and other securities from financial institutions for the purpose of stabilizing the financial markets. There can be no assurance what impact these purchases or similar actions by the U.S. government will have on the financial markets. Although we are not one of the institutions that would sell securities to the U.S. Treasury, the ultimate effects of these actions on the financial markets and the economy in general could materially and adversely affect our business, financial condition and results of operations, or the trading price of our common units.

Knight’s May 2007 going-private transaction resulted in a downgrade of the ratings of our debt securities, which has increased our cost of capital.

On May 30, 2007, Knight completed its going-private transaction. In connection with the transaction, Standard & Poor’s Rating Services and Moody’s Investor Service, Inc. downgraded the ratings assigned to our senior unsecured debt to BBB and Baa2, respectively. Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007. 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.

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 the 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 may suffer financial losses not offset by physical transactions.

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

In the past, competitors to our interstate natural gas pipelines have constructed or expanded pipeline capacity into the areas served by our pipelines. To the extent that an excess of supply into these market areas is created and persists, our ability to recontract for expiring transportation capacity at favorable rates or to maintain existing customers could be impaired. In addition, our products pipelines compete against proprietary pipelines owned and operated by major oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars. Throughput on our products pipelines may decline if the rates we charge become uncompetitive compared to alternatives.

Future business development of our products, crude oil and natural gas pipelines is dependent on the supply of, and demand for, those commodities.

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 oil sands. 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 or natural gas 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 oil sands. 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 the operations of our Kinder Morgan Canada segment, 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.

Terrorist attacks, or the threat of them, may adversely affect our business.

The U.S. government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations. These potential targets might include our pipeline systems or storage facilities. Our operations could become subject to increased governmental scrutiny that would require increased security measures. 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 in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.

Hurricanes and other natural disasters could have a material adverse effect on our business, financial condition and results of operations.

Some of our pipelines, terminals and other assets are located in areas that are susceptible to hurricanes and other natural disasters. These natural disasters could potentially damage or destroy our pipelines, terminals and other assets and disrupt the supply of the products we transport through our pipelines, which could have a material adverse effect our business, financial condition and results of operations.

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 common 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).

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 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.

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 United States 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 United States federal income tax purposes. In order for us to be treated as a partnership for United States 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 United States 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 United States federal income tax purposes, we would pay United States 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 United States federal income tax purposes or otherwise subject us to entity-level taxation. Members of Congress are considering substantive changes to the existing United States federal income tax laws that affect certain publicly-traded partnerships. For example, United States 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 an 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. This tax reduces, and the imposition of such a tax on us by 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.

We may have potential liability arising out of a possible dissemination of one or more prospectuses (in the form of Current Reports on Form 8-K and 8-K/A) not meeting the requirements of the Securities Act.

On December 16, 2008, we furnished to the Securities and Exchange Commission two Current Reports on Form 8-K and one Current Report on Form 8-K/A (in each case, containing disclosures under item 7.01 of Form 8-K) containing certain information with respect to a public offering of our common units. We filed a prospectus supplement with respect to this 3,900,000 common unit offering on December 17, 2008, and the common units were sold at a public offering price of $46.75 per common unit for total gross proceeds of $182,325,000. These Current Reports may have constituted prospectuses not meeting the requirements of the Securities Act due to the legends used in the Current Reports. Accordingly, under certain circumstances, purchasers of the common units from us in the offering might have the right to require us to repurchase the common units they purchased or, if they have sold those common units, to pay damages. Consequently, we could have a potential liability arising out of these possible violations of the Securities Act. The magnitude of any potential liability is presently impossible to quantify, and would depend upon whether it is demonstrated we violated the Securities Act, the number of common units that purchasers in the offering sought to require us to repurchase and the trading price of our common units.

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 2008.

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

2008
First Quarter	$	60.62	$	50.80	$	0.9600		0.017716
Second Quarter		60.89		53.81		0.9900		0.018124
Third Quarter		59.48		48.67		1.0200		0.021570
Fourth Quarter		56.00		35.59		1.0500		0.024580

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

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 $4.20 per unit for 2009; 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, 2009, there were approximately 255,000 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 2008 or sell any unregistered units in the fourth quarter of 2008.

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,

	2008(6)			2007(7)			2006(8)			2005(9)			2004(10)

	(In millions, except per unit and ratio data)
Income and Cash Flow Data:
Revenues	$	11,740.3		$	9,217.7		$	9,048.7		$	9,745.9		$	7,893.0
Costs, Expenses and Other:
Gas purchases and other costs of sales		7,716.1			5,809.8			5,990.9			7,167.3			5,767.0
Operations and maintenance		1,010.2			1,024.6			777.0			719.5			488.6
Fuel and power		272.6			237.5			223.7			178.5			146.4
Depreciation, depletion and amortization		702.7			540.0			423.9			341.6			281.1
General and administrative		297.9			278.7			238.4			216.7			170.5
Taxes, other than income taxes		186.7			153.8			134.4			106.5			79.1
Other expense (income)		2.6			365.6			(31.2	)		—			—

		10,188.8			8,410.0			7,757.1			8,730.1			6,932.7

Operating income		1,551.5			807.7			1,291.6			1,015.8			960.3

Other income/(expense):
Earnings from equity investments		160.8			69.7			74.0			89.6			81.8
Amortization of excess cost of equity investments		(5.7	)		(5.8	)		(5.6	)		(5.5	)		(5.6	)
Interest, net		(388.2	)		(391.4	)		(337.8	)		(259.0	)		(192.9	)
Other, net		19.2			14.2			12.0			3.3			2.2
Minority interest		(13.7	)		(7.0	)		(15.4	)		(7.3	)		(9.6	)
Income tax provision		(20.4	)		(71.0	)		(29.0	)		(24.5	)		(19.7	)

Income from continuing operations		1,303.5			416.4			989.8			812.4			816.5
Income (loss) from discontinued operations(1)		1.3			173.9			14.3			(0.2	)		15.1

Net income	$	1,304.8		$	590.3		$	1,004.1		$	812.2		$	831.6
Less: General Partner’s interest in net income		(805.8	)		(611.6	)		(513.3	)		(477.3	)		(395.1	)

Limited Partners’ interest in net income (loss)	$	499.0		$	(21.3	)	$	490.8		$	334.9		$	436.5


Basic Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations(2)	$	1.94		$	(0.82	)	$	2.12		$	1.58		$	2.14
Income from discontinued operations		—			0.73			0.07			—			0.08

Net income (loss) per unit	$	1.94		$	(0.09	)	$	2.19		$	1.58		$	2.22
��

Diluted Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations(2)	$	1.94		$	(0.82	)	$	2.12		$	1.58		$	2.14
Income from discontinued operations		—			0.73			0.06			—			0.08

Net income (loss) per unit	$	1.94		$	(0.09	)	$	2.18		$	1.58		$	2.22


Per unit cash distribution declared(3)	$	4.02		$	3.48		$	3.26		$	3.13		$	2.87
Ratio of earnings to fixed charges(4)	$	3.77		$	2.13		$	3.64			3.76			4.84
Additions to property, plant and equipment	$	2,533.0		$	1,691.6		$	1,182.1		$	863.1		$	747.3

Balance Sheet Data (at end of period):
Net property, plant and equipment	$	13,241.4		$	11,591.3		$	10,106.1		$	8,864.6		$	8,168.9
Total assets	$	17,885.8		$	15,177.8		$	13,542.2		$	11,923.5		$	10,552.9
Long-term debt(5)	$	8,274.9		$	6,455.9		$	4,384.3		$	5,220.9		$	4,722.4




(1)	Represents income or loss from the operations of our North System natural gas liquids pipeline system. 2008 and 2007 amounts include gains of $1.3 million and $152.8 million, respectively, 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 per unit. Basic Limited Partners’ income per unit from continuing operations was computed by dividing the interest of our unitholders in income from continuing operations by the weighted average


	number of units outstanding during the period. Diluted Limited Partners’ income per unit from continuing operations 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 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 $951.3 million as of December 31, 2008, $152.2 million as of December 31, 2007, $42.6 million as of December 31, 2006, $98.5 million as of December 31, 2005 and $130.2 million as of December 31, 2004.

(6)	Includes results of operations for the terminal assets acquired from Chemserve, Inc. and the Phoenix, Arizona refined petroleum products storage terminal acquired from ConocoPhillips since effective dates of acquisition. We acquired the terminal assets from Chemserve effective August 15, 2008, and we acquired the Phoenix, Arizona products terminal effective December 10, 2008.

(7)	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 in note (8).

(8)	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 because regulatory accounting provisions required capitalization of revenues and expenses until the second segment of the Entrega Pipeline was complete and in-service.

(9)	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.

(10)	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 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.

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

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 2008, 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 to any uncertainties described in this discussion and analysis, our “Risk Factors” disclosure provides a more detailed description of a variety of risks that could have a material adverse effect on our business, financial condition, cash flows and results of operations.

General

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.

Our five reportable business segments are:


	• Products Pipelines—the ownership and operation of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;

	• Natural Gas Pipelines—the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems;

	• CO₂—(i) the production, transportation and marketing of carbon dioxide, referred to as CO₂, to oil fields that use CO₂ to increase production of oil, (ii) ownership interests in and/or operation of oil fields in West Texas, and (iii) the ownership and operation of a crude oil pipeline system in West Texas;

	• Terminals—the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the United States; and

	• Kinder Morgan Canada—(i) the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington; and (ii) the 33 1/3% interest in the Express pipeline system and the Jet Fuel pipeline system we acquired from Knight effective August 28, 2008. Following the acquisition of these two businesses, the operations of our Trans Mountain, Express and Jet Fuel pipeline systems have been combined to represent our “Kinder Morgan Canada” segment.

As an energy infrastructure owner and operator in multiple facets of the United States’ and Canada’s various energy businesses and markets, we examine a number of variables and factors on a routine basis to evaluate our

current performance and our prospects for the future. Many of our operations are regulated by various U.S. and Canadian regulatory bodies. The profitability of our products pipeline transportation business is generally driven by the utilization of our facilities in relation to their capacity, as well as the prices we receive for our services. Transportation volume levels are primarily driven by the demand for the petroleum products being shipped or stored, and the prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index. Because of the overall effect of utilization on our products pipeline transportation business, we seek to own refined products pipelines located in, or that transport to, stable or growing markets and population centers.

With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets tend to be received under contracts with terms that are fixed for various periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. However, changes, either positive or negative, in actual quantities transported on our interstate natural gas pipelines may not accurately measure or predict associated changes in profitability because many of the underlying transportation contracts, sometimes referred to as take-or-pay contracts, specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity.

Our CO₂ sales and transportation business, like our natural gas pipelines business, generally has take-or-pay contracts, although the contracts in our CO₂business typically have minimum volume requirements. In the long term, our success in this business is driven by the demand for CO₂. However, short-term changes in the demand for CO₂ typically do not have a significant impact on us due to the required minimum transport volumes under many of our contracts. In the oil and gas producing activities within our CO₂business segment, we monitor the amount of capital we expend in relation to the amount of production that is added or the amount of declines in oil and gas production that are postponed. In that regard, our production during any period and the reserves that we add during that period are important measures. In addition, the revenues we receive from our crude oil, natural gas liquids and CO₂ sales are affected by the prices we realize from the sale of these products. Over the long term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, published market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.

As with our pipeline transportation businesses, the profitability of our terminals businesses is generally driven by the utilization of our terminals facilities in relation to their capacity, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. The extent to which changes in these variables affect our terminals businesses in the near term is a function of the length of the underlying service contracts, the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.

In our discussions of the operating results of individual businesses which follow, we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods. We believe that we have a history of making accretive acquisitions and economically advantageous expansions of existing businesses. Our ability to increase earnings and increase distributions to our unitholders will, to some extent, be a function of completing successful acquisitions and expansions. We continue to have opportunities for expansion of our facilities in many markets, and we expect to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict.

Our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates and, to some extent, our ability to raise necessary capital to fund such acquisitions, factors over which we have limited or no control. Thus, we have no way to determine the extent to which we will be able to identify accretive acquisition candidates, or the number or size of such candidates in the future, or whether we will complete the acquisition of any such candidates.

On November 24, 2008, we announced that we expect to declare cash distributions of $4.20 per unit for 2009, a 4.5% increase over our cash distributions of $4.02 per unit for 2008. Our expected growth in distributions in 2009 assumes an average West Texas Intermediate crude oil price of $68 per barrel in 2009 with some minor adjustments for timing, quality and location differences. Based on actual prices received through the first seven weeks of 2009 and the forward curve, adjusted for the same factors as the budget, our average realized price for 2009 is currently projected to be $43 per barrel. Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO2 business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. We hedge the majority of our crude oil production, but do have exposure to unhedged volumes, the majority of which are natural gas liquids volumes. For 2009, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 segment’s cash flows by approximately $6 million (or approximately 0.2% of our combined business segments’ anticipated distributable cash flow). This sensitivity to the average WTI price is very similar to what we experienced in 2008. Our 2009 cash distribution expectations do not take into account any capital costs associated with financing any payment we may be required to make of reparations sought by shippers on our Pacific operations’ interstate pipelines.

Basis of Presentation

As discussed in Note 3 of the accompanying notes to our consolidated financial statements, our financial statements and the financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations reflect the August 28, 2008 transfer of both the 33 1/3% interest in the Express pipeline system net assets and the Jet Fuel pipeline system net assets from Knight as of the date of transfer. Accordingly, we have included the financial results of the Express and Jet Fuel pipeline systems within our Kinder Morgan Canada business segment disclosures presented in this report for all periods subsequent to August 28, 2008.

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.

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. Generally, 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, 2008, our most significant ongoing litigation proceedings involved our West Coast Products pipelines. Tariffs charged by certain of these 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 product 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 West Coast Products pipeline 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 FERC 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.

There have not been any significant changes in these policies and estimates during 2008; however, during the second quarter of 2008, we changed the date of our annual goodwill impairment test date to May 31 of each year (from January 1), and we have determined that our goodwill was not impaired as of May 31, 2008. Although our change to a new testing date, when applied to prior periods, does not yield different financial statement results, this change constitutes a change in the method of applying an accounting principle, as discussed in paragraph 4 of SFAS

No. 154, “Accounting Changes and Error Corrections.” For more information on this change, see Note 2 to our consolidated financial statements included elsewhere in this report.

As of December 31, 2008 and 2007, our goodwill was $1,058.9 million and $1,077.8 million, respectively. Included in our December 31, 2008 goodwill balance is $203.6 million related to our Trans Mountain pipeline system, 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, 2008 and 2007, these intangibles totaled $205.8 million and $238.6 million, respectively. For more information on our goodwill and other intangible assets, see Note 8 to our consolidated financial statements included elsewhere in this report.

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 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 variable 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 because 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.

2008 Hurricanes and Fires

In September 2008, two hurricanes struck the Gulf Coast communities of southern Texas and Louisiana and a third hurricane made U.S. landfall near the South Carolina-North Carolina border. The three named hurricanes—Hanna, Gustav, and Ike—caused wide-spread damage to residential and commercial property, but our primary assets in those areas experienced only relatively minor damage. Our Terminals, Products Pipelines, Natural Gas Pipelines and CO₂ business segments were negatively impacted by these hurricanes and we realized a combined $11.1 million decrease in net income due to incremental expenses associated with the clean-up and asset damage from these storms (but excluding estimates for lost business and lost revenues). This decrease is described in the footnotes to the tables below.

Additionally, in the third quarter of 2008, we experienced fire damage at three separate terminal locations. The largest was an explosion and fire at our Pasadena, Texas liquids terminal facility on September 23, 2008. The fire primarily damaged a manifold system used for liquids distribution. We intend to repair the damaged portions of each separate terminal facility, and we recognized a combined $7.2 million decrease in net income from our Terminals’ business segment due to incremental expenses and asset damage associated with these fires (excluding estimates for lost business and lost revenues). This decrease is described in the footnotes to the tables below.

Results of Operations

Consolidated


	Year Ended December 31,

	2008			2007			2006

	(In millions)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(b)	$	546.2		$	569.6		$	491.2
Natural Gas Pipelines(c)		760.6			600.2			574.8
CO₂(d)		759.9			537.0			488.2
Terminals(e)		523.8			416.0			408.1
Kinder Morgan Canada(f)		141.2			(293.6	)		76.5

Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		2,731.7			1,829.2			2,038.8

Depreciation, depletion and amortization expense(g)		(702.7	)		(547.0	)		(432.8	)
Amortization of excess cost of equity investments		(5.7	)		(5.8	)		(5.7	)
General and administrative expenses(h)		(297.9	)		(278.7	)		(238.4	)
Interest and other non-operating expenses(i)		(420.6	)		(407.4	)		(357.8	)

Net income	$	1,304.8		$	590.3		$	1,004.1




(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)	2008 amount includes (i) a combined $10.0 million decrease in income from the proposed settlement of certain litigation matters related to our Pacific operations’ East Line pipeline and other legal liability adjustments; (ii) a $10.0 million decrease in income associated with environmental liability adjustments; (iii) a $3.6 million decrease in income resulting from unrealized foreign currency losses on long-term debt transactions; (iv) a combined $2.7 million decrease in income resulting from refined product inventory losses and certain property, plant and equipment write-offs; (v) a $0.3 million decrease in income related to hurricane clean-up and repair activities; and (vi) a $1.3 million gain from the 2007 sale of our North System. 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 increase in 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.

(c)	2008 amount includes (i) a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC; (ii) a combined $5.6 million increase in income resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas; (iii) a $0.5 million decrease in expense associated with environmental liability adjustments; (iv) a $5.0 million increase in expense related to hurricane clean-up and repair activities, and (v) a $0.3 million increase in expense associated with legal liability adjustments. 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.

(d)	2008 amount includes a $0.3 million increase in expense associated with environmental liability adjustments. 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.

(e)	2008 amount includes (i) a $7.2 million decrease in income related to fire damage and repair activities; (ii) a $5.7 million decrease in income related to hurricane clean-up and repair activities; (iii) a combined $2.8 million increase in expense from the settlement of certain litigation matters related to our Elizabeth River bulk terminal and our Staten Island liquids terminal, and other legal liability adjustments; and (iv) a $0.6 million decrease in expense associated with environmental liability adjustments. 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) a $1.2 million increase in expense associated with legal liability adjustments; and (iv) an increase in income of $1.8 million from property casualty gains associated with the 2005 hurricane season. 2006 amount includes an $11.3 million 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).

(f)	2008 amount includes a $19.3 million decrease in expense associated with favorable changes in Canadian income tax rates, and an $18.9 increase in expense from the amounts previously reported in our 2008 fourth quarter earnings release issued on January 21, 2009, due to certain non-cash regulatory accounting adjustments. 2007 amount includes losses of $349.2 million for periods prior to our acquisition date of April 30, 2007 (including a $377.1 million goodwill impairment expense associated with a non-cash reduction in the carrying value of Trans Mountain’s goodwill), 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.

(g)	2008 amount includes a $6.9 million increase in expense from the amounts previously reported in our 2008 fourth quarter earnings release issued on January 21, 2009, due to certain non-cash regulatory accounting adjustments. 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 litigation and environmental expenses. 2008 amount includes (i) a $5.6 million increase in non-cash compensation expense, allocated to us from Knight (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $0.9 million increase in expense for certain Express pipeline system acquisition costs; (iii) a $0.4 million expense resulting from the write-off of certain acquisition costs pursuant to a newly adopted accounting principle; (iv) a $0.1 million increase in expense related to hurricane clean-up and repair activities; and (v) a $2.0 million decrease in expense due to the adjustment of certain insurance related liabilities. 2007 amount includes (i) a $26.2 million increase in expense, allocated to us from Knight, associated with closing the going-private transaction (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $5.5 million expense for Trans Mountain general and administrative 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 (i) an $18.8 million expense for Trans Mountain general and administrative expenses for periods prior to our acquisition date of April 30, 2007; (ii) a $2.4 million increase in expense related to the cancellation of certain commercial insurance policies; and (iii) 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 (capitalization of overhead expense).

(i)	Includes unallocated interest income and income tax expense, interest and debt expense, and minority interest expense. 2008 amount includes (i) a $7.1 million decrease in interest expense from the amounts previously reported in our 2008 fourth quarter earnings release issued on January 21, 2009, due to certain non-cash Trans Mountain regulatory accounting adjustments; (ii) a $2.0 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition; and (iii) a $0.2 million increase in interest expense related to the proposed settlement of certain litigation matters related to our Pacific operations’ East Line pipeline. 2007 amount includes a $2.4 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition, and a $1.2 million expense for Trans Mountain interest expense for periods prior to our acquisition date of April 30, 2007. 2006 amount includes a $6.3 million expense for Trans Mountain interest expenses. 2008, 2007 and 2006 amounts also include a $0.4 million decrease in expense, a $3.9 million decrease in expense, and a $3.5 million increase in expense, respectively, related to the minority interest effect from all of the 2008, 2007 and 2006 items previously disclosed in these footnotes.

For the year 2008, our net income was $1,304.8 million on revenues of $11,740.3 million. This compares with net income of $590.3 million on revenues of $9,217.7 million in 2007 and net income of $1,004.1 million on revenues of $9,048.7 million in 2006. Our 2007 net income included an impairment expense of $377.1 million associated with a non-cash reduction in the carrying value of Trans Mountain’s goodwill. 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. 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 as defined in our partnership agreement generally consists 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.

As a result of internal growth and expansion across our business portfolio, as well as incremental contributions from asset acquisitions, our total segment earnings before depreciation, depletion and amortization increased $902.5 million (49%) in 2008, when compared to 2007. The certain items described in the footnotes to the table above (including the goodwill impairment expense) accounted for $367.5 million of the overall increase (combining to decrease segment EBDA by $26.5 million in 2008 and to decrease segment EBDA by $394.0 million in 2007). The remaining $535.0 million (24%) increase in year-to-year segment earnings before depreciation, depletion and amortization resulted from incremental earnings from our CO₂, Natural Gas Pipelines, Terminals and Kinder Morgan Canada business segments. Specifically, in 2008, we benefitted from higher revenues from crude oil and carbon dioxide sales, the start-up of the Rockies Express-West natural gas pipeline, improved margins from our Texas intrastate natural gas pipeline group, incremental earnings from expanded bulk and liquids terminal operations, and a full year impact of Trans Mountain and its expansions.

The overall increase in our earnings compared to last year was tempered by such factors as (i) a continued slowing economy; (ii) the negative impact of higher energy prices—primarily in the first three quarters on demand for petroleum products—which negatively impacted our deliveries of gasoline, diesel and jet fuel in 2008; (iii) increases in average construction and fuel costs—which negatively impacted both our capital expansion programs and our existing operations when compared to 2007; (iv) a weakening of the Canadian dollar—relative to the U.S. dollar and primarily since the end of the third quarter of 2008; and (v) lower crude oil, natural gas liquids and natural gas prices in the fourth quarter of 2008.

In light of the economic uncertainties we are taking cost reduction measures for 2009. We are reducing our travel costs and compensation costs, decreasing the use of outside consultants, reducing overtime where possible and reviewing capital and operating budgets to identify the costs we can reduce without compromising operating efficiency, maintenance or safety.

In 2007, total segment earnings before depreciation, depletion and amortization decreased $209.6 million (10%) when compared to the previous year, and 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 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 acquisitions of both the Trans Mountain pipeline system and the remaining interest in the Cochin pipeline system that we did not already own.

Products Pipelines


	Year Ended December 31,

	2008			2007			2006

	(In millions, except operating statistics)
Revenues(a)	$	815.9		$	844.4		$	776.3
Operating expenses(b)		(291.0	)		(451.8	)		(308.3	)
Other income (expense)(c)		(1.3	)		154.8			—
Earnings from equity investments(d)		24.4			32.5			16.3
Interest income and Other, net-income (expense)(e)		2.0			9.4			12.1
Income tax benefit (expense)(f)		(3.8	)		(19.7	)		(5.2	)

Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	546.2		$	569.6		$	491.2


Gasoline (MMBbl)		398.4			435.5			449.8
Diesel fuel (MMBbl)		157.9			164.1			158.2
Jet fuel (MMBbl)		117.3			125.1			119.5

Total refined product volumes (MMBbl)		673.6			724.7			727.5
Natural gas liquids (MMBbl)		27.3			30.4			34.0

Total delivery volumes (MMBbl)(g)		700.9			755.1			761.5




(a)	2008 amount includes a $5.1 million decrease in revenues from the proposed settlement of certain litigation matters related to our Pacific operations’ East Line pipeline.

(b)	2008, 2007 and 2006 amounts include increases in expense of $9.2 million, $15.9 million and $13.5 million, respectively, associated with environmental liability adjustments. 2008 amount also includes a combined $5.0 million increase in expense from the proposed settlement of certain litigation matters related to our Pacific operations’ East Line pipeline and other legal liability adjustments, a $0.5 million increase in expense resulting from refined product inventory losses, and a $0.2 million increase in expense related to hurricane clean-up and repair activities. 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.

(c)	2008 and 2007 amounts include gains of $1.3 million and $152.8 million, respectively, from the 2007 sale of our North System. 2008 amount also includes a $2.2 million decrease in income resulting from certain property, plant and equipment write-offs.

(d)	2008 amount includes an expense of $1.3 million associated with our portion of environmental liability adjustments on Plantation Pipe Line Company, and an expense of $0.1 million reflecting our portion of Plantation Pipe Line Company’s expenses related to hurricane clean-up and repair activities. 2007 amount includes an expense of $0.1 million associated with our portion of legal liability adjustments on Plantation Pipe Line Company. 2006 amount includes an expense of $4.9 million associated with our portion of environmental liability adjustments on Plantation Pipe Line Company.

(e)	2008 and 2007 amounts include a $3.6 million decrease in income and a $1.8 million increase in income, respectively, resulting from unrealized foreign currency losses and gains on long-term debt transactions. 2006 amount includes a $5.7 million increase in income resulting from transmix contract settlements.

(f)	2008 amount includes a $0.5 million decrease in expense reflecting the tax effect (savings) on our proportionate share of environmental expenses incurred by Plantation Pipe Line Company and described in footnote (d), and a $0.1 million decrease in expense reflecting the tax effect (savings) on the incremental legal expenses described in footnote (b). 2006 amount includes a $1.9 million decrease in expense reflecting the tax effect (savings) on our proportionate share of environmental expenses incurred by Plantation Pipe Line Company and described in footnote (d).

(g)	Includes Pacific, Plantation, Calnev, Central Florida, Cochin, and Cypress pipeline volumes.

Earnings before depreciation, depletion and amortization expenses decreased by $23.4 million in 2008 compared to 2007 and increased $78.4 million in 2007 compared to 2006. Combined, the certain items described in the footnotes to the table above account for $9.0 million of the decrease in 2008 compared to 2007, and a $5.5 million decrease in the results between 2007 and 2006. 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 2008 and 2007, when compared to the respective prior year:


Year Ended December 31, 2008 versus Year Ended December 31, 2007

	EBDA increase/(decrease)					Revenues increase/(decrease)

	(In millions, except percentages)
North System	$	(28.1	)	n/a		$	(41.1	)	n/a
Pacific operations		(9.8	)	(4	)%		(0.7	)	0	%
Plantation Pipeline		(2.4	)	(6	)%		1.8		4	%
Southeast Terminals		9.4		22	%		13.7		20	%
Cochin Pipeline System		6.6		15	%		(11.6	)	(15	)%
Central Florida Pipeline		5.8		16	%		6.0		13	%
West Coast Terminals		3.9		8	%		7.5		10	%
All other (including eliminations)		0.2		0	%		1.0		1	%

Total Products Pipelines	$	(14.4	)	(2	)%	$	(23.4	)	(3	)%


Year Ended December 31, 2007 versus Year Ended December 31, 2006

	EBDA increase/(decrease)				Revenues 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	%

The decrease in both segment earnings before depreciation, depletion and amortization expenses and segment revenues in 2008 versus 2007 attributable to our North System were due to our October 2007 divestiture of the pipeline system 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. Following purchase price adjustments, we received approximately $295.7 million in cash for the sale. We accounted for our North System business as a discontinued operation pursuant to generally accepted accounting principles which require that our income statement be formatted to separate the divested business from our continuing operations; however, as discussed above, because 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, we have included the North System’s operating 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.

Our North System generated $28.1million of earnings before depreciation, depletion and amortization expenses in 2007 prior to the effective sale date of October 5, 2007. In addition, we recognized a $152.8 million gain on disposal of the North System in the fourth quarter of 2007. We also recorded incremental gain adjustments of $1.3 million in 2008. The gains, unlike the earnings before depreciation, depletion and amortization expenses, are not reflected in the operating results above. For more information regarding this divestiture, see Note 3 to our consolidated financial statements included elsewhere in this report. 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.

The decrease in earnings before depreciation, depletion and amortization from our Pacific operations in 2008 compared to 2007 was primarily due to an increase in system-wide operating and maintenance expenses. The increase primarily reflects lower product gains in 2008, due both to lower physical gains and to the impact of unfavorable changes in diesel fuel versus gasoline prices; lower capitalized overhead credits, due to lower capital

spending in 2008; higher labor and payroll expenses due to an increase in headcount; and incremental expenses associated with litigation and right-of-way liability adjustments.

Total revenues earned by our Pacific operations in 2008 were essentially flat compared to 2007, as higher pipeline delivery revenues were largely offset by lower fee-based terminal revenues. The year-over-year increase in refined products delivery revenues resulted from both higher average tariff rates in 2008 and a more favorable delivery mix of higher-rate East Line volumes versus lower-rate West Line volumes. The increase was offset by decreases of 7% and 5%, respectively, in gasoline and diesel fuel delivery volumes, relative to last year, as U.S. gasoline and diesel demand has trailed year-earlier levels.

The decrease in earnings from our equity investment in Plantation was due to lower overall net income earned by Plantation Pipe Line Company, mainly due to lower product transportation and pipeline service revenues. For the year 2008, pipeline throughput volumes dropped 10% compared to the previous year. The 2008 drop in delivery volumes was due to a combination of decreased demand due to lower product consumption, supply disruptions caused by hurricane related refinery outages, and a volume shift by customers to competing pipelines.

When compared to last year, our Products Pipelines business segment benefitted from higher earnings before depreciation, depletion and amortization expenses from our Southeast terminal operations, our Cochin and Central Florida pipeline systems, and our West Coast terminal operations. The improved performances from our Southeast and West Coast terminal operations were primarily related to higher margins on liquids inventory sales, increased earnings from incremental terminal throughput and storage activity at higher rates, and incremental returns from the completion of a number of capital expansion projects that modified and upgraded terminal infrastructure, enabling us to provide additional terminal and ethanol related services to our customers.

We continue to invest in projects that have now added ethanol storage and blending capabilities to six separate terminal facilities included in our Southeast terminal operations, and we are currently in the process of securing commercial commitments to support the installation of ethanol handling infrastructure at our remaining Southeast terminals. In addition, in the fourth quarter of 2008, we completed construction of four new fuel storage tanks with a combined capacity of 320,000 barrels at two military bases in the state of California.

The increase in earnings before depreciation, depletion and amortization expenses from our Cochin Pipeline was driven largely by a year-end 2008 reduction in income tax expense, related to lower Canadian operating results in 2008 and to Canadian income tax liability adjustments. The decrease in income tax expense more than offset a 15% year-over-year drop in operating revenues that was primarily related to lower pipeline transportation revenues. The decrease in delivery revenues was due both to a continued decrease in demand for propane in Eastern Canadian and Midwestern U.S. petrochemical and fuel markets since the end of 2007 and to Cochin’s ceasing of ethane transportation in July 2007.

The increase in earnings from our Central Florida Pipeline was chiefly revenue related, driven by incremental ethanol terminal revenues that began in April 2008 and by incremental ethanol pipeline transportation revenues that began in October 2008. The increase in revenues was also related to higher product delivery revenues, driven by an increase in the average tariff as a result of a mid-year tariff rate increase on product deliveries.

For all segment assets combined, revenues for 2008 from refined petroleum products deliveries increased a slight 0.8%, but total volumes delivered fell 7.1%, when compared to 2007. Compared to last year, the segment’s volumes were negatively impacted by reductions in demand, driven primarily by higher crude oil and refined product prices and weaker economic conditions, and partly by lost business associated with hurricanes in the third quarter of 2008. The decrease in delivery volumes included an 8.5% drop in gasoline volumes, a 3.8% drop in diesel fuel volumes, and a 6.2% decline in total jet fuel volumes. Excluding deliveries by Plantation Pipeline, total segment revenues from refined petroleum products deliveries increased 1.5% in 2008, when compared to last year, and total refined products delivery volumes decreased 5.9%. Although Plantation sustained no hurricane damage in 2008, the pipeline system pumped reduced volumes in the third quarter of 2008 due to hurricane-induced refinery shut-downs and to extended delays in restarting certain refineries impacted by the hurricanes.

All of the assets in our Products Pipelines business segment produced higher earnings before depreciation, depletion and amortization expenses in 2007 than in 2006. 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.

Other increases in segment earnings before depreciation, depletion and amortization expenses in 2007 compared with 2006 included the following:


	• an increase from our West Coast terminal operations—due mainly 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, and from our Linnton and Willbridge terminals located in Portland, Oregon. The increase in volumes at our Carson terminal was partly due to completed storage expansion projects since the end of 2006. The decrease in operating expenses was largely related to higher environmental expenses recognized in 2006, due to adjustments to accrued environmental liabilities;

	• an increase from our approximate 51% equity investment in Plantation Pipe Line Company—due to higher overall net income earned by Plantation, largely resulting from both higher pipeline revenues and lower year-to-year operating expenses. The increase in revenues was largely due to a higher oil loss allowance percentage in 2007, relative to 2006, and the drop in operating expenses was due to decreases in both refined products delivery volumes and pipeline integrity expenses;

	• an increase from our petroleum pipeline transmix operations—reflecting incremental revenues from our Greensboro, North Carolina transmix facility and higher processing revenues from our Colton, California facility. We constructed and placed into service our Greensboro facility in May 2006, and 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 a year-to-year increase in average processing contract rates;

	• an increase from our Pacific operations—largely revenue related, attributable to increases in both products 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;

	• an increase from our Calnev Pipeline—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; and

	• an increase from our Southeast terminal operations—driven by higher overall liquids throughput volumes; and

	• an increase from our North System—mainly due to lower combined operating expenses, due to its sale in the fourth quarter of 2007 (the decline in expense was greater than the associated decline in revenue).

Combining all of the segment’s operations, while revenues from refined petroleum products deliveries increased 6.2% in 2007, compared to the prior year, total refined products delivery volumes decreased 0.4%. Gasoline delivery volumes decreased 3.2% (primarily due to Plantation), while diesel and jet fuel volumes were up 3.7% and 4.7%, respectively, in 2007 versus 2006. 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.

Natural Gas Pipelines


	Year Ended December 31,

	2008			2007			2006

	(In millions, except operating statistics)
Revenues	$	8,422.0		$	6,466.5		$	6,577.7
Operating expenses(a)		(7,804.0	)		(5,882.9	)		(6,057.8	)
Other income (expense)(b)		2.7			3.2			15.1
Earnings from equity investments(c)		113.4			19.2			40.5
Interest income and Other, net-income (expense)(d)		29.2			0.2			0.7
Income tax benefit (expense)		(2.7	)		(6.0	)		(1.4	)

Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	760.6		$	600.2		$	574.8


Natural gas transport volumes (Trillion Btus)(e)		2,156.3			1,712.6			1,440.9

Natural gas sales volumes (Trillion Btus)(f)		866.9			865.5			909.3




(a)	2008, 2007 and 2006 amounts include a $0.5 million decrease in expense, a $0.4 million decrease in expense and a $1.5 million increase in expense, respectively, associated with environmental liability adjustments. 2008 amount also includes a combined $5.6 million increase in income resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas, a $5.0 million increase in expense related to hurricane clean-up and repair activities, and a $0.3 million increase in expense associated with legal liability adjustments. Beginning in the second quarter of 2008, our Casper and Douglas gas processing operations discontinued hedge accounting. 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)	2008 amount includes a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC.

(e)	Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC, and Texas intrastate natural gas pipeline group pipeline volumes.

(f)	Represents Texas intrastate natural gas pipeline group volumes.

Combined, the certain items described in the footnotes to the table account for $14.4 million of the $160.4 million increase in earnings before depreciation, depletion and amortization (EBDA) between 2007 and 2008, and a $20.5 million decrease in EBDA between 2006 and 2007.

Following is information related to the increases and decreases in the segment’s (i) remaining changes in earnings before depreciation, depletion and amortization expenses (EBDA); and (ii) changes in operating revenues in both 2008 and 2007, when compared to the respective prior year:


Year Ended December 31, 2008 versus Year Ended December 31, 2007

	EBDA Increase/(decrease)					Revenues increase/(decrease)

	(In millions, except percentages)
Rockies Express Pipeline	$	97.0		769	%	$	—		—
Texas Intrastate Natural Gas Pipeline Group		37.7		11	%		1,924.9		32	%
Kinder Morgan Louisiana Pipeline		11.2		n/a			—		n/a
TransColorado Pipeline		11.1		26	%		12.5		24	%
Kinder Morgan Interstate Gas Transmission		5.4		5	%		(1.8	)	(1	)%
Casper and Douglas gas processing		(8.1	)	(38	)%		24.6		24	%
Trailblazer Pipeline		(5.6	)	(11	)%		(5.2	)	(9	)%
All others		(2.7	)	(8	)%		2.8		1096	%
Intrasegment Eliminations		—		—			(2.3	)	(170	)%

Total Natural Gas Pipelines	$	146.0		24	%	$	1,955.5		30	%


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	%
Kinder Morgan Interstate Gas Transmission		1.2		1	%		17.6		10	%
Rockies Express Pipeline		(12.6	)	n/a			(0.8	)	n/a
Red Cedar Gathering Company		(7.4	)	(20	)%		—		—
All others		(0.9	)	(1	)%		8.4		8	%
Intrasegment Eliminations		—		—			0.2		11	%

Total Natural Gas Pipelines	$	45.9		8	%	$	(111.2	)	(2	)%

In 2008, our Natural Gas Pipelines business segment benefitted from incremental contributions from our 51% equity ownership interest in Rockies Express Pipeline LLC, the owner of the Rockies Express Pipeline. We account for our investment in Rockies Express under the equity method of accounting, and the increase in our equity earnings reflects higher net income earned in 2008 by Rockies Express, primarily due to the start-up of service on the Rockies Express-West pipeline segment in January and May 2008.

The Rockies Express Pipeline began limited interim service in the first quarter of 2006 on its westernmost segment (the line that extends from Meeker, Colorado to Wamsutter, Wyoming), and the $12.6 million decrease in earnings before depreciation, depletion and amortization from Rockies Express in 2007 reflected lower net income, when compared to 2006, due primarily to incremental depreciation and interest expense allocable to another segment of the pipeline 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.

The segment realized increases in earnings before depreciation, depletion and amortization expenses in both 2008 and 2007 from 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.

The higher earnings in both 2008 and 2007, when compared to the respective prior years, were primarily due to higher sales margins on renewal and incremental sales contracts, increased transportation revenues from higher volumes and rates, greater value from natural gas storage activities, and higher natural gas processing margins. The earnings improvement in both years from higher natural gas sales margins reflected more favorable market conditions and year-over-year customer growth. The increases in earnings from transportation and storage activities in both 2008 and 2007 were partly driven by incremental natural gas transport and fee-based storage revenues due to a long-term contract with one of the group’s largest customers that became effective April 1, 2007. The increases in gas processing margins were largely due to more favorable price changes in natural gas liquids relative to the price of natural gas.

With regard to natural gas sales activity, our intrastate group’s business strategy involves relying both on long and short-term natural gas sales and purchase agreements; however, the spot market activity of our Texas intrastate group, which involves purchasing and selling natural gas under short-term commitments at a single volume price, gives us greater flexibility to balance supply and demand in order to react to changing market conditions. Furthermore, our spot market transactions can often be accomplished under contract terms that are less complex than traditional long-term arrangements and allow us to take advantage of the large concentration of buyers and sellers (as pipeline interconnections) located close to a large consuming region (the state of Texas). We use this flexibility with regard to our natural gas sales activities to help optimize the margins we realize by capturing favorable differences due to changes in timing, location, prices and volumes. Generally, we attempt to lock-in an acceptable margin by capturing the difference between our average gas sales prices and our average gas purchase and cost of fuel prices.

Because our intrastate group buys and sells significant quantities of natural gas, the variances from period to period in both segment revenues and segment operating expenses (which include natural gas costs of sales) are partly due to changes in our intrastate group’s average prices and volumes for natural gas purchased and sold. To the extent possible, we balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to balance sales with purchases at the index price on the date of settlement.

Following is information on other year-to-year increases and decreases in segment earnings before depreciation, depletion and amortization expenses in 2008 compared to 2007:


	• incremental earnings from our Kinder Morgan Louisiana Pipeline—reflecting other non-operating income realized in 2008 pursuant to FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance). The equity cost of capital allowance provides for a reasonable return on construction costs that are funded by equity contributions, similar to the allowance for capital costs funded by borrowings;

	• an increase in earnings from our TransColorado Pipeline—reflecting natural gas transportation contract improvements, pipeline expansions completed since the end of 2007, and an increase in natural gas production in the Piceance and San Juan basins of New Mexico and Colorado.

	• an increase in earnings from our Kinder Morgan Interstate Gas Transmission system—driven by lower power expenses, due to decreased electricity use and lower negotiated rates in 2008, a higher gross margin due to both higher operational natural gas sales margins and additional transportation revenues, and lower tax expenses payable to the state of Texas. (KMIGT’s operational gas sales are primarily made possible by collection of fuel in kind pursuant to its currently effective gas transportation tariff);

	• a decrease in earnings from our Casper Douglas gas processing operations—primarily attributable to higher natural gas purchase costs, due to increases in both prices and volumes, relative to 2007. The higher cost of sales expense more than offset a year-to-year revenue increase resulting from both higher average prices on natural gas liquids sales and higher sales of excess natural gas; and

	• a decrease in earnings from our Trailblazer Pipeline—mainly due to a 9% drop in revenues in 2008, relative to 2007, due mainly to lower revenues from both the sales of excess natural gas and backhaul natural gas transportation services.

And following is information on other year-to-year increases and decreases in segment earnings before depreciation, depletion and amortization expenses in 2007 compared to 2006:


	• an increase in earnings from our Casper Douglas operations—driven by an overall 6% increase in operating revenues, primarily attributable to higher natural gas liquids sales revenues due to increases in both prices and volume;

	• a decrease in earnings from our 49% equity investment in the Red Cedar Gathering Company—mainly due to lower prices on incremental sales of excess fuel gas and to lower natural gas gathering revenues.

CO₂


	Year Ended December 31,

	2008			2007			2006

	(In millions, except operating statistics)
Revenues(a)	$	1,133.0		$	824.1		$	736.5
Operating expenses(b)		(391.8	)		(304.2	)		(268.1	)
Other income (expense)		—			—			—
Earnings from equity investments		20.7			19.2			19.2
Other, net-income (expense)		1.9			—			0.8
Income tax benefit (expense)		(3.9	)		(2.1	)		(0.2	)

Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	759.9		$	537.0		$	488.2

Carbon dioxide delivery volumes (Bcf)(c)		732.1			637.3			669.2

SACROC oil production (gross)(MBbl/d)(d)		28.0			27.6			30.8

SACROC oil production (net)(MBbl/d)(e)		23.3			23.0			25.7

Yates oil production (gross)(MBbl/d)(d)		27.6			27.0			26.1

Yates oil production (net)(MBbl/d)(e)		12.3			12.0			11.6

Natural gas liquids sales volumes (net)(MBbl/d)(e)		8.4			9.6			8.9

Realized weighted average oil price per Bbl(f)(g)	$	49.42		$	36.05		$	31.42

Realized weighted average natural gas liquids price per Bbl(g)(h)	$	63.00		$	52.91		$	43.90




(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)	2008 and 2007 amounts include increases in expense associated with environmental liability adjustments of $0.3 million and $0.2 million, respectively.

(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 approximately 97% working interest in the SACROC unit and an approximately 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.

Combined, the certain items described in the footnotes to the table above account for a $0.1 million decrease in earnings before depreciation, depletion and amortization expenses (EBDA) between 2007 and 2008, and $1.6 million of the $48.8 million increase in EBDA between 2006 and 2007. The items also account for a $1.8 million increase in revenues between 2006 and 2007. For each of the segment’s two primary businesses, following is information related to the remaining changes in (i) earnings before depreciation, depletion and amortization expenses; and (ii) operating revenues in both 2008 and 2007, when compared to the respective prior year:


Year Ended December 31, 2008 versus Year Ended December 31, 2007

	EBDA increase/(decrease)				Revenues increase/(decrease)

	(In millions, except percentages)
Sales and Transportation Activities	$	123.5	70	%	$	147.3		79	%
Oil and Gas Producing Activities		99.5	28	%		198.5		29	%
Intrasegment Eliminations		—	—			(36.9	)	(77	)%

Total CO₂	$	223.0	42	%	$	308.9		37	%


Year Ended December 31, 2007 versus Year Ended December 31, 2006

	EBDA increase/(decrease)					Revenues 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	%

The segment’s overall $223.0 million (42%) increase in earnings before depreciation, depletion and amortization in 2008, when compared to 2007, was driven almost evenly by higher earnings from its carbon dioxide sales and transportation activities and its oil and gas producing activities. The earnings increase was largely revenue related, driven by increased crude oil, carbon dioxide, and natural gas liquids sales revenues, due primarily to increases in average crude oil (which also impacts the price of carbon dioxide) and natural gas plant product prices during the first three quarters of 2008.

Generally, earnings for the segment’s oil and gas producing activities, which include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants, are closely aligned with our realized price levels for crude oil and natural gas liquids products. Revenues from crude oil sales and natural gas plant products sales increased $186.2 million (40%) and $7.0 million (4%), respectively, in 2008 compared to 2007, driven by increases of 37% and 19%, respectively, in the realized weighted average price per barrel.

Crude oil sales volumes increased 2% in 2008, when compared to last year, but natural gas liquids sales volumes dropped 13% in 2008, due primarily to the effects from Hurricane Ike, and in part to operational issues on a third party owned pipeline, which resulted in pro-rationing (production allocation). Hurricane Ike, which made landfall at Galveston, Texas, on September 13, 2008, temporarily shut-down third-party fractionation facilities, which caused a decline in liquids production volumes in and around the Permian Basin area through the end of November.

Because prices of crude oil and natural gas liquids are subject to external factors over which we have no control, and because future price changes may be volatile, our CO₂ segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. To some extent, we are able to 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. Nonetheless, decreases in the prices of crude oil and natural gas liquids will have a negative impact on the results of our CO₂ business segment. 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 $97.70 per barrel in 2008, $69.63 per barrel in 2007 and $63.27 per barrel in 2006. For more information on our hedging activities, see Note 14 to our consolidated financial statements included elsewhere in this report.

The year-over-year increase in earnings before depreciation, depletion and amortization from the segment’s sales and transportation activities in 2008 was driven by a $87.9 million (137%) increase in carbon dioxide sales revenues and a $16.1 million (23%) increase in carbon dioxide and crude oil pipeline transportation revenues. The increase in carbon dioxide sales revenues was driven by a 75% increase in average sales prices and a 21% increase in average sales volumes, when compared to 2007. The increase in total pipeline transportation revenues was chiefly due to a 15% increase in carbon dioxide delivery volumes in 2008, relative to last year.

The increase in average carbon dioxide sales prices reflect continued customer demand for carbon dioxide for use in oil recovery projects throughout the Permian Basin area and, in addition, a portion of our carbon dioxide contracts are tied to crude oil prices, which as discussed above, have increased since the end of 2007. We do not recognize profits on carbon dioxide sales to ourselves. The increases in carbon dioxide sales and delivery volumes were largely due to the January 17, 2008 start-up of the Doe Canyon carbon dioxide source field located in Dolores County, Colorado. We hold an approximately 87% working interest in Doe Canyon. Since July 2006, we have invested approximately $90 million to develop this source field. In addition, investments were also made to drill

additional carbon dioxide wells at the McElmo Dome unit, increase transportation capacity on the Cortez Pipeline, and extend the Cortez Pipeline to the new Doe Canyon Deep unit.

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. 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, largely due 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 in 2007 was primarily due to a decrease in carbon dioxide sales revenues, resulting mainly from lower average prices for carbon dioxide, and partly from a 3% drop in carbon dioxide sales 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 significant high-priced sales contract in December 2006.

The $85.8 million (12%) increase in segment revenues in 2007, when compared to 2006, was mainly due to higher revenues from the segment’s oil and gas producing activities’ natural gas liquids and crude oil sales. Combined, plant product and crude oil sales revenues increased $77.9 million (14%) in 2007 compared to 2006.

The increase in revenues from the sales of natural gas liquids and crude oil was driven by favorable sales price variances—our realized weighted average price per barrel for liquids products increased 21% in 2007, relative to 2006, and our average crude oil realization increased 15% in 2007 compared to the prior year. Plant product liquids volumes also increased 8%, but total crude oil sales volumes decreased 6% in 2007 compared to 2006, largely due to a 10% decline in gross production at the SACROC field unit. The decline in crude oil production at SACROC was mainly attributable to lower observed recoveries from certain project areas and partly attributable 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.

Terminals


	Year Ended December 31,

	2008			2007			2006

	(In millions, except operating statistics)
Revenues	$	1,173.6		$	963.7		$	864.8
Operating expenses(a)		(631.8	)		(536.4	)		(461.9	)
Other income (expense)(b)		(2.7	)		6.3			15.2
Earnings from equity investments		2.7			0.6			0.2
Other, net-income (expense)		1.7			1.0			2.1
Income tax benefit (expense)(c)		(19.7	)		(19.2	)		(12.3	)

Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	523.8		$	416.0		$	408.1


Bulk transload tonnage (MMtons)(d)		99.1			96.2			95.1

Liquids leaseable capacity (MMBbl)		54.2			47.5			43.5

Liquids utilization %		97.5	%		95.9	%		96.3	%

(a)

2008 and 2007 amounts include a $0.6 million decrease in expense and a $2.0 million increase in expense, respectively, associated with environmental liability adjustments. 2008 amount also includes a $5.3 million increase in expense related to hurricane clean-up and repair activities; a combined $2.8 million increase in expense from the settlement of certain litigation matters related to our Elizabeth River bulk terminal and our Staten Island liquids terminal, and other legal liability adjustments; and a $1.9 million increase in expense related to fire damage and repair activities. 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)	2008 amount includes a decrease in income of $5.3 million from property casualty losses related to fire damage, and a decrease in income of $0.8 million from property casualty losses related to hurricane damage. 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)	2008 amount includes a decrease in expense (reflecting tax savings) of $0.4 million related to hurricane clean-up and repair expenses and casualty losses. 2006 amount includes a $1.1 million increase in expense associated with casualty gains and hurricane expenses.

(d)	Volumes for acquired terminals are included for all periods.

Combined, the certain items described in the footnotes to the table above account for $11.3 million of the $107.8 increase in earnings before depreciation, depletion and amortization between 2007 and 2008, and a $37.7 million decrease in earnings before depreciation, depletion and amortization between 2006 and 2007. The segment’s remaining $96.5 million (22%) increase in earnings before depreciation, depletion and amortization expenses in 2008 compared to 2007, and its remaining $45.6 million (11%) increase in 2007 compared to 2006, were driven by a combination of internal asset expansions and strategic business acquisitions completed since the end of 2006.

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 terminal storage, handling and throughput capacity. Beginning with our acquisition of the Vancouver Wharves bulk marine terminal on May 30, 2007 and including, among others, the terminal assets we acquired from Marine Terminals, Inc. effective September 1, 2007, we have invested approximately $179.0 million in cash to acquire both terminal assets and equity interests in terminal operations, and combined, these acquired operations accounted for incremental earnings before depreciation, depletion and amortization of $30.4 million, revenues of $86.6 million, equity earnings of $1.7 million, and operating expenses of $57.9 million in 2008.

In 2007, we also benefitted significantly from the incremental contributions attributable to the bulk and liquids terminal businesses we acquired during 2007 and 2006. Combined, these acquired 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 2008 and 2007 amounts listed above represent the earnings, revenues and expenses from acquired terminals’ operations during the additional months of ownership in 2008 and 2007, respectively, and do not include increases or decreases during the same months we owned the assets in the respective prior year. For more information on our acquisitions, see Note 3 to our consolidated financial statements included elsewhere in this report.

For all other terminal operations (those owned during identical periods in both pairs of comparable years), earnings before depreciation, depletion and amortization expenses increased $66.1 million (15%) in 2008, and $14.4 million (4%) in 2007, when compared to the respective prior years. The increases in earnings represent net changes in terminal results at various locations, and the $66.1 million year-over-year increase in 2008 compared to 2007 for terminal operations owned during identical periods in both years included the following:


	• a $27.8 million (25%) increase from our Gulf Coast terminal facilities, primarily our two large liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas. The increase was due mainly to higher liquids throughput volumes and increased liquids storage capacity as a result of expansions completed since the end of 2007;

	• a $20.3 million (50%) increase from our Mid-Atlantic terminals, primarily our Pier IX bulk terminal located in Newport News, Virginia, due to higher period-over-period coal transfer volumes, and our Fairless Hills, Pennsylvania bulk terminal, largely due to incremental earnings from a new import fertilizer facility that began operations in the second quarter of 2008. The increases in coal throughput at Pier IX were largely due to an almost $70 million capital improvement project, completed in the first quarter of 2008, that involved the construction of a new ship dock and the installation of additional terminal equipment. The import fertilizer facility at Fairless Hills cost approximately $11.2 million to build, and included the construction of two storage domes, conveying equipment, and outbound loading facilities for both rail and truck;

	• a $10.5 million (16%) increase from our Northeast terminals, largely due to higher earnings from our New York Harbor liquids terminals, which include our Perth Amboy, New Jersey terminal; our Carteret, New


	Jersey terminal; and our Kinder Morgan Staten Island terminal. The year-over-year increase in earnings from these terminals was driven by a combined 21% increase in liquids throughput volumes (resulting both from incremental business driven by strong demand for imported fuel and from tank expansions completed since the end of 2007), higher transfer and storage rates, and incremental revenues from ancillary terminal services; and

	• a $7.0 million (30%) increase from our West region terminals, mainly from our Vancouver Wharves bulk marine terminal and from our Kinder Morgan North 40 terminal, a crude oil tank farm located in Edmonton, Alberta, Canada. We announced the construction of the North 40 terminal in June 2006, and we completed construction and began terminal operations in the second quarter of 2008. The increase from Vancouver Wharves was due largely to higher terminal revenues from liquids throughput and handling services.

The $14.4 million (4%) increase in earnings before depreciation, depletion and amortization in 2007 compared to 2006 from terminal operations owned during identical periods in both years was largely due to the following:


	• a $9.7 million (10%) increase from our two liquids terminal facilities located in Pasadena and Galena Park, Texas. The two terminals benefitted from both completed expansions that added new liquids tank and truck loading rack capacity since the end of 2006 and incremental business from ethanol and biodiesel storage and transfer activity. For the entire terminals segment combined, our expansion projects and acquisitions completed since the end of 2006 increased our liquids terminals’ leaseable capacity by 9% in 2007, more than offsetting a less than 1% drop in our overall utilization percentage;

	• a $3.7 million (23%) increase from the combined operations of our Argo and Chicago, Illinois liquids terminals, due to increased ethanol throughput and incremental liquids storage and handling business;

	• a $1.8 million (4%) increase from our Texas Petcoke terminals, due largely to higher petroleum coke throughput volumes in 2007 at our Port of Houston facility;

	• a $1.2 million (15%) increase from our Pier IX bulk terminal, chiefly due to a 19% year-to-year increase in coal transfer volumes and higher rail incentives; and

	• a $2.0 million (6%) decrease from our Lower River (Louisiana) terminals, primarily due to both lower revenues from our 66 2/3% interest in the International Marine Terminals partnership facility, a multi-product bulk terminal located in Sulphur Springs, Louisiana, and to higher income tax expense accruals. The decrease in revenues from IMT was mainly due to lower tonnage volumes and lower ship dockage revenues in 2007, and the increase in income tax expense was largely due to higher taxable income attributable to Kinder Morgan Bulk Terminals, Inc., our tax-paying subsidiary that owns many of our Louisiana bulk terminal businesses which handle non-qualifying products.

Kinder Morgan Canada


	Year Ended December 31,

	2008			2007			2006(e)

	(In millions, except operating statistics)
Revenues	$	196.7		$	160.8		$	137.8
Operating expenses		(67.9	)		(65.9	)		(53.3	)
Other income (expense)(a)		—			(377.1	)		0.9
Earnings from equity investments		(0.4	)		—			—
Interest income and Other, net-income (expense)(b)		(6.2	)		8.0			1.0
Income tax benefit (expense)(c)		19.0			(19.4	)		(9.9	)

Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(d)	$	141.2		$	(293.6	)	$	76.5


Transport volumes (MMBbl)		86.7			94.4			83.7




(a)	2007 amount represents a goodwill impairment expense recorded by Knight in the first quarter of 2007.

(b)	2008 amount includes a $19.3 million decrease in expense associated with favorable changes in Canadian income tax rates, and a $12.3 decrease in other non-operating income from the amounts previously reported in our 2008 fourth quarter earnings release issued on January 21, 2009, due to certain non-cash Trans Mountain regulatory accounting adjustments.

(c)	2008 amount includes a $6.6 million increase in expense from the amounts previously reported in our 2008 fourth quarter earnings release issued on January 21, 2009, due to certain non-cash Trans Mountain regulatory accounting adjustments.

(d)	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.

(e)	2006 amounts relate to periods prior to our acquisition date of April 30, 2007. See discussion below.

After taking into effect the certain items described in footnote to the table above, the remaining increases in earnings before depreciation, depletion and amortization totaled $83.9 million (147%) in 2008 versus 2007, and $56.9 million in 2007 versus 2006. The 2007 increase related entirely to our acquisition of Trans Mountain effective April 30, 2007, and the 2008 increase consisted of (i) higher earnings of $38.1 million (67%) from the Trans Mountain pipeline assets we owned in the same periods in both years (May through December); and (ii) incremental earnings of $45.8 million from periods we owned assets in 2008 only (Trans Mountain for the period January through April, and Express and Jet Fuel for the period September through December).

The $38.1 million increase in earnings from assets owned during the same periods in both 2008 and 2007 was driven primarily by higher operating revenues, due largely to the completion of the Trans Mountain Pipeline Anchor Loop expansion project discussed elsewhere in this report.

The Anchor Loop project boosted pipeline capacity from 260,000 to 300,000 barrels per day and resulted in higher period-to-period average toll rates. The higher tariffs became effective in June 2008, and more than offset an 8% decline in mainline throughput volumes, which resulted primarily from lower demand for water-borne exports out of Vancouver, British Columbia.

Other


	Year Ended December 31,						Earnings increase/(decrease)
	2008			2007			Earnings increase/(decrease)

	(In millions-income (expense), except percentages)
General and administrative expenses(a)	$	(297.9	)	$	(278.7	)	$	(19.2	)	(7	)%


Unallocable interest expense, net of interest income(b)		(397.6	)		(395.8	)		(1.8	)	—
Unallocable income tax benefit (expense)		(9.3	)		(4.6	)		(4.7	)	(102	)%
Minority interest(c)		(13.7	)		(7.0	)		(6.7	)	(96	)%

Total interest and other non-operating expenses	$	(420.6	)	$	(407.4	)	$	(13.2	)	(3	)%


	Year Ended December 31,						Earnings increase/(decrease)
	2007			2006			Earnings increase/(decrease)

	(In millions-income (expense), except percentages)
General and administrative expenses(a)	$	(278.7	)	$	(238.4	)	$	(40.3	)	(17	)%


Unallocable interest expense, net of 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 other non-operating expenses	$	(407.4	)	$	(357.8	)	$	(49.6	)	(14	)%




(a)	Includes such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services. 2008 amount includes (i) a $5.6 million increase in non-cash compensation expense, allocated to us from Knight (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $0.9 million increase in expense for certain Express pipeline system acquisition costs; (iii) a $0.4 million expense resulting from the write-off of certain acquisition costs pursuant to a newly adopted accounting principle; (iv) a $0.1 million increase in expense related to hurricane clean-up and repair activities; and (v) a $2.0 million decrease in expense due to the adjustment of certain insurance related liabilities. 2007 amount includes (i) a $26.2 million increase in expense, allocated to us from Knight, associated with closing the going-private transaction (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (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 (i) an $18.8 million expense related to Trans Mountain expenses; (ii) a $2.4 million increase in expense related to the cancellation of certain commercial insurance policies; and (iii) 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 (capitalization of overhead expense).

(b)	2008 amount includes (i) a $7.1 million decrease in interest expense from the amounts previously reported in our 2008 fourth quarter earnings release issued on January 21, 2009, due to certain non-cash Trans Mountain regulatory accounting adjustments; (ii) a $2.0 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition; and (iii) a $0.2 million increase in interest expense related to the proposed settlement of certain litigation matters related to our Pacific operations’ East Line pipeline. 2007 amount includes a $2.4 million increase in expense related to imputed interest on our Cochin Pipeline acquisition, and a $1.2 million expense for Trans Mountain expenses for periods prior to our acquisition date of April 30, 2007. 2006 amount includes Trans Mountain expenses of $6.3 million.

(c)	2008, 2007 and 2006 amounts include a $0.4 million decreases in expense, a $3.9 million decrease in expense, and a $3.5 million increase in expense, respectively, related to the minority interest effect from all of the 2008, 2007 and 2006 items previously disclosed in the footnotes to the tables included in “—Results of Operations.”

Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense and minority interest. Overall, our total general and administrative expenses increased $19.2 million (7%) in 2008 compared to 2007, and $40.3 million (17%) in 2007 compared to 2006. However, the certain items described in footnote (a) to the tables above resulted in a combined $32.8 million decrease in expense in 2008 compared to 2007, and a combined $17.0 million increase in expense in 2007 compared to 2006.

The remaining $52.0 million (22%) and $23.3 million (11%) increases in general and administrative expenses in 2008 and 2007 were largely due to (i) higher compensation-related expenses—comprising salary and benefit expenses, payroll taxes and other employee and contractor related expenses; and (ii) higher shared corporate services expenses—including legal services, corporate secretary, tax, human resources, information technology and other shared services. These increases in administrative expenses were associated with our larger year-over-year asset base and included incremental expenses and higher corporate overhead associated with the assets and operations we have acquired since the end of 2005, including the Trans Mountain, Express (one-third interest) and Jet Fuel pipeline systems we acquired from Knight, and the acquired bulk and liquids terminal operations that are described above in “—Terminals.” Acquiring assets and supporting internal growth initiatives result in increased spending levels and expenses; however, we continue to manage aggressively our infrastructure expenses in order to operate our assets in the most efficient manner possible.

Unallocable interest expense, net of interest income, increased $1.8 million (less than 1%) in 2008 compared to 2007, and $53.4 million (16%) in 2007 compared to 2006. The certain items described in footnote (b) to the tables above decreased interest expense by $8.5 million in 2008 and decreased interest expense by $2.7 million in 2007, when compared to the respective prior year periods.

The remaining $10.3 million (3%) increase in expense in 2008 compared to 2007 was driven by a 22% increase in average borrowings (excluding the value of interest rate swap agreements), partially offset by a 15% drop in our weighted average interest rate. The decrease in our weighted average borrowing rate in 2008 reflects a general decrease in variable interest rates since the end of last year—the weighted average interest rate on all of our borrowings was approximately 5.44% during 2008 and 6.40% during 2007. The remaining $56.1 million (17%) increase in interest expense in 2007 compared to 2006 was due to both higher average debt levels and higher effective interest rates. In 2007, average borrowings increased 17% and the weighted average interest rate on all of our borrowings increased from 6.2% in 2006 to 6.4% in 2007.

The year-over-year increases in our average borrowings was largely due to the capital spending (for asset expansion and improvement projects, including additional pipeline construction costs) and the external business acquisitions we have made since the end of 2005. Generally, we initially fund both our discretionary capital spending (including payments for pipeline project construction costs) and our acquisition outlays from borrowings under our commercial paper program or our long-term revolving bank credit facility. From time to time, we issue senior notes and equity 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.”

As of December 31, 2008, approximately 34% of our $8,563.6 million consolidated debt balance (excluding the value of interest rate swap agreements) was subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. As of December 31, 2007, approximately 42% of our $7,066.1 million consolidated debt balance was subject to variable interest rates.

The incremental unallocable income tax expense, in both 2008 and 2007, relates to higher year-to-year corporate income tax accruals for the Texas margin tax, an entity-level tax initiated January 1, 2007 and imposed on the amount of our total revenue that is apportioned to the state of Texas. Minority interest, which represents the deduction in our consolidated net income attributable to all outstanding ownership interests in our operating limited partnerships and their consolidated subsidiaries that are not held by us, increased in 2008 and decreased in 2007, when compared to the respective prior year. Both the increase, in 2008, and the drop, in 2007, was due to overall lower partnership income in 2007, relative to both 2008 and 2006.

Liquidity and Capital Resources

General

As of December 31, 2008, we believe our balance sheet and liquidity positions remained strong. Cash on hand was $62.5 million at the close of the year, and on December 19, 2008, we demonstrated our continued access to the term debt market by issuing $500 million in senior notes that mature on February 1, 2019. Also in December 2008, we took advantage of the general decrease in variable interest rates since the start of the year by terminating two of our existing fixed-to-variable interest rate swap agreements, and we received combined proceeds of $194.3 million from the early termination of these swap agreements (we terminated a third swap agreement in January 2009 and received additional proceeds of $144.4 million). Similarly, we demonstrated continued access to the equity market by raising $176.6 million in cash from the public offering of 3,900,000 additional common units on December 22, 2008.

In addition, our diverse set of energy assets generated $2,235.9 million in cash from operations in 2008, and based on long-term contracted customer commitments and current cost estimates, we expect to realize incremental returns from completed capital expansion projects that are currently in process. We also had, at December 31, 2008, $1.47 billion of borrowing capacity available under our $1.85 billion bank credit facility (discussed below in “—Short-term Liquidity”) and, at Knight’s third quarter board meeting on October 15, 2008, Knight’s board indicated its willingness to contribute up to $750 million of equity to us over the subsequent 18 months, if necessary, in order to support our capital raising efforts.

Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures (defined as capital expenditures which do not increase the capacity of an asset), expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder 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 long-term notes or additional common units or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of additional KMR shares.

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.

Credit Ratings and Capital Market Liquidity

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. 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, and 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.

On May 30, 2006, Standard & Poor’s Rating Services and Moody’s Investors Service each placed our long-term credit ratings on credit watch pending the resolution of KMI’s going-private transaction. On January 5, 2007, in anticipation of the going-private transaction closing, S&P downgraded us one level to BBB and removed our rating from credit watch with negative implications. 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. Currently, our long-term corporate debt credit rating is BBB, Baa2 and BBB, respectively, at S&P, Moody’s and Fitch.

On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One Lehman entity was a lending institution that provided a portion of our, Rockies Express’, and Mid Continent Express’ respective credit facilities. Since Lehman Brothers declared bankruptcy, its affiliate, which is a party to the aforementioned credit facilities, has not met its obligations to lend under those agreements. As such, the commitments have been effectively reduced by $63 million, $41 million, and $100 million, respectively, to $1.79 billion, $1.96 billion, and $1.30 billion. The commitments of the other banks remain unchanged, and the facilities are not defaulted.

On October 13, 2008, S&P revised its outlook on our long-term credit rating to negative from stable (but affirmed our long-term credit rating at BBB), due to our previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project. At the same time, S&P lowered our short-term credit rating to A-3 from A-2. As a result, we no longer have access to the commercial paper market. However, we believe that our $1.8 billion credit facility is adequate to meet our short term liquidity needs.

Additionally, 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. These financial problems may arise from the current financial crises, changes in commodity prices or otherwise. We have and are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers. We cannot provide assurance that one or more of our current or future 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; however, we believe we have provided adequate allowance for such customers.

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 outstanding short-term debt as of December 31, 2008 was $288.7 million, primarily consisting of a $250 million principal amount of 6.3% senior notes that matured and was paid on February 1, 2009. As of December 31, 2007, our outstanding short-term debt was $610.2 million.

Our principal sources of short-term liquidity are:


	• our $1.85 billion five-year senior unsecured revolving bank credit facility that matures August 18, 2010; and

	• our cash from operations (discussed following in “—Operating Activities”).

Borrowings under our five-year credit facility can be used for general partnership purposes and as a backup for a commercial paper program. The facility can be amended to allow for borrowings up to $2.1 billion. As of both December 31, 2008 and 2007, we had no borrowings under our five-year credit facility. We provide for liquidity by maintaining excess borrowing capacity under our five year revolving credit facility. After reduction for (i) our letters of credit; (ii) commercial paper and/or borrowings under our revolving credit facility outstanding (none at December 31, 2008); and (iii) lending commitments made by a Lehman Brothers related bank, the remaining available borrowing capacity under our bank credit facility was $1,473.7 million as of December 31, 2008.

As a result of the revision to our short-term credit rating and the current commercial paper market conditions, we are unable to access commercial paper borrowings and as of December 31, 2008, there were no borrowings under our commercial paper program. However, we expect that our financing and liquidity needs will continue to be met through borrowings made under our long-term bank credit facility, and we do not anticipate that fluctuations in the availability of the commercial paper market will affect our liquidity because of the flexibility provided by our credit facility. As of December 31, 2007, we had $589.1 million of commercial paper outstanding.

Currently, we believe our liquidity to be adequate, and we continue to monitor the status of the capital markets and regularly evaluate the effect that changes in capital market conditions may have on our announced business strategy to grow our portfolio of businesses. We expect that part of our short-term financing and liquidity needs will continue to be met through our long-term bank credit facility. For more information on 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 by utilizing the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.

On September 19, 2008, we filed a registration statement with the Securities and Exchange Commission under the Securities Act of 1933 on Form S-3. This registration statement, commonly referred to as a shelf registration statement, will allow us to sell up to $5 billion of additional common units or debt securities. The shelf registration statement is intended to provide us with flexibility to raise funds from the offering of our securities in one or more offerings, in amounts, and at prices to be set forth in subsequent filings made with the SEC at the time of each separate offering. This registration statement on Form S-3 was declared effective by the SEC on December 15, 2008.

Pursuant to this shelf registration statement, on January 16, 2009, we entered into an Equity Distribution Agreement with UBS Securities LLC. According to the provisions of this Agreement, we may offer and sell from time to time common units having an aggregate offering value of up to $300 million through UBS, as sales agent. Sales of the units, if any, will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions or as otherwise agreed between us and UBS. Under the terms of this Agreement, we also may sell common units to UBS as principal of its own account at a price agreed upon at the time of the sale. Any sale of common units to UBS as principal would be pursuant to the terms of a separate terms agreement between us and UBS.

We believe this Equity Distribution Agreement provides us further flexibility to raise funds from the offering of our securities because it provides us the right, but not the obligation, to draw down on the facility in the future, at prices we deem appropriate. We retain at all times complete control over the amount and the timing of each draw down, and we will designate the maximum number of common units to be sold through UBS, on a daily basis or otherwise as we and UBS agree. UBS will then use its reasonable efforts to sell, as our sales agent and on our behalf, all of the designated common units. We may instruct UBS not to sell common units if the sales cannot be effected at or above the price designated by us in any such instruction. Either we or UBS may suspend the offering of common units pursuant to the Agreement by notifying the other party. As of February 20, 2009, we have issued 612,083 of our common units pursuant to this Agreement. We received net proceeds of approximately $29.9 million for the issuance of these common units.

Our offerings would be subject to market conditions and our capital needs, and unless we specify otherwise in a prospectus supplement, we intend to use the net proceeds from the sale of offered securities for general partnership purposes. This may include, among other things, additions to working capital, repayment or refinancing of existing indebtedness or other partnership obligations, financing of capital expenditures and acquisitions, investment in existing and future projects, and repurchases and redemptions of securities. Pending any specific application, we may initially invest funds in short-term marketable securities or apply them to the reduction of other indebtedness.

We are subject, however, to changes in the equity and debt markets for our limited partner units and long-term notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units and/or long-term notes in the future. If we were unable or unwilling to issue additional limited partner units, we would be required to either restrict potential future acquisitions or pursue other debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Furthermore, our ability to access the public and private debt markets is affected by our credit ratings. See “—Credit Ratings and Capital Market Liquidity” above for a discussion of our credit ratings.

Equity Issuances

For information on our 2007 and 2008 equity issuances, see Note 11 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report.

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.

As of December 31, 2008 and 2007, the total liability balance due on the various series of our senior notes was $8,381.5 million and $6,288.8 million, respectively, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $182.1 million and $188.2 million, respectively. For additional information regarding our debt securities, see Note 9 to our consolidated financial statements included elsewhere in

this report; for specific information with regard to the 2007 and 2008 changes in the various series of our senior notes, including debt issuances, see Note 9 “Debt—Long-Term Debt—Senior Notes.”

Capital Structure

We attempt to maintain a relatively conservative overall capital structure, financing our expansion capital expenditures and acquisitions with approximately 50% equity and 50% debt. In the short-term, we fund these expenditures from borrowings under our credit facility until the amount borrowed is of a sufficient size to cost effectively do either a debt or equity offering, or both.

With respect to our debt financed expenditures, we target a debt mixture of approximately 50% fixed and 50% variable. We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate payments. Our interest rate mix is currently weighted more heavily towards fixed interest rates due to a decision to terminate a portion of our interest rate swap agreements at attractive prices in December 2008 and January 2009 as discussed under “—Interest Rate Risk” below.

Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares to institutional investors).

Capital Expenditures

Our sustaining capital expenditures for the year 2008 were $180.6 million (including approximately $0.1 million for our proportionate share of Rockies Express’ sustaining capital expenditures), and our forecasted expenditures for 2009 for sustaining capital expenditures are approximately $202.4 million (including $0.4 million for our proportionate share of Rockies Express). Generally, we fund our sustaining capital expenditures with our cash flows from operations.

All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. The discretionary capital expenditures reflected in our consolidated financial statements for the year 2008 were $2,352.5 million, and we forecasted $1,188.2 million for discretionary capital expenditures in our 2009 budget and capital expenditure plan. In addition to these amounts, we contributed an aggregate amount of $333.5 million for both the Rockies Express and Midcontinent Express natural gas pipeline projects in 2008, and we expect to contribute approximately $1.5 billion in the aggregate for both projects in 2009.

Capital Requirements for Recent Transactions

During 2008, our cash outlays for the acquisition of assets and investments totaled$40.2 million. For more information on our capital requirements during 2008 in regard to our acquisition expenditures, see Note 3 to our consolidated financial statements included elsewhere in this report. For more information on our recent debt related transactions, see Note 9 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, 2008, 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(i)		Total Entity Debt			Our Contingent Share of Entity Debt(j)

Cortez Pipeline Company	General Partner	50	%	(a)	$	95.7	$	169.6			$	84.8	(b)

West2East Pipeline LLC(c)	Limited Liability	51	%	ConocoPhillips and Sempra Energy	$	4,741.4	$	3,458.9	(d)		$	1,102.1	(e)


Midcontinent Express Pipeline LLC(f)	Limited Liability	50	%	Energy Transfer Partners, L.P.	$	981.1	$	837.5			$	418.8	(g)

Nassau County, Florida Ocean Highway And Port Authority (h)	N/A	N/A		Nassau County, Florida Ocean Highway and Port Authority		N/A		N/A			$	10.2




(a)	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.

(b)	We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt. As of December 31, 2008, Shell Oil Company shares our several guaranty obligations jointly and severally for $53.6 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, 2008 we have a letter of credit in the amount of $26.8 million issued by JP Morgan Chase, in order to secure our indemnification obligations to Shell for 50% of the Cortez debt balance of $53.6 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.

(c)	West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. As of December 31, 2008, 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%.

(d)	Amount includes an aggregate of $1.3 billion in principal amount of fixed rate senior notes issued by Rockies Express Pipeline LLC in a private offering in June 2008. All payments of principal and interest in respect of these senior notes are the sole obligation of Rockies Express. Noteholders have no recourse against us or the other member owners of West2East Pipeline LLC for any failure by Rockies Express to perform or comply with its obligations pursuant to the notes or the indenture.

(e)	In addition, there is a letter of credit outstanding to support the construction of the Rockies Express Pipeline. As of December 31, 2008, this letter of credit, issued by JPMorgan Chase, had a face amount of $31.4 million. Our contingent responsibility with regard to this outstanding letter of credit was $16.0 million (51% of total face amount).

(f)	Midcontinent Express Pipeline LLC is a limited liability company and the owner of the Midcontinent Express Pipeline. In January 2008, in conjunction with the signing of additional binding pipeline transportation commitments, Midcontinent Express Pipeline LLC 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 Pipeline LLC after the pipeline is fully constructed and placed into service. If the option is exercised, we and Energy Transfer Partners, L.P. will each own 45% of Midcontinent Express Pipeline LLC, while MarkWest will own the remaining 10%.


(g)	In addition, there is a letter of credit outstanding to support the construction of the Midcontinent Express Pipeline. As of December 31, 2008, this letter of credit, issued by the Royal Bank of Scotland plc, had a face amount of $33.3 million. Our contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).

(h)	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, 2008, the face amount of this letter of credit outstanding under our credit facility was $10.2 million. Principal payments on the bonds are made on the first of December each year and reductions are made to the letter of credit.

(i)	Principally property, plant and equipment.

(j)	Represents the portion of the entity’s debt that we may be responsible for if the entity cannot satisfy the obligation.

For additional information with regard to our contingent debt obligations, Note 9 “Debt—Contingent Debt” to our consolidated financial statements included elsewhere in this report.

We account for our investments in Cortez Pipeline Company, West2East Pipeline LLC and Midcontinent Express Pipeline LLC under the equity method of accounting. For the year ended December 31, 2008, our share of earnings, based on our ownership percentage and before amortization of excess investment cost, if any, was $20.8 million from Cortez Pipeline Company, $84.9 million from West2East Pipeline LLC, and $0.5 million from Midcontinent Express 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	$	—	$	—	$	—	$	—	$	—
Other debt borrowings-principal payments		8,582.1		288.7		992.7		1,975.5		5,325.2
Interest payments(a)		7,735.7		542.9		1,020.9		848.5		5,323.4
Lease obligations(b)		149.0		31.3		50.1		32.1		35.5
Pension and post-retirement welfare plans(c)		70.5		5.1		10.7		12.2		42.5
Other obligations(d)		15.1		8.3		6.8		—		—

Total	$	16,552.4	$	876.3	$	2,081.2	$	2,868.3	$	10,726.6


Other commercial commitments:
Standby letters of credit(e)	$	343.8	$	273.3	$	25.7	$	26.8	$	18.0

Capital expenditures(f)	$	581.0	$	581.0	$	—	$	—	$	—




(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, 2008.

(d)	Consist of payments due under carbon dioxide take-or-pay contracts and, for the 1 Year or Less column only, our purchase and sale agreement with LPC Packaging (a California corporation) for the acquisition of certain bulk terminal assets.

(e)	The $343.8 million in letters of credit outstanding as of December 31 2008 consisted of the following: (i) 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; (ii) a $55.9 million letter of credit supporting our pipeline and terminal operations in Canada; (iii) a combined $40.0 million in two letters of credit supporting our hedging of energy commodity price risks; (iv) 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; (v) a $26.8 million letter of credit supporting our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; (vi) a $25.4 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $18.0 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (viii) a $10.2 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; (ix) a $5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois Development Revenue Bonds; and (x) a combined $16.6 million in seven 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, 2008.

Operating Activities

Net cash provided by operating activities was $2,235.9 million in 2008, versus $1,741.8 million in 2007. The overall year-to-year increase of $494.1 million (28%) in cash flow from operations consisted of:


	• a $422.2 million increase in cash from overall higher partnership income—after adding back, among other things, gains and losses on property sales and casualties and certain non-cash expense items, including the $377.1 million goodwill impairment charge recognized in the first quarter of 2007, and non-cash legal expenses associated with certain adjustments made to our reserves related to the legal fees, transportation rate cases and other litigation liabilities of our pipeline and terminal operations—including the $140.0 million expense associated with an increase to our litigation reserves in the fourth quarter of 2007. The higher partnership income reflects an increase in cash earnings from our five reportable business segments in 2008, as discussed above in “—Results of Operations;”

	• a $179.3 million increase in cash from settlements related to the early termination of interest rate swap agreements. In December 2008, we terminated two existing fixed-to-variable interest rate swap agreements having a combined notional principal amount of $700 million and we received combined proceeds of $194.3 million; in March 2007, we terminated a fixed-to-variable interest rate swap agreement having a notional principal amount of $100 million and we received a termination payment of $15.0 million;

	• a $54.3 million increase related to higher distributions received from equity investments—chiefly due to $82.9 million of initial distributions received in 2008 from our investment in West2East Pipeline LLC, the sole owner of Rockies Express Pipeline LLC. Currently, we own a 51% equity interest in West2East Pipeline LLC, and when construction of the Rockies Express Pipeline is completed, our ownership interest will be reduced to 50% and the capital accounts of West2East Pipeline LLC will be trued-up to reflect our 50% economic interest in the project.

	The overall increase in period-to-period distributions from equity investments includes a $28.9 million decrease in distributions received from the Red Cedar Gathering Company. In the first quarter of 2007, Red Cedar distributed to us $32.6 million following a refinancing of its long-term debt obligations. Red Cedar used the proceeds received from the March 2007 sale of unsecured senior notes to refund and retire the outstanding balance on its then-existing senior notes, and to make a distribution to its two owners;

	• a $107.7 million decrease in cash inflows related to period-to-period changes in both non-current assets and liabilities and other non-cash expenses. The decrease in cash was driven by, among other things, lower transportation and dock prepayments received from Trans Mountain pipeline system customers in 2008, lower increases in environmental liability reserves in 2008, and lower non-cash general and administrative expenses in 2008, due to higher expenses in 2007 related to the activities required to complete KMI’s going-private transaction.

	With regard to the going-private transaction expenses, for accounting purposes, Knight is required to allocate to us a portion of these transaction-related amounts and we are required to recognize the amounts as expense on our income statements; however, we were not responsible for paying these buyout expenses, and


	accordingly, we recognize the unpaid amount as both a contribution to “Partners’ Capital” and an increase to “Minority interest” on our balance sheet;

	• a $30.2 million decrease in cash attributable to reparation and/or refund payments made in 2008 to certain shippers on our Pacific operations’ pipelines. The settlement payments were made pursuant to both FERC orders and certain litigation settlement agreements—primarily related to a FERC ruling in February 2008 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; and

	• a $23.8 million decrease in cash inflows relative to net changes in working capital items.

Investing Activities

Net cash used in investing activities was $2,825.4 million for the year ended December 31, 2008, compared to $2,428.5 million in the prior year. The $396.9 million (16%) overall increase in funds utilized in investing activities was primarily attributable to the following:


	• a $841.4 million increase in cash used from higher capital expenditures—largely due to increased investment undertaken to construct our Kinder Morgan Louisiana Pipeline, add infrastructure to our carbon dioxide producing and delivery operations, and expand our Trans Mountain crude oil and refined petroleum products pipeline system.

	Since the end of 2007, rising construction costs, additional regulatory requirements, and certain weather delays have continued to create a challenging business environment and accordingly, the amount of capital expenditures we made on our major projects during 2008 increased from the projection we made at the beginning of 2008. Most of this increase has been on our major natural gas pipeline projects—for example, market conditions for consumables, labor and construction equipment along with certain provisions in the final environmental impact statement have resulted in increased construction costs for the Rockies Express Pipeline. Our current estimate of total construction costs for the entire Rockies Express pipeline project is now approximately $6.2 billion (our proportionate share is 51% and this cost estimate is consistent with our January 21, 2009 fourth quarter earnings press release).

	We continue to be focused on managing these cost increases in order to complete our expansion projects as close to on-time and on-budget as possible, and we attempt to identify ancillary opportunities to increase our returns where possible. In addition to utilizing cash generated from its operations or proceeds from contributions received from its member owners, Rockies Express can fund its cash requirements for capital expenditures through borrowings under its own credit facility, issuing its own short-term commercial paper (when credit market conditions are favorable), or issuing long-term notes.

	Our sustaining capital expenditures totaled $180.6 million in 2008 and $152.6 million in 2007. The above amounts include our proportionate share of Rockies Express’ sustaining capital expenditures—approximately $0.1 million in 2008 and none in 2007—but do not include the sustaining capital expenditures of our Trans Mountain pipeline system for periods prior to our acquisition date of April 30, 2007. Generally, we fund our sustaining capital expenditures with existing cash or from cash flows from operations. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary, and our discretionary capital expenditures—including expenditures for internal expansion projects—totaled $2,352.5 million for 2008, versus $1,539.0 million for 2007;

	• a $254.8 million increase in cash used due to lower net proceeds received from the sales of investments, property, plant and equipment, and other net assets (net of salvage and removal costs). The decrease in cash sales proceeds was driven by the approximately $298.6 million we received for the fourth quarter 2007 sale of our North System operations. In 2008, we received approximately $50.7 million for the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC (both divestitures are discussed in Note 3 to our consolidated financial statements included elsewhere in this report);


	• a $109.6 million increase in cash used from a loan we made in December 2008 to a single customer of our Texas Intrastate natural gas pipeline group;

	• a $90.6 million increase in cash used from incremental contributions to investments in 2008, largely driven by a $306.0 million equity investment paid in February 2008 to West2East Pipeline LLC to partially fund its Rockies Express Pipeline construction costs. Total contributions to West2East Pipeline increased $101.2 million in 2008, when compared to 2007, and in 2008 we also purchased a combined $13.2 million in principal amount of tax-exempt development revenue bonds and contributed $9.0 million to Fayetteville Express Pipeline LLC, our 50% owned equity investee that will construct and operate the Fayetteville Express natural gas pipeline.

	Our purchase of the revenue bonds was linked to corresponding loan agreements we entered into with borrowing authorities in the states of Louisiana and Mississippi. Per the loan agreements, we received $13.2 million under the same payment and interest terms of the bonds, and we used the cash to partially fund our construction of our Kinder Morgan Louisiana Pipeline and our bulk terminal facility expansions within the state of Mississippi.

	The overall increase in period-to-period contributions to investments includes a $34.1 million decrease in contributions paid to Midcontinent Express Pipeline LLC, the sole owner of the Midcontinent Express Pipeline. In 2008 and 2007, we contributed $27.5 million and $61.6 million, respectively, for our proportionate share of Midcontinent Express Pipeline construction costs.

	• a $696.5 million decrease in cash used for acquisitions, including a decrease of $572.5 million related to our acquisition of Trans Mountain from Knight. In 2007, we paid $549.1 million to Knight to acquire the net assets of Trans Mountain, and in April 2008, we received a cash contribution of $23.4 million from Knight as a result of certain true-up provisions in our acquisition agreement. For more information on our acquisition of Trans Mountain from Knight, see Note 3 to our consolidated financial statements included elsewhere in this report. The remaining $124 million decrease in cash used was primarily related to higher expenditures for terminal assets in 2007 compared to 2008;

	• a $141.2 million decrease in cash used due to lower period-to-period payments for margin and restricted deposits in 2008 compared to 2007, associated largely with our utilization of derivative contracts to hedge (offset) against the volatility of energy commodity price risks; and

	• an $89.1 million decrease in cash used related to a return of capital received from Midcontinent Express Pipeline LLC in the first quarter of 2008. In February 2008, Midcontinent entered into and then made borrowings under a new $1.4 billion three-year, unsecured revolving credit facility due February 28, 2011. Midcontinent then made distributions (in excess of cumulative earnings) to its two member owners to reimburse them for prior contributions made to fund its pipeline construction costs.

	• a $27.3 million increase in cash used due to changes in natural gas stored underground and natural gas linefill, property casualty indemnifications, and other items.

	*Financing Activities*

Net cash provided by financing activities amounted to $601.3 million in 2008; while in the prior year, our financing activities provided net cash of $735.7 million. The $134.4 million (18%) overall decrease in cash inflows provided by financing activities was primarily due to:

	• a $334.4 million decrease in cash from higher partnership distributions in 2008, when compared to distributions paid in 2007. Distributions to all partners, consisting of our common and Class B unitholders, our general partner and our minority interests, totaled $1,488.7 million in 2008, compared to $1,154.3 million last year.


	The increase in partnership distributions reflects higher year-over-year distributable cash, which represents the amount of cash we generate that is available to pay our unitholders. The increase in distributable cash was in turn driven by the increase in total segment earnings before depreciation and amortization expenses (discussed above in “—Results of Operations”). More information on our cash distributions is provided below in “—Partnership Distributions”;

	• a $79.9 million decrease in cash inflows from partnership equity issuances. The decrease relates to the combined $560.9 million we received, after commissions and underwriting expenses, from three separate offerings of additional common units in 2008, versus the combined $640.8 million we received last year from our May 2007 issuance of additional i-units to KMR and our December 2007 public offering of additional common units. Both our 2008 and 2007 equity issuances are discussed more fully in Note 11 to our consolidated financial statements included elsewhere in this report;

	• a $225.3 million increase in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The period-to-period increase in cash from overall financing activities was primarily due to (i) a $295.7 million increase in cash inflows from net issuances and payments of senior notes; (ii) a $13.2 million increase in cash from funds we originally invested in long-term tax-exempt development revenue bonds (described above in “—Investing Activities”); and (iii) an $80.0 million decrease in cash inflows from lower overall net commercial paper borrowings.

	The increase in cash from changes in senior notes outstanding reflects the combined $2,080.2 million we received from three separate public offerings of senior notes in 2008 (discussed in Note 9 to our consolidated financial statements included elsewhere in this report), versus the $1,784.5 million increase in cash inflows from the issuances and payments of senior notes during 2007 (see Note 9 to our consolidated financial statements included elsewhere in this report for more information on our issuances and payments of senior notes). We used the proceeds from each of our 2007 debt offerings and from our first two 2008 offerings to reduce the borrowings under our commercial paper program. We used the proceeds from our third and final 2008 debt offering (in December) to reduce the borrowings under our revolving bank credit facility; and

	• a $51.0 million increase in cash inflows from net changes in cash book overdrafts—resulting from timing differences on checks issued but not yet endorsed.

	• a $3.6 million increase in cash from repayment from (loans to) related party, contributions from minority interest, and other.

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, sustaining 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 2008, 2007 and 2006, we distributed approximately 100%, 100% and 103%, respectively, of the total of cash receipts less cash disbursements (calculations assume that KMR unitholders received cash instead of additional i-units). The difference between these numbers and 100% of distributable cash flow reflects net changes in reserves.

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;

	• 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 2008 and 2007 was $800.8 million and $611.9 million, respectively, while the incentive distribution paid to our general partner during 2008 and 2007 was $754.6 million and $559.6 million, respectively. The difference between declared and paid distributions is because our distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year.

On February 13, 2009, we paid a quarterly distribution of $1.05 per unit for the fourth quarter of 2008. This distribution was 14% greater than the $0.92 distribution per unit we paid for the fourth 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 $1.05 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, 2008, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $78.9 million. In addition, we have recorded a receivable of $20.7 million for expected cost recoveries that have been deemed probable. As of December 31, 2007, our environmental reserve totaled $92.0 million and our estimated receivable for environmental cost recoveries totaled $37.8 million, respectively.

Our environmental reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired or accidental spills or releases at facilities that we own. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort. In assessing environmental risks in conjunction with proposed acquisitions, we review records relating to environmental issues, conduct site inspections, interview employees, and, if appropriate, collect soil and groundwater samples.

Additionally, as of December 31, 2008 and 2007, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $234.8 million and $247.9 million, respectively. This reserve is primarily related to various claims from lawsuits arising from our West Coast Products Pipelines 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.

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. However, changing circumstances could cause these matters to have a material adverse impact.

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

Please refer to Notes 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 may 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 were required to be completed by March 31, 2008 and we met that deadline. We have included all incremental expenditures estimated to occur during 2009 associated with the Pipeline Safety Improvement Act of 2002 and the integrity management of our products pipelines in our 2009 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.

Fair Value Measurements

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, and utilize interest rate swap agreements to mitigate our risk from fluctuations in interest rates. Pursuant to current accounting provisions, we record our derivative contracts at their estimated fair values as of each reporting date. For more information on our risk management activities, see Note 10 to our consolidated financial statements included elsewhere in this report.

SFAS No. 157, “Fair Value Measurements” establishes a hierarchal disclosure framework associated with the level of pricing observability utilized in measuring fair value. The hierarchy of valuation techniques is based upon whether the inputs to those valuation techniques reflect assumptions other market participants would use based upon market data obtained from independent sources (observable inputs) or reflect a company’s own assumptions of market participant valuation (unobservable inputs). This framework defines three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. In accordance with SFAS No. 157, the lowest level of fair value hierarchy based on these two types of inputs is designated as Level 3, and is based on prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

As of December 31, 2008, the fair value of our derivative contracts classified as Level 3 under the established fair value hierarchy consisted primarily of West Texas Intermediate crude oil options (costless collars) and West Texas Sour crude oil hedges. Costless collars are designed to establish floor and ceiling prices on anticipated future oil production from the assets we own in the SACROC oil field unit. While the use of these derivative contracts limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. In addition to these oil-commodity derivatives, our Level 3 derivative contracts included natural gas basis swaps and natural gas options. Basis swaps are used in connection with another derivative contract to reduce hedge ineffectiveness by reducing a basis difference between a hedged exposure and a derivative contract. Natural gas options are used to offset the exposure related to certain physical contracts.

The following table summarizes the total fair value asset and liability measurements of our Level 3 energy commodity derivative contracts in accordance with SFAS No. 157.


	Significant Unobservable Inputs (Level 3)

	Assets							Liabilities

	December 31, 2008		December 31, 2007		Change			December 31, 2008			December 31, 2007			Change


WTI options	$	34.3	$	—	$	34.3		$	(2.2	)	$	—		$	(2.2	)
WTS oil swaps		17.1		—		17.1			(0.2	)		(94.5	)		94.3
Natural gas basis swaps		3.3		2.8		0.5			(5.2	)		(4.7	)		(0.5	)
Natural gas options		—		—		—			(2.7	)		—			(2.7	)
Other		0.5		1.0		(0.5	)		(0.8	)		(4.9	)		4.1

Total	$	55.2	$	3.8	$	51.4		$	(11.1	)	$	(104.1	)	$	93.0

The largest changes in the fair value of our Level 3 assets and liabilities between December 31, 2008 and December 31, 2007 were related to West Texas Intermediate options and West Texas Sour hedges. We entered into the majority of our WTI option contracts during 2008, which accounts for the changes. The changes in value from our WTS swap contracts were largely due to favorable crude oil price changes since the end of 2007. There were no transfers into or out of Level 3 during the period.

The valuation techniques used for the above Level 3 input derivative contracts are as follows:


	• Option contracts—valued using internal model. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes;

	• WTS oil swaps—prices obtained from a broker using their proprietary model for similar assets and liabilities, quotes are non-binding; and

	• Natural gas basis swaps—values obtained through a pricing service, derived by combining raw inputs from the New York Mercantile Exchange (referred to in this report as NYMEX) with proprietary quantitative models and processes. Although the prices are originating from a liquid market (NYMEX), we believe the incremental effort to further validate these prices would take undue effort and would not materially alter the assumptions. As a result, we have classified the valuation of these derivatives as Level 3.

For our energy commodity derivative contracts, the most observable inputs available are used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, we use broker quotes for identical or similar contracts, or internally prepared valuation models as primary inputs to determine fair value. No adjustments were made to quotes or prices obtained from brokers and pricing services, and our valuation methods have not changed during the quarter ended December 31, 2008.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence, including but not limited to our credit default swap quotes as of

December 31, 2008. Collateral agreements with our counterparties serve to reduce our credit exposure and are considered in the adjustment. We adjust the fair value measurements of our energy commodity derivative contracts for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, our consolidated “Accumulated other comprehensive loss” balance included a gain of $2.2 million related to discounting the value of our energy commodity derivative net assets for the effect of credit risk.

With the exception of our Casper and Douglas hedges and the ineffective portion of our derivative contracts, our energy commodity derivative contracts are accounted for as cash flow hedges. In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (after amendment by SFAS No. 137, SFAS No. 138 and SFAS No. 149; collectively, SFAS No. 133), gains and losses associated with cash flow hedges are reported in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets.

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, electricity, coal and other bulk materials and chemicals in North America;

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

	• changes in our tariff rates 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 expand our facilities;

	• 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, such as the Permian Basin area of West Texas, the U.S. Rocky Mountains and the Alberta oil sands;

	• changes in laws or regulations, third-party relations and approvals, and 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, which 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 and credit markets conditions, inflation and interest rates;

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

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

	• our ability to achieve cost savings and revenue growth;

	• 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;

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

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

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

	• the timing and success of our 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.

The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, 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 us financially 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, or anticipated 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 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 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 transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Services):


	Credit Rating

Citigroup	A
J. Aron & Company / Goldman Sachs	A
Morgan Stanley	A

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 (loss), pending occurrence of the expected transaction. Other comprehensive income (loss) 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 until the expected transaction occurs.

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.

The accumulated components of other comprehensive income are reported separately as accumulated other comprehensive income or loss in the stockholders’ equity section of the balance sheet. For us, the amounts included in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets primarily include (i) the effective portion of the gains and losses on cash flow hedging items; and (ii) foreign currency translation adjustments. The gains and losses on hedging items primarily relate 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. The translation adjustments are a cumulative total, resulting from translating all of our foreign denominated assets and liabilities at current exchange rates, while equity is translated by using historical or weighted-average exchange rates.

The total “Accumulated other comprehensive loss” included within the Partners’ Capital section of our accompanying balance sheets as of December 31, 2008 and December 31, 2007, included amounts associated with energy commodity price risk management activities of $63.2 million and $1,377.2 million, respectively. The total “Accumulated other comprehensive loss” as of December 31, 2008 also included a cumulative translation debit (unrealized loss) balance of $217.3 million. The total “Accumulated other comprehensive loss” as of December 31, 2007 included a cumulative translation credit (unrealized gain) balance of $112.5 million

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 indicating the minimum expected loss in a portfolio over a given holding period, 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, 2008 and 2007, our value-at-risk reached a high of $1.8 million and $1.6 million, respectively, and a low of $0.7 million and $0.7 million, respectively. Value-at-risk as of December 31, 2008 was $0.7 million, and averaged $1.5 million for 2008. Value-at-risk as of December 31, 2007 was $1.6 million, and averaged $1.2 million for 2007.

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, 2008 and 2007, the carrying values of our fixed rate debt were approximately $8,469.5 million and $6,382.9 million, respectively. These amounts compare to, as of December 31, 2008 and 2007, fair values of $7,536.4 million and $6,518.7 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 54 basis points) in the average interest rates applicable to such debt for 2008 and 2007, would result in changes of approximately $284.2 million and $259.9 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 $94.5 million as of December 31, 2008 and $684.5 million as of December 31, 2007. 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, 2008 and 2007, including adjustments for notional swap amounts, would result in changes of approximately $15.8 million and $19.1 million, respectively, in our 2008 and 2007 annual pre-tax earnings.

We adjusted the fair value measurement of our long-term debt as of December 31, 2008 in accordance with SFAS No. 157, and the estimated fair value of our debt as of December 31, 2008 includes a decrease of $261.1 million related to discounting the fair value measurement for the effect of credit risk.

As of December 31, 2008 and 2007, we were a party to interest rate swap agreements with notional principal amounts of $2.8 billion and $2.3 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 purpose of 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, 2008 and 2007, 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, 2008, our cash and investment portfolio included approximately $13.2 million in fixed-income debt securities. Because our investment in debt securities was made and will be maintained in the future to directly offset the interest rate risk on a like amount of long-term debt, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio; and because 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 124.

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

None.

Item 9A.Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2008, 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 inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework inInternal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2008.

The effectiveness of our internal control over financial reporting as of December 31, 2008, 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 2008 were excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008. The excluded businesses consisted of the following:


	• the bulk terminal assets we acquired from Chemserve, Inc., effective August 15, 2008; and

	• the refined petroleum products storage terminal we acquired from ConocoPhillips, effective December 10, 2008.

These businesses, in the aggregate, constituted 0.01% of our total operating revenues for 2008 and 0.23% of our total assets as of December 31, 2008.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.Other Information.

None.

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	64	Director, Chairman and Chief Executive Officer
C. Park Shaper	40	Director and President
Steven J. Kean	47	Executive Vice President, Chief Operating Officer and President, Natural Gas Pipelines
Gary L. Hultquist	65	Director
C. Berdon Lawrence	66	Director
Perry M. Waughtal	73	Director
Kimberly A. Dang	39	Vice President and Chief Financial Officer
Jeffrey R. Armstrong	40	Vice President (President, Terminals)
Thomas A. Bannigan	55	Vice President (President, Products Pipelines)
Richard T. Bradley	53	Vice President (President, CO₂)
David D. Kinder	34	Vice President, Corporate Development and Treasurer
Joseph Listengart	40	Vice President, General Counsel and Secretary
James E. Street	52	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. He is also President, Natural Gas Pipelines of KMR and Kinder Morgan G.P., Inc. Mr. Kean was elected Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and Knight in January 2006. He was named President, Natural Gas Pipelines of KMR and Kinder Morgan G.P., Inc. in July 2008. 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 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.

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.

C. Berdon Lawrence is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Lawrence was elected Director of KMR and Kinder Morgan G.P., Inc. in January 2009. Since October 1999, Mr. Lawrence has served Kirby Corporation as Chairman of the Board. Prior to that, he served for 30 years as President of Hollywood Marine, an inland tank barge company of which he was the founder. Mr. Lawrence holds an M.B.A. degree and a B.B.A. degree in business administration from Tulane University.

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.

Kimberly A. Dang is Vice President 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 and served in that role until January 2009. From November 2001 to July 2002, she served as Director, Investor Relations of KMR, Kinder Morgan G.P., and Knight. She has also served as Chief Financial Officer of Knight Holdco LLC since May 2007. Mrs. Dang 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.

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.

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. Hultquist, Lawrence and Waughtal. Mr. Waughtal 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 8, 2008, 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 8, 2008, 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.

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,

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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 2008.

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). Until October 2008, we paid 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, based upon independent salary surveys in which we participate. The cap for our executive officers’ base salaries was raised to an annual amount not to exceed $300,000. We believe the base salaries paid to our executive officers

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continue to be below the industry average for similarly positioned executives. While not awarded by us, KMR’s 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 2008, 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.

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 Mr. Richard D. Kinder and KMR’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, 2007 and 2008, no restricted stock or options to purchase shares of KMI, units of us or shares of KMR were granted to any of our named executive officers.

As a result of the May 2007 going-private transaction, Knight became a wholly owned subsidiary of Knight Holdco LLC, and in connection with the going-private transaction, Knight Holdco LLC awarded members of Knight’s management Class A-1 and Class B units of Knight Holdco LLC. While not awarded by us, KMR’s compensation committee was aware of the units awarded by Knight Holdco LLC and took these awards into account as components of the total compensation received by our executive officers in 2007. 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. The Class A-1 and Class B units awarded to members of our management may be viewed as a replacement of restricted stock as a component of long-term executive compensation. For more information concerning the Knight Holdco LLC units, see “Elements of Compensation—Other Compensation—Knight Holdco LLC Units” below.

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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, 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 Knight with its Chairman and Chief Executive Officer, Richard D. Kinder, special severance agreements or change of control agreements for our 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 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.

At his request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, receives $1 of base salary per year and no other compensation from Knight. 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 composed of two elements: (i) a base cash salary; and (ii) a possible annual cash bonus. Mr. Richard D. Kinder and our compensation committee review and approve annually the financial goals and objectives of both Knight and us that are relevant to the compensation of our named executive officers.

Information is solicited from relevant members of senior management regarding the performance of our named executive officers and determinations and recommendations are made at the regularly scheduled first quarter board and compensation committee meetings. If any of Knight’s executive officers is also an executive officer of our general partner or KMR, the 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, 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 be allocated among Knight, on the one hand, and KMR and our general partner, on the other.

Base Salary

Base salary is paid in cash. Until October 2008, 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. The cap for our executive officers’ base salaries was raised to an annual amount not to exceed $300,000. Generally, we believe that our executive officers’ base salaries are below base salaries for executives in similar positions and with similar responsibilities at companies of comparable size and scope, based upon independent salary surveys in which we participate.

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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 to them additional incentives through the possible payment of annual cash bonuses. Under the plan, annual cash bonuses are budgeted for at the beginning of each year and may be paid to our executive officers and other employees depending on whether Knight and its subsidiaries (including us) meet certain performance objectives. Assuming the performance objectives are met, the budgeted pool of bonus dollars is further assessed and potentially decreased or increased based on Knight and its subsidiaries’ (including us) overall performance in a variety of areas, including safety and environmental goals and regulatory compliance.

Once the aggregate pool of bonus dollars is determined, further assessment is done at the business segment level. Each business segment’s financial performance as well as its safety and environmental goals and regulatory compliance are assessed and factored, positively or negatively, into the amount of bonus dollars allocated to that business segment. The business unit’s safety and environmental goals and regulatory compliance are assessed against its performance in these areas in previous years and industry benchmarks. These assessments as well as individual performance factor into bonus awards at the business segment level.

Knight and its subsidiaries’ (including us) overall performance, including whether it has met the performance objectives as well as how, on an overall basis, it has performed with respect to a variety of areas such as safety and environmental goals and regulatory compliance, negatively or positively, impacts the bonuses of our named executive officers. Also, with respect to our named executive officers, individual performance impacts their bonuses. Our named executive officers have different areas of responsibility that require different skill sets. Consequently, many of the skills and aspects of performance taken into account in determining the bonus awards for the respective named executive officers differ based on their areas of responsibility. However, some skills, such as working within a budget, are applicable for all of the executive officers. While no formula is used in assessing individual performance, the process of assessing the performance of each of the named executive officers is consistent, with each such officer being assessed relative to the officer’s performance of his or her job in preceding years as well as with respect to specific matters assigned to the officer over the course of the year. Individual performance, as described above, as well as safety and environmental goals and regulatory compliance were taken into account with respect to the 2008 awards.

All of Knight’s employees and the employees of 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 KMR’s compensation committee 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 “Compensation Discussion and Analysis”, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, has elected to not participate under the plan. As of December 31, 2008, excluding Mr. Richard D. Kinder, ten of our current officers were eligible to participate in the executive plan component. All other U.S. eligible employees were eligible for the non-executive plan component.

Following recommendations and determinations, KMR’s compensation committee establish which of our 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. A bonus opportunity is established for each executive officer, which is the bonus the executive officer could earn if the performance objectives are fully satisfied. A minimum acceptable level of achievement of each performance objective may be set, below which no bonus is payable with respect to that objective. Additional levels may be set 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

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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 KMR’s compensation committee has the discretion to reduce the bonus amounts 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;

	• 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 free cash flow, 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;

	• 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; or

	• KMP’s distribution per unit.

Two financial performance objectives were set for 2008 under both the executive plan component and the non-executive plan component. The 2008 financial performance objectives were $4.02 in cash distributions per common unit by us, and $1,056 million of EBITDA less capital spending by Knight. Our targets were the same as our previously disclosed 2008 budget expectations. At the end of 2008 the extent to which the financial performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by KMR’s compensation committee was determined.

The 2008 bonuses for our executive officers were overwhelmingly based on whether the established financial performance objectives were met. Other factors, such as individual over performance or under performance, were considered. With respect to using these other factors in assessing performance, KMR’s compensation committee did not find it practicable to, and did not, use a “score card”, or quantify or assign relative weight to the specific criteria considered. The amount of a downward or upward adjustment, subject to the maximum bonus opportunity that was established at the beginning of the year, was not subject to a formula. Specific aspects of an individual’s performance were not identified in advance. Rather, the adjustment was based on KMR’s compensation committee’s judgment, giving consideration to the totality of the record presented, including the individual’s performance, and the magnitude of any positive or negative factors.

The table below sets forth the bonus opportunities that could be payable by Knight and us to our executive officers if the performance objectives established for 2008 are 100% achieved. The amount of the portion of the bonus actually paid by us to any executive officer under the plan may be reduced from the amount of any bonus opportunity open to such executive officer. Because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established 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

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compensation committee set bonus opportunities under the plan for 2008 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 2008 are set forth in the Summary Compensation Table in the column entitled “Non-Equity Incentive Plan Compensation.”


Knight Annual Incentive Plan
Bonus Opportunities for 2008

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)

Joseph Listengart, Vice President, General Counsel and Secretary		1,000,000	(2)

C. Park Shaper, Director and President		1,500,000	(3)



(1)	Declined to participate.

(2)	Under the plan, for 2008, 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 2008, 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 year 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 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. For employees of our Terminals business segment hired after October 1, 2005, a tiered employer contribution schedule applies and all employer contributions vest on the third anniversary of the date of hire. 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.

In July 2008, Mr. Richard D. Kinder and KMR’s compensation committee approved a special contribution through July 2009 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 2008 and continuing through the last pay period of July 2009. The additional 1%

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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, Mr. Kinder’s and the KMR compensation committee’s approvals will be required annually for each additional contribution. During the first quarter of 2009, excluding our portion of the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2008.

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 1/2, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.

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, 2008, 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

Name	Plan Name	Current Credited Yrs of Service		Present Value of Accumulated Benefit(1)		Contributions During 2008

Richard D. Kinder	Cash Balance		8	$	—	$	—
Kimberly A. Dang	Cash Balance		7		39,693		8,285
Steven J. Kean	Cash Balance		7		50,479		8,755
Joseph Listengart	Cash Balance		8		60,267		9,188
C. Park Shaper	Cash Balance		8		60,267		9,188

(1)

The present values in the Pension Benefits table are based on certain assumptions, including a 6.25% discount rate, 5.0% cash balance interest crediting rate, and a lump sum calculated using the IRS 2009 Mortality Tables. We assumed benefits would commence at normal retirement age, which is 65. 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 7th. 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.

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

Knight Holdco LLC Units.In connection with the going-private transaction, some of our directors and executive officers received Class A-1 and Class B units of Knight Holdco LLC, Knight’s parent company. None of our independent directors, Messrs. Hultquist, Lawrence and Waughtal, received Knight Holdco LLC units. Generally, Knight Holdco LLC has three classes of units—Class A units, Class A-1 units, and Class B units.

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 third, fourth and fifth year anniversary of the issuance of such Class B units to such holder. The amended and restated limited liability company agreement of Knight Holdco LLC 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. Richard D. Kinder, and approved by other, non-management investors in Knight Holdco LLC.

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 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.

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 2008 (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 2008, 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)
Name and Principal Position	Year	Salary		Bonus		Stock Awards by KMI		Option Awards by KMI		Non-Equity Incentive Plan Compensation		Change in Pension Value		All Other Compensation		Unit Awards by Knight Holdco LLC		Total

Richard D. Kinder	2008	$	1	$	—	$	—	$	—	$	—	$	—	$	—	$	1,741,834	$	1,741,835
Director, Chairman and Chief	2007		1		—		—		—		—		—		—		1,016,000		1,016,001
Executive Officer	2006		1		—		—		—		—		—		—		—		1

Kimberly A. Dang	2008		223,077		—		—		—		440,000		8,285		11,863		126,523		809,748
Chief Vice President and	2007		200,000		—		338,095		—		400,000		7,294		32,253		73,800		1,051,442
Financial Officer	2006		200,000		—		139,296		37,023		270,000		6,968		46,253		—		699,540

Steven J. Kean	2008		223,077		—		—		—		1,150,000		8,755		13,007		505,822		1,900,661
Executive Vice President And	2007		200,000		—		4,397,080		—		1,100,000		7,767		147,130		295,010		6,146,987
Chief Operating Officer	2006		200,000		—		1,591,192		147,943		—		7,422		284,919		—		2,231,476

Joseph Listengart	2008		223,077		—		—		—		900,000		9,188		11,629		316,923		1,460,817
Vice President, General	2007		200,000		—		847,350		—		1,000,000		8,194		102,253		184,872		2,342,669
Counsel and Secretary	2006		200,000		—		721,817		—		—		7,835		224,753		—		1,154,405

C. Park Shaper	2008		223,077		—		—		—		1,200,000		9,188		12,769		799,236		2,244,270
Director and President	2007		200,000		—		1,950,300		—		1,200,000		8,194		155,953		466,110		3,980,557
	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 2008, 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 2008, 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. Amounts were earned in the fiscal year indicated but were paid in the next fiscal year. Messrs. Kean, Listengart and Shaper refused to accept a bonus for 2006. The compensation committee agreed that this was not a reflection of performance on these individuals.

(4)	Represents the 2008, 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 include 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, for 2006 and 2007 only, dividends paid on unvested restricted stock awards. Amounts in 2006 and 2007 include $10,000 and in 2008 include $11,154 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. Listengart $91,875; and Mr. Shaper $144,375; for 2006—Mrs. Dang $35,875; Mr. Kean $273,000; Mr. Listengart $214,375; and Mr. Shaper $336,875.

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(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 “Elements of Compensation—Other Compensation—Knight Holdco LLC Units” above for further discussion of these units.

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 2008 to our named executive officers. The table includes awards made during or for 2008. The information in the table under the caption “Estimated Future Payments Under Non-Equity Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the Knight Annual Incentive Plan for performance in 2008. Amounts actually paid under that plan for 2008 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 2008.


	Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)


Name	Threshold		Target		Maximum

Richard D. Kinder	$	—	$	—	$	—
Kimberly A. Dang		500,000		1,000,000		1,500,000
Steven J. Kean		750,000		1,500,000		2,000,000
Joseph Listengart		500,000		1,000,000		1,500,000
C. Park Shaper		750,000		1,500,000		2,000,000




(1)	See “Elements of Compensation—Possible Annual Cash Bonus (Non-Equity Cash Incentive)” above for further discussion of these awards.

Outstanding Equity Awards at Fiscal Year-End

The only unvested equity awards outstanding at the end of fiscal 2008 were the Class B units of Knight Holdco LLC awarded in 2007 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

Name	Type of units	Number of units that have not vested	Market value of units of stock that have not vested(1)

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
Joseph Listengart	Class B units	79,140,545	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.

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Director Compensation

Compensation Committee Interlocks and Insider Participation. The compensation committee of KMR functions as our compensation committee. KMR’s compensation committee is comprised of Mr. Gary L. Hultquist, Mr. C. Berdon Lawrence (since January 21, 2009), and Mr. Perry M. Waughtal (and Mr. Edward O. Gaylord serving until his death on September 28, 2008). KMR’s compensation committee 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 2008 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 (described following) have 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 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 is 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 2007 was made effective January 17, 2007; the election for 2008 was made effective January 16, 2008; and the election for 2009 was made effective January 21, 2009 for Messrs. Hultquist and Waughtal, and effective January 28, 2009 for Mr. Lawrence. 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.

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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 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 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) was paid in cash to each of the non-employee directors as described above, and no other compensation was paid to the non-employee directors during 2008.

On January 21, 2009, each of KMR’s three non-employee directors (with Mr. Lawrence replacing Mr. Gaylord) was awarded cash compensation of $160,000 for board service during 2009. Effective January 21, 2009, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only. Effective January 28, 2009, Mr. Lawrence elected to receive compensation of $159,136.00 in the form of our common units and was issued 3,200 common units. His remaining compensation ($864.00) will be paid in cash as described above. No other compensation will be paid to the non-employee directors during 2009.

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 then 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 then 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. In 2008, Mr. Hultquist exercised his remaining 10,000 unit appreciation rights and received a cash amount of $123,100. As of December 31, 2008, 35,000 unit appreciation rights had been granted, vested and remained outstanding.

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The following table discloses the compensation earned by each of KMR’s three non-employee directors for board service during fiscal year 2008. 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.


Name	Fees Earned or Paid in Cash		Common Unit Awards(1)		All Other Compensation(2)		Total

Edward O. Gaylord	$	73,565	$	84,831	$	2,858	$	161,254
Gary L. Hultquist		158,380		—		—		158,380
Perry M. Waughtal		54		157,273		5,298		162,625




(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, 1,520 units elected on January 16, 2008 times the closing price of $55.81, and for Mr. Waughtal, 2,818 units elected times the closing price of $55.81.

(2)	For each, represents (i) the unrealized 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, 2007 to December 31, 2008; and (ii) distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors.

	For Mr. Gaylord and Mr. Waughtal, represents $2,858 and $5,298, respectively, for distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors. For each, during 2008, no unrealized value of common unit appreciation rights was earned due to the decrease in common unit closing price from December 31, 2007 to December 31, 2008 (equal to $53.99 at December 31, 2007 and $45.75 at December 31, 2008). As described above, in 2008, Mr. Hultquist exercised his remaining 10,000 unit appreciation rights and received a cash amount of $123,100.

Compensation Committee Report

Throughout fiscal 2008, the compensation committee of KMR’s board of directors was comprised of two directors (Mr. Gary L. Hultquist and Mr. Perry M. Waughtal), and up to the time of his death on September 28, 2008, a third director (Mr. Edward O. Gaylord), each of whom the KMR board of directors has determined meets (or met) 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 2008 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 2008.

KMR Compensation Committee:
Gary L. Hultquist
Perry M. Waughtal

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

The following tables set forth information as of January 31, 2009, regarding (i) the beneficial ownership of (a) our common and Class B units, (b) KMR shares and (c) Knight Holdco LLC units 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 and KMR shares by all persons known by our general partner to own beneficially at least 5% of such units or shares. 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.

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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		*			—		—			111,782		*
C. Park Shaper		4,000		*			—		—			25,618		*
Gary L. Hultquist		7,500		*			—		—			—		—
C. Berdon Lawrence(6)		3,200		*			—		—			—		—
Perry M. Waughtal		46,918		*			—		—			49,726		*
Steven J. Kean		—		—			—		—			—		—
Joseph Listengart		4,198		*			—		—			—		—
Kimberly A. Dang		121		*			—		—			473		*
Directors and Executive Officers as a group (13 persons)(7)		395,195		*			—		—			209,873		*
Knight Inc.(8)		16,370,428		8.94	%		5,313,400		100.00	%		11,128,825		14.27	%
Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne(9)		—		—			—		—			6,210,408		7.96	%
Janus Capital Management LLC(10)		—		—			—		—			5,855,967		7.55	%




*	Less than 1%.

(1)	Except as noted otherwise, each beneficial owner has sole voting power and sole investment power over the units and shares listed. 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 by the end of the fifth calendar year following the later to occur of (i) January 18, 2005 or (ii) the election date of the director to KMR's board.

(2)	As of January 31, 2009, we had 183,169,827 common units issued and outstanding.

(3)	As of January 31, 2009, we had 5,313,400 Class B units issued and outstanding.

(4)	Represent the limited liability company shares of KMR. As of January 31, 2009, there were 77,997,906 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 3,200 restricted common units.

(7)	Includes 3,200 restricted common units. Also includes 719 KMR shares purchased by one of our executives for his children. The executive disclaims any beneficial ownership in such KMR shares.

(8)	Includes common units owned by Knight Inc. and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.

(9)	As reported on the Schedule 13G/A filed February 13, 2009 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 shares, shared voting power over 6,207,400 shares, sole disposition power over 0 shares and shared disposition power over 6,207,400 shares. Mr. Kayne reports that in regard to KMR shares, he had sole voting power over 3,008 shares, shared voting power over 6,207,400 shares, sole disposition power over 3,008 shares and shared disposition power over 6,207,400 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.

(10)	As reported on the Schedule 13G/A filed February 17, 2009 by Janus Capital Mangement LLC. Janus Capital Management reported that in regard to KMR shares, it has sole voting power over 5,844,967 shares, shared voting power over 11,000 shares, sole disposition power over 5,844,967 and shared disposition power over 11,000 shares. Janus Capital Management LLC’s address is 151 Detroit Street, Denver, Colorado, 80206.

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Amount and Nature of Beneficial Ownership(1)


		Knight Holdco LLC Class A Units		% of Class A Units(2)			Knight Holdco LLC Class A-1 Units		% of Class A-1 Units(3)			Knight Holdco LLC Class B Units		% of Class B Units(4)

Richard D. Kinder(5)			2,424,000,000		30.6	%		—		—			791,405,452		40.0	%
C. Park Shaper(6)			13,598,785		*			7,799,775		28.3	%		217,636,499		11.0	%
Gary L. Hultquist			—		—			—		—			—		—
C. Berdon Lawrence			—		—			—		—			—		—
Perry M. Waughtal	��		—		—			—		—			—		—
Steven J. Kean			6,684,149		*			3,833,788		13.9	%		158,281,090		8.0	%
Joseph Listengart			6,059,449		*			3,475,483		12.6	%		79,140,545		4.0	%
Kimberly A. Dang(7)			750,032		*			430,191		1.6	%		49,462,841		2.5	%
Directors and Executive Officers as a group (13 persons)			2,460,763,539		31.1	%		21,086,247		76.5	%		1,626,338,205		82.2	%




*	Less than 1%.

(1)	Except as noted otherwise, each beneficial owner has sole voting power and sole investment power over the units listed.

(2)	As of January 31, 2009, Knight Holdco LLC had 7,914,367,913 Class A Units issued and outstanding.

(3)	As of January 31, 2009, 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.

(4)	As of January 31, 2009, Knight Holdco LLC had 1,927,566,908 Class B Units issued and outstanding and 50,946,724 phantom Class B Units issued and outstanding. The phantom Class B Units were issued to Canadian management employees.

(5)	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.

(6)	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.

(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.

Equity Compensation Plan Information

The following table sets forth information regarding our equity compensation plans as of December 31, 2008. Specifically, the table provides information regarding our Common Unit Compensation Plan for Non-Employee Directors, described in 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		77,882


Total		77,882

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

Related Transactions

Transactions with Kirby Corporation

The recently elected director of the boards of our general partner and KMR, Mr. C. Berdon Lawrence, is Chairman of the Board of Kirby Corporation. In addition, Mr. Lawrence’s son was a vice president of a subsidiary of Kirby Corporation during part of 2008. In 2008, Kirby Corporation received payments from our subsidiaries totaling $430,835 and made payments to our subsidiaries totaling $144,300 for services in the ordinary course of Kirby Corporation’s and our Terminals segment’s businesses.

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.

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

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	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. Hultquist, Lawrence 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 2009, Mr. Hultquist 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.

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, 2008 and 2007 (in dollars):


	Year Ended December 31,

	2008		2007

Audit fees(1)	$	2,409,571	$	2,070,205
Tax fees(2)		2,144,808		2,563,793

Total	$	4,554,379	$	4,633,998




(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 2008 and 2007, amounts include fees of $1,679,358 and $2,352,533, respectively, billed for professional services rendered for tax processing and preparation of Forms K-1 for our unitholders. Amounts also include fees of $465,450 and $211,260, 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

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committee has reviewed the external auditors’ fees for audit and non audit services for fiscal year 2008. 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 124.

(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).

*3.4 —	Amendment No. 3 to 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 8-K, filed April 21, 2008).

*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.

*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).

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*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).

*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).

120


*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 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2007 filed February 26, 2008).

4.29 —	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 9.00% Senior Notes due 2019.

4.30 —	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 —	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).

*10.2 —	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).

*10.3 —	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).

*10.4 —	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).

*10.5 —	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).

*10.6 —	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).

*10.7 —	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).

*10.8 —	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).

*10.9 —	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).

*10.10 —	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).

*10.11 —	Retention and Relocation Agreement, dated as of March 5, 2007, between Kinder Morgan, Inc. and Scott E. Parker (filed as Exhibit 10.2 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007).

*10.12 —	First Amendment to Retention and Relocation Agreement, dated as of July 16, 2008, between Knight Inc. and Scott E. Parker (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed July 25, 2008).

11.1 —	Statement re: computation of per share earnings.

12.1 —	Statement re: computation of ratio of earnings to fixed charges.

121


*18.1 —	Letter re: change in accounting principle (filed as exhibit 18 to Kinder Morgan Energy Partners, L.P. Form 10-Q, filed August 7, 2008).

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.

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.

122

INDEX TO FINANCIAL STATEMENTS


	Page Number

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

Report of Independent Registered Public Accounting Firm	124

Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006	126

Consolidated Statements of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006	127

Consolidated Balance Sheets as of December 31, 2008 and 2007	128

Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	129

Consolidated Statements of Partners’ Capital for the years ended December 31, 2008, 2007 and 2006	130

Notes to Consolidated Financial Statements	131

123

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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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, 2008, based on criteria established inInternal 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 bulk terminal assets acquired from Chemserve, Inc., effective August 15, 2008; and

•	The refined petroleum products storage terminal acquired from ConocoPhillips, effective December 10, 2008,

124

(the “Acquired Businesses”) from its assessment of internal control over financial reporting as of December 31, 2008 because these businesses were each acquired by the Partnership in purchase business combinations during 2008. 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, represent 0.23% and 0.01%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2008.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
February 23, 2009

125

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


	Year Ended December 31,

	2008			2007			2006

	(In millions except per unit amounts)
Revenues
Natural gas sales	$	7,705.2		$	5,834.7		$	6,039.9
Services		2,770.3			2,449.2			2,177.6
Product sales and other		1,264.8			933.8			831.2

		11,740.3			9,217.7			9,048.7

Costs, Expenses and Other
Gas purchases and other costs of sales		7,716.1			5,809.8			5,990.9
Operations and maintenance		1,010.2			1,024.6			777.0
Fuel and power		272.6			237.5			223.7
Depreciation, depletion and amortization		702.7			540.0			423.9
General and administrative		297.9			278.7			238.4
Taxes, other than income taxes		186.7			153.8			134.4
Goodwill impairment expense		—			377.1			—
Other expense (income)		2.6			(11.5	)		(31.2	)

		10,188.8			8,410.0			7,757.1


Operating Income		1,551.5			807.7			1,291.6

Other Income (Expense)
Earnings from equity investments		160.8			69.7			74.0
Amortization of excess cost of equity investments		(5.7	)		(5.8	)		(5.6	)
Interest, net		(388.2	)		(391.4	)		(337.8	)
Other, net		19.2			14.2			12.0
Minority Interest		(13.7	)		(7.0	)		(15.4	)


Income from Continuing Operations Before Income Taxes		1,323.9			487.4			1,018.8

Income Taxes		(20.4	)		(71.0	)		(29.0	)


Income from Continuing Operations		1,303.5			416.4			989.8

Discontinued Operations:
Income from operations of North System		—			21.1			14.3
Gain on disposal of North System		1.3			152.8			—

Income (loss) from Discontinued Operations		1.3			173.9			14.3

Net Income	$	1,304.8		$	590.3		$	1,004.1


Calculation of Limited Partners’ interest in Net Income (loss):
Income from Continuing Operations	$	1,303.5		$	416.4		$	989.8
Less: General Partner’s interest		(805.8	)		(609.9	)		(513.2	)

Limited Partners’ interest		497.7			(193.5	)		476.6
Add: Limited Partners’ interest in Discontinued Operations		1.3			172.2			14.2

Limited Partners’ interest in Net Income (loss)	$	499.0		$	(21.3	)	$	490.8


Basic Limited Partners’ Net Income (loss) per Unit:
Income (loss) from Continuing Operations	$	1.94		$	(0.82	)	$	2.12
Income from Discontinued Operations		—			0.73			0.07

Net Income (loss)	$	1.94		$	(0.09	)	$	2.19

Weighted average number of units outstanding		257.2			236.9			224.6


Diluted Limited Partners’ Net Income (loss) per Unit:
Income (loss) from Continuing Operations	$	1.94		$	(0.82	)	$	2.12
Income from Discontinued Operations		—			0.73			0.06

Net Income (loss)	$	1.94		$	(0.09	)	$	2.18

Weighted average number of units outstanding		257.2			236.9			224.9


Per unit cash distribution declared	$	4.02		$	3.48		$	3.26

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

126

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended December 31,

	2008			2007			2006

	(In millions)

Net Income	$	1,304.8		$	590.3		$	1,004.1

Change in fair value of derivatives used for hedging purposes		651.4			(974.2	)		(187.5	)
Reclassification of change in fair value of derivatives to net income		663.7			433.2			428.1
Foreign currency translation adjustments		(329.8	)		132.5			(19.6	)
Minimum pension liability adjustments, other post-retirement benefit plan transition obligations, pension and other post-retirement benefit plan actuarial gains/losses, and reclassification of pension and other post-retirement benefit plan actuarial gains/losses, prior service costs/credits and transition obligations to net income, net of tax		3.6			(3.5	)		(1.8	)

Total other comprehensive income (loss)		988.9			(412.0	)		219.2


Comprehensive Income	$	2,293.7		$	178.3		$	1,223.3

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

127

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,

	2008			2007

	(Dollars in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	62.5		$	58.9
Restricted deposits		—			67.9
Accounts, notes and interest receivable, net
Trade		978.9			960.2
Related parties		9.0			3.6
Inventories
Products		16.2			19.5
Materials and supplies		28.0			18.3
Gas imbalances
Trade		14.1			21.2
Related parties		—			5.7
Other current assets		135.7			54.4

		1,244.4			1,209.7

Property, Plant and Equipment, net		13,241.4			11,591.3
Investments		954.3			655.4
Notes receivable
Trade		—			0.1
Related parties		178.1			87.9
Goodwill		1,058.9			1,077.8
Other intangibles, net		205.8			238.6
Deferred charges and other assets		1,002.9			317.0

Total Assets	$	17,885.8		$	15,177.8

LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts	$	42.8		$	19.0
Trade		831.0			926.7
Related parties		24.6			22.6
Current portion of long-term debt		288.7			610.2
Accrued interest		172.3			131.2
Accrued taxes		51.9			73.8
Deferred revenues		41.1			22.8
Gas imbalances
Trade		10.2			23.7
Related parties		2.2			—
Accrued other current liabilities		317.3			728.3

		1,782.1			2,558.3

Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding		8,274.9			6,455.9
Value of interest rate swaps		951.3			152.2

		9,226.2			6,608.1
Deferred revenues		12.9			14.2
Deferred income taxes		178.0			202.4
Asset retirement obligations		74.0			50.8
Other long-term liabilities and deferred credits		496.3			1,254.1

		9,987.4			8,129.6

Commitments and Contingencies (Notes 13 and 16)
Minority Interest		70.7			54.2

Partners’ Capital
Common Units (182,969,427 and 170,220,396 units issued and outstanding as of December 31, 2008 and 2007, respectively)		3,458.9			3,048.4
Class B Units (5,313,400 and 5,313,400 units issued and outstanding as of December 31, 2008 and 2007, respectively)		94.0			102.0
i-Units (77,997,906 and 72,432,482 units issued and outstanding as of December 31, 2008 and 2007, respectively)		2,577.1			2,400.8
General Partner		203.3			161.1
Accumulated other comprehensive loss		(287.7	)		(1,276.6	)

		6,045.6			4,435.7

Total Liabilities and Partners’ Capital	$	17,885.8		$	15,177.8

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

128

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,

	2008			2007			2006

	(In millions)
Cash Flows From Operating Activities
Net income	$	1,304.8		$	590.3		$	1,004.1
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		702.7			547.0			432.8
Amortization of excess cost of equity investments		5.7			5.8			5.7
Impairment of goodwill		—			377.1			—
Income from the allowance for equity funds used during construction		(10.6	)		—			—
Income from the sale of property, plant and equipment and investments		(11.7	)		(162.5	)		(15.2	)
Income from property casualty indemnifications		—			(1.8	)		(15.2	)
Earnings from equity investments		(160.8	)		(71.5	)		(76.2	)
Distributions from equity investments		158.4			104.1			67.9
Proceeds from termination of interest rate swap agreements		194.3			15.0			—
Changes in components of working capital:
Accounts receivable		105.4			92.6			15.8
Other current assets		(9.1	)		3.9			13.8
Inventories		(7.3	)		(6.9	)		0.9
Accounts payable		(100.6	)		(79.7	)		(48.8	)
Accrued interest		41.1			47.3			8.0
Accrued liabilities		57.4			(9.5	)		(10.6	)
Accrued taxes		(22.3	)		40.7			14.2
Rate reparations, refunds and other litigation reserve adjustments		(13.7	)		140.0			(19.1	)
Other, net		2.2			109.9			(14.2	)

Net Cash Provided by Operating Activities		2,235.9			1,741.8			1,363.9


Cash Flows From Investing Activities
Acquisitions of assets and equity investments		(40.2	)		(164.2	)		(387.2	)
Repayment (Payment) for Trans Mountain Pipeline		23.4			(549.1	)		—
Loans to customers		(109.6	)		—			—
Additions to property, plant and equip. for expansion and maintenance projects		(2,533.0	)		(1,691.6	)		(1,182.1	)
Sale of property, plant and equipment, and other net assets net of removal costs		47.8			302.6			70.8
Property casualty indemnifications		—			8.0			13.1
Net proceeds from (Investments in) margin deposits		71.0			(70.2	)		2.3
Contributions to investments		(366.7	)		(276.1	)		(2.5	)
Distributions from equity investments		89.1			—			—
Natural gas stored underground and natural gas liquids line-fill		(7.2	)		12.3			(12.9	)
Other		—			(0.2	)		(3.4	)

Net Cash Used in Investing Activities		(2,825.4	)		(2,428.5	)		(1,501.9	)


Cash Flows From Financing Activities
Issuance of debt		9,028.6			7,686.1			4,632.5
Payment of debt		(7,525.0	)		(6,409.3	)		(3,698.7	)
Repayments from (Loans to) related party		1.8			4.4			1.1
Debt issue costs		(12.7	)		(13.8	)		(2.0	)
Increase (Decrease) in cash book overdrafts		23.8			(27.2	)		15.8
Proceeds from issuance of common units		560.9			342.9			248.4
Proceeds from issuance of i-units		—			297.9			—
Contributions from minority interest		9.3			8.9			109.8
Distributions to partners:
Common units		(684.5	)		(552.6	)		(512.1	)
Class B units		(20.7	)		(18.0	)		(17.2	)
General Partner		(764.7	)		(567.7	)		(523.2	)
Minority interest		(18.8	)		(16.0	)		(119.0	)
Other, net		3.3			0.1			(3.0	)

Net Cash Provided by Financing Activities		601.3			735.7			132.4


Effect of exchange rate changes on cash and cash equivalents		(8.2	)		3.2			0.2


Increase (Decrease) in Cash and Cash Equivalents		3.6			52.2			(5.4	)
Cash and Cash Equivalents, beginning of year		58.9			6.7			12.1

Cash and Cash Equivalents, end of year	$	62.5		$	58.9		$	6.7


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
Related party assets acquired by the issuance of units		116.0			—			—
Assets acquired by the assumption or incurrence of liabilities		4.8			19.7			6.1
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)		373.3			336.0			329.2
Cash paid during the year for income taxes		35.7			6.2			25.6

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

129

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL


	2008					2007					2006

	Units		Amount			Units		Amount			Units		Amount

	(Dollars in millions)
Common Units:
Beginning Balance		170,220,396	$	3,048.4			162,816,303	$	3,414.9			157,005,326	$	2,680.4
Net income (loss)		—		343.4			—		(20.4	)		—		347.8
Units issued as consideration pursuant to common unit compensation plan for non-employee directors		4,338		0.3			7,280		0.4			5,250		0.3
Units issued as consideration in the acquisition of assets		2,014,693		116.0			266,813		15.0			34,627		1.6
Units issued for cash		10,730,000		560.3			7,130,000		342.5			5,771,100		248.2
Trans Mountain Pipeline acquisition		—		16.4			—		(166.8	)		—		648.7
Express/Jet Fuel Pipelines acquisition		—		52.7			—		—			—		—
Knight Inc. going-private transaction exp.		—		5.9			—		15.4			—		—
Distributions		—		(684.5	)		—		(552.6	)		—		(512.1	)

Ending Balance		182,969,427		3,458.9			170,220,396		3,048.4			162,816,303		3,414.9

Class B Units:
Beginning Balance		5,313,400		102.0			5,313,400		126.1			5,313,400		109.6
Net income (loss)		—		10.4			—		(0.6	)		—		11.6
Trans Mountain Pipeline acquisition		—		0.5			—		(6.0	)		—		22.1
Express/Jet Fuel Pipelines acquisition		—		1.6			—		—			—		—
Knight Inc. going-private transaction exp.		—		0.2			—		0.5			—		—
Distributions		—		(20.7	)		—		(18.0	)		—		(17.2	)

Ending Balance		5,313,400		94.0			5,313,400		102.0			5,313,400		126.1

i-Units:
Beginning Balance		72,432,482		2,400.8			62,301,676		2,154.2			57,918,373		1,783.6
Net income (loss)		—		145.2			—		(0.3	)		—		131.4
Units issued for cash		—		—			5,700,000		297.6			—		—
Trans Mountain Pipeline acquisition		—		6.0			—		(57.4	)		—		239.2
Express/Jet Fuel Pipelines acquisition		—		22.6			—		—			—		—
Knight Inc. going-private transaction exp.		—		2.5			—		6.7			—		—
Distributions		5,565,424		—			4,430,806		—			4,383,303		—

Ending Balance		77,997,906		2,577.1			72,432,482		2,400.8			62,301,676		2,154.2

General Partner:
Beginning Balance		—		161.1			—		119.2			—		119.9
Net income		—		805.8			—		611.6			—		513.3
Trans Mountain Pipeline acquisition		—		0.2			—		(2.2	)		—		9.2
Express/Jet Fuel Pipelines acquisition		—		0.8			—		—			—		—
Knight Inc. going-private transaction exp.		—		0.1			—		0.2			—		—
Distributions		—		(764.7	)		—		(567.7	)		—		(523.2	)

Ending Balance		—		203.3			—		161.1			—		119.2

Accum. other comprehensive income (loss):
Beginning Balance		—		(1,276.6	)		—		(866.1	)		—		(1,079.7	)
Change in fair value of derivatives used for hedging purposes		—		651.4			—		(974.2	)		—		(187.5	)
Reclassification of change in fair value of derivatives to net income		—		663.7			—		433.2			—		428.1
Foreign currency translation adjustments		—		(329.8	)		—		132.5			—		(19.6	)
Pension and other post-retirement benefit liability changes		—		3.6			—		(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		—		(287.7	)		—		(1,276.6	)		—		(866.1	)


Total Partners’ Capital		266,280,733	$	6,045.6			247,966,278	$	4,435.7			230,431,379	$	4,948.3

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

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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, buying, selling, gathering, treating and processing natural gas;

	•	CO₂ – transporting oil, 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

	•	Kinder Morgan Canada – transporting crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington, and owning an interest in an integrated oil transportation network that connects Canadian and United States producers to refineries in the U.S. Rocky Mountain and Midwest regions.

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: (i) Kinder Morgan Operating L.P. “A” (OLP-A); (ii) Kinder Morgan Operating L.P. “B” (OLP-B); (iii) Kinder Morgan Operating L.P. “C” (OLP-C); (iv) Kinder Morgan Operating L.P. “D” (OLP-D); and (v) 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) the Highstar Funds;

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(iii) The Carlyle Group; and (iv) Riverstone Holdings LLC. This transaction is referred to in this report as the going-private transaction.

Knight is privately owned and indirectly owns all of the common stock 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. As of December 31, 2008, Knight and its consolidated subsidiaries owned, through its general and limited partner interests, an approximate 14.1% 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, 2008, KMR owned approximately 29.3% 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 were prepared in accordance with accounting principles generally accepted in the United States and 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, and certain amounts from prior years have been reclassified to conform to the current presentation. Our accompanying consolidated financial statements reflect amounts on a historical cost basis, and, accordingly, do not reflect any purchase accounting adjustments related to the May 30, 2007 going-private transaction of KMI, now known as Knight.

In addition, 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.

Prior to the third quarter of 2008, we reported five business segments: Products Pipelines; Natural Gas Pipelines; CO₂; Terminals; and Trans Mountain. As discussed in Note 3 below, we acquired (i) a one-third interest in the Express pipeline system; and (ii) the Jet Fuel pipeline system from Knight on August 28, 2008, and following the acquisition of these businesses, the operations of our Trans Mountain, Express and Jet Fuel pipeline systems have

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been combined to represent the “Kinder Morgan Canada” segment. For more information on our reportable business segments, see Note 15.

We believe that certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.

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. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments 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, 2008, 2007 and 2006 (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, 2008	$	7.0	$	0.6	$	—	$	(1.5)	$	6.1

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


(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 and currency translation adjustments.

In addition, the balances of “Accrued other current liabilities” in our accompanying consolidated balance sheets include amounts related to customer prepayments of approximately $10.8 million as of December 31, 2008 and $6.5 million as of December 31, 2007.

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. In December of 2008, we recognized a lower of cost or market adjustment of $12.9 million in our CO₂ business segment. Additionally, as of December 31, 2008 and 2007, we owed certain customers a total of $1.0 million and $8.3 million, respectively, for the value of natural gas inventory stored in our underground storage facilities, and we reported these amounts within “Accounts Payable—Trade” 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

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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 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 1.6% 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. In December 2008, we completed an impairment test of the long-lived assets included within our CO₂ business segment and determined that the assets were not impaired as of December 31, 2008.

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. Due to the decline in crude oil and natural gas prices during the course of 2008, on December 31, 2008, we conducted an impairment test on our oil and gas producing properties in our CO₂ business segment and determined that no impairment was necessary. For the purpose of impairment testing, we use the forward curve prices as observed at the test date. The forward curve cash flows may differ from the amounts presented in Note 20 due to differences between the forward curve and spot prices. 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.

Pursuant to our adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” on January 1, 2002, we selected a goodwill impairment measurement date of January 1 of each year, and we have determined that our goodwill was not impaired as of January 1, 2008. In the second quarter of 2008, we changed the date of our annual goodwill impairment test date to May 31 of each year. The change was made following our management’s decision to match our impairment testing date to the impairment testing date of Knight—following the completion of its going-private transaction on May 30, 2007, Knight established as its goodwill impairment measurement date May 31 of each year. This change to the date of our annual goodwill impairment test constitutes a change in the method of applying an accounting principle, as discussed in paragraph 4 of SFAS No. 154, “Accounting Changes and Error Corrections.” We believe that this change in accounting principle is preferable because our test would then be performed at the same time as Knight, which indirectly owns all the common stock of our general partner.

SFAS No. 154 requires an entity to report a change in accounting principle through retrospective application of the new accounting principle to all periods, unless it is impracticable to do so. However, our change to a new testing date, when applied to prior periods, does not yield different financial statement results. Furthermore, there were no impairment charges resulting from the May 31, 2008 impairment testing, and no event indicating an impairment has occurred subsequent to that date. However, our consolidated income statement for the year ended December 31,

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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 $1,058.9 million as of December 31, 2008 and $1,077.8 million as of December 31, 2007. 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, 2008 and December 31, 2007. 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 $169.0 million and $174.7 million as of December 31, 2008 and 2007, respectively, and similar to our treatment of equity method goodwill, we included these amounts within “Investments” on our accompanying consolidated balance sheets. As of December 31, 2008, this excess investment cost is being amortized over a weighted average life of approximately 29.9 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, 2008, 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

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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.

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 on debt represents the estimated cost of capital, from borrowed funds, during the construction period. Total AFUDC on debt resulting from the capitalization of interest expense in 2008, 2007 and 2006 was $48.6 million, $31.4 million and $20.3 million, respectively. Similarly, AFUDC on equity represents an estimate of the cost of capital funded by equity contributions, and in the twelve months ended December 31, 2008, 2007 and 2006, we also capitalized approximately $10.6 million, $6.1 million and $2.2 million, respectively, of equity AFUDC.

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

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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 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, 2008, our 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;

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	• the 1% interest in River Terminals Properties, L.P., a Tennessee partnership owned 99% and controlled by Kinder Morgan River Terminals LLC; and

	• the 35% interest in Guilford County Terminal Company, LLC, a limited liability company owned 65% 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.

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 both energy commodity price risk and interest rate risk; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other post-retirement benefit plan liabilities. 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, 2007 and 2008 (in millions):

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	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, 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	)
Change for period		1,315.1			(329.8	)		3.6			988.9

December 31, 2008	$	(64.6	)	$	(217.3	)	$	(5.8	)	$	(287.7	)

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. See Note 18 for further information regarding recent accounting pronouncements relating to earnings per unit.

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. 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.

Furthermore, 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.

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 and disclosures.

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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 amount of regulatory assets and liabilities 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, 2008 and December 31, 2007 are not material to our consolidated balance sheets.

3. Acquisitions, Joint Ventures and Divestitures

Acquisitions from Unrelated Entities

During 2008, 2007 and 2006, we completed the following acquisitions, and except for our acquisitions from Knight (discussed below in “—Acquisitions from Knight”), 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) were 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

(1)	2/06	Entrega Gas Pipeline LLC	$	244.6	$	—	$	244.6	$	—	$	—
(2)	4/06	Oil and Gas Properties		63.6		0.1		63.5		—		—
(3)	4/06	Terminal Assets		61.9		0.5		43.6		—		17.8
(4)	11/06	Transload Services, LLC		16.6		1.6		6.6		—		8.4
(5)	12/06	Devco USA L.L.C.		7.3		0.8		—		6.5		—
(6)	12/06	Roanoke, Virginia Products Terminal		6.4		—		6.4		—		—
(7)	1/07	Interest in Cochin Pipeline		47.8		—		47.8		—		—
(8)	5/07	Vancouver Wharves Marine Terminal		59.5		6.1		53.4		—		—
(9)	9/07	Marine Terminals, Inc. Assets		102.1		0.2		60.8		22.5		18.6
(10)	8/08	Wilmington, North Carolina Liquids Terminal		12.7		—		5.9		—		6.8
(11)	12/08	Phoenix, Arizona Products Terminal		27.5		—		27.5		—		—

(1) 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.

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On the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline of over 300 miles in length. 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 project, with an expected cost of $6.3 billion (including expansion), 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% 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,” because 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.

(2) 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.

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(3) 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. We believe the purchase price for the assets, including intangible assets, exceeded the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.

(4) 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 because 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.

(5) 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.

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(6) 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.

(7) 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 pipe operating between Fort Saskatchewan, Alberta, and Windsor, Ontario, Canada. Its operations are included as part of our Products Pipelines business segment.

(8) 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 $59.5 million, consisting of $38.8 million in cash and $20.7 million in assumed liabilities. The acquisition both expanded and complemented our existing terminal operations, and all of the acquired assets are included in our Terminals business segment.

In the first half of 2008, we made our final purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities. Our adjustments increased “Property, Plant and Equipment, net” by $2.7 million, reduced working capital balances by $1.6 million, and increased long-term liabilities by $1.1 million. Based on our estimate of fair market values, we allocated $53.4 million of our combined purchase price to “Property, Plant and Equipment, net,” and $6.1 million to items included within “Current Assets.”

(9) Marine Terminals, Inc. Assets

Effective September 1, 2007, we acquired certain bulk terminals assets from Marine Terminals, Inc. for an aggregate consideration of $102.1 million, consisting of $100.8 million in cash and assumed liabilities of $1.3 million. The acquired assets and operations are primarily involved in the handling and storage of steel and alloys. The acquisition both expanded and complemented our existing ferro alloy terminal operations and will provide 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.

In the first nine months of 2008, we paid an additional $0.5 million for purchase price settlements, and we made purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities. Our 2008 adjustments primarily reflected changes in the allocation of the purchase cost to intangible assets acquired. Based on our estimate of fair market values, we allocated $60.8 million of our combined purchase price to “Property, Plant and Equipment, net;” $21.7 million to “Other intangibles, net;” $18.6 million to “Goodwill;” and $1.0 million to “Other current assets” and “Deferred charges and other assets.”

The allocation to “Other intangibles, net” included a $20.1 million amount representing the fair value of a service contract entered into with Nucor Corporation, a large domestic steel company with significant operations in the Southeast region of the United States. For valuation purposes, the service contract was determined to have a useful life of 20 years, and pursuant to the contract’s provisions, the acquired terminal facilities will continue to provide Nucor with handling, processing, harboring and warehousing services.

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The allocation to “Goodwill,” which is expected to be deductible for tax purposes, was based on the fact that this 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. We believe the acquired value of the assets, including all contributing intangible assets, exceeded the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.

(10) Wilmington, North Carolina Liquids Terminal

On August 15, 2008, we purchased certain terminal assets from Chemserve, Inc. for an aggregate consideration of $12.7 million, consisting of $11.8 million in cash and $0.9 million in assumed liabilities. The liquids terminal facility is located in Wilmington, North Carolina and stores petroleum products and chemicals. The acquisition both expanded and complemented our existing Mid-Atlantic region terminal operations, and all of the acquired assets are included in our Terminals business segment. In the fourth quarter of 2008, we allocated our purchase price to reflect final fair value of acquired assets and final expected value of assumed liabilities. A total of $6.8 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 because of certain advantageous factors (including the synergies provided by increasing our liquids storage capacity in the Southeast region of the U.S.) that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.

(11) Phoenix, Arizona Products Terminal

Effective December 10, 2008, our West Coast Products Pipelines operations acquired a refined petroleum products terminal located in Phoenix, Arizona from ConocoPhillips for approximately $27.5 million in cash. The terminal has storage capacity of approximately 200,000 barrels for gasoline, diesel fuel and ethanol. The acquisition complemented our existing Phoenix liquids assets, and the acquired incremental storage will increase our combined storage capacity in the Phoenix market by approximately 13%. The acquired terminal is included as part our Products Pipelines business segment.

Pro Forma Information

Pro forma consolidated income statement information that gives effect to all of the acquisitions we have made and all of the joint ventures we have entered into since January 1, 2007 as if they had occurred as of January 1, 2007 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

Acquisitions from Knight

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,” effective January 1, 2006, Knight (which indirectly owns all the common stock of our general partner) was deemed to have control over us and no longer accounted for its investment in us under the equity method of accounting. Instead, as of this date, Knight included our accounts, balances and results of operations in its consolidated financial statements and, as required by the provisions of SFAS No. 141, we accounted for each of the two separate acquisitions discussed below as transfers of net assets between entities under common control.

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.

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In April 2008, as a result of finalizing certain “true-up” provisions in our acquisition agreement related to Trans Mountain pipeline expansion spending, we received a cash contribution of $23.4 million from Knight. Pursuant to the accounting provisions concerning transfers of net assets between entities under common control, and consistent with our treatment of cash payments made to Knight for Trans Mountain net assets in 2007, we accounted for this cash contribution as an adjustment to equity—primarily as an increase in “Partners’ Capital” in our accompanying consolidated balance sheet. We also included this $23.4 million receipt as a cash inflow item from investing activities in our accompanying consolidated statement of cash flows.

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, completed a pump station expansion in April 2007 that increased pipeline throughput capacity to approximately 260,000 barrels per day. An additional expansion that increased pipeline capacity by 25,000 barrels per day was completed and began service on May 1, 2008. We completed construction on a final 15,000 barrel per day expansion on October 30, 2008, and total pipeline capacity is now approximately 300,000 barrels per day.

In addition, because 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 identified our Trans Mountain pipeline system as a separate reportable business segment prior to the third quarter of 2008. Following the acquisition of our interests in the Express and Jet Fuel pipeline systems on August 28, 2008, discussed following, we combined the operations of our Trans Mountain, Express and Jet Fuel pipeline systems to represent the “Kinder Morgan Canada” segment.

Express and Jet Fuel Pipeline Systems

Effective August 28, 2008, we acquired Knight’s 33 1/3% ownership interest in the Express pipeline system. The pipeline system is a batch-mode, common-carrier, crude oil pipeline system consisting of both the Express Pipeline and the Platte Pipeline (collectively referred to in this report as the Express pipeline system). We also acquired Knight’s full ownership of an approximately 25-mile jet fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada (referred to in this report as the Jet Fuel pipeline system). As consideration for these assets, we paid to Knight approximately 2.0 million common units, valued at $116.0 million. The acquisition complemented our existing Canadian pipeline system (Trans Mountain), and all of the acquired assets (including an acquired cash balance of $7.4 million) are included in our Kinder Morgan Canada business segment.

We now operate the Express pipeline system, and we account for our 33 1/3% ownership in the system under the equity method of accounting. In addition to our 33 1/3% equity ownership, our investment in Express includes an investment in unsecured debenture bonds issued by Express Holdings U.S. L.P., the partnership that maintains ownership of the U.S. portion of the Express pipeline system. For more information on this long-term note receivable, see Note 12.

When accounting for transfers of net assets between 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 net asset 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 consideration paid and the book value of the net assets acquired).

Therefore, in each of these two business acquisitions from Knight, we recognized the 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 the carrying amount of the assets and liabilities transferred to us were carried forward to our balance sheet, and all of the acquired equity accounts were also carried forward intact initially, and subsequently adjusted due to differences between (i) the consideration we paid for the acquired net assets; and (ii) the book value (carrying value) of the acquired net assets.

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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 financial statements presented be combined as of the date of common control, and all financial statements and financial information presented for prior periods should be restated to furnish comparative information. However, based upon our management’s consideration of all of the quantitative and qualitative aspects of the transfer of the interests in the Express and Jet Fuel pipeline system net assets from Knight to us, we determined that the presentation of combined financial statements which include the financial information of the Express and Jet Fuel pipeline systems would not be materially different from financial statements which did not include such information and accordingly, we elected not to include the financial information of the Express and Jet Fuel pipeline systems in our consolidated financial statements for any periods prior to the transfer date of August 28, 2008.

Our consolidated financial statements and all other financial information included in this report therefore, have been prepared assuming that the transfer of both the 33 1/3% interest in the Express pipeline system net assets and the Jet Fuel pipeline system net assets from Knight to us had occurred at the date of transfer (August 28, 2008).

Joint Ventures

Rockies Express Pipeline LLC

In the first quarter of 2008, we made capital contributions of $306.0 million to West2East Pipeline LLC (the sole owner of Rockies Express Pipeline LLC) to partially fund its Rockies Express Pipeline construction costs. We included this cash contribution as an increase to “Investments” in our accompanying consolidated balance sheet as of December 31, 2008, and we included it within “Contributions to investments” in our accompanying consolidated statement of cash flows for the year ended December 31, 2008. We own a 51% equity interest in West2East Pipeline LLC.

On June 24, 2008, Rockies Express completed a private offering of an aggregate of $1.3 billion in principal amount of fixed rate senior notes. Rockies Express received net proceeds of approximately $1.29 billion from this offering, after deducting the initial purchasers’ discount and estimated offering expenses, and virtually all of the net proceeds from the sale of the notes were used to repay short-term commercial paper borrowings.

All payments of principal and interest in respect of these senior notes are the sole obligation of Rockies Express. Noteholders will have no recourse against us, Sempra Energy or ConocoPhillips (the two other member owners of West2East Pipeline LLC), or against any of our or their respective officers, directors, employees, shareholders, members, managers, unitholders or affiliates for any failure by Rockies Express to perform or comply with its obligations pursuant to the notes or the indenture.

Midcontinent Express Pipeline LLC

In 2008, we made capital contributions of $27.5 million to Midcontinent Express Pipeline LLC to partially fund its Midcontinent Express Pipeline construction costs. We included this cash contribution as an increase to “Investments” in our accompanying consolidated balance sheet as of December 31, 2008, and we included it within “Contributions to investments” in our accompanying consolidated statement of cash flows for the year ended December 31, 2008. We own a 50% equity interest in Midcontinent Express Pipeline LLC.

We also received, in the first quarter of 2008, an $89.1 million return of capital from Midcontinent Express Pipeline LLC. In February 2008, Midcontinent entered into and then made borrowings under a new $1.4 billion three-year, unsecured revolving credit facility due February 28, 2011. Midcontinent then made distributions (in excess of cumulative earnings) to its two member owners to reimburse them for prior contributions made to fund its pipeline construction costs, and we reflected this cash receipt separately within the investing section of our accompanying consolidated statement of cash flows.

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Fayetteville Express Pipeline LLC

On October 1, 2008, we announced that we have entered into a 50/50 joint venture with Energy Transfer Partners, L.P. to build and develop the Fayetteville Express Pipeline, a new natural gas pipeline that will provide shippers in the Arkansas Fayetteville Shale area with takeaway natural gas capacity, added flexibility, and further access to growing markets.

The new pipeline will also interconnect with Natural Gas Pipeline Company of America LLC’s pipeline in White County, Arkansas; Texas Gas Transmission LLC’s pipeline in Coahoma County, Mississippi; and ANR Pipeline Company’s pipeline in Quitman County, Mississippi. Natural Gas Pipeline Company of America’s pipeline is operated and 20% owned by Knight. The Fayetteville Express Pipeline will have an initial capacity of two billion cubic feet of natural gas per day. Pending necessary regulatory approvals, the approximately $1.2 billion pipeline project is expected to be in service by late 2010 or early 2011. Fayetteville Express Pipeline LLC has secured binding 10-year commitments totaling approximately 1.85 billion cubic feet per day.

In the fourth quarter of 2008, we made capital contributions of $9.0 million to Fayetteville Express Pipeline LLC to fund our proportionate share of certain pre-construction pipeline costs. We included this cash contribution as an increase to “Investments” in our accompanying consolidated balance sheet as of December 31, 2008, and we included it within “Contributions to investments” in our accompanying consolidated statement of cash flows for the year ended December 31, 2008.

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.

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 in the fourth quarter of 2007 from the sale of these net assets. We reported this gain separately as “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. Prior to the sale, all of the assets were included in our Products Pipelines business segment.

In the first half of 2008, following final account and inventory reconciliations, we paid a net amount of $2.4 million to ONEOK to fully settle amounts related to (i) working capital items; (ii) total physical product liquids inventory and inventory obligations for certain liquids products; and (iii) the allocation of pre-acquisition investee distributions. Based primarily upon these adjustments, which were below the amounts reserved, we recognized an additional gain of $1.3 million in 2008, and we reported this gain separately as “Adjustment to gain on disposal of

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North System” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2008.

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 and the gains on disposal of the North System have been reclassified to discontinued operations in our accompanying consolidated statements of income.

Summarized financial information of the North System is as follows (in millions):


	Year Ended December 31,

	2008		2007			2006

Operating revenues	$	—	$	41.1		$	43.7
Operating expenses		—		(14.8	)		(22.7	)
Depreciation and amortization		—		(7.0	)		(8.9	)
Earnings from equity investments		—		1.8			2.2
Amortization of excess cost of equity investments		—		—			(0.1	)
Other, net – income (expense)		—		—			0.1

Income from operations		—		21.1			14.3
Gain on disposal		1.3		152.8			—

Total earnings from discontinued operations	$	1.3	$	173.9		$	14.3

Additionally, in our accompanying consolidated statement of cash flows, we elected not to present separately the North System’s operating and investing cash flows as discontinued operations, and, because 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 results within our Products Pipelines business segment disclosures for all periods presented in this report.

Thunder Creek Gas Services, LLC

Effective April 1, 2008, we sold our 25% ownership interest in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek, to PVR Midstream LLC, a subsidiary of Penn Virginia Corporation. Prior to the sale, we accounted for our investment in Thunder Creek under the equity method of accounting and included its financial results within our Natural Gas Pipelines business segment. In the second quarter of 2008, we received cash proceeds, net of closing costs and settlements, of approximately $50.7 million for our investment, and we recognized a gain of $13.0 million with respect to this transaction. We used the proceeds from this sale to reduce the outstanding balance on our commercial paper borrowings, and we included the amount of the gain within the caption “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2008.

4. Asset Retirement Obligations

According to the provisions of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” we record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

In our CO₂ business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of December 31, 2008 and December 31, 2007, we have recognized asset retirement obligations in the aggregate amount of $74.1 million and $49.2 million, respectively, relating to these requirements at existing sites within our CO₂ business segment. The $24.9 million increase since December 31, 2007 was primarily related to higher estimated service, material and equipment costs related to our legal obligations associated with the retirement of tangible long-lived assets.

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In our Natural Gas Pipelines business segment, the operating systems are composed of underground piping, compressor stations and associated facilities, natural gas storage facilities and certain other facilities and equipment. Currently, we have no plans to abandon any of these facilities, the majority of which have been providing utility services for many years. However, if we were to cease providing utility services in total or in any particular area, we may be required to remove certain surface facilities and equipment from land belonging to our customers and others (we would generally have no obligations for removal or remediation with respect to equipment and facilities, such as compressor stations, located on land we own). We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities and as of December 31, 2008 and December 31, 2007, we have recognized asset retirement obligations in the aggregate amount of $2.4 million and $3.0 million, respectively, relating to the businesses within our Natural Gas Pipelines business segment.

We have included $2.5 million of our total asset retirement obligations as of December 31, 2008 with “Accrued other current liabilities” in our accompanying consolidated balance sheet. The remaining $74.0 million obligation is reported separately as a non-current liability. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the years ended December 31, 2008 and 2007 is as follows (in millions):


	Year Ended December 31,

	2008			2007

Balance at beginning of period	$	52.2		$	50.3
Liabilities incurred/revised		26.2			0.4
Liabilities settled		(5.4	)		(1.1	)
Accretion expense		3.5			2.6

Balance at end of period	$	76.5		$	52.2

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):


	Year Ended December 31,

	2008			2007			2006

Taxes current expense:
Federal	$	24.4		$	12.7		$	12.8
State		8.5			8.2			2.3
Foreign		(4.5)			31.5			11.2

Total		28.4			52.4			26.3
Taxes deferred expense:
Federal		6.0			11.8			1.6
State		1.5			6.2			0.2
Foreign		(15.5)			0.6			0.9

Total		(8.0)			18.6			2.7

Total tax provision	$	20.4		$	71.0		$	29.0

Effective tax rate		1.5	%		14.6	%		2.8	%

The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:

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	Year Ended December 31,

	2008			2007			2006

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		1.6	%		3.0	%		1.0	%
Income tax expense attributable to corporate equity earnings		0.6	%		2.3	%		0.5	%
Income tax expense attributable to foreign corporate earnings		(1.2)	%		6.6	%		1.1	%
State taxes		0.5	%		2.7	%		0.2	%

Effective tax rate		1.5	%		14.6	%		2.8	%

Our deferred tax assets and liabilities as of December 31, 2008 and 2007 result from the following (in millions):


	December 31,

	2008		2007

Deferred tax assets:
Book accruals	$	3.2	$	13.1
Net Operating Loss/Alternative minimum tax credits		1.4		1.2
Other		1.8		1.7

Total deferred tax assets		6.4		16.0

Deferred tax liabilities:
Property, plant and equipment		161.3		189.9
Other		23.1		28.5

Total deferred tax liabilities		184.4		218.4

Net deferred tax liabilities	$	178.0	$	202.4

Pursuant to the provisions of FASB’s Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109,” which became effective January 1, 2007, 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 each of the years ended December 31, 2008 and 2007 is as follows (in millions):


	Year Ended December 31,

	2008			2007

Balance at beginning of period	$	6.3		$	3.2
Additions based on current year tax positions		0.4			4.7
Additions based on prior year tax positions		9.6			0.1
Reductions based on settlements with taxing authority		(0.1	)		—
Reductions due to lapse in statute of limitations		(1.3	)		(1.7	)

Balance at end of period	$	14.9		$	6.3

As of December 31, 2007, we had $0.7 million of accrued interest and no accrued penalties, and our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2008, we recognized approximately $0.5 million in interest expense, and during the year ended December 31, 2007, we recognized interest income of approximately $0.4 million.

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As of December 31, 2008 (i) we had $1.2 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 $0.2 million during the next twelve months; and (iii) we believe approximately all of the total $14.9 million of unrecognized tax benefits on our consolidated balance sheet as of December 31, 2008 would affect our effective 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 2008.

6. Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2008 and 2007, our property, plant and equipment consisted of the following (in millions):


	December 31,

	2008			2007

Natural gas, liquids, crude oil and carbon dioxide pipelines	$	5,752.4		$	5,498.4
Natural gas, liquids, carbon dioxide pipeline, and terminals station equipment		6,432.1			5,076.2
Natural gas, liquids (including linefill), and transmix processing		210.3			168.3
Other		1,523.1			1,060.4
Accumulated depreciation and depletion		(2,554.0	)		(2,044.0	)

		11,363.9			9,759.3
Land and land right-of-way		549.0			551.5
Construction work in process		1,328.5			1,280.5

Property, Plant and Equipment, net	$	13,241.4		$	11,591.3

Depreciation and depletion expense charged against property, plant and equipment consisted of $684.2 million in 2008, $529.3 million in 2007 and $416.6 million in 2006.

Property Casualties

2005 Hurricanes

On August 29, 2005, Hurricane Katrina made landfall in the United States Gulf Coast causing widespread damage to residential and commercial 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. All of our terminal facilities affected by these storms were repaired and re-opened, and all of the facilities were covered by property casualty insurance. Some of the facilities were also covered by business interruption insurance.

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 and 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 recognized additional casualty gains of approximately $1.8 million in the first quarter of 2007, based upon our final determination of the book value of the fixed assets destroyed or damaged and indemnities pursuant to flood insurance coverage. These recognized casualty gains are reported within the captions “Other expense (income)” in our accompanying consolidated statements of income for each of the years ended December 31, 2006 and 2007.

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In addition to the $15.2 million 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 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.

We also collected, in 2006 and 2007, property insurance indemnities of $13.1 million and $8.0 million, respectively, and we disclosed these cash receipts separately as “Property casualty indemnifications” within investing activities on our accompanying consolidated statements of cash flows. We also incurred capital expenditures related to the repair and replacement of damaged assets due to these 2005 storms. 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.

2008 Hurricanes and Fires

In September 2008, two hurricanes struck the Gulf Coast communities of southern Texas and Louisiana and a third hurricane made U.S. landfall near the South Carolina-North Carolina border. The three named hurricanes—Hanna, Gustav, and Ike—caused wide-spread damage to residential and commercial property but our primary assets in those areas experienced only relatively minor damage. We realized a combined $11.1 million decrease in net income due to incremental expenses associated with the clean-up and asset damage from these storms (but excluding estimates for lost business and lost revenues). The decrease to net income primarily consisted of a $10.5 million increase in operating and maintenance expenses from hurricane repair and clean-up activities included within the caption “Operations and maintenance” in our accompanying consolidated statement of income for 2008.

Additionally, in the third quarter of 2008, we experienced fire damage at three separate terminal locations. The largest was an explosion and fire at our Pasadena, Texas liquids terminal facility on September 23, 2008. The fire primarily damaged a manifold system used for liquids distribution. We intend to repair the damaged portions of each separate terminal facility, and we recognized a combined $7.2 million decrease in net income due to incremental expenses and asset damage associated with these fires (excluding estimates for lost business and lost revenues). The decrease to net income primarily consisted of combined casualty losses totaling $5.3 million and reported within the caption “Other expense (income)” in our accompanying consolidated statement of income for 2008.

7. Investments

Our long-term investments as of December 31, 2008 consisted of equity investments totaling $941.1 million and bond investments totaling $13.2 million. Our bond investments consist of certain tax exempt, fixed-income development revenue bonds acquired in the fourth quarter of 2008. Because we have both the ability and the intent to hold these debt securities to maturity, we account for these investments at historical cost. Our bond investments are further discussed in Note 9.

Our significant equity investments as of December 31, 2008 consisted of:


	• West2East Pipeline LLC (51%);

	• Plantation Pipe Line Company (51%);

	• Red Cedar Gathering Company (49%);

	• Express pipeline system (33 1/3%);

	• Cortez Pipeline Company (50%); and

	• Midcontinent Express Pipeline LLC (50%).

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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, because 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 of accounting.

Similarly, 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.

We acquired our ownership interest in the Red Cedar Gathering Company from Knight (then Kinder Morgan, Inc.) on December 31, 1999. We acquired our ownership interest in the Express pipeline system from Knight effective August 28, 2008. We acquired a 50% ownership interest in Cortez Pipeline Company from affiliates of Shell in April 2000. We formed Midcontinent Express Pipeline LLC in May 2006.

In 2007, we began making cash contributions to Midcontinent Express, the sole owner of the Midcontinent Express Pipeline, for our share of the Midcontinent Express Pipeline construction costs; however, as of December 31, 2008, we had no net investment in Midcontinent Express because in 2008, Midcontinent Express established and made borrowings under its own revolving bank credit facility in order to fund its pipeline construction costs and to make distributions to its member owners to fully reimburse them for prior contributions.

In January 2008, Midcontinent Express Pipeline LLC 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 Pipeline LLC after the pipeline is fully constructed and fully placed into service—currently estimated to be August 1, 2009. If the option is exercised, we and Energy Transfer Partners, L.P. will each own 45% of Midcontinent Express Pipeline LLC, while MarkWest will own the remaining 10%.

In addition to the investments listed above (excluding Express), our significant equity investments as of December 31, 2007 included our 25% equity interest in Thunder Creek Gas Services, LLC. We sold our ownership interest in Thunder Creek to PVR Midstream LLC on April 1, 2008. Both the acquisition of our investment in Express and the divestiture of our investment in Thunder Creek are discussed in Note 3.

Our total equity investments consisted of the following (in millions):


	December 31,

	2008		2007

West2East Pipeline LLC	$	501.1	$	191.9
Plantation Pipe Line Company		196.6		195.4
Red Cedar Gathering Company		138.9		135.6
Express pipeline system		64.9		—
Cortez Pipeline Company		13.6		14.2
Midcontinent Express Pipeline LLC		—		63.0
Thunder Creek Gas Services, LLC		—		37.0
All others		26.0		18.3

Total equity investments	$	941.1	$	655.4

Our earnings (losses) from equity investments were as follows (in millions):

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	Year Ended December 31,

	2008			2007			2006

West2East Pipeline LLC	$	84.9		$	(12.4	)	$	—
Red Cedar Gathering Company		26.7			28.0			36.3
Plantation Pipe Line Company		22.3			29.4			12.8
Cortez Pipeline Company		20.8			19.2			19.2
Thunder Creek Gas Services, LLC		1.3			2.2			2.4
Midcontinent Express Pipeline LLC		0.5			1.4			—
Express pipeline system		(0.5	)		—			—
All others		4.8			1.9			3.3

Total	$	160.8		$	69.7		$	74.0

Amortization of excess costs	$	(5.7	)	$	(5.8	)	$	(5.6	)

Summarized combined unaudited financial information for our significant equity investments (listed or described above) is reported below (in millions; amounts represent 100% of investee financial information):


	Year Ended December 31,

Income Statement	2008		2007		2006

Revenues	$	1,015.0	$	473.0	$	441.9
Costs and expenses		681.6		355.1		299.5

Earnings before extraordinary items and Cumulative effect of a change in accounting principle		333.4		117.9		142.4
Net income	$	333.4	$	117.9	$	142.4


	December 31,

Balance Sheet	2008		2007

Current assets	$	221.7	$	138.3
Non-current assets		6,797.5		3,519.5
Current liabilities		3,690.1		319.5
Non-current liabilities		2,015.3		2,624.1
Partners’/owners’ equity		1,313.8		714.2


8.	Intangibles

Goodwill and Excess Investment Cost

As an investor, the price we pay to acquire an ownership interest in an investee’s net assets will most likely differ from the underlying interest in the net assets’ 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 us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount.

Pursuant to our adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” on January 1, 2002, we selected a goodwill impairment measurement date of January 1 of each year; and we have determined that our goodwill was not impaired as of January 1, 2008. In the second quarter of 2008, we changed our impairment measurement date to May 31 of each year. The change was made following our management’s decision to match our impairment testing date to the impairment testing date of Knight—following the completion of its going-private transaction on May 30, 2007, Knight established May 31 of each year as its goodwill impairment measurement date. This change in the date of our annual goodwill impairment test constitutes a change in the method of applying an accounting principle, as discussed in paragraph 4 of SFAS No. 154, “Accounting Changes and Error Corrections.” We believe that this change in accounting principle is preferable because our test would then be performed at the same time as Knight, which indirectly owns all the common stock of our general partner.

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In conjunction with our goodwill impairment test on May 31, 2008, the fair value of each of our segment’s reporting units was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using market multiples between six and nine times cash flows) discounted at a rate of 9.0%. In accordance with paragraph 23 of SFAS No. 142, the value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date.

Changes in the carrying amount of our goodwill for each of the two years ended December 31, 2007 and 2008 are summarized as follows (in millions):


	Products Pipelines		Natural Gas Pipelines		CO₂		Terminals			Kinder Morgan Canada(a)			Total

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
Acquisitions and purchase price adjs.		—		—		—		28.5			—			28.5
Disposals		—		—		—		—			—			—
Impairments		—		—		—		—			—			—
Currency translation adjustments		—		—		—		—			(47.4	)		(47.4	)

Balance as of December 31, 2008	$	263.2	$	288.4	$	46.1	$	257.6		$	203.6		$	1,058.9




(a)	On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from Knight, and this transaction was completed April 30, 2007 (discussed in Note 3). Following the provisions of generally accepted accounting principles, the consideration of this transaction caused Knight to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired. Based on this determination, Knight recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007, and because we have included all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006, this impairment expense is now reflected in our consolidated results of operations.

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, 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, 2008 and 2007, we have reported $138.2 million in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.

We also periodically reevaluate the difference between the fair value of net assets accounted for under the equity method and our proportionate share of the underlying book value (that is, the investee’s net assets per its financial statements) of the investee at date of acquisition. In almost all instances, this differential, relating to the discrepancy between our share of the investee’s recognized net assets at book values and at current fair values, represents our share of undervalued depreciable assets, and since those assets (other than land) are subject to depreciation, we amortize this portion of our investment cost against our share of investee earnings. We reevaluate this differential, as well as the amortization period for such undervalued depreciable assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives in accordance with APB Opinion No. 18. The caption “Investments” in our accompanying consolidated balance sheets includes excess fair value of net assets over book value costs of $169.0 million as of December 31, 2008 and $174.7 million as of December 31, 2007.

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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, 2008			December 31, 2007

Customer relationships, contracts and agreements
Gross carrying amount	$	246.0		$	264.1
Accumulated amortization		(51.1	)		(36.9	)

Net carrying amount		194.9			227.2


Technology-based assets, lease value and other
Gross carrying amount		13.3			13.3
Accumulated amortization		(2.4	)		(1.9	)

Net carrying amount		10.9			11.4


Total Other intangibles, net	$	205.8		$	238.6

Our customer relationships, contracts and agreements relate primarily to our Terminals business segment, and include relationships and contracts for handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, coal, petroleum coke, fertilizer, steel and ores. The values of these intangible assets were determined by us (often in conjunction with third party valuation specialists) by first, estimating the revenues derived from a customer relationship or contract (offset by the cost and expenses of supporting assets to fulfill the contract), and secondly, discounting the revenues at a risk adjusted discount rate.

The decrease in the carrying amount of customer relationships, contracts and agreements since December 31, 2007 was primarily due to purchase price adjustments related to the fair value of an intangible customer contract included in our purchase of certain assets from Marine Terminals, Inc. on September 1, 2007. For more information on this acquisition, see Note 3 “Acquisitions and Joint Ventures—Acquisitions from Unrelated Entities—Marine Terminals, Inc. Assets.”

We amortize our intangible assets by applying the straight-line method - the method of amortizing cost to amortization expense such that there is an even allocation of expense over the life of the intangible. We believe amortizing our intangibles on a straight-line basis most appropriately recognizes the pattern of economic benefits realized from these assets, because our experience has demonstrated that the benefit generally will be realized through the cash flows under each asset essentially equally throughout its corresponding life. For the years ended December 31, 2008, 2007 and 2006, the amortization expense on our intangibles totaled $14.7 million, $14.3 million and $13.7 million, respectively. These expense amounts primarily consisted of amortization of our customer relationships, contracts and agreements. Our estimated amortization expense for these assets for each of the next five fiscal years (2009 – 2013) is approximately $13.8 million, $13.6 million, $13.4 million, $13.1 million and $13.1 million, respectively.

The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. As of December 31, 2008, the weighted average amortization period for our intangible assets was approximately 17.3 years.

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9.	Debt

Short-Term Debt

Our outstanding short-term debt as of December 31, 2008 was $288.7 million. The balance consisted of (i) $250 million in principal amount of 6.30% senior notes due February 1, 2009; (ii) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, but are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (our subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds); (iii) an $8.5 million portion of a 5.40% long-term note payable (our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note); and (iv) a $6.5 million portion of 5.23% senior notes (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes).

Our outstanding short-term debt as of December 31, 2007 was $610.2 million, consisting of (i) $589.1 million of commercial paper borrowings; (ii) a $9.9 million portion of the 5.40% long-term note payable due from our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company; (iii) a $6.2 million portion of the 5.23% senior notes due from our subsidiary Kinder Morgan Texas Pipeline, L.P.; and (iv) a remaining $5.0 million in principal amount of 7.84% senior notes due July 23, 2008 from our subsidiary Central Florida Pipe Line LLC, the obligor on the notes.

The weighted average interest rate on all of our borrowings was approximately 5.44% during 2008 and 6.40% during 2007.

Credit Facility

Our $1.85 billion five-year unsecured bank credit facility matures August 18, 2010 and can be amended to allow for borrowings up to $2.1 billion. Borrowings under our credit facility can be used for general partnership purposes and as a backup for our commercial paper program. As of both December 31, 2008 and 2007, there were no borrowings under the credit facility.

As of December 31, 2008, the amount available for borrowing under our credit facility was reduced by an aggregate amount of $313.0 million, consisting of (i) 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; (ii) a combined $73.7 million in three letters of credit that support tax-exempt bonds; (iii) a combined $55.9 million in letters of credit that support our pipeline and terminal operations in Canada; (iv) a combined $40 million in two letters of credit that support our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil; (v) a $26.8 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (vi) a combined $16.6 million in other letters of credit supporting other obligations of us and our subsidiaries.

On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One Lehman entity was a lending institution that provided $63 million of our credit facility. Since Lehman Brothers declared bankruptcy, its affiliate, which is a party to our credit facility, has not met its obligations to lend under those agreements and our credit facility has effectively been reduced by its commitment. The commitments of the other banks remain unchanged, and the facility is not defaulted.

Our five-year credit facility is with a syndicate of financial institutions, and Wachovia Bank, National Association is the administrative agent. The 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.

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Our credit facility included the following restrictive covenants as of December 31, 2008:


•	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 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

On October 13, 2008, Standard & Poor’s Rating Services lowered our short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, we are currently unable to access commercial paper borrowings, and as of December 31, 2008, we had no commercial paper borrowings. However, we expect that our financing and liquidity needs will continue to be met through borrowings made under our bank credit facility described above.

As of December 31, 2007, we had $589.1 million of commercial paper outstanding with a weighted average interest rate of 5.58%. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during 2007.

Long-Term Debt

Our outstanding long-term debt, excluding the value of interest rate swaps, as of December 31, 2008 and 2007 was $8,274.9 million and $6,455.9 million, respectively. The balances consisted of the following (in millions):

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	December 31,

	2008			2007

Kinder Morgan Energy Partners, L.P. borrowings:
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			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			600.0
5.95% senior notes due February 15, 2018		975.0			—
9.00% senior notes due February 1, 2019		500.0			—
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			400.0
6.95% senior notes due January 15, 2038		1,175.0			550.0
Commercial paper borrowings		—			589.1
Bank credit facility borrowings		—			—
Subsidiary borrowings:
Central Florida Pipe Line LLC-7.840% senior notes due July 23, 2008		—			5.0
Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010		5.3			5.3
Kinder Morgan Louisiana Pipeline LLC-6.0% LA Development Revenue note due Jan. 1, 2011		5.0			—
Kinder Morgan Operating L.P. “A”-5.40% BP note, due March 31, 2012		19.4			23.6
Kinder Morgan Canada Company-5.40% BP note, due March 31, 2012		17.2			21.0
Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014		37.0			43.2
Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018		25.0			25.0
Kinder Morgan Columbus LLC-5.50% MS Development Revenue note due Sept. 1, 2022		8.2			—
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		1.3			1.4
Unamortized debt discount on senior notes		(18.5	)		(11.2	)
Current portion of long-term debt		(288.7	)		(610.2	)

Total Long-term debt	$	8,274.9		$	6,455.9

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 (i) $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; (ii) $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 (iii) $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.

During 2008, we also completed three separate public offerings of senior notes. With regard to the three offerings, we received proceeds, net of underwriting discounts and commissions, as follows (i) $894.1 million from a February 12, 2008 public offering of 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 (these notes constitute a further issuance of the $550 million aggregate principal amount of 6.95% notes we issued on June 21, 2007 and form a single series with those notes); (ii) $687.7 million from a June 6, 2008 public offering of a total of $700 million in principal amount of senior notes, consisting of $375 million of 5.95% notes due February 15, 2018 (these notes constitute a further issuance of the $600 million aggregate principal amount of 5.95% notes we issued on February 12, 2008 and form a single series with those notes), and $325 million of 6.95% notes due January 15, 2038 (these notes constitute a further issuance of the combined $850 million aggregate principal amount of 6.95% notes we issued on June 21, 2007 and February 12, 2008, and form a single series with those notes); and (iii) $498.4

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million from a December 19, 2008 public offering of $500 million in principal amount of 9.00% senior notes due February 1, 2019.

All of our fixed rate senior 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. In addition, the $500 million in principal amount of 9.00% senior notes issued in December 2008 may be repurchased at the noteholders’ option. Each holder of the notes has the right to require us to repurchase all or a portion of the notes owned by such holder on February 1, 2012 at a purchase price equal to 100% of the principal amount of the notes tendered by the holder plus accrued and unpaid interest to, but excluding, the repurchase date. On and after February 1, 2012, interest will cease to accrue on the notes tendered for repayment. A holder’s exercise of the repurchase option is irrevocable.

We used the proceeds from each of the three 2007 debt offerings and from the first two 2008 debt offerings to reduce the borrowings under our commercial paper program. We used the proceeds from our December 2008 debt offering to reduce the borrowings under our credit facility.

As of December 31, 2008 and 2007, our total liability balance due on the various series of our senior notes was $8,381.5 million and $6,288.8 million, respectively. For a listing of the various outstanding series of our senior notes, see the table above included in “—Long-Term Debt.”

Interest Rate Swaps

Information on our interest rate swaps is contained in Note 14.

Subsequent Event

On February 2, 2009, we paid $250 million to retire the principal amount of our 6.3% senior notes that matured on that date.

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 was 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 had a fixed annual interest rate of 7.84% with repayments in annual installments of $5 million beginning July 23, 2001. Central Florida Pipeline LLC paid the final $5.0 million outstanding principal amount on July 23, 2008.

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, 2008, the interest rate was 1.328%. 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.

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Kinder Morgan Operating L.P. “A” Debt

Effective January 1, 2007, we acquired the remaining approximately 50.2% interest in the Cochin pipeline system that we did not already own (see Note 3 “Acquisitions and Joint Ventures—Acquisitions from Unrelated Entities—Interest in Cochin Pipeline”). 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. We paid the first installment on March 31, 2008, and 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, 2008, the outstanding balance under the note was $36.6 million.

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, 2008, KMTP’s outstanding balance under the senior notes was $37.0 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, 2008, the interest rate was 0.52%. We have an outstanding letter of credit issued by Citibank in the amount of $25.4 million that backs-up the $25.0 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 46 days computed at 12% on a per annum basis on the principal thereof.

Kinder Morgan Operating L.P. “B” Debt

As of December 31, 2008, our subsidiary Kinder Morgan Operating L.P. “B” was the obligor of a principal amount of $23.7 million of tax-exempt bonds due April 1, 2024. The bonds were issued by the Jackson-Union Counties Regional Port District, a political subdivision embracing the territories of Jackson County and Union County in the state of Illinois. These variable rate demand bonds bear interest at a weekly floating market rate and are backed-up by a letter of credit issued by Wachovia.

The bond indenture also contains certain standby purchase agreement provisions which allow investors to put (sell) back their bonds at par plus accrued interest. In the fourth quarter of 2008 certain investors elected to sell back their bonds and we paid a total principal and interest amount of $5.2 million according to the letter of credit reimbursement provisions. However, the bonds were subsequently resold and as of December 31, 2008, we were fully reimbursed for our prior payments. As of December 31, 2008, the interest rate on these bonds was 3.04%. Our outstanding letter of credit issued by Wachovia totaled $18.0 million, which backs-up a principal amount of $17.7 million and $0.3 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

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million Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. As of December 31, 2008, the interest rate on these bonds was 2.20%.

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.

Gulf Opportunity Zone Bonds

To help fund our business growth in the states of Mississippi and Louisiana, we completed the purchase of a combined $13.2 million in principal amount of tax exempt revenue bonds in two separate transactions in December 2008. The bond offerings were issued under the Gulf Opportunity Zone Act of 2005 and consisted of the following: (i) $8.2 million in principal amount of 5.5% Development Revenue Bonds issued by the Mississippi Business Finance Corporation, a public, non-profit corporation that coordinates a variety of resources used to assist business and industry in the state of Mississippi; and (ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued by the Louisiana Community Development Authority, a political subdivision of the state of Louisiana.

The Mississippi revenue bonds mature on September 1, 2022, and both principal and interest is due in full at maturity. We hold an option to redeem in full (and settle the note payable to MBFC) the principal amount of bonds held by us without penalty after one year. The Louisiana revenue bonds have a maturity date of January 1, 2011 and provide for semi-annual interest payments each July 1 and January 1.

Maturities of Debt

The scheduled maturities of our outstanding debt, excluding value of interest rate swaps, as of December 31, 2008, are summarized as follows (in millions):


Year	Commitment

2009	$	288.7
2010		270.8
2011		721.2
2012		1,466.4
2013		506.5
Thereafter		5,310.0

Total	$	8,563.6

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 performance under such guarantee is remote. The following is a description of our contingent debt agreements as of December 31, 2008.

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.

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As of December 31, 2008, the debt facilities of Cortez Capital Corporation consisted of (i) $53.6 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, 2008, Cortez Capital Corporation had outstanding borrowings of $116.0 million under its five-year credit facility. The average interest rate on the Series D notes was 7.14%.

In October 2008, Standard & Poor’s Rating Services lowered Cortez Capital Corporation’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Cortez is unable to access commercial paper borrowings; however, it expects that its financing and liquidity needs will continue to be met through borrowings made under its long-term bank 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. As of December 31, 2008, JP Morgan Chase has issued a letter of credit on our behalf in the amount of $26.8 million to secure our indemnification obligations to Shell for 50% of the $53.6 million in principal amount of Series D notes outstanding as of December 31, 2008.

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.

In October 2008, pursuant to the standby purchase agreement provisions contained in the bond indenture—which require the sellers of those guarantees to buy the debt back—certain investors elected to put (sell) back their bonds at par plus accrued interest. A total principal and interest amount of $11.8 million was tendered and drawn against our letter of credit and accordingly, we paid this amount pursuant to the letter of credit reimbursement provisions. This payment reduced the face amount of our letter of credit from $22.5 million to $10.7 million. In December 2008, the bonds that were put back were re-sold, and we were fully reimbursed for our prior letter of credit payments. As of December 31, 2008, this letter of credit had a face amount of $10.2 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, 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 and/or its credit facility 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. The $600 million in principal amount of senior notes were issued on September 20, 2007. The notes are unsecured and are not redeemable prior to maturity. Interest on the notes is paid and computed quarterly at an interest rate of three-month LIBOR (with a floor of 4.25%) plus a spread of 0.85%. Upon maturity in August 2009, we expect that Rockies Express will repay these senior notes from equity contributions received from its member owners.

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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 maturity dates of August 20, 2009. On September 24, 2008, Rockies Express terminated one of the aforementioned interest rate swaps that had Lehman Brothers as the counterparty. The notional principal amount of the terminated swap agreement was $300 million. The remaining interest rate swap agreement effectively converts the interest expense associated with $300 million of these senior notes from its stated variable rate to a fixed rate of 5.47%.

In October 2008, Standard & Poor’s Rating Services lowered Rockies Express Pipeline LLC’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Rockies Express is unable to access commercial paper borrowings, and as of December 31, 2008, there were no borrowings under its commercial paper program. However, Rockies Express expects that its financing and liquidity needs will continue to be met through borrowings made under its long-term bank credit facility and contributions by its equity investors.

As of December 31, 2008, in addition to the $600 million in floating rate senior notes, Rockies Express had outstanding borrowings of $1,561.0 million under its five-year credit facility. Accordingly, as of December 31, 2008, our contingent share of Rockies Express’ debt was $1,102.1 million (51% of total guaranteed borrowings). In addition, there is a letter of credit outstanding to support the construction of the Rockies Express Pipeline. As of December 31, 2008, this letter of credit, issued by JPMorgan Chase, had a face amount of $31.4 million. Our contingent responsibility with regard to this outstanding letter of credit was $16.0 million (51% of total face amount).

One of the Lehman entities was a lending bank with an approximately $41 million commitment to the Rockies Express $2.0 billion credit facility. Since declaring bankruptcy, Lehman has not met its obligations to lend under the credit facility and our credit facility has effectively been reduced by its commitment. The commitments of the other banks remain unchanged and the facility is not defaulted.

Midcontinent Express Pipeline LLC Debt

Pursuant to certain guaranty agreements, each of the two member owners of Midcontinent Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Midcontinent Express Pipeline LLC, borrowings under Midcontinent’s $1.4 billion three-year, unsecured revolving credit facility, entered into on February 29, 2008 and due February 28, 2011. The facility is with a syndicate of financial institutions with The Royal Bank of Scotland plc as the administrative agent. Borrowings under the credit agreement will be used to finance the construction of the Midcontinent Express Pipeline system and to pay related expenses. One of the Lehman entities was a lending bank with an approximately $100 million commitment to the Midcontinent Express $1.4 billion credit facility and our credit facility has effectively been reduced by its commitment. Since declaring bankruptcy, Lehman has not met its obligations to lend under the credit facility. The commitments of the other banks remain unchanged and the facility is not defaulted.

Midcontinent Express Pipeline LLC is an equity method investee of ours, and the two member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan Operating L.P. “A” – 50%, and Energy Transfer Partners, L.P. – 50%. As of December 31, 2008, Midcontinent Express Pipeline LLC had $837.5 million borrowed under its three-year credit facility. Accordingly, as of December 31, 2008, our contingent share of Midcontinent Express’ debt was $418.8 million (50% of total borrowings). Furthermore, the revolving credit facility can be used for the issuance of letters of credit to support the construction of the Midcontinent Express Pipeline, and as of December 31, 2008, a letter of credit having a face amount of $33.3 million was issued under the credit facility. Accordingly, as of December 31, 2008, our contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).

In addition, on September 4, 2007, Midcontinent Express Pipeline LLC entered into a $197 million reimbursement agreement with JPMorgan Chase as the administrative agent. The agreement included covenants and required payments of fees that are common in such arrangements, and both we and Energy Transfer Partners, L.P. agreed to guarantee borrowings under the reimbursement agreement in the same proportion as the associated percentage ownership of Midcontinent Express’ member interests. This reimbursement agreement expired on September 3, 2008.

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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, 2008 and December 31, 2007 and is disclosed below (in millions).


	December 31, 2008				December 31, 2007

	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value

Total Debt	$	8,563.6	$	7,627.3	$	7,066.1	$	7,201.8

We adjusted the fair value measurement of our long-term debt as of December 31, 2008 in accordance with SFAS No. 157, and the estimated fair value of our debt as of December 31, 2008 (presented in the table above) includes a decrease of $261.1 million related to discounting the fair value measurement for the effect of credit risk.

10. Pensions and Other Post-Retirement Benefits

Pension and Post-Retirement Benefit Plans

Due to our acquisition of the Trans Mountain pipeline system (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 2008 and 2007 were approximately $3.5 million and $3.2 million, respectively, recognized ratably over each year. As of December 31, 2008, we estimate our overall net periodic pension and post-retirement benefit costs for these plans for the year 2009 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 $7.7 million to these benefit plans in 2009.

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 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 was a credit of less than $0.1 million in 2008, a credit of $0.2 million in 2007, and a credit of $0.3 million in 2006. The credits in all three years resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost. As of December 31, 2008, we estimate our overall net periodic post-retirement benefit cost for the SFPP post-retirement benefit plan for the year 2009 will be a credit of approximately $0.1 million; however, this estimate could change if a future significant event would require a remeasurement of liabilities. In addition, we expect to contribute approximately $0.3 million to this post-retirement benefit plan in 2009.

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

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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. We adopted SFAS No. 158 on December 31, 2006, and pursuant to the provisions of this Statement, we report amounts that have not yet been recognized as a component of benefit expense as part of the net benefit liability on our balance sheet (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.

As of December 31, 2008 and 2007, the recorded value of our pension and post-retirement benefit obligations for these plans was a combined $33.4 million and $37.5 million, respectively. 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 $7.8 million for the year ended December 31, 2008, $6.7 million for the year ended December 31, 2007, and $6.3 million for the year ended December 31, 2006.

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 compensation, on a pre-tax basis, into participant accounts. In addition to a 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 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 $13.3 million during 2008, $11.7 million during 2007, and $10.2 million during 2006.

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 third anniversary of the date of hire.

At its July 2008 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 2008 and continuing through the last pay period of July 2009. 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 2009, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2008.

Additionally, participants have an option to make after-tax “Roth” contributions (Roth 401(k) option) to a separate participant account. 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

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fifth year of participation in the Roth 401(k) option, and (ii) attainment of age 59 1/2, 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 credit each participating employee’s personal retirement account an amount 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 three years, and they may take a lump sum distribution upon termination of employment or retirement.

11. Partners’ Capital

Limited Partner Units

As of December 31, 2008 and 2007, our partners’ capital consisted of the following limited partner units:


	December 31, 2008		December 31, 2007

Common units		182,969,427		170,220,396
Class B units		5,313,400		5,313,400
i-units		77,997,906		72,432,482

Total limited partner units		266,280,733		247,966,278

The total limited partner units represent our limited partners’ interest and an effective 98% 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, 2008, our common unit total consisted of 166,598,999 units held by third parties, 14,646,428 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, 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.

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, 2008 and December 31, 2007, all of our i-units were held 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.

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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 1,646,891 i-units on November 14, 2008. These additional i-units distributed were based on the $1.02 per unit distributed to our common unitholders on that date. During the year ended December 31, 2008, KMR received distributions of 5,565,424 i-units. These additional i-units distributed were based on the $3.89 per unit distributed to our common unitholders during 2008. During 2007, KMR received distributions of 4,430,806 i-units, based on the $3.39 per unit distributed to our common unitholders during 2007.

Equity Issuances

2007 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 these 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 $49.34 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 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.

2008 Issuances

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.

On March 3, 2008, we issued, in a public offering, 5,000,000 of our common units at a price of $57.70 per unit, less commissions and underwriting expenses. At the time of the offering, we granted the underwriters a 30-day option to purchase up to an additional 750,000 common units from us on the same terms and conditions, and pursuant to this option, we issued an additional 750,000 common units on March 10, 2008 upon exercise of this option. After commissions and underwriting expenses, we received net proceeds of $324.2 million for the issuance of these 5,750,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

In connection with our August 28, 2008 acquisition of Knight’s 33 1/3% ownership interest in the Express pipeline system and Knight’s full ownership of the Jet Fuel pipeline system, we issued 2,014,693 of our common units to Knight. The units were issued August 28, 2008, and as agreed between Knight and us, were valued at $116.0 million. For more information on this acquisition, see Note 3 “Acquisitions and Joint Ventures—Acquisitions from Knight—Express and Jet Fuel Pipeline Systems.”

In addition, on December 22, 2008, we issued, in a public offering, 3,900,000 of our common units at a price of $46.75 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $176.6 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our bank credit facility.

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containing certain information with respect to this public offering of our common units. We also filed a prospectus supplement with respect to this common unit offering on December 17, 2008. These Current Reports may have constituted prospectuses not meeting the requirements of the Securities Act due to the legends used in the Current Reports. Accordingly, under certain circumstances, purchasers of the common units from us in the offering might have the right to require us to repurchase the common units they purchased, or if they have sold those common units, to pay damages. Consequently, we could have a potential liability arising out of these possible violations of the Securities Act. The magnitude of any potential liability is presently impossible to quantify, and would depend upon whether it is demonstrated we violated the Securities Act, the number of common units that purchasers in the offering sought to require us to repurchase and the trading price of our common units.

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, 2008, 2007 and 2006, we declared distributions of $4.02, $3.48 and $3.26 per unit, respectively. Under the terms of our partnership agreement, our total distributions to unitholders for 2008, 2007 and 2006 required incentive distributions to our general partner in the amount of $800.8 million, $611.9 million and $528.4 million, respectively. The increased incentive distributions paid for 2008 over 2007, and 2007 over 2006 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 2008 Incentive Distribution

On January 21, 2009, we declared a cash distribution of $1.05 per unit for the quarterly period ended December 31, 2008. This distribution was paid on February 13, 2009, to unitholders of record as of January 31, 2009. 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 $1.05 distribution per common unit. The number of i-units distributed was 1,917,189. For each outstanding i-unit that KMR held, a fraction of an i-unit (0.024580) was issued. The fraction was determined by dividing:


	• $1.05, the cash amount distributed per common unit

by

	• $42.717, the average of KMR’s limited liability shares’ closing market prices from January 13-27, 2009, 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 13, 2009 distribution included an incentive distribution to our general partner in the amount of $216.6 million. Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2008 balance sheet as a distribution payable.

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. Because we did not meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan; however,

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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 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.

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 certain of our assets (discussed below in “Operations”). These employees’ expenses are allocated without a profit component between Knight on the one hand, and the appropriate members of the Group, on the other hand.

Additionally, due to certain going-private transaction expenses allocated to us from Knight, we recognized a total of $5.6 million in non-cash compensation expense in 2008. For accounting purposes, Knight is required to allocate to us a portion of these transaction-related amounts and we are required to recognize the amounts as expense on our income statements; however, we were not responsible for paying these buyout expenses, and accordingly, we recognize the unpaid amount as both a contribution to “Partners’ Capital“ and an increase to “Minority interest” on our balance sheet.

Furthermore, 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.

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:

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	• 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.

In addition, as of December 31, 2008, our general partner owned 1,724,000 common units, representing approximately 0.65% of our outstanding limited partner units.

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 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

	• 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.”

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Knight Inc.

Knight Inc. remains the sole indirect stockholder of our general partner. Also, as of December 31, 2008, Knight directly owned 10,852,788 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 11,128,826 KMR shares, representing an indirect ownership interest of 11,128,826 i-units. Together, these units represented approximately 12.3% of our outstanding limited partner units. Including both its general and limited partner interests in us, at the 2008 distribution level, Knight received approximately 51% of all quarterly distributions from us, of which approximately 44% was attributable to its general partner interest and the remaining 7% 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, 2008, KMR, our general partner’s delegate, remained the sole owner of our 77,997,906 i-units.

Asset Acquisitions and Sales

In March 2008, our subsidiary Kinder Morgan CO₂ Company, L.P. sold certain pipeline meter equipment to Cortez Pipeline Company, its 50% equity investee, for its current fair value of $5.7 million. The meter equipment is still being employed in conjunction with our CO₂ business segment.

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 and Products Pipelines Business Segments

On February 15, 2008, Knight sold an 80% ownership interest in NGPL PipeCo LLC, which owns Natural Gas Pipeline Company of America LLC and certain affiliates (collectively referred to in this report as NGPL) to Myria Acquisition Inc. for approximately $5.9 billion. Myria is comprised of a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group. Knight accounts for its remaining 20% ownership interest in NGPL under the equity method of accounting and, pursuant to the provisions of a 15-year operating agreement, continues to operate NGPL’s assets.

Knight (or its subsidiaries) and NGPL operate and maintain for us the assets comprising our Natural Gas Pipelines business segment. NGPL 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 “Divestitures—North System Natural Gas Liquids Pipeline System – Discontinued Operations”), 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 combined amounts paid to Knight and NGPL for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company

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LLC, were $45.0 million of actual costs incurred for 2008 (and no fixed costs), $1.0 million of fixed costs and $48.1 million of actual costs incurred for 2007, and $1.0 million of fixed costs and $37.9 million of actual costs incurred for 2006.

We believe the amounts paid to Knight and NGPL 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 both Knight and NGPL in performing such services. We also reimburse both Knight and NGPL for operating and maintenance costs and capital expenditures incurred with respect to our assets.

In addition, we purchase natural gas transportation and storage services from NGPL. For each of the years 2008, 2007 and 2006, these expenses totaled $8.1 million, $6.8 million and $3.6 million, respectively, and we included these expense amounts within the caption “Gas purchases and other costs of sales” in our accompanying consolidated statements of income.

CO₂ Business Segment

Knight or its subsidiaries also 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 nearly 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.

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 2008, 2007 and 2006 for operating and maintaining the power plant were $3.1 million, $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.

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 17 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 May 2007 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

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Knight, two of those investors became “related parties” to us (as that term is defined in authoritative accounting literature): (i) American International Group, Inc., referred to in this report as AIG, 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 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 our energy commodity derivative contracts that are (i) associated with commodity price risk management activities with related parties; and (ii) included on our accompanying consolidated balance sheets as of December 31, 2008 and December 31, 2007 (in millions):


	December 31, 2008			December 31, 2007

Derivatives- asset/(liability)
Other current assets	$	60.4		$	—
Deferred charges and other assets		20.1			—
Accrued other current liabilities		(13.2	)		(239.8	)
Other long-term liabilities and deferred credits	$	(24.1	)	$	(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 $7.6 million in 2008, $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 $88.5 million as of December 31, 2008, and $89.7 million as of December 31, 2007. Of these amounts, $3.7 million and $2.4 million were included within “Accounts, notes and interest receivable, net—Related parties,” as of December 31, 2008 and December 31, 2007, respectively, and the remainder was included within “Notes receivable—Related parties” at each reporting date.

Express US Holdings LP

In conjunction with the acquisition of our 33 1/3% equity ownership interest in the Express pipeline system (discussed in Note 3 “Acquisitions and Joint Ventures—Acquisitions from Knight—Express and Jet Fuel Pipeline Systems”) from Knight on August 28, 2008, we acquired a long-term investment in a debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system. As of our acquisition date, the value of this unsecured debenture was equal to Knight’s carrying value of $107.0 million. The note is denominated in Canadian dollars, and the principal amount of the note is $113.6 million Canadian dollars, due in full on January 9, 2023. It bears interest at the rate of 12.0% per annum and

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provides for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year.

As of December 31, 2008, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $93.3 million, and we included this amount within “Notes receivable—Related parties” on our accompanying consolidated balance sheet.

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. The note had no fixed terms of repayment and was denominated in Canadian dollars. In each of the second and third quarters of 2008, we received payments of $0.3 million in principal amount under this note, and as of December 31, 2008, there was no outstanding balance due under this note. The above amounts represent translated amounts 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 Red Cedar Gathering on September 1, 2006 (described below), 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.

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, 2008 and 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

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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.

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, 2008			December 31, 2007

Leasehold improvements	$	2.2		$	2.2
Less: Accumulated amortization		(0.4	)		(0.3	)

Total	$	1.8		$	1.9

Future commitments under capital lease obligations as of December 31, 2008 are as follows (in millions):


Year	Commitment

2009	$	0.2
2010		0.2
2011		0.2
2012		0.2
2013		0.2
Thereafter		0.5

Subtotal		1.5
Less: Amount representing interest		(0.5	)

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, 2008 are as follows (in millions):


Year	Commitment

2009	$	31.1
2010		27.7
2011		22.1
2012		17.9
2013		13.8
Thereafter		34.9

Total minimum payments	$	147.5

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We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $1.1 million. Total lease and rental expenses were $61.7 million for 2008, $49.2 million for 2007 and $54.2 million for 2006.

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 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.

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 (discussed following).

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. During 2008, 10,000 unit appreciation rights were exercised by one director at an aggregate fair value of $60.32 per unit. As of December 31, 2008, 35,000 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 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 elections under this plan for 2006, 2007, and 2008 were made effective January 17, 2006, January 17, 2007 and January 16, 2008, respectively. The election for 2009 by Messrs. Hultquist and Waughtal were made effective January 21, 2009, and the election for 2009 by Mr. Lawrence was made effective January 28, 2009. 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

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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 17, 2006, each of KMR’s then 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.

On January 17, 2007, each of KMR’s then 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 then 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) was paid to each of the non-employee directors as described above, and no other compensation was paid to the non-employee directors during 2008.

On January 21, 2009, each of KMR’s three non-employee directors (with Mr. Lawrence replacing Mr. Gaylord after Mr. Gaylord’s death) was awarded cash compensation of $160,000 for board service during 2009. Effective January 21, 2009, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only. Effective January 28, 2009, Mr. Lawrence elected to receive compensation of $159,136.00 in the

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form of our common units and was issued 3,200 common units. His remaining compensation ($864.00) will be paid in cash as described above. No other compensation will be paid to the non-employee directors during 2009.


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, 2008, our principal use of energy commodity derivative contracts was to mitigate the risk associated with unfavorable 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.

Discontinuance of Hedge Accounting

Effective at the beginning of the second quarter of 2008, we determined that the derivative contracts of our Casper and Douglas natural gas processing operations that previously had been designated as cash flow hedges for accounting purposes no longer met the hedge effectiveness assessment as required by SFAS No. 133. Consequently, we discontinued hedge accounting treatment for these relationships (primarily crude oil hedges of heavy natural gas liquids sales) effective as of March 31, 2008. Since the forecasted sales of natural gas liquids volumes (the hedged item) are still expected to occur, all of the accumulated losses through March 31, 2008 on the related derivative contracts remained in accumulated other comprehensive income, and will not be reclassified into earnings until the physical transactions occurs. Any changes in the value of these derivative contracts subsequent to March 31, 2008 will no longer be deferred in other comprehensive income, but rather will impact current period income. As a result, we recognized an increase in income of $5.6 million in 2008 related to the increase in value of derivative contracts outstanding as of December 31, 2008 for which hedge accounting had been discontinued.

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 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 $2.4 million during 2008, a loss of $0.1 million during 2007 and a loss of $1.3 million during 2006, 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

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2008, 2007 and 2006, we did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness.

Furthermore, during the years 2008, 2007 and 2006, we reclassified $663.7 million, $433.2 million and $428.1 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 “Divestitures—Douglas Gas Gathering and Painter Gas Fractionation”), none of the reclassification of “Accumulated other comprehensive loss” into earnings during 2008, 2007 or 2006 resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred). The proceeds or payments resulting from the settlement of cash flow hedges are reflected in the operating section of our statement of cash flows as changes to net income and working capital.

Our consolidated “Accumulated other comprehensive loss” balance was $287.7 million as of December 31, 2008 and $1,276.6 million as of December 31, 2007. These consolidated totals included “Accumulated other comprehensive loss” amounts associated with the commodity price risk management activities of $63.2 million as of December 31, 2008 and $1,377.2 million as of December 31, 2007. Approximately $20.4 million of the total amount associated with our commodity price risk management activities as of December 31, 2008 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

Derivative contracts that are entered into for the purpose of mitigating commodity price risk include swaps, futures and options. Additionally, basis swaps may also be used in connection with another derivative contract to reduce hedge ineffectiveness by reducing a basis difference between a hedged exposure and a derivative contract. The fair values of these derivative contracts are included in our accompanying consolidated balance sheets within “Other current assets,” “Deferred charges and other assets,” “Accrued other current liabilities,” and “Other long-term liabilities and deferred credits.”

The following table summarizes the fair values of our energy commodity derivative contracts associated with our commodity price risk management activities and included on our accompanying consolidated balance sheets as of December 31, 2008 and December 31, 2007 (in millions):


	December 31, 2008			December 31, 2007

Derivatives-net asset/(liability)
Other current assets	$	115.3		$	37.0
Deferred charges and other assets		48.9			4.4
Accrued other current liabilities		(129.5	)		(593.9	)
Other long-term liabilities and deferred credits	$	(92.2	)	$	(836.8	)

As of December 31, 2008, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through April 2013. Additional information on the fair value measurements of our energy commodity derivative contracts is included below in “—SFAS No. 157.”

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.

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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 variable 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, 2007, we were a party to interest rate swap agreements with a total notional principal amount of $2.3 billion. On February 12, 2008, following our issuance of $600 million of 5.95% senior notes on that date, we entered into two additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million. On June 6, 2008, following our issuance of $700 million in principal amount of senior notes in two separate series on that date, we entered into two additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $700 million. Then, in December 2008, we took advantage of the market conditions by terminating two of our existing fixed-to-variable swap agreements. In separate transactions, we terminated fixed-to-variable interest rate swap agreements having (i) a notional principal amount of $375 million and a maturity date of February 15, 2018; and (ii) a notional principal amount of $325 million and a maturity date of January 15, 2038. We received combined proceeds of $194.3 million from the early termination of these swap agreements.

Therefore, as of December 31, 2008, we had a combined notional principal amount of $2.8 billion of fixed-to-variable 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. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2008, 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.

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 differences between the fair value and the original carrying value associated with our interest rate swap agreements, that is, the derivative contracts’ changes in fair value, are included within “Deferred charges and other assets” and “Other long-term liabilities and deferred credits” in our accompanying consolidated balance sheets. The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Value of interest rate swaps” on our accompanying consolidated balance sheets, which also includes any unamortized portion of proceeds received from the early termination of interest rate swap agreements.

Our settlement amounts continue to be accounted for in connection with the original anticipated interest payments that the swap was established to offset (since they are still expected to occur as designated), and accordingly, we amortize this deferred gain or loss (as a reduction or increase to periodic interest expense) over the remaining term of the original swap periods. To date, all the swaps we have terminated have resulted in deferred gains. As of December 31, 2008, unamortized premiums received from early swap terminations totaled $204.2 million. In addition to the two swap agreements we terminated in December 2008, discussed above, in March 2007 we terminated an existing fixed-to-variable 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 as of December 31, 2007, this unamortized premium totaled $14.2 million.

The following table summarizes the net fair value of our interest rate swap agreements associated with our interest rate risk management activities and included on our accompanying consolidated balance sheets as of December 31, 2008 and December 31, 2007 (in millions):

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	December 31, 2008			December 31, 2007

Derivatives-net asset/(liability)
Deferred charges and other assets		$	747.1		$	138.0
Other long-term liabilities and deferred credits			—			—

Net fair value of interest rate swaps		$	747.1		$	138.0

Additional information on the fair value measurements of our interest rate swap agreements is included below in “—SFAS No. 157.”

Subsequent Event

In January 2009 we terminated an existing fixed-to-variable swap agreement having a notional principal amount of $300 million and a maturity date of March 15, 2031. We received proceeds of $144.4 million from the early termination of this swap agreement.

SFAS No. 157

On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” In general, fair value measurements and disclosures are made in accordance with the provisions of this Statement and, while not requiring material new fair value measurements, SFAS No. 157 established a single definition of fair value in generally accepted accounting principles and expanded disclosures about fair value measurements. The provisions of this Statement apply to other accounting pronouncements that require or permit fair value measurements; the Financial Accounting Standards Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute.

On February 12, 2008, the FASB issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157,” referred to as FAS 157-2 in this report. FAS 157-2 delayed 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).

Accordingly, we adopted SFAS No. 157 for financial assets and financial liabilities effective January 1, 2008. The adoption did not have a material impact on our balance sheet, statement of income, or statement of cash flows since we already apply its basic concepts in measuring fair values. We adopted SFAS No. 157 for non-financial assets and non-financial liabilities effective January 1, 2009. This includes applying the provisions of SFAS No. 157 to (i) nonfinancial assets and liabilities initially measured at fair value in business combinations; (ii) reporting units or nonfinancial assets and liabilities measured at fair value in conjunction with goodwill impairment testing; (iii) other nonfinancial assets measured at fair value in conjunction with impairment assessments; and (iv) asset retirement obligations initially measured at fair value. The adoption did not have a material impact on our balance sheet, statement of income, or statement of cash flows since we already apply its basic concepts in measuring fair values.

On October 10, 2008, the FASB issued FASB Staff Position FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” referred to as FAS 157-3 in this report. FAS 157-3 provides clarification regarding the application of SFAS 157 in inactive markets. The provisions of FAS 157-3 were effective upon issuance. This Staff Position did not have any material effect on our consolidated financial statements.

The degree of judgment utilized in measuring the fair value of financial instruments generally correlates to the level of pricing observability. Pricing observability is affected by a number of factors, including the type of financial instrument, whether the financial instrument is new to the market, and the characteristics specific to the transaction. Financial instruments with readily available active quoted prices or for which fair value can be measured from actively quoted prices generally will have a higher degree of pricing observability and a lesser degree of judgment utilized in measuring fair value. Conversely, financial instruments rarely traded or not quoted will generally have less (or no) pricing observability and a higher degree of judgment utilized in measuring fair value.

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SFAS No. 157 established a hierarchal disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defined three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the SFAS No. 157 hierarchy are as follows:


	• Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

	• Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

	• Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

Derivative contracts can be exchange-traded or over-the-counter, referred to in this report as OTC. Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical securities.

OTC derivative contracts are valued using models utilizing a variety of inputs including contractual terms; commodity, interest rate and foreign currency curves; and measures of volatility. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information, and the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivative contracts are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. Our fair value measurements of derivative contracts are adjusted for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, our consolidated “Accumulated other comprehensive loss” balance includes a gain of $2.2 million related to discounting the value of our energy commodity derivative liabilities for the effect of credit risk. We also adjusted the fair value measurements of our interest rate swap agreements for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, our consolidated “Value of interest rate swaps” balance included a decrease (loss) of $10.6 million related to discounting the fair value measurement of our interest rate swap agreements’ asset value for the effect of credit risk.

The following tables summarize the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of December 31, 2008, based on the three levels established by SFAS No. 157, and does not include cash margin deposits, which are reported as “Restricted deposits” in our accompanying consolidated balance sheets (in millions):

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	Asset Fair Value Measurements as of December 31, 2008 Using
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)


Energy commodity derivative contracts(a)	$	164.2			$	0.1		$	108.9			$	55.2

Interest rate swap agreements		747.1				—			747.1				—



	Liability Fair Value Measurements as of December 31, 2008 Using
	Total			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)


Energy commodity derivative contracts(b)	$	(221.7	)		$	—		$	(210.6	)		$	(11.1	)

Interest rate swap agreements		—				—			—				—




	(a)	Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX. Level 3 consists primarily of West Texas Intermediate options and West Texas Sour hedges.

	(b)	Level 2 consists primarily of OTC West Texas Intermediate hedges. Level 3 consists primarily of natural gas basis swaps, natural gas options and West Texas Intermediate options.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for the year ended December 31, 2008 (in millions):


Significant Unobservable Inputs (Level 3)

	Year Ended December 31, 2008

Derivatives-net asset/(liability)
Beginning of Period		$	(100.3	)
Realized and unrealized net losses			69.6
Purchases and settlements			74.8
Transfers in (out) of Level 3			—

End of Period		$	44.1


Change in unrealized net losses relating to contracts still held as of December 31, 2008		$	88.8

Credit Risks

We have counterparty credit risk as a result of our use of energy commodity derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings); (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

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

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In addition, in conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2008 and December 31, 2007, we had outstanding letters of credit totaling $40.0 million and $298.0 million, respectively, in support of our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil. Additionally, as of December 31, 2008, our counterparties associated with our energy commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $3.1 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet. 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.

We are also exposed to credit related losses in the event of nonperformance by counterparties to our interest rate swap agreements. As of December 31, 2008, all of our interest rate swap agreements were with counterparties with investment grade credit ratings, and the $747.1 million total value of our interest rate swap derivative assets at December 31, 2008 (disclosed above) included amounts of $301.8 million and $249.0 million related to open positions with Citigroup and Merrill Lynch, respectively.

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

	• Kinder Morgan Canada

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 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. We identified our Trans Mountain pipeline system as a separate reportable business segment prior to the third quarter of 2008. Following the acquisition of our interests in the Express and Jet Fuel pipeline systems on August 28, 2008, discussed in Note 3, we combined the operations of our Trans Mountain, Express and Jet Fuel pipeline systems to represent the “Kinder Morgan Canada” segment.

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

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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 Kinder Morgan Canada business segment derives its revenues primarily from the transportation of crude oil and refined products.

As discussed in Note 3, due to the October 2007 sale of our North System, an approximately 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):


	2008			2007			2006

Revenues
Products Pipelines
Revenues from external customers	$	815.9		$	844.4		$	776.3
Intersegment revenues		—			—			—
Natural Gas Pipelines
Revenues from external customers		8,422.0			6,466.5			6,577.7
Intersegment revenues		—			—			—
CO₂
Revenues from external customers		1,133.0			824.1			736.5
Intersegment revenues		—			—			—
Terminals
Revenues from external customers		1,172.7			963.0			864.1
Intersegment revenues		0.9			0.7			0.7
Kinder Morgan Canada
Revenues from external customers		196.7			160.8			137.8
Intersegment revenues		—			—			—

Total segment revenues		11,741.2			9,259.5			9,093.1
Less: Total intersegment revenues		(0.9	)		(0.7	)		(0.7	)

		11,740.3			9,258.8			9,092.4
Less: Discontinued operations		—			(41.1	)		(43.7	)

Total consolidated revenues	$	11,740.3		$	9,217.7		$	9,048.7


Operating expenses(a)
Products Pipelines	$	291.0		$	451.8		$	308.3
Natural Gas Pipelines		7,804.0			5,882.9			6,057.8
CO₂		391.8			304.2			268.1
Terminals		631.8			536.4			461.9
Kinder Morgan Canada		67.9			65.9			53.3

Total segment operating expenses		9,186.5			7,241.2			7,149.4
Less: Total intersegment operating expenses		(0.9	)		(0.7	)		(0.7	)

		9,185.6			7,240.5			7,148.7
Less: Discontinued operations		—			(14.8	)		(22.7	)

Total consolidated operating expenses	$	9,185.6		$	7,225.7		$	7,126.0


Other expense (income)
Products Pipelines	$	1.3		$	(154.8	)	$	—
Natural Gas Pipelines		(2.7	)		(3.2	)		(15.1	)
CO₂		—			—			—
Terminals		2.7			(6.3	)		(15.2	)
Kinder Morgan Canada(b)		—			377.1			(0.9	)

Total segment Other expense (income)		1.3			212.8			(31.2	)
Less: Discontinued operations		1.3			152.8			—

Total consolidated Other expense (income)	$	2.6		$	365.6		$	(31.2	)

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	2008			2007			2006

Depreciation, depletion and amortization
Products Pipelines	$	89.4		$	89.2		$	82.9
Natural Gas Pipelines		68.5			64.8			65.4
CO₂		385.8			282.2			190.9
Terminals		122.6			89.3			74.6
Kinder Morgan Canada		36.4			21.5			19.0

Total segment depreciation, depletion and amortiz		702.7			547.0			432.8
Less: Discontinued operations		—			(7.0	)		(8.9	)

Total consol. depreciation, depletion and amortiz	$	702.7		$	540.0		$	423.9


Earnings from equity investments
Products Pipelines	$	24.4		$	32.5		$	16.3
Natural Gas Pipelines		113.4			19.2			40.5
CO₂		20.7			19.2			19.2
Terminals		2.7			0.6			0.2
Kinder Morgan Canada		(0.4	)		—			—

Total segment earnings from equity investments		160.8			71.5			76.2
Less: Discontinued operations		—			(1.8	)		(2.2	)

Total consolidated equity earnings	$	160.8		$	69.7		$	74.0


Amortization of excess cost of equity investments
Products Pipelines	$	3.3		$	3.4		$	3.4
Natural Gas Pipelines		0.4			0.4			0.3
CO₂		2.0			2.0			2.0
Terminals		—			—			—
Kinder Morgan Canada		—			—			—

Total segment amortization of excess cost of invests		5.7			5.8			5.7
Less: Discontinued operations		—			—			(0.1	)

Total consol. amortization of excess cost of invests	$	5.7		$	5.8		$	5.6


Interest income
Products Pipelines	$	4.3		$	4.4		$	4.5
Natural Gas Pipelines		1.2			—			0.1
CO₂		—			—			—
Terminals		—			—			—
Kinder Morgan Canada		3.9			—			—

Total segment interest income		9.4			4.4			4.6
Unallocated interest income		0.6			1.3			3.1

Total consolidated interest income	$	10.0		$	5.7		$	7.7


Other, net-income (expense)
Products Pipelines	$	(2.3	)	$	5.0		$	7.6
Natural Gas Pipelines		28.0			0.2			0.6
CO₂		1.9			—			0.8
Terminals		1.7			1.0			2.1
Kinder Morgan Canada		(10.1	)		8.0			1.0

Total segment other, net-income (expense)		19.2			14.2			12.1
Less: Discontinued operations		—			—			(0.1	)

Total consolidated other, net-income (expense)	$	19.2		$	14.2		$	12.0

Income tax benefit (expense)
Products Pipelines	$	(3.8	)	$	(19.7	)	$	(5.2	)
Natural Gas Pipelines		(2.7	)		(6.0	)		(1.4	)
CO₂		(3.9	)		(2.1	)		(0.2	)
Terminals		(19.7	)		(19.2	)		(12.3	)
Kinder Morgan Canada		19.0			(19.4	)		(9.9	)

Total segment income tax benefit (expense)		(11.1	)		(66.4	)		(29.0	)
Unallocated income tax benefit (expense)		(9.3	)		(4.6	)		—

Total consolidated income tax benefit (expense)	$	(20.4	)	$	(71.0	)	$	(29.0	)

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	2008			2007			2006

Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(c)
Products Pipelines	$	546.2		$	569.6		$	491.2
Natural Gas Pipelines		760.6			600.2			574.8
CO₂		759.9			537.0			488.2
Terminals		523.8			416.0			408.1
Kinder Morgan Canada		141.2			(293.6	)		76.5

Total segment earnings before DD&A		2,731.7			1,829.2			2,038.8
Total segment depreciation, depletion and amortiz		(702.7	)		(547.0	)		(432.8	)
Total segment amortization of excess cost of invests		(5.7	)		(5.8	)		(5.7	)
General and administrative expenses		(297.9	)		(278.7	)		(238.4	)
Interest and other non-operating expenses(d)		(420.6	)		(407.4	)		(357.8	)

Total consolidated net income	$	1,304.8		$	590.3		$	1,004.1


Capital expenditures(e)
Products Pipelines	$	221.7		$	259.4		$	196.0
Natural Gas Pipelines		946.5			264.0			271.6
CO₂		542.6			382.5			283.0
Terminals		454.1			480.0			307.7
Kinder Morgan Canada		368.1			305.7			123.8

Total consolidated capital expenditures	$	2,533.0		$	1,691.6		$	1,182.1


Investments at December 31
Products Pipelines	$	202.6		$	202.3		$	211.1
Natural Gas Pipelines		654.0			427.5			197.9
CO₂		13.6			14.2			16.1
Terminals		18.6			10.6			0.5
Kinder Morgan Canada		65.5			0.8			0.7

Total consolidated investments	$	954.3		$	655.4		$	426.3


Assets at December 31
Products Pipelines	$	4,183.0		$	4,045.0		$	3,910.5
Natural Gas Pipelines		5,535.9			4,347.3			3,946.6
CO₂		2,339.9			2,004.5			1,870.8
Terminals		3,347.6			3,036.4			2,397.5
Kinder Morgan Canada		1,583.9			1,440.8			1,314.0

Total segment assets		16,990.3			14,874.0			13,439.4
Corporate assets(f)		895.5			303.8			102.8

Total consolidated assets	$	17,885.8		$	15,177.8		$	13,542.2




(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, and other expense (income).

(d)	Includes unallocated interest income and income tax expense, interest and debt expense, and minority interest expense.

(e)	Sustaining capital expenditures, including our share of Rockies Express’ sustaining capital expenditures, totaled $180.6 million in 2008, $152.6 million in 2007 and $125.5 million in 2006. These listed amounts do not include sustaining capital expenditures for the Trans Mountain Pipeline (part of Kinder Morgan Canada) for periods prior to our acquisition date of April 30, 2007. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.

(f)	Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and 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, 2008, 2007 and 2006, we reported (in millions) total consolidated interest expense of $398.2 million, $397.1 million and $345.5 million, respectively.

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Our total operating revenues are derived from a wide customer base. For each of the three years ended December 31, 2008, 2007 and 2006, 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):


	2008		2007		2006

Revenues from external customers
United States	$	11,452.0	$	8,986.3	$	8,889.9
Canada		267.0		211.9		139.3
Mexico and other(a)		21.3		19.5		19.5

Total consol. revenues from external customers	$	11,740.3	$	9,217.7	$	9,048.7


Long-lived assets at December 31(b)
United States	$	13,563.2	$	11,054.3	$	9,917.2
Canada		1,547.6		1,420.0		766.4
Mexico and other(a)		87.8		89.5		91.4

Total consolidated long-lived assets	$	15,198.6	$	12,563.8	$	10,775.0


(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.

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 2008. This note also contains a description of any material legal proceeding initiated during 2008 in which we are involved.

Federal Energy Regulatory Commission Proceedings

•

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; FERC Docket No. OR92-8-025—Complainants/Protestants: BP WCP; ExxonMobil; Chevron; ConocoPhillips; and Ultramar—Defendant: SFPP—Subject: Complaints against East Line and West Line rates and Watson Station Drain-Dry Charge

•	FERC Docket No. OR96-2, et al.—Complainants/Protestants: All Shippers except Chevron (which is an intervenor)—Defendant: SFPP—Subject: Complaints against all SFPP rates

•

FERC Docket Nos. OR02-4 and OR03-5—Complainant/Protestant: Chevron—Defendant: SFPP; FERC Docket No. OR04-3—Complainants/Protestants: America West Airlines, Southwest Airlines, Northwest Airlines, and Continental Airlines—Defendant: SFPP; FERC Docket Nos. OR03-5, OR05-4 and OR05-5—Complainants/Protestants: BP WCP, ExxonMobil, and ConocoPhillips (other shippers intervened)—Defendant: SFPP—Subject: Complaints against all SFPP rates; OR02-4 was dismissed and Chevron appeal pending at U.S. Court of Appeals for D.C. Circuit (“D.C. Circuit”)

•	FERC Docket Nos. OR07-1 & OR07-2—Complainant/Protestant: Tesoro—Defendant: SFPP—Subject: Complaints against North Line and West Line rates; held in abeyance

•	FERC Docket Nos. OR07-3 & OR07-6—Complainants/Protestants: BP WCP, Chevron, ConocoPhillips; ExxonMobil, Tesoro, and Valero Marketing—Defendant: SFPP—Subject: Complaints against 2005 and 2006 indexed rate increases; dismissed by FERC; appeal pending at D.C. Circuit

•	FERC Docket No. OR07-4—Complainants/Protestants: BP WCP, Chevron, and ExxonMobil—Defendants: SFPP, Kinder Morgan G.P., Inc., and Knight Inc.—Subject: Complaints against all SFPP rates; held in abeyance; complaint withdrawn as to SFPP’s affiliates

•	FERC Docket Nos. OR07-5 and OR07-7 (consolidated) and IS06-296—Complainants/Protestants: ExxonMobil and Tesoro—Defendants: Calnev, Kinder Morgan G.P., Inc., and Knight Inc —Subject: Complaints and protest against Calnev rates; OR07-5 and IS06-296 were settled in 2008

•	FERC Docket Nos. OR07-8 and OR07-11 (consolidated)—Complainants/Protestants: BP WCP and ExxonMobil —Defendant: SFPP—Subject: Complaints against SFPP 2005 index rates; settled in 2008

•	FERC Docket No. OR07-9—Complainant/Protestant: BP WCP—Defendant: SFPP—Subject: Complaint against ultra low sulfur diesel surcharge; dismissed by FERC; BP WCP appeal dismissed by D.C. Circuit

•	FERC Docket No. OR07-14—Complainants/Protestants: BP WCP and Chevron—Defendants: SFPP, Calnev, and several affiliates—Subject: Complaint against cash management practices; dismissed by FERC

•	FERC Docket No. OR07-16—Complainant/Protestant: Tesoro—Defendant: Calnev—Subject: Complaint against Calnev 2005, 2006 and 2007 indexed rate increases; dismissed by FERC; Tesoro appeal dismissed by D.C. Circuit

•	FERC Docket Nos. OR07-18, OR07-19 & OR07-22—Complainants/Protestants: Airline Complainants, BP WCP, Chevron, ConocoPhillips and Valero Marketing—Defendant: Calnev—Subject: Complaints against Calnev rates; complaint amendments pending before FERC

•	FERC Docket No. OR07-20—Complainant/Protestant: BP WCP—Defendant: SFPP—Subject: Complaint against 2007 indexed rate increases; dismissed by FERC; appeal pending at D.C. Circuit

•	FERC Docket Nos. OR08-13 & OR08-15—Complainants/Protestants: BP WCP and ExxonMobil—Defendant: SFPP—Subject: Complaints against all SFPP rates and 2008 indexed rate increases

•	FERC Docket No. IS05-230 (North Line rate case)—Complainants/Protestants: Shippers—Defendant: SFPP—Subject: SFPP filing to increase North Line rates to reflect expansion; initial decision issued; pending at FERC

•	FERC Docket No. IS05-327—Complainants/Protestants: Shippers—Defendant: SFPP—Subject: 2005 indexed rate increases; protests dismissed by FERC; appeal dismissed by D.C. Circuit

•	FERC Docket Nos. IS06-283, IS06-356, IS08-28 and IS08-302—Complainants/Protestants: Shippers—Defendant: SFPP—Subject: East Line expansion rate increases; settled

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•	FERC Docket Nos. IS06-356, IS07-229 and IS08-302—Complainants/Protestants: Shippers—Defendant: SFPP—Subject: 2006, 2007 and 2008 indexed rate increases; protests dismissed by FERC; East Line rates resolved by East Line settlement

•	FERC Docket No. IS07-137—Complainants/Protestants: Shippers—Defendant: SFPP—Subject: ULSD surcharge

•	FERC Docket No. IS07-234—Complainants/Protestants: BP WCP and ExxonMobil—Defendant: Calnev—Subject: 2007 indexed rate increases; protests dismissed by FERC

•	FERC Docket No. IS08-390—Complainants/Protestants: BP WCP, ExxonMobil, ConocoPhillips, Valero, Chevron, the Airlines—Defendant: SFPP—Subject: West Line rate increase

•	Motions to compel payment of interim damages (various dockets)—Complainants/Protestants: Shippers—Defendants: SFPP, Kinder Morgan G.P., Inc., and Knight Inc.; Motion for resolution on the merits (various dockets)—Complainants/Protestants: BP WCP and ExxonMobil—Defendant: SFPP and Calnev.

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/Ultramar Inc. as Ultramar; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; America West Airlines, Inc., Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airline Complainants; and the Federal Energy Regulatory Commission, as FERC.

The tariffs and rates charged by SFPP and CALNEV are subject to numerous ongoing proceedings at the FERC, including the above listed shippers’ complaints and protests regarding interstate rates on these pipeline systems. These complaints have been filed over numerous years beginning in 1992 through and including 2008. In general, these complaints allege the rates and tariffs charged by SFPP and CALNEV are not just and reasonable. If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach up to two years prior to the filing of their complaint) or refunds of any excess rates paid, and SFPP and CALNEV may be required to reduce their rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.

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, 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 are justified; and (iv) the appropriate level of return and income tax allowance we may include in our rates. The issues involving CALNEV are similar.

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; consequently, the level of income tax allowance to which SFPP will ultimately be entitled is not certain. In May of 2007, the D.C. Court upheld the FERC’s tax allowance policy.

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. 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 a March 2006 SFPP compliance filing to FERC, SFPP received a FERC order that directed us to submit revised compliance filings and revised tariffs. In conjunction with FERC’s December 2007 order, our other FERC and CPUC rate cases, and other unrelated litigation matters, we increased

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our litigation reserves by $140.0 million in the fourth quarter of 2007. And, in accordance with FERC’s December 2007 order and its February 2008 order on rehearing, SFPP submitted a compliance filing to FERC in February 2008, and further rate reductions were implemented on March 1, 2008.

During 2008, SFPP and CALNEV made combined settlement payments to various shippers totaling approximately $30 million in connection with OR92-8-025, IS6-283 and OR07-5. In October 2008, SFPP entered into a settlement resolving disputes regarding its East Line rates filed in Docket No. IS08-28 and related dockets. In January 2009, the FERC approved the settlement. Upon the finality of FERC’s approval, reduced settlement rates are expected to go into effect on May 1, 2009, and SFPP will make refunds and settlement payments shortly thereafter estimated to total approximately $16.0 million.

Based on our review of these FERC proceedings, we estimate that as of December 31, 2008, shippers are seeking approximately $355 million in reparation and refund payments and approximately $30 to $35 million in additional annual rate reductions. We assume that, with respect to our SFPP litigation reserves, any reparations and accrued interest thereon will be paid no earlier than the second quarter of 2009.

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 and refunds with respect to previously untariffed charges for certain pipeline transportation and related services.

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 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.

On June 6, 2008, as required by CPUC order, SFPP and Calnev Pipe Line Company filed separate general rate case applications, neither of which request a change in existing pipeline rates and both of which assert that existing pipeline rates are reasonable. On September 26, 2008, SFPP filed an amendment to its general rate case application, requesting CPUC approval of a $5 million rate increase for intrastate transportation services to become effective November 1, 2008. Protests to the amended rate increase application have been filed by various shippers and, as a consequence, the related rate increase is being collected subject to refund. The CPUC has issued a ruling suspending further activity with respect to the SFPP and Calnev Pipe Line Company general rate case applications, pending CPUC resolution of the 1997 CPUC complaint and Power Surcharge proceedings. Consequently, no action has been taken by the CPUC with respect to either the SFPP amended general rate case filing or the Calnev general rate case filing.

Carbon Dioxide Litigation

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

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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 filed motions for summary judgment on all claims.

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. Effective April 8, 2008, the Shell and Kinder Morgan defendants and plaintiff Gray entered into an indemnification agreement that provides for the dismissal of Gray’s claims with prejudice.

On April 22, 2008, the federal district court granted defendants’ motions for summary judgment and ruled that plaintiffs Bailey, Ptasynski, and Gray take nothing on their claims. The court entered final judgment in favor of defendants on April 30, 2008. Defendants have filed a motion seeking sanctions against plaintiff Bailey. The plaintiffs have appealed the final judgment to the United States Fifth Circuit Court of Appeals. In October 2008, plaintiffs filed their brief in the Fifth Circuit Court of Appeals. Defendants filed their brief in the Fifth Circuit in December 2008.

CO₂Claims 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 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. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. On June 21, 2007, the New Mexico federal district court entered final judgment confirming the August 7, 2006 arbitration decision.

On October 2, 2007, the plaintiff initiated a second arbitration (CO₂ Committee, Inc. v. Shell CO₂ Company, Ltd., aka Kinder Morgan CO₂ Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO₂and an ExxonMobil entity. The second arbitration asserts claims similar to those asserted in the first arbitration. On June 3, 2008, the plaintiff filed a request with the American Arbitration Association seeking administration of the arbitration. In October 2008, the New Mexico federal district court entered an order declaring that the panel in the first arbitration should decide whether the claims in the second arbitration are barred by res judicata. The plaintiff filed a motion for reconsideration of that order, which was denied by the New Mexico federal district court in January 2009. Plaintiff has appealed to the Tenth Circuit Court of Appeals and continues to seek administration of the second arbitration by the American Arbitration Association.

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

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No. CP07-001” from the U.S. Department of the Interior, Minerals Management Service, referred to in this note as the MMS. This Notice, and the MMS’s 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 stated that civil penalties will continue to accrue at the same rate until the alleged violations are corrected.

The parties have reached a settlement of the Notice of Noncompliance and Civil Penalty. The settlement agreement is subject to final MMS approval and upon approval will be funded from existing reserves and indemnity payments by Shell CO₂General LLC and Shell CO₂ LLC pursuant to a royalty claim indemnification agreement.

MMS Order to Report and Pay

On March 20, 2007, Kinder Morgan CO₂ received an “Order to Report and Pay” from the MMS. 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. The MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO₂ must use its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations. The MMS set a due date of April 13, 2007 for Kinder Morgan CO₂’s payment of the $4.6 million in claimed additional royalties, with possible late payment charges and civil penalties for failure to pay the assessed amount.

Kinder Morgan CO₂ has not paid the $4.6 million, and on April 19, 2007, it submitted a notice of appeal and statement of reasons in response to the Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 C.F.R. sec. 290.100, et seq.

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.

The MMS and Kinder Morgan CO₂have reached a settlement of the March 2007 and August 2007 Orders to Report and Pay. The settlement is subject to final MMS approval and upon approval will be funded from existing reserves and indemnity payments from Shell CO₂General LLC and Shell CO₂ LLC pursuant to a royalty claim indemnification agreement.

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.

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The case was tried to a jury in the trial court in September 2008. The plaintiffs sought $6.8 million in actual damages as well as punitive damages. The jury returned a verdict finding that Kinder Morgan did not breach the settlement agreement and did not breach the claimed duty to market carbon dioxide. The jury also found that Kinder Morgan breached a duty of good faith and fair dealing and found compensatory damages of $0.3 million and punitive damages of $1.2 million. On October 16, 2008, the trial court entered judgment on the verdict.

On January 6, 2009, the district court entered orders vacating the judgment and granting a new trial in the case. Kinder Morgan filed a petition with the New Mexico Supreme Court, asking that court to authorize an immediate appeal of the new trial orders. No action has yet been taken by the New Mexico Supreme Court on that petition. Subject to potential further review by New Mexico Supreme Court, the district court scheduled a new trial to occur beginning on October 19, 2009.

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 2009.

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. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP has appealed this decision, and in December 2008, the appellate court affirmed the 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.

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In May 2005, a Special Master appointed in this litigation found that because there was a prior public disclosure of the allegations and that Grynberg was not an original source, the Court lacked subject matter jurisdiction. As a result, the Special Master recommended that the Court dismiss all the Kinder Morgan defendants. In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the Kinder Morgan defendants on jurisdictional grounds. Grynberg has appealed this Order to the Tenth Circuit Court of Appeals. Briefing was completed and oral argument was held on September 25, 2008. No decision has yet been issued.

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.

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.

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

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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.

Pasadena Terminal Fire

On September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena, Texas terminal facility. One of our employees was injured and subsequently died. In addition, the pit 3 manifold was severely damaged. The cause of the incident is currently under investigation by the Railroad Commission of Texas and the United States Occupational Safety and Health Administration. The remainder of the facility returned to normal operations within 24 hours of the incident.

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. Following court ordered mediation, we have settled with plaintiffs in all of the wrongful death cases and the personal injury and property damages cases. On January 12, 2009, the Contra Costa Superior Court granted summary judgment in favor of Kinder Morgan G.P. Services Co., Inc. in the last remaining civil suit – a claim for indemnity brought by co-defendant Camp, Dresser & McKee, Inc. The only remaining pending matter is our appeal of a civil fine of $140,000 issued by the California Division of Occupational Safety and Health.

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 was investigated by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA. In March 2008, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (“NOPV”) to El Paso Corporation in which it concluded that El Paso failed to comply with federal law and its internal policies and procedures regarding protection of its pipeline, resulting in this incident.

To date, PHMSA has not issued any NOPV’s to REX, and we do not expect that it will do so. 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, REX and several other parties in the District Court of Harris County, Texas, 189 Judicial District, at case number 2007-57916. The plaintiffs seek unspecified compensatory and exemplary damages plus interest, attorney’s fees and costs of suit. We have asserted contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers. On March 25, 2008, we entered into a settlement agreement with one of the plaintiffs, the decedent’s daughter, resolving any and all of her claims against us, REX and its contractors. We were indemnified for the full amount of this settlement by one of REX’s contractors. On October 17, 2008, the remaining plaintiffs filed a Notice of Nonsuit, which dismissed the remaining claims against all defendants without prejudice to the plaintiffs’ ability to re-file their claims at a later date. The remaining plaintiffs re-filed their Complaint against REX, KMP and several other parties on November 7, 2008, Cause No. 2008-66788, currently pending in the District Court of Harris County, Texas, 189 Judicial District. The parties are currently engaged in discovery.

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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. 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 has engaged 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 three other historical releases from Plantation, including a February 2003 release near Hull, Georgia. Plantation has entered into a consent decree 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 proposed consent decree was filed in U.S. District Court and is awaiting entry by the court.

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 reached a settlement with the builder of the residential subdivision. Plantation continues to negotiate with the owner of the property to address any potential claims that it 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 (i) has migrated underneath the Navy’s Marine Corps Logistics Base in Barstow; (ii) has 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, it is 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 near completion. 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.

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. Defendants have denied liability and discovery has begun.

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Although no assurance can be given, we believe that we have meritorious defenses to the 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, 2008, and December 31, 2007, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $234.8 million and $247.9 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, LLC. and ST Services, Inc.

On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County. 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 Support Terminals. The terminal is now owned by Pacific Atlantic Terminals, LLC, (PAT) and it too is a party to the lawsuit.

The complaint seeks any and all damages related to remediating all environmental contamination 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. The parties are currently involved in mandatory mediation and met in June and October 2008. No progress was made at any of the mediations. The mediation judge will now refer the case back to the litigation court room.

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 ExxonMobil Corporation and Kinder Morgan Liquids Terminals LLC, f/k/a GATX Terminals Corporation. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and we filed third party complaints against Support Terminals seeking to bring Support Terminals into the case. Support Terminals filed motions to dismiss the third party complaints, which were denied. Support Terminals is now joined in the case and it filed an Answer denying all claims.

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 cleanup costs and 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 ExxonMobil against GATX Terminals, the issue is whether the plaintiffs’ claims are within the scope of the indemnity obligations between GATX Terminals (and therefore, Kinder Morgan Liquids Terminals) and Support Terminals. The court may consolidate the two cases.

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. The court denied in part and granted in part the Motion to Dismiss and gave the City leave to amend their complaint. The City submitted its Amended Complaint and we filed an Answer. The parties have commenced with discovery. This site

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has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board.

In June 2008, we received an Administrative Civil Liability Complaint from the California Regional Water Quality Control Board (RWQCB) for violations and penalties associated with permitted surface water discharge from the remediation system operating at the Mission Valley terminal facility. In December 2008, we settled the Administrative Civil Liability Complaint with the RWQCB, paying a civil penalty of $0.2 million.

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.

General

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, 2008, we have accrued an environmental reserve of$78.9 million, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations. As of December 31, 2007, our environmental reserve totaled $92.0 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.

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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-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2008, 2007 and 2006, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines.

Below is a brief description of our ongoing regulatory matters, including any material developments that occurred during 2008. This note also contains a description of any material regulatory matters initiated during 2008 in which we are involved.

FERC Order No. 2004/690/717

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”). 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.

However, 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 October 16, 2008, the FERC issued a Final Rule in Order 717 revising the FERC Standards of Conduct for natural gas and electric transmission providers by eliminating Order No. 2004’s concept of Energy Affiliates and corporate separation in favor of an employee functional approach as used in Order No. 497. A transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. The final rule also retains the long-standing no-conduit rule, which prohibits a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit. Additionally, the final rule requires that a transmission provider provide annual training on the Standards of Conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information. This rule became effective November 26, 2008.

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.

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 proposed 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.

On March 21, 2008 the FERC issued a Final Rule regarding changes to the Form 2, 2-A and 3Q. The revisions were designed to enhance the forms’ usefulness by updating them to reflect current market and cost information relevant to interstate pipelines and their customers. The rule is effective January 1, 2008 with the filing of the revised Form 3-Q beginning with the first quarter of 2009. The revised Form 2 and 2-A for calendar year 2008 material would be filed by April 30, 2009. On June 20, 2008, the FERC issued an Order Granting in Part and Denying in Part Rehearing and Granting Request for Clarification. No substantive changes were made to the March 21, 2008 Final Rule.

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. On November 20, 2008, the FERC issued an order terminating the inquiry.

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Notice of Proposed Rulemaking – Promotion of a More Efficient Capacity Release Market-Order 712

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.

On June 19, 2008, the FERC issued a final rule in Order 712 regarding changes to the capacity release program. The FERC permitted market based pricing for short-term capacity releases of a year or less. Long-term capacity releases and a pipeline’s sale of its own capacity remain subject to a price cap. The ruling would facilitate asset management arrangements by relaxing the FERC’s prohibitions on tying and on bidding requirements for certain capacity releases. The FERC further clarified that its prohibition on tying does not apply to conditions associated with gas inventory held in storage for releases for firm storage capacity. Finally, the FERC waived the prohibition on tying and bidding requirements for capacity releases made as part of state-approved retail open access programs. The final rule became effective on July 30, 2008.

On November 20, 2008, the FERC issued an order generally denying requests for rehearing and/or clarification that had been filed. The FERC reaffirmed its final rule, Order 712, and denied requests for rehearing stating the removal of the rate ceiling for short-term capacity release transactions is designed to extend to capacity release transactions, the pricing flexibility already available to pipelines through negotiated rates without compromising the fundamental protection provided by the availability of recourse rate service. Additionally, the FERC clarified several areas of the rule as it relates to asset management arrangements.

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.

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 ten million MMBtus of natural gas per year; (ii) fall entirely upstream of a processing plant; and (iii) deliver more than 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 mainline segments. Initial comments were filed by numerous parties on March 13, 2008. A Technical Conference was held on April 3, 2008. Numerous reply comments were received on April 14, 2008.

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 became 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 of our natural gas pipelines to report

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annual volumes of relevant transactions to the FERC. Technical workshops were held on April 22, 2008 and May 19, 2008. The FERC issued Order 704-A on September 18, 2008. This order generally affirmed the rule, while clarifying what information certain natural gas market participants must report in Form 552. The revisions pertain to the reporting of transactions occurring in calendar year 2008. The first report is due May 1, 2009 and each May 1st thereafter for subsequent calendar years. Order 704-A became effective October 27, 2008.

On November 20, 2008, the FERC issued Order 720, which is the final rule in the Docket No. RM08-2-000 proceeding. The final rule established new reporting requirements for interstate and major non-interstate pipelines. A major non-interstate pipeline is defined as a pipeline who delivers annually more than 50 million MMBtu of natural gas measured in average deliveries for the previous three calendar years. Interstate pipelines will be required to post no-notice activity at each receipt and delivery point three days after the day of gas flow. Major non-interstate pipelines will be required to post design capacity, scheduled volumes and available capacity at each receipt or delivery point with a design capacity of 15,000 MMbtus of natural gas per day or greater when gas is scheduled at the point. The final rule became effective January 27, 2009 for interstate pipelines. Non-major interstate pipelines must comply with the requirements of Order 720 within 150 days following the issuance of an order addressing the pending request for rehearing.

FERC Equity Return Allowance

On April 17, 2008, the FERC adopted a new policy under Docket No. PL07-2-000 that will allow master limited partnerships to be included in proxy groups for the purpose of determining rates of return for both interstate natural gas and oil pipelines. Additionally, the policy statement concluded that (i) there should be no cap on the level of distributions included in the FERC’s current discounted cash flow methodology; (ii) the Institutional Brokers Estimated System forecasts should remain the basis for the short-term growth forecast used in the discounted cash flow calculation; (iii) there should be an adjustment to the long-term growth rate used to calculate the equity cost of capital for a master limited partnership, specifically the long term growth rate would be set at 50% of the gross domestic product; and (iv) there should be no modification to the current respective two-thirds and one-third weightings of the short-term and long-term growth factors. Additionally, the FERC decided not to explore other methods for determining a pipeline’s equity cost of capital at this time. The policy statement will govern all future gas and oil rate proceedings involving the establishment of a return on equity, as well as those cases that are currently pending before either the FERC or an administrative law judge. On May 19, 2008, an application for rehearing was filed by The American Public Gas Association. On June 13, 2008, the FERC dismissed the request for rehearing.

Notice of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids Pipelines

On September 6, 2006, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as 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 C.F.R. 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 is 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.

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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.

Kinder Morgan Liquid Terminals – U.S. Department of Transportation Jurisdiction

With regard to several of our liquids terminals, we are working with the U.S. Department of Transportation, referred to in this report as the DOT, to supplement our compliance program for certain of our tanks and internal piping. We anticipate the program will call for incremental capital spending over the next several years to improve and/or add to our facilities. These improvements will enhance the tanks and piping previously considered outside the jurisdiction of DOT to conduct DOT jurisdictional transfers of products. Our original estimate called for an incremental $3 million to $5 million of annual capital spending over the next six to ten years for this work; however, we continue to assess the amount of capital that will be required and the amount may exceed our original estimate.

Natural Gas Pipeline Expansion Filings

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.

Rockies Express Pipeline-Currently Certificated Facilities

We own a 51% ownership interest in West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC, and operate the Rockies Express Pipeline. 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, because 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 commenced in the second quarter of 2008, and the expected in-service date for this compressor station is the second quarter of 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’ facilities described above, and is comprised of approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne Hub to an interconnection with

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Panhandle Eastern Pipe Line located in Audrain County, Missouri. The project also includes certain improvements to existing Rockies Express facilities located to the west of the Cheyenne Hub. Construction on Rockies Express-West commenced on May 21, 2007, and interim service for up to 1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles of pipe began on January 12, 2008. The project commenced deliveries to Panhandle Eastern Pipe Line at Audrain County, Missouri on the remaining 210 miles of pipe on May 20, 2008. The Rockies Express-West pipeline segment transports approximately 1.5 million cubic feet per day of natural gas across five states: Wyoming, Colorado, Nebraska, Kansas and Missouri.

Rockies Express replaced certain pipe to reflect a higher class location and conducted further hydrostatic testing of portions of its system during September 2008 to satisfy U.S. Department of Transportation testing requirements to operate at its targeted higher operating pressure. This pipe replacement and hydrostatic testing, conducted from September 3, 2008 through September 26, 2008, resulted in the temporary outage of pipeline delivery points and an overall reduction of firm capacity available to firm shippers. By the terms of the Rockies Express FERC Gas Tariff, firm shippers are entitled to daily reservation revenue credits for non-force majeure and planned maintenance outages. The estimated impact of these revenue credits is included in our 2008 results of operations.

Rockies Express Meeker to Cheyenne Expansion Project

Pursuant to certain rights exercised by Encana Gas Marketing USA as a result of its foundation shipper status on the former Entrega Gas Pipeline LLC facilities, Rockies Express is requesting authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne, Wyoming expansion project. The proposed expansion will consist of additional natural gas compression at its Big Hole compressor station located in Moffat County, Colorado and its Arlington compressor station located in Carbon County, Wyoming. Upon completion, the additional compression will permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado. The expansion is fully contracted and is expected to be operational in April 2010. The total estimated cost for the proposed project is approximately $78 million. Rockies Express submitted a FERC application seeking approval to construct and operate this expansion on February 3, 2009.

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.

By order issued May 30, 2008, the FERC authorized the certificate to construct the Rockies Express Pipeline-East Project. Construction commenced on the Rockies Express-East pipeline segment on June 26, 2008. Delays in securing permits and regulatory approvals, as well as weather-related delays, have caused Rockies Express to set revised project completion dates. Rockies Express-East is currently projected to commence service on April 1, 2009 to interconnects upstream of Lebanon, followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15, 2009, with final completion and deliveries to Clarington, Ohio commencing by November 1, 2009.

On October 31, 2008, Rockies Express filed an amendment to its certificate application, seeking authorization to revise its tariff-based recourse rates for transportation service on the REX East Project facilities to reflect updated construction costs for the project. The proposed amendment is pending FERC approval.

Current market conditions for consumables, labor and construction equipment along with certain provisions in the final regulatory orders have resulted in increased costs for the project and have impacted certain projected completion dates. Our current estimate of total completed cost on the Rockies Express Pipeline is now approximately $6.2 billion (consistent with our January 21, 2009 fourth quarter earnings press release).

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Kinder Morgan Interstate Gas Transmission Pipeline

On August 6, 2007, Kinder Morgan Interstate Gas Transmission Pipeline, referred to in this report as KMIGT, filed, in FERC Docket CP07-430, for regulatory approval to construct and operate a 41-mile natural gas pipeline, referred to in this report as the Colorado Lateral, 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. On February 21, 2008, the FERC granted the certificate application. On July 8, 2008, in response to a rehearing request by Public Service Company of Colorado, referred to in this report as PSCo, the FERC granted rehearing and denied KMIGT recovery in initial transportation rates $6.2 million in costs associated with non-jurisdictional laterals constructed by KMIGT to serve Atmos. The recourse rate adjustment does not have any material effect on the negotiated rate paid by Atmos to KMIGT or the economics of the project. On July 25, 2008, KMIGT filed an amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the Colorado Lateral to reflect updated construction costs for jurisdictional mainline facilities. The FERC approved the revised initial recourse rates on August 22, 2008.

PSCo, a competitor serving markets off the Colorado Lateral, also filed a complaint before the State of Colorado Public Utilities Commission (“CoPUC”) against Atmos, the anchor shipper on the project. The CoPUC conducted a hearing on April 14, 2008 on the complaint. On June 9, 2008, PSCo also filed before the CoPUC seeking a temporary cease and desist order to halt construction of the lateral facilities being constructed by KMIGT to serve Atmos. Atmos filed a response to that motion on June 24, 2008. By order dated June 27, 2008 an administrative law judge for the CoPUC denied PSCo’s request for a cease and desist order. On September 4, 2008, an administrative law judge for the CoPUC issued an order wherein it denied PSCo’s claim to exclusivity to serve Atmos and the Greeley market area but affirmed PSCo’s claim that Atmos’ acquisition of the delivery laterals is not in the ordinary course of business and requires separate approvals. Accordingly, Atmos may require a certificate of public convenience and necessity related to the delivery lateral facilities from KMIGT. While the need for approvals by Atmos before the CoPUC remains pending, service on the subject facilities commenced in November, 2008.

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. No protests to the application were filed and the project was approved by the FERC. Construction commenced on April 9, 2008. These facilities went into service in October 2008.

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 LLC. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. The entire estimated project cost is now expected to be approximately $950 million (consistent with our January 21, 2009 fourth quarter earnings press release), and it is expected to be fully operational during the third quarter of 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, or EIS, which addressed the potential environmental effects of the construction and operation of the Kinder Morgan Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of the National Environmental Policy Act. It concluded that approval of the Kinder Morgan Louisiana Pipeline project would have limited adverse environmental impacts. On June 22, 2007, the FERC issued an order granting construction and operation of the project. Kinder Morgan Louisiana Pipeline officially accepted the order on July 10, 2007.

On July 11, 2008, Kinder Morgan Louisiana Pipeline filed an amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the Kinder Morgan Louisiana Pipeline system to

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reflect updated construction costs for the project. The amendment was accepted by the FERC on August 14, 2008. On December 30, 2008, KMLP filed a second amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the KMLP system to reflect an additional increase in projected construction costs for the project. The filing is still pending.

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 approximately 500-mile Midcontinent Express Pipeline natural gas transmission system.

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 at an interconnection with the Transco Pipeline near Butler, Alabama. The Midcontinent Express Pipeline is a 50/50 joint venture between us and Energy Transfer Partners, L.P., and it has a total capital cost of approximately $2.2 billion, including the expansion capacity.

On July 25, 2008, the FERC approved the application made by Midcontinent Express Pipeline to construct and operate the 500-mile Midcontinent Express Pipeline natural gas transmission system along with the lease of 272 million cubic feet of capacity on the Oklahoma intrastate system of Enogex Inc. Initial design capacity for the pipeline was 1.5 billion cubic feet of natural gas per day, which was fully subscribed with long-term binding commitments from creditworthy shippers. A successful binding open season was completed in July 2008 which will increase the main segment of the pipeline’s capacity to 1.8 billion cubic feet per day, subject to regulatory approval.

Midcontinent Express Pipeline accepted the FERC Certificate on July 30, 2008. Mobilization for construction of the pipeline began in the third quarter, and subject to the receipt of regulatory approvals, interim service on the first portion of the pipeline is expected to be available by the second quarter of 2009 with full in service in the third quarter of 2009. On January 9, 2009, Midcontinent Express filed an amendment to its original certificate application requesting authorization to revise its initial rates for transportation service on the pipeline system to reflect an increase in projected construction costs for the project. The filing is still pending.

On January 30, 2009, MEP filed a certificate application in Docket No. CP09-56-000 requesting authorization to increase the capacity in Zone 1 from 1.5 Bcf to 1.8 Bcf/d. The Application is still pending.

Kinder Morgan Texas Pipeline LLC

On May 30, 2008, Kinder Morgan Texas Pipeline LLC filed in Docket No. PR08-25-000 a petition seeking market-based rate authority for firm and interruptible storage services performed under section 311 of the Natural Gas Policy Act of 1978 (NGPA) at the North Dayton Gas Storage Facility in Liberty County, Texas, and at the Markham Gas Storage Facility in Matagorda County, Texas. On October 3, 2008, FERC approved this petition effective May 30, 2008.


18.	Recent Accounting Pronouncements

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

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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.

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 fifty percent likelihood of being realized upon ultimate resolution. Our adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative effect adjustment to “Partners’ Capital” on our consolidated balance sheet. For more information related to FIN 48, see Note 5.

SFAS No. 157

For information on SFAS No. 157, see Note 14 “—SFAS No. 157.”

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 (disclosed in Note 14 “—SFAS No. 157”) and in SFAS No. 107 “Disclosures about Fair Value of Financial Instruments” (disclosed in Note 9 “—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 consolidated 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

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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). The adoption of this Statement did not have a material impact on our consolidated financial statements.

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 to 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 to 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 to be accounted for consistently and similarly—as equity transactions.

This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for us). SFAS No. 160 is to 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 are to be applied retrospectively for all periods presented. The adoption of this Statement did not have a material impact on our consolidated financial statements.

SFAS No. 161

On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This Statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and is intended to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows through enhanced disclosure requirements. The enhanced disclosures include, among other things, (i) a tabular summary of the fair value of derivative instruments and their gains and losses; (ii) disclosure of derivative features that are credit-risk–related to provide more information regarding an entity’s liquidity; and (iii) cross-referencing within footnotes to make it easier for financial statement users to locate important information about derivative instruments.

This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for us). This Statement expands and enhances disclosure requirements only, and as such, the adoption of this Statement did not have any impact on our consolidated financial statements.

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EITF 07-4

In March 2008, the Emerging Issues Task Force reached a consensus on Issue No. 07-4, or EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” EITF 07-4 provides guidance for how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights.

This Issue is effective for fiscal years beginning after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The guidance in this Issue is to be applied retrospectively for all financial statements presented; however, the adoption of this Issue did not have any impact on our consolidated financial statements.

FASB Staff Position No. FAS 142-3

On April 25, 2008, the FASB issued FASB Staff Position FAS 142-3 “Determination of the Useful Life of Intangible Assets.” This Staff Position amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets”. This Staff Position is effective for financial statements issued for fiscal years beginning after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The adoption of this Staff Position did not have a material impact on our consolidated financial statements.

SFAS No. 162

On May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This Statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. generally accepted accounting principles, referred to in this note as GAAP, for nongovernmental entities.

Statement No. 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. Statement No. 162 is effective 60 days following the U.S. Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles,” and is only effective for nongovernmental entities. We do not expect the adoption of this Statement to have any effect on our consolidated financial statements.

FASB Staff Position No. EITF 03-6-1

On June 16, 2008, the FASB issued FASB Staff Position FAS EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This Staff Position clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the calculation of basic earnings per share. This Staff Position is effective for financial statements issued for fiscal years beginning after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The adoption of this Staff Position did not have an impact on our consolidated financial statements.

FASB Staff Position No. FAS 157-3

On October 10, 2008, the FASB issued FASB Staff Position FAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This Staff Position provides guidance clarifying how SFAS No. 157, “Fair Value Measurements” should be applied when valuing securities in markets that are not active. This Staff Position applies the objectives and framework of SFAS No. 157 to determine the fair value of a financial asset in a market that is not active, and it reaffirms the notion of fair value as an exit price as of the measurement date. Among other things, the guidance also states that significant judgment is required in valuing

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financial assets. This Staff Position became effective upon issuance, and did not have any material effect on our consolidated financial statements.

EITF 08-6

On November 24, 2008, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 08-6, or EITF 08-6, “Equity Method Investment Accounting Considerations.” EITF 08-6 clarifies certain accounting and impairment considerations involving equity method investments. This Issue is effective for fiscal years beginning on or after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The guidance in this Issue is to be applied prospectively for all financial statements presented. The adoption of this Issue did not have any impact on our consolidated financial statements.

FASB Staff Position No. FAS 140-4 and FIN 46(R)-8

On December 11, 2008, the FASB issued FASB Staff Position FAS 140-4 and FIN 46(R)-8 “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities.” This Staff Position requires enhanced disclosure and transparency by public entities about their involvement with variable interest entities and their continuing involvement with transferred financial assets. The disclosure requirements in this Staff Position are effective for annual and interim periods ending after December 15, 2008 (December 31, 2008 for us). The adoption of this Staff Position did not have any impact on our consolidated financial statements.

FASB Staff Position No. FAS 132(R)-1

On December 30, 2008, the FASB issued FASB Staff Position FAS 132(R)-1, “Employer’s Disclosures About Postretirement Benefit Plan Assets.” This Staff Position is effective for financial statements ending after December 15, 2009 (December 31, 2009 for us) and requires additional disclosure of pension and post retirement benefit plan assets regarding (i) investment asset classes; (ii) fair value measurement of assets; (iii) investment strategies; (iv) asset risk; and (v) rate-of-return assumptions. We do not expect this Staff Position to have a material impact on our consolidated financial statements.

Securities and Exchange Commission’s Final Rule on Oil and Gas Disclosure Requirements

On December 31, 2008, the Securities and Exchange Commission issued its final rule “Modernization of Oil and Gas Reporting,” which revises the disclosures required by oil and gas companies. The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities. The provisions of this final rule are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. We do not expect this final rule to have a material impact on our consolidated financial statements.

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19.	Quarterly Financial Data (Unaudited)


	Operating Revenues		Operating Income			Income from Continuing Operations			Income from Discontinued Operations		Net Income

	(In millions)
2008
First Quarter	$	2,720.3	$	419.4		$	346.2		$	0.5	$	346.7
Second Quarter		3,495.7		406.2			361.4			0.8		362.2
Third Quarter		3,232.8		407.9			329.8			—		329.8
Fourth Quarter		2,291.5		318.0			266.1			—		266.1
2007
First Quarter	$	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


	Income (loss) from Continuing Operations			Income (loss) from Discontinued Operations		Net Income

Basic Limited Partners’ income (loss) per Unit:
2008
First Quarter	$	0.63		$	—	$	0.63
Second Quarter		0.64			0.01		0.65
Third Quarter		0.48			—		0.48
Fourth Quarter		0.19			—		0.19
2007
First Quarter	$	(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

Diluted Limited Partners’ income (loss) per Unit:
2008
First Quarter	$	0.63		$	—	$	0.63
Second Quarter		0.64			0.01		0.65
Third Quarter		0.48			—		0.48
Fourth Quarter		0.19			—		0.19
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




(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.

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Our capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing Activities


	December 31,

	2008			2007			2006

Consolidated Companies(a)
Wells and equipment, facilities and other	$	2,106.9		$	1,612.5		$	1,369.5
Leasehold		348.9			348.1			347.4

Total proved oil and gas properties		2,455.8			1,960.6			1,716.9
Accumulated depreciation and depletion		(1,064,3	)		(725.5	)		(470.2	)

Net capitalized costs	$	1,391.5		$	1,235.1	��	$	1,246.7




(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,

	2008		2007		2006

Consolidated Companies(a)
Property Acquisition Proved oil and gas properties	$	—	$	—	$	36.6
Development		495.2		244.4		261.8




(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.

Our results of operations from oil and gas producing activities for each of the years 2008, 2007 and 2006 are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing Activities


	Year Ended December 31,

	2008		2007		2006

Consolidated Companies(a)
Revenues(b)	$	785.5	$	589.7	$	524.7
Expenses:
Production costs		308.4		243.9		208.9
Other operating expenses(c)		99.0		56.9		66.4
Depreciation, depletion and amortization expenses		342.2		258.5		169.4

Total expenses		749.6		559.3		444.7

Results of operations for oil and gas producing activities	$	35.9	$	30.4	$	80.0




(a)	Amounts relate to Kinder Morgan CO₂ Company, L.P. and its consolidated subsidaries.

(b)	Revenues include losses attributable to our hedging contracts of $693.3 million, $434.2 million and $441.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

(c)	Consists primarily of carbon dioxide expense.

The table below represents estimates, as of December 31, 2008, 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

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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 2008, we filed estimates of our oil and gas reserves for the year 2007 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 and gas reserves reported on Form EIA-23 and those reported in this report exceeds 5%.


Reserve Quantity Information

	Consolidated Companies(a)

	Crude Oil (MBbls)			NGLs (MBbls)			Nat. Gas (MMcf)(b)

Proved developed and undeveloped reserves:
As of December 31, 2005		141,951			18,983			2,153
Revisions of previous estimates(c)		(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(d)		10,361			2,784			1,077
Production		(12,984	)		(2,005	)		(290	)

As of December 31, 2007		121,355			11,112			1,078
Revisions of previous estimates(e)		(29,536	)		(2,490	)		695
Production		(13,240	)		(1,762	)		(499	)

As of December 31, 2008		78,579			6,860			1,274


Proved developed reserves:
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
As of December 31, 2008		53,346			4,308			1,274


(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)	Based on lower than expected recoveries of a section of the SACROC unit carbon dioxide flood project.

(d)	Associated with an expansion of the carbon dioxide flood project area of the SACROC unit.

(e)	Predominantly due to lower product prices used to determine reserve volumes.

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;

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	• 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.

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,

		2008			2007			2006

Consolidated Companies(a)
Future cash inflows from production	$	3,498.0		$	12,099.5		$	7,534.7
Future production costs		(1,671.6	)		(3,536.2	)		(2,617.9	)
Future development costs(b)		(910,3	)		(1,919.2	)		(1,256.8	)

Undiscounted future net cash flows		916.1			6,644.1			3,660.0
10% annual discount		(257.7	)		(2,565.7	)		(1,452.2	)

Standardized measure of discounted future net cash flows	$	658.4		$	4,078.4		$	2,207.8


(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

		2008			2007			2006

Consolidated Companies(a)
Present value as of January 1	$	4,078.4		$	2,207.8		$	3,075.0
Changes during the year:
Revenues less production and other costs(b)		(1,012.4	)		(722.1	)		(690.0	)
Net changes in prices, production and other costs(b)		(3,076.9	)		2,153.2			(123.0	)
Development costs incurred		495.2			244.5			261.8
Net changes in future development costs		231.1			(547.8	)		(446.0	)
Purchases of reserves in place		—			—			3.2
Revisions of previous quantity estimates(c)		(417.1	)		510.8			(179.5	)
Accretion of discount		392.9			198.1			307.4
Timing differences and other		(32.8	)		33.9			(1.1	)

Net change for the year		(3,420.0	)		1,870.6			(867.2	)

Present value as of December 31	$	658.4		$	4,078.4		$	2,207.8



(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 $639.3 million, $434.2 million and $441.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

(c)	2008 revisions are predominantly due to lower product prices used to determine reserve volumes. 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.

215

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. Registrant (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
	(principal financial and accounting officer)

Date: February 23, 2009

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 Officer of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc. (principal financial officer and principal accounting officer)	February 23, 2009

Kimberly A. Dang




/s/ RICHARD D. KINDER	Chairman of the Board and Chief	February 23, 2009
	Executive Officer of Kinder Morgan
Richard D. Kinder	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc. (principal executive officer)

/s/ GARY L. HULTQUIST	Director of Kinder Morgan	February 23, 2009
	Management, LLC, Delegate of
Gary L. Hultquist	Kinder Morgan G.P., Inc.

/s/ C. BERDON LAWRENCE	Director of Kinder Morgan	February 23, 2009
	Management, LLC, Delegate of
C. Berdon Lawrence	Kinder Morgan G.P., Inc.

/s/ PERRY M. WAUGHTAL	Director of Kinder Morgan	February 23, 2009
	Management, LLC, Delegate of
Perry M. Waughtal	Kinder Morgan G.P., Inc.


/s/ C. PARK SHAPER	Director and President of	February 23, 2009
	Kinder Morgan Management, LLC,
C. Park Shaper	Delegate of Kinder Morgan G.P., Inc.

216

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Kinder Morgan Energy Partners L P 10-K2008 FY Annual report

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