Edgar Filing: KINDER MORGAN ENERGY PARTNERS L P

form10k_2010.htm

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, 2010

[ ]

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 Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

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

_______________

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

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

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

None

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]

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. [ ]

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

Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]

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, 2010 was approximately $12,836,486,727. As of January 31, 2011, the registrant had 218,993,455 Common Units outstanding.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page Number
	PART I
Items 1 and 2.	Business and Properties	4
	General Development of Business	4
	Organizational Structure	4
	Recent Developments	5
	Financial Information about Segments	11
	Narrative Description of Business	11
	Business Strategy	11
	Business Segments	11
	Products Pipelines	12
	Natural Gas Pipelines	16
	CO2	24
	Terminals	27
	Kinder Morgan Canada	31
	Major Customers	32
	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.	(Removed and Reserved)	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	54
	General	54
	Critical Accounting Policies and Estimates	57
	Results of Operations	59
	Liquidity and Capital Resources	77
	Recent Accounting Pronouncements	83
	Information Regarding Forward-Looking Statements	83
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	85
	Energy Commodity Market Risk	85
	Interest Rate Risk	87
Item 8.	Financial Statements and Supplementary Data	88
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	88
Item 9A.	Controls and Procedures	88
Item 9B.	Other Information	89

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	90
	Directors and Executive Officers of our General Partner and its Delegate	90
	Corporate Governance	92
	Section 16(a) Beneficial Ownership Reporting Compliance	93
Item 11.	Executive Compensation	93
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
Item 13.	Certain Relationships and Related Transactions, and Director Independence	106
Item 14.	Principal Accounting Fees and Services	107

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	109
	Index to Financial Statements	114
Signatures		194

PART I

Items 1 and 2. Business and Properties.

Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America, and unless the context requires otherwise, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., our operating limited partnerships and their majority-owned and controlled subsidiaries. We own an interest in or operate approximately 28,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described more fully below in “—(c) Narrative Description of Business—Business Segments”).

Our pipelines transport natural gas, refined petroleum products, 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 $30 billion. The address of our principal executive offices is 500 Dallas Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000.

You should read the following in conjunction with our audited consolidated financial statements and the notes thereto included elsewhere in this report. We have prepared our accompanying consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission. Our accounting records are maintained in United States dollars, and all references to dollars in this report are United States dollars, except where stated otherwise. Canadian dollars are designated as C$. Our consolidated financial statements include our accounts and those of our operating limited partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.

(a) General Development of Business

Organizational Structure

We are a Delaware limited partnership formed in August 1992, and our common units, which represent limited partner interests in us, trade on the New York Stock Exchange under the symbol “KMP.” Our general partner is Kinder Morgan G.P., Inc., a Delaware corporation.

In general, our limited partner units, consisting of common units, 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) and i-units, will vote together as a single class, with each common unit, Class B unit, and i-unit having one vote. Our partnership agreement requires us to distribute all of our available cash, as defined in our partnership agreement, to our partners on a quarterly basis within 45 days after the end of each calendar quarter. Our available cash may consist of cash from operations and cash from interim capital transactions. We pay our quarterly distributions from operations and interim capital transactions to our common unitholders and our sole Class B unitholder in cash, and we pay our quarterly distributions to our sole i-unitholder in additional i-units rather than in cash.

Kinder Morgan, Inc., a Delaware corporation and referred to as KMI in this report, indirectly owns all the common stock of Kinder Morgan Kansas, Inc. Kinder Morgan Kansas, Inc. is a Kansas corporation and indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc.; however, in July 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.

Prior to May 30, 2007, Kinder Morgan Kansas, Inc. was known as Kinder Morgan, Inc., and on that date, it merged with a wholly-owned subsidiary of its parent, Knight Holdco LLC, a private company owned by investors led by Richard D. Kinder, Chairman and Chief Executive Officer of both our general partner and Kinder Morgan Management, LLC (our general partner’s delegate, discussed following). This merger is referred to in this report as the going-private transaction, and following the merger, Kinder Morgan, Inc. (the surviving legal entity from the merger) was renamed Knight, Inc. On July 15, 2009, Knight Inc. changed its name back to Kinder Morgan, Inc., and subsequently, Knight Holdco LLC was renamed Kinder Morgan Holdco LLC.

On November 23, 2010, Kinder Morgan Holdco LLC filed a registration statement on Form S-1 with the Securities and Exchange Commission for a proposed initial public offering of its common stock. The registration statement became effective on February 10, 2011, and the initial public offering closed on February 16, 2011. In connection with the offering, Kinder Morgan Holdco LLC converted from a Delaware limited liability company to a Delaware corporation named Kinder Morgan, Inc. (KMI), and the former Kinder Morgan, Inc. was renamed Kinder Morgan Kansas, Inc. All of the common stock that was sold in the offering was sold by existing investors, consisting of funds advised by or affiliated with Goldman, Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC. KMI did not receive any proceeds from the offering. On February 11, 2011, KMI’s common stock began trading on the New York Stock Exchange under the symbol “KMI.”

As of December 31, 2010, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management LLC (discussed following), an approximate 12.8% interest in us. In addition to the distributions it receives from its limited and general partner interests, KMI 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 2010 distribution level, KMI received approximately 47% of all quarterly distributions of available cash from us, with approximately 40% and 7% of all quarterly distributions from us attributable to KMI’s general partner and limited partner interests, respectively. These percentages were impacted due to a portion of our available cash distribution for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations. For our fourth quarter 2010 distribution of available cash, KMI received approximately 50% of the total distribution, with approximately 44% attributable to its general partner interests and 6% attributable to its limited partner interests. For additional information on our 2010 partnership distributions, see Notes 10 and 11 to our consolidated financial statements included elsewhere in this report.

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, 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 majority-owned and controlled 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 majority-owned and controlled subsidiaries. As of December 31, 2010, KMR, through its sole ownership of our i-units, owned approximately 29.1% of all of our outstanding limited partner units.

Recent Developments

The following is a brief listing of significant developments since December 31, 2009. We begin with developments pertaining to our reportable business segments. Additional information regarding most of these items may be found elsewhere in this report.

Products Pipelines

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On March 1, 2010, we acquired the refined products terminal assets at Mission Valley, California from Equilon Enterprises LLC (d/b/a Shell Oil Products US) for $13.5 million in cash. The acquired assets are included in our West Coast Products Pipelines operations, and include buildings, equipment, delivery facilities (including two truck loading racks), and storage tanks with a total capacity of approximately 170,000 barrels for gasoline, diesel fuel and jet fuel. The terminal operates with the support of a long-term terminaling agreement with Tesoro Refining and Marketing Company;

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On April 20, 2010, we announced plans to modify and expand our Cochin pipeline system to provide for the transportation of natural gas liquids from the Marcellus shale gas formation in the Appalachian Basin to fractionation plants and chemical markets located near Sarnia, Ontario, and Chicago, Illinois. Currently, we continue to pursue commercial agreements with shippers for a proposed 240-mile natural gas liquids pipeline that would originate in Marshall County, West Virginia and terminate at an interconnect with our Cochin system near Metamora, Ohio;

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On May 26, 2010, our West Coast terminal operations completed and placed in-service an approximately $69 million expansion project that added six storage tanks and 480,000 barrels of refined petroleum products storage capacity at our Carson, California products terminal. We have entered into long-term contracts with customers for all six of the new tanks. In April 2010, we announced plans to invest approximately $85 million to build seven more tanks with a combined capacity of 560,000 barrels. We have entered into a long-term agreement with a major oil company to lease six of these tanks. We expect to place two of the tanks into service in 2012, three of the tanks in service in 2013, and bring the remaining two tanks in service in 2014;

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On May 28, 2010, the Federal Energy Regulatory Commission, referred to in this report as the FERC, approved a settlement agreement that our subsidiary SFPP, L.P. reached with 11 of 12 shippers regarding various rate challenges. We refer to this settlement agreement as the Historical Cases Settlement, and it resolved a wide range of rate challenges dating back as early as 1992. The Historical Cases Settlement resolved all but two of the cases outstanding between SFPP and the eleven shippers, and we do not expect any material adverse impacts on our business from the remaining two unsettled cases. The twelfth shipper entered into a separate settlement agreement with SFPP, L.P. in February 2011. The FERC has not yet acted on the second settlement. In 2010, we recognized a $172.0 million expense due to adjustments of our liabilities related to both the Historical Cases Settlement and other matters related to SFPP and other rate litigation, and in June 2010, we made settlement payments to various shippers totaling $206.3 million. Our cash distributions of $4.40 per unit to our limited partners for 2010 were not impacted by these rate case litigation settlement payments because, from a cash perspective, a portion of our partnership distributions for the second quarter of 2010 was a distribution of cash from interim capital transactions, rather than a distribution of cash from operations;

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On July 22, 2010, our West Coast Products Pipelines began construction on an approximately $48 million expansion project that will transport and store incremental military jet fuel for Travis Air Force Base located in Fairfield, California. In October 2010, we completed construction of a 1.6-mile, 16-inch diameter delivery pipeline to the air base from our Concord, California to Sacramento, California main line. We are currently constructing three 150,000 barrel storage tanks and related facilities for the project, and we expect the project to be in service in March 2012;

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On October 1, 2010, we sold a 50% interest in our subsidiary, Cypress Interstate Pipeline LLC, to Westlake Chemical Corporation and we received proceeds of $10.2 million. We recognized an $8.8 million gain for both the interest sold and the noncontrolling investment retained, and pursuant to a long-term agreement with Westlake, we continue to operate the Cypress pipeline system; and

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On October 8, 2010, we acquired four separate refined petroleum products terminals from Chevron U.S.A. Inc. for an aggregate consideration of $32.3 million, consisting of $31.5 million in cash and an assumed environmental liability of $0.8 million. Combined, the terminals have storage capacity of approximately 650,000 barrels for gasoline, diesel fuel and jet fuel. Chevron has entered into long-term contracts with us to handle and store product at the terminals.

Natural Gas Pipelines

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On May 14, 2010, we and Copano Energy, L.L.C. entered into formal agreements for a joint venture to provide natural gas gathering, transportation and processing services to natural gas producers in the Eagle Ford shale gas formation in south Texas. Eagle Ford Gathering LLC is owned 50% by us and 50% by Copano. Copano also serves as operator and managing member of Eagle Ford Gathering LLC. We and Copano have committed approximately 375 million cubic feet per day of natural gas capacity to the joint venture through 2024 for transportation on our natural gas pipeline that extends from Laredo to Katy, Texas, and for processing at Copano’s natural gas processing plant located in Colorado County, Texas.

On July 6, 2010, Eagle Ford Gathering LLC announced the execution of a definitive long-term, fee-based gas services agreement with SM Energy Company. According to the provisions of the agreement, SM Energy will commit Eagle Ford production from its assets located in LaSalle, Dimmitt, and Webb Counties, Texas up to a maximum level of 200 million cubic feet per day over a ten year term. Eagle Ford Gathering LLC committed to construct approximately 85 miles of 24-inch and 30-inch diameter pipeline to serve SM Energy’s acreage in the western Eagle Ford shale formation, and to connect it to our Freer compressor station located in Duval County, Texas.

On November 15, 2010, Eagle Ford Gathering LLC announced the execution of a similar fourteen year gas services agreement with Chesapeake Energy Marketing, Inc. for the remainder of the initial project capacity. Eagle Ford will construct approximately 25 miles of additional 24-inch and 30-inch diameter pipeline to access the Chesapeake acreage and combined, we and Copano will invest approximately $175 million for the expanded project. As of December 31, 2010, our capital contributions (and net equity investment) in Eagle Ford Gathering LLC totaled $29.9 million.

On January 6, 2011, we and Copano announced plans to invest an additional aggregate $100 million to further expand our Eagle Ford joint venture by providing incremental gathering and processing capacity of more than 200 million cubic feet per day of natural gas to producers through construction of additional pipeline facilities and a long-term agreement with Formosa Hydrocarbons Company for additional processing and fractionation services. Related to this expansion, Eagle Ford Gathering will construct both a 54 mile, 24-inch diameter crossover pipeline between our existing pipelines, and an additional 20 mile, 20-inch diameter pipeline that will enable Eagle Ford to deliver gas to Formosa. We will construct and operate the two additional pipelines for Eagle Ford. In addition, Eagle Ford executed an agreement with Formosa under which Formosa will provide the joint venture gas processing and fractionation services at its Point Comfort, Texas facilities. On February 3, 2011, we and Copano announced the execution of a gas services agreement with Anadarko E&P Company L.P. for a significant portion of the expanded capacity resulting from the crossover project. We expect the crossover facilities to be completed by the end of 2011;

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On May 21, 2010, we purchased a 50% ownership interest in Petrohawk Energy Corporation’s natural gas gathering and treating business in the Haynesville shale gas formation located in northwest Louisiana. We paid an aggregate consideration of $917.4 million in cash for our 50% equity ownership interest. Petrohawk continued to operate the business during a short transition period, and beginning October 1, 2010, a newly formed company named KinderHawk Field Services LLC, owned 50% by us and 50% by Petrohawk, assumed the joint venture operations. Through year-end 2011, our general partner has agreed not to take incentive distributions on the approximately 7.9 million units we issued to finance this transaction. Further information on KinderHawk Field Services LLC is discussed below in “—(c) Narrative Description of Business—Natural Gas Pipelines—Texas Intrastate Natural Gas Pipeline Group and Other—KinderHawk Field Services LLC;”

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On August 13, 2010, our subsidiary Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, completed construction and placed into service all remaining capital improvements that increased the storage and withdrawal capability of its Huntsman natural gas storage facility, located near Sidney, Nebraska. Project construction commenced in October 2009, and total costs for the project were approximately $10.1 million, significantly under the original budget. Incremental storage capacity arising from the expansion project is contracted under a firm service agreement for a five-year term, and we began incremental service on these new facilities on February 1, 2010;

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On September 1, 2010, we acquired the natural gas treating assets of Gas-Chill, Inc. for an aggregate consideration of $13.1 million, consisting of $10.5 million in cash paid on closing, and an obligation to pay a holdback amount of $2.6 million within eighteen months from closing. The acquired assets primarily consist of more than 100 mechanical refrigeration units that are used to remove hydrocarbon liquids from natural gas streams prior to entering transmission pipelines. The refrigeration units are designed to extract natural gas liquids from the inlet gas stream. The acquisition complemented and expanded our existing natural gas treating operations;

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In September 2010, we completed construction on an approximately $100 million expansion project that significantly increases the working capacity of our North Dayton natural gas storage facility located in Liberty County, Texas. The project involved the development and mining of a third underground storage cavern that added approximately 7.0 billion cubic feet of working natural gas storage capacity at the facility. The new cavern is anticipated to be fully operational in the second quarter of 2011;

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On October 5, 2010, our 50%-owned Rockies Express Pipeline LLC completed construction on its Arlington natural gas compression station located in Carbon County, Wyoming. Combined with its Big Hole compression station located in Moffat County, Colorado that was completed in December 2009, the compression expansion project allows for the transportation of an additional 200 million cubic feet per day of natural gas on the Rockies Express system that runs from the Meeker Hub, located in Rio Blanco County, Colorado, eastward to the Cheyenne Hub, located in Weld County, Colorado (on the Rockies Express-Entrega pipeline segment). Total costs for these two compression facilities were approximately $50.5 million, significantly under the original budget;

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On October 12, 2010, Fayetteville Express Pipeline LLC began interim pipeline transportation service on its Fayetteville Express natural gas pipeline system, a 187-mile, 42-inch diameter pipeline that provides shippers in the Arkansas Fayetteville shale gas area with takeaway natural gas capacity and further access to growing markets. The pipeline system began firm contract transportation service to customers on January 1, 2011, and construction was fully completed in January 2011. We own a 50% interest in Fayetteville Express Pipeline LLC, and Energy Transfer Partners L.P. owns the remaining interest and also operates the Fayetteville Express pipeline system. Our current estimate of total construction costs on the project is slightly less than $1.0 billion (versus the original budget of $1.3 billion). Further information on the Fayetteville Express pipeline system is discussed below in “—(c) Narrative Description of Business—Natural Gas Pipelines—Central Interstate Natural Gas Pipeline Group—Fayetteville Express Pipeline LLC;”

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On November 18, 2010, KMIGT was notified by the FERC of a proceeding against it pursuant to Section 5 of the Natural Gas Act. The proceeding will set the matter for hearing and determine whether KMIGT’s current transportation rates, which were approved by the FERC in KMIGT’s last transportation rate case settlement, remain just and reasonable. For further information on this proceeding, see Note 16 to our consolidated financial statements included elsewhere in this report; and

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As of the date of this report, KMIGT continues construction on the expansion of its mainline natural gas pipeline facilities that run from Franklin to Hastings, Nebraska. The pipeline expansion and capital improvements will create up to ten million cubic feet per day of natural gas capacity to serve an ethanol plant located near Aurora, Nebraska. Project construction commenced in October 2009 and is expected to be completed in spring 2011. Our current estimate of total construction costs on the project is approximately $18.6 million.

CO2

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In December 2010, we completed construction on our previously announced Eastern Shelf Pipeline project in the eastern Permian Basin area of Texas. The project, discussed further below, involved the installation of a 91-mile, 10-inch carbon dioxide distribution pipeline, and the development of a new carbon dioxide flood in the Katz oil field located near Knox City, Texas. Announced in July 2009, the project further expands our carbon dioxide operations, and we currently expect total construction costs on the project to be approximately $230 million.

The new carbon dioxide pipeline begins near Snyder, Texas and ends west of Knox City. It provides customers with access to a steady supply of carbon dioxide for enhanced oil recovery, and it has an initial capacity of 65 million cubic feet per day, with the ability to increase the capacity to 200 million cubic feet per day. We began injecting carbon dioxide into the line in November 2010, and carbon dioxide injections into the Katz field commenced in December 2010. The development of a new carbon dioxide flood in the Katz field is projected to produce an incremental 25 million barrels of oil over the next 15 to 20 years and will provide a platform for future enhanced oil recovery operations in the region; and

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During 2010, we entered into new sales and delivery contracts of over 1.3 trillion cubic feet of carbon dioxide to ten customers for an average term of eight years. These agreements include both contracts with new customers and the replacement or extension of existing agreements (which were set to expire over the next few years) at generally more favorable terms. Nearly one trillion cubic feet of the carbon dioxide contracted for is with third-party customers, with the remaining amount for use at our SACROC and Katz oil fields.

Terminals

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On January 15, 2010, we acquired three ethanol handling train terminals from US Development Group LLC for an aggregate consideration of $201.1 million, consisting of $114.3 million in cash, $81.7 million in common units, and $5.1 million in assumed liabilities. The three train terminals are located in Linden, New Jersey; Baltimore, Maryland; and Euless, Texas. As part of the transaction, we announced the formation of a joint venture with US Development Group LLC to optimize and coordinate customer access to the three acquired terminals, other ethanol terminal assets we already own and operate, and other terminal projects currently under development by both parties;

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On March 5, 2010, we acquired a diverse mix of bulk and liquids terminal assets from Slay Industries for an aggregate consideration of $101.6 million, consisting of $97.0 million in cash, assumed liabilities of $1.6 million, and an obligation to pay additional cash consideration of $3.0 million in years 2013 through 2019, contingent upon the purchased assets providing us an agreed-upon amount of earnings during the three years following the acquisition. Including accrued interest, we expect to pay approximately $2.0 million of this contingent consideration in the first half of 2013.

The acquired assets include (i) a marine terminal located in Sauget, Illinois; (ii) a transload liquid operation located in Muscatine, Iowa; (iii) a liquid bulk terminal located in St. Louis, Missouri; and (iv) a warehousing distribution center located in St. Louis. All of the acquired terminals have long-term contracts with large creditworthy shippers. As part of the transaction, we and Slay Industries entered into joint venture agreements at both the Kellogg Dock coal bulk terminal, located in Modoc, Illinois, and at the newly created North Cahokia terminal, located in Sauget and which has approximately 175 acres of land ready for development. All of the assets located in Sauget have access to the Mississippi River and are served by five rail carriers;

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On April 16, 2010, we placed into service a new, state-of-the-art mineral concentrate ship loader at our Vancouver Wharves bulk marine terminal, located in Vancouver, British Columbia, Canada. The ship loader and conveyance systems significantly improved dust control and environmental performance while providing for additional expansion opportunities. The total project cost was approximately C$42.4 million, including the ship loader, dock improvements and associated conveyors;

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On April 29, 2010, we signed a definitive agreement with a major oil company to support a new ethanol unit train facility at our Deer Park, Texas terminal. As part of the expansion, we will also build a new pipeline with connectivity to our large liquids terminal complex located on the Houston Ship Channel. Our current estimate of total construction costs on the project is approximately $17.8 million and we expect to complete the project in the second quarter of 2011;

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On July 22, 2010, we acquired a terminal with ethanol tanks, a truck rack and additional acreage in Euless, Texas, from Direct Fuels Partners, L.P. for an aggregate consideration of $16 million, consisting of $15.9 million in cash and an assumed property tax liability of $0.1 million. The acquired terminal facility is connected to and complements the Dallas, Texas unit train terminal we acquired from USD Development Group LLC in January 2010 (described above);

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On October 1, 2010, we acquired certain bulk terminal assets and real property located in Chesapeake, Virginia, from Allied Concrete Products, LLC and Southern Concrete Products, LLC for an aggregate consideration of $8.6 million, consisting of $8.1 million in cash and an assumed environmental liability of $0.5 million. The acquired terminal facility is situated on 42 acres of land and can handle approximately 250,000 tons of material annually, including pumice, aggregates and sand. The acquisition complements the bulk commodity handling operations at our nearby Elizabeth River terminal, also located in Chesapeake;

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As of December 31, 2010, construction continues on an expansion project that will add 1.15 million barrels of new petroleum and ethanol storage tank capacity at our liquids terminal located in Carteret, New Jersey. In July 2009, we entered into an agreement with a major oil company for this additional capacity. The project involves the construction of seven new blending tanks, and our current estimate of total construction costs on the project is approximately $60.5 million. We expect three tanks to be completed by early-summer 2011, and the remaining four should be completed in the third quarter of 2011;

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On January 3, 2011, we made an initial $50 million preferred equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the United States. Watco also operates transload/intermodal and mechanical services divisions. Our investment provides capital to Watco for further expansion of specific projects, complements our existing terminal network, and provides our customers more transportation services for many of the commodities that we currently handle. It also offers us the opportunity to share in additional growth opportunities through new projects, such as crude oil unit train operations and incremental business at our terminal storage facilities. In addition, the agreement allows for an additional preferred contribution of $100 million during 2011;

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In January 2011, we completed construction of an approximately $16.2 million railcar loop track at our Deepwater petroleum coke terminal facility located in Pasadena, Texas. The track is used to transport a major petroleum coke producer’s volumes to the facility; and

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In January and February 2011, in order to capitalize on increasing demand for coal export activity, we entered into a contract and a letter of intent with two separate major coal producers to expand our coal terminal operations. We signed a contract with a major central Appalachian coal producer that involves an expansion of our International Marine Terminals facility, a multi-product, import-export facility located in Port Sulphur, Louisiana and owned 66 2/3% by us. The approximately $70 million project will enable IMT to handle an incremental six million tons of coal with a minimum commitment of four million tons, and we expect this project to be completed in 2012. The letter of intent is with a major western coal producer and entails an expansion of one of our Houston, Texas petroleum coke facilities to handle up to 2.2 million tons of coal at the facility. We expect this project to cost approximately $15 million and should be completed in the third quarter of 2011, pending the obtaining of permits.

Kinder Morgan Canada

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During 2010, average throughput on our Trans Mountain pipeline system, which transports heavy crude oil and other products from Alberta to terminals and refineries located in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States, was approximately 297,000 barrels per day. Total pipeline deliveries were oversubscribed for eight of the last twelve months of 2010, and over the past two years, Trans Mountain has set record loadings at our Westridge dock facility, located in Burnaby, British Columbia.

Financings

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On May 19, 2010, we issued a total of $1 billion in principal amount of senior notes in two separate series, consisting of $600 million of 5.30% notes due September 15, 2020, and $400 million of 6.55% notes due September 15, 2040. We used the net proceeds received from this debt offering to reduce the borrowings under our commercial paper program and our bank credit facility;

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On June 23, 2010, we successfully renegotiated our previous $1.79 billion five-year unsecured revolving bank credit facility that was due August 18, 2010, replacing it with a new $2.0 billion three-year, senior unsecured revolving credit facility that expires June 23, 2013. Similar to our previous bank credit facility, our $2.0 billion facility is with a syndicate of financial institutions and permits us to obtain bids for fixed rate loans from members of the lending syndicate. The covenants of this credit facility are also substantially similar to the covenants of our previous facility; however, the interest rates for borrowings under this facility have increased from our previous facility. Wells Fargo Bank, National Association is the administrative agent, and borrowings under the credit facility can be used for general partnership purposes and as a backup for our $2 billion commercial paper program. As of December 31, 2010, we had approximately $1.2 billion of borrowing capacity available under our $2.0 billion senior unsecured revolving bank credit facility;

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On November 1, 2010, we paid $250 million to retire the principal amount of our 7.50% senior notes that matured on that date;

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In November 2010, we terminated five existing fixed-to-variable interest rate swap agreements in five separate transactions. These swap agreements had a combined notional principal amount of $825 million, and we received combined proceeds of $157.6 million from the early termination of these swap agreements; and

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In 2010, we issued 11,569,540 common units for $758.7 million in cash, described following. We used the net proceeds received from the issuance of these common units to reduce the borrowings under our commercial paper program and our bank credit facility:

On May 7, 2010, we issued 6,500,000 of our common units at a price of $66.25 per unit. After commissions and underwriting expenses, we received net proceeds of $417.4 million for the issuance of these common units;

On July 2, 2010, we completed an offering of 1,167,315 of our common units at a price of $64.25 per unit in a privately negotiated transaction, and we received net proceeds of $75.0 million for the issuance of these common units; and

During 2010, we issued 3,902,225 of our common units pursuant to our equity distribution agreement with UBS Securities LLC. After commissions, we received net proceeds of $266.3 million from the issuance of these common units.

2011 Outlook

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On November 29, 2010, we announced that we expect to declare cash distributions of $4.60 per unit for 2011, a 4.5% increase over our cash distributions of $4.40 per unit for 2010.

Our expected growth in distributions assumes an average West Texas Intermediate (WTI) crude oil price of approximately $89 per barrel in 2011. 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 2011, 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 $5.5 million (or less than 0.2% of our combined business segments’ anticipated earnings before depreciation, depletion and amortization expenses). This sensitivity to the average WTI price is very similar to what we experienced in 2010.

Also on November 29, 2010, we announced that for the year 2011, we anticipate that (i) our business segments will generate approximately $3.6 billion in earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments (and will generate $3.8 billion in segment earnings including our share of all non-cash depreciation, depletion and amortization expenses of certain joint ventures accounted for under the equity-method of accounting); (ii) we will distribute approximately $1.5 billon to our limited partners; and (iii) we will invest approximately $1.4 billion for our capital expansion program (including small acquisitions and contributions to joint ventures). Our anticipated 2011 expansion investment will help drive earnings and cash flow growth in 2011 and beyond, and we estimate that approximately $430 million of the equity required for our 2011 investment program will be funded by cash retained as a function of KMR distributions being paid in additional units rather than in cash.

In 2010, our capital expansion program was approximately $2.5 billion—including discretionary capital spending, equity contributions to our equity investees, and acquisition cash expenditures.

(b) Financial Information about Segments

For financial information on our five reportable business segments, see Note 15 to our consolidated financial statements included elsewhere in this report.

Business Strategy

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

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

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

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

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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 KMI 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:

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Products Pipelines—which consists of approximately 8,400 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;

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Natural Gas Pipelines—which consists of approximately 15,500 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;

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CO2— which produces, markets and transports, through approximately 2,000 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates eight oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;

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Terminals—which consists of approximately 124 owned or operated liquids and bulk terminal facilities and approximately 33 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

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Kinder Morgan Canada—which transports crude oil and refined petroleum products through over 2,500 miles of pipelines from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States.

Products Pipelines

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

West Coast Products Pipelines

Our West Coast Products Pipelines include our SFPP, L.P. operations (often referred to in this report as our Pacific 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 Pacific operations serve six western states with approximately 2,500 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. In 2010, our Pacific operations’ mainline pipeline system transported approximately 1,079,400 barrels per day of refined products, with the product mix being approximately 61% gasoline, 23% diesel fuel, and 16% jet fuel. In 2009, our Pacific operations’ pipeline system delivered approximately 1,078,800 barrels per day of refined petroleum products.

Our Calnev pipeline system 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 approximately 55 miles of pipeline serves Edwards Air Force Base. In 2010, our Calnev pipeline system transported approximately 120,200 barrels per day of refined products, with the product mix being approximately 44% gasoline, 30% diesel fuel, and 26% jet fuel. In 2009, the system delivered approximately 120,400 barrels per day of refined petroleum products.

Our West Coast Products Pipelines include 15 truck-loading terminals (13 on our Pacific operations and two on Calnev) with an aggregate usable tankage capacity of approximately 15.4 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. Combined, these terminals have a total capacity of approximately 9.0 million barrels of storage for both petroleum products and chemicals. Our West Coast Products Pipelines and associated West Coast Terminals together handled 16.8 million barrels of ethanol in 2010, a 46% increase when compared to the 11.5 million barrels handled in 2009.

Markets. Combined, our Pacific operations and Calnev pipeline system transport approximately 1.2 million barrels per day of refined petroleum products, providing pipeline service to approximately 28 customer-owned terminals, 11 commercial airports and 15 military bases. The pipeline systems serve approximately 72 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, in turn, the volumes we transport, depends on such factors as prevailing economic conditions, government specifications and regulations, vehicular use, and purchase patterns and demographic changes in the markets served. Certain product volumes can also experience seasonal variations and, consequently, overall delivery 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 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 Pacific and Calnev operations are (i) proprietary pipelines owned and operated by oil companies in the area where our pipelines deliver products; and (ii) 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 will be built in the foreseeable future. However, the possibility of individual pipelines such as the Holly/Sinclair UNEV pipeline from Salt Lake City, Utah 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 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, Wilmington Liquid Bulk Terminals (Vopak), NuStar, Pro Petroleum 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, the sole owner of the approximately 3,100-mile refined petroleum products Plantation pipeline system serving the southeastern United States. We operate the system pursuant to agreements with Plantation and a related entity, Plantation Services LLC. The Plantation pipeline system 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. An affiliate of ExxonMobil Corporation owns the remaining approximately 49% ownership interest, and ExxonMobil has historically been one of the largest shippers on the Plantation system both in terms of volumes and revenues.

In 2010, Plantation delivered approximately 498,300 barrels per day of refined petroleum products, with the product mix being approximately 65% gasoline, 22% diesel fuel, and 13% jet fuel. In 2009, Plantation delivered approximately 487,000 barrels per day of refined petroleum products.

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. During 2010, Plantation’s top eight shippers represented approximately 97% 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) and military jet fuel to military facilities in the Southeast.

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 2.5 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 both the mid-Atlantic and northeastern United States.

Central Florida Pipeline

Our Central Florida pipeline operations consist of (i) a 110-mile, 16-inch diameter pipeline that transports gasoline and ethanol; (ii) an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando; and (iii) two separate liquids terminals located in Tampa and Taft, Florida, which we own and operate.

Both pipelines service our Taft terminal (located near Orlando), and the 10-inch diameter pipeline has an additional intermediate delivery point at Intercession City, Florida, and is also the sole pipeline supplying jet fuel to the Orlando International Airport in Orlando, Florida. In 2010, the pipeline system transported approximately 104,800 barrels per day of refined products, with the product mix being approximately 69% gasoline and ethanol, 11% diesel fuel, and 20% jet fuel. In 2009, our Central Florida pipeline system delivered approximately 107,100 barrels per day of refined petroleum products. In addition to being connected to our Tampa terminal, our Central Florida pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, BP, and Marathon Petroleum.

Our 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 terminal provides storage for gasoline, ethanol, diesel fuel and jet fuel for further movement into either trucks or into the Central Florida pipeline system, and also provides storage and truck rack blending services for bio-diesel. Our Taft terminal contains approximately 0.7 million barrels of storage capacity, for gasoline, ethanol, and diesel fuel for further movement into trucks.

Markets. 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 356,000 barrels per day, or 45% of the consumption of refined products in the state, and gasoline is, by far, the largest component of that demand. 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. The market in Central Florida is seasonal and heavily influenced by tourism, with demand peaks in March and April during spring break and again in the summer vacation season.

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 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 utilize 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 the Citgo terminals located along the Port of Tampa, the Chevron and Motiva terminals located in Port Tampa, and terminals owned by Marathon Petroleum and BP. These competing 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.

Cochin Pipeline System

Our Cochin pipeline system consists of an approximately 1,900-mile, 12-inch diameter multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor, Ontario, along with 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 2010 and 2009, the pipeline system transported approximately 20,000 and 29,300 barrels per day of natural gas liquids, respectively. Further information about our Cochin system is discussed above in “—(a) General Development of Business—Recent Developments—Products Pipelines.”

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 Aux Sable, which processes and markets the natural gas liquids in the Chicago market.

Cypress Pipeline

We now own 50% of Cypress Interstate Pipeline LLC, the sole owner of the Cypress pipeline system. The 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 connection with Westlake Chemical Corporation, a major petrochemical producer in the Lake Charles, Louisiana area. Effective October 1, 2010, Westlake Petrochemicals LLC, a wholly-owned subsidiary of Westlake Chemical Corporation, exercised its option to purchase from us a 50% ownership interest in Cypress Interstate Pipeline LLC; however, we remain the operator of the Cypress pipeline system.

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. The Cypress pipeline system has a current capacity of approximately 55,000 barrels per day for natural gas liquids, and in 2010 and 2009, the system transported approximately 49,000 and 43,400 barrels per day, respectively.

Markets. The Cypress pipeline system services Westlake pursuant to the provisions of a ship-or-pay transportation agreement entered into in October 2010. The transportation agreement expires in April 2021, and requires a minimum volume of 35,000 barrels per day.

Supply. The Cypress pipeline system 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 of the Unites States 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 26 high-quality, liquid petroleum products terminals located along the Plantation/Colonial pipeline corridor in the Southeastern United States. Combined, our Southeast terminals have a total storage capacity of approximately 8.3 million barrels. In 2010 and 2009, these terminals transferred approximately 358,900 and 348,000 barrels of refined products per day, respectively.

Markets. The acquisition and marketing activities of our Southeast terminal operations 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. Combined, our Southeast terminal operations have a physical presence in markets representing almost 80% of the pipeline-supplied demand in the Southeast and offer a competitive alternative to marketers seeking relationships with independent truck terminal service providers.

Beginning in 2009, our Southeast terminal operations expanded their ethanol blending and storage services into several conventional gasoline markets, and in 2010, it completed the installation of automated ethanol blending facilities at a second gasoline terminal located in Selma, North Carolina. Our Southeast terminals now have ethanol blending capabilities in 12 of the 15 markets it serves and can adjust blending ratios as needed in order to help customers meet changing regulatory requirements. Combined, our Southeast terminal operations handled 9.0 million barrels of ethanol in 2010, a 25% increase when compared to the 7.2 million barrels handled in 2009.

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 our Southeast terminals to both of the Plantation and Colonial pipeline systems. In addition to pipeline supply, we are also able to take marine receipts at both our Richmond and Chesapeake, Virginia terminals.

Competition. 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. We process and separate pipeline transmix into pipeline-quality gasoline and light distillate products 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 and 10.0 million barrels of transmix in 2010 and 2009, respectively.

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 region 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, Enterprise, 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 Pipeline Company.

Competition. Placid Refining is our main competitor in the Gulf Coast area. There are various processors in the Mid-Continent region of the United States who compete with our transmix facilities, primarily ConocoPhillips, Gladieux Refining and Williams Energy Services. Motiva Enterprises’ 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 regions of the United States. 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 15,500 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 and Other

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 5.5 billion cubic feet per day of natural gas and approximately 145 billion cubic feet of on-system natural gas storage capacity, including 11 billion cubic feet contracted from a third party. 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 102-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, Kleberg 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 KMI 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 our 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, our intrastate group owns and operates 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 three storage caverns providing approximately 16.5 billion cubic feet of total capacity, consisting of 11.0 billion cubic feet of working capacity and 5.5 billion cubic feet of cushion gas.

We also own the West Clear Lake natural gas storage facility located in Harris County, Texas, and we lease five salt dome caverns located near Markham, Texas in Matagorda County, and two salt dome caverns located in Brazoria County, Texas. Pursuant to a long term contract that expires in 2012, Shell Energy North America (US), L.P. operates and controls the 96 billion cubic feet of natural gas working capacity at the West Clear Lake facility, and we provide transportation service into and out of the facility. We lease the natural gas storage capacity at the Markham facility from Texas Brine Company, LLC according to the provisions of an operating lease that expires in March 2013, and we can, at our sole option, extend the term of this lease for two additional ten-year periods. The facility consists of five salt dome caverns with approximately 22.0 billion cubic feet of working natural gas capacity and up to 1.1 billion cubic feet per day of peak deliverability. We lease the two storage caverns located in Brazoria County, Texas (known as the Stratton Ridge facilities) from Ineos USA, LLC. The Stratton Ridge facilities have a combined working natural gas capacity of 1.4 billion cubic feet and a peak day deliverability of 100 million cubic feet per day. In addition to the aforementioned storage facilities, we contract for storage services from third parties.

Additionally, our intrastate group owns both a 40% equity ownership interest in Endeavor Gathering LLC (acquired on November 1, 2009) and a 50% equity ownership interest in Eagle Ford Gathering LLC (formed on May 14, 2010). Endeavor Gathering LLC provides natural gas gathering service to GMX Resources’ exploration and production activities in its Cotton Valley Sands and Haynesville/Bossier Shale horizontal well developments located in East Texas. GMX Resources operates and owns the remaining 60% ownership interest in Endeavor Gathering LLC. Further information about Eagle Ford Gathering LLC is discussed above in “—(a) General Development of Business—Recent Developments—Natural Gas Pipelines.”

Markets. Texas is one of the largest natural gas consuming states in the country. The natural gas demand profile in our Texas intrastate natural gas 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 natural gas 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 2010, deliveries through the existing interconnection near Arguellas fluctuated from zero to approximately 276 million cubic feet per day of natural gas. Deliveries to Monterrey also ranged from zero to 338 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 LNG terminal located near Sabine Pass, 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.

Kinder Morgan Treating L.P.

We believe we have the largest contracted natural gas treating fleet operation in the United States. Our subsidiary, Kinder Morgan Treating, L.P., owns and operates (or leases to producers for operation) treating plants that remove impurities (carbon dioxide and hydrogen sulfide) from natural gas before it is delivered into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications. Its primary treating assets include approximately 212 natural gas amine-treating plants and approximately 56 dew point control plants. In addition, effective September 1, 2010, it acquired the natural gas treating assets of Gas-Chill, Inc., as discussed above in “—(a) General Development of Business—Recent Developments—Natural Gas Pipelines.”

The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to remove these impurities from the gas. After mixing, gas and reacted amine are separated and the impurities are removed from the amine by heating. Treating plants are sized by the amine circulation capacity in terms of gallons per minute.

Dew point control is complementary to our treating business, as pipeline companies enforce gas quality specifications to lower the hydrocarbon dew point of the gas they receive and transport. A higher relative dew point can sometimes cause liquid hydrocarbons to condense in the pipeline and cause operating problems and gas quality issues to the downstream markets. Hydrocarbon dew point plants, which consist of skid mounted processing equipment, remove these hydrocarbons. These plants lower the temperature of the gas stream and collect the liquids before they enter the downstream pipeline. As of December 31, 2010, we had approximately 268 treating and hydrocarbon dew point control plants in operation. We typically charge a fixed monthly rental fee plus, in those instances where we operate the equipment, a fixed monthly operating fee.

Supply. Natural gas from certain formations is high in carbon dioxide, which generally needs to be removed before introduction of the gas into transportation pipelines. Many of our active plants are treating natural gas from the Wilcox and Edwards gas formations in the Texas Gulf Coast, and the Haynesville shale gas formation in North Louisiana and East Texas, all of which are deep formations that are high in carbon dioxide.

Markets. Shale reservoirs being developed today have concentrations of carbon dioxide above the normal pipeline quality specifications of 2.0%. The Eagle Ford shale gas formation in South Texas and the Bossier shale gas formation in North Louisiana and East Texas are experiencing robust development, and we believe that our treating business strategy is well suited to the producers in these areas.

Competition. Our natural gas treating operations face competition from manufacturers of new treating and hydrocarbon dew point control plants and from a number of regional operators that provide plants and operations similar to ours. We also face competition from vendors of used equipment that occasionally operate plants for producers. In addition, we may lose business to natural gas gatherers who have underutilized treating or processing capacity. We may also lose wellhead treating opportunities to blending, which is a pipeline company’s ability to waive quality specifications and allow producers to deliver their contaminated natural gas untreated. This is generally referred to as blending because of the receiving company’s ability to blend this natural gas with cleaner natural gas in the pipeline such that the resulting natural gas meets pipeline specification.

KinderHawk Field Services LLC

In May 2010, our subsidiary KM Gathering LLC purchased a 50% ownership interest in KinderHawk Field Services LLC, which gathers and treats natural gas in the Haynesville shale gas formation located in northwest Louisiana. A subsidiary of Petrohawk Energy Corporation owns the remaining 50% ownership interest.

KinderHawk’s assets consist of more than 365 miles of natural gas gathering pipeline currently in service, with projected average throughput of approximately one billion cubic feet per day of natural gas in 2011. Ultimately, KinderHawk is expected to have approximately two billion cubic feet per day of throughput capacity, which will make it one of the largest natural gas gathering and treating systems in the United States. Additionally, the system’s natural gas amine treating plants have a current capacity of approximately 2,160 gallons per minute.

KinderHawk received a dedication to gather and treat all of Petrohawk’s operated Haynesville and Bossier shale gas production in northwest Louisiana for the life of the leases at agreed upon rates, as well as minimum volume commitments from Petrohawk for the first five years of the joint venture agreement. Since our acquisition, KinderHawk also secured additional new third-party gas gathering and treating commitments. These contracts provide for the dedication of 17 sections, from three shippers, for three- to ten-year terms. The anticipated daily volume from third-parties could approach over 200 million cubic feet per day of natural gas depending on expected drill schedules and operational techniques.

Upstream

Our Natural Gas Pipelines’ upstream operations consist of our Casper and Douglas, Wyoming natural gas processing operations and our 49% ownership interest in the Red Cedar Gas Gathering Company.

Casper and Douglas Natural Gas Processing Systems

We own and operate our Casper and Douglas, Wyoming natural gas processing plants, and combined, these plants have the capacity to process up to 185 million cubic feet per day of natural gas depending on raw gas quality. We also own the operations of a carbon dioxide/sulfur treating facility located in the West Frenchie Draw field of the Wind River Basin of Wyoming, and we include this facility as part of our Casper and Douglas operations. The West Frenchie Draw treating facility has a capacity of 50 million cubic feet per day of natural gas.

Markets. Casper and Douglas are processing plants servicing natural gas streams flowing into our KMIGT pipeline system. 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 its 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. West Frenchie Draw has full capacity dedication through 2014 with two of the area’s major natural gas producers: Encana and ExxonMobil. It treats a natural gas stream which contains approximately 4% carbon dioxide down to KMIGT’s pipeline specification of 2%. The facility’s only outlet feeds into the KMIGT system.

Competition. Other regional facilities in the Greater Powder River Basin include (i) the Rawlins plant, which has a processing capacity of approximately 230 million cubic feet per day and is owned and operated by El Paso; (ii) the Sage Creek plant, which has a processing capacity of approximately 50 million cubic feet per day and is owned and operated by Merit Energy; and (iii) the Hilight plant, which has a processing capacity of approximately 30 million cubic feet per day and is owned and operated by Western Gas Partners, L.P. Casper and Douglas, however, are the only plants which provide straddle processing of natural gas flowing into the KMIGT pipeline system.

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. 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. The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe.

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’s natural gas gathering system currently consists of approximately 743 miles of gathering pipeline connecting more than 1,200 producing wells, 89,400 horsepower of compression at 21 field compressor stations and two carbon dioxide treating plants. The capacity and throughput of the Red Cedar gathering system is approximately 750 million cubic feet per day of natural gas.

Red Cedar also owns Coyote Gas Treating, LLC. The sole asset owned by Coyote Gas Treating, LLC is a 175 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. The inlet gas stream treated by this plant contains an average carbon dioxide content of between 12% and 13%, and the plant treats the gas down to a carbon dioxide concentration of 2% in order to meet interstate natural gas pipeline quality specifications. It then compresses the natural gas into our TransColorado pipeline system for transport to the Blanco, New Mexico-San Juan Basin Hub.

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 three natural gas pipeline systems (i) Kinder Morgan Interstate Gas Transmission Pipeline; (ii) TransColorado Pipeline; and (iii) our 50% ownership interest in the Rockies Express Pipeline.

Kinder Morgan Interstate Gas Transmission LLC

KMIGT owns approximately 5,300 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska. Our KMIGT pipeline system is powered by 25 transmission and storage compressor stations having approximately 157,000 horsepower. KMIGT also owns the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, which has approximately 34.8 billion cubic feet of total capacity, consisting of 14.8 billion cubic feet of working capacity and 20.0 billion cubic feet of cushion gas. KMIGT has 11 billion cubic feet of firm capacity commitments and provides for withdrawals of up to 179 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.

Our KMIGT system 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. Additionally, the KMIGT pipeline system includes the Colorado Lateral, which is a 41-mile, 12-inch pipeline extending from the Cheyenne Hub southward to the Greeley, Colorado area. The Colorado Lateral serves Atmos Energy under a long-term firm transportation contract, and KMIGT is currently marketing additional capacity along its route.

Markets. Markets served by our KMIGT pipeline system provide a stable customer base with expansion opportunities due to the system’s access to Rocky Mountain supply sources. Markets served by the system 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 the KMIGT system 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 also seen a significant increase in demand from ethanol producers, and has expanded its system to meet the demands from the ethanol producing community.

Supply. As of December 31, 2010, approximately 8%, by volume, of KMIGT’s contracted firm transport capacity expires within one year and 60% expires between one and five years. Over 90% of the system’s total firm transport capacity is currently subscribed, with 71% of KMIGT’s transport business in 2010 being conducted with its 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.

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 the Blanco Hub near Bloomfield, New Mexico. It has multiple points of interconnection with various interstate and intrastate pipelines, gathering systems, and local distribution companies. Our TransColorado pipeline system is powered by eight compressor stations having an aggregate of approximately 39,000 horsepower.

Our TransColorado system has the ability to flow gas south or north. It receives gas from a single 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. Natural gas transmitted south through the pipeline system flows into the El Paso, Transwestern and Questar Southern Trail pipeline systems. Natural gas transmitted north through the system flows into the Colorado Interstate, Wyoming Interstate and Questar pipeline systems at the Greasewood Hub, and into 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.

Markets. Our TransColorado system 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 2010 and 2009, TransColorado transported an average of approximately 472 million and 617 million cubic feet per day, respectively, of natural gas from these supply basins.

Supply. During 2010, 95% of TransColorado’s transport business was with processors or producers or their own marketing affiliates, and 5% was with marketing companies and various gas marketers. Approximately 65% of TransColorado’s transport business in 2010 was conducted with its three largest customers. Nearly all of TransColorado’s long-haul southbound pipeline capacity is committed under firm transportation contracts that extend at least through year-end 2011. As of December 31, 2010, approximately 2%, by volume, of TransColorado’s firm transportation contracts expire within one year, and 64% expire between one and five years; however, TransColorado is actively pursuing contract extensions and/or replacement contracts to increase firm subscription levels beyond 2011.

Competition. Our TransColorado system 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 and a reduction of rigs drilling in this area for gas have had the effect of reducing that price differential.

Rockies Express Pipeline

We operate and own 50% of the 1,679-mile Rockies Express natural gas pipeline system, one of the largest natural gas pipelines ever constructed in North America. The system is powered by 18 compressor stations totaling approximately 427,000 horsepower, and the system is capable of transporting 1.8 billion cubic feet per day of natural gas.

Our ownership is through our 50% equity interest in Rockies Express Pipeline LLC, the sole owner of the Rockies Express pipeline system and referred to in this report as Rockies Express. The Rockies Express system has binding firm commitments secured for nearly all of the 1.8 billion cubic feet per day of pipeline capacity. Sempra Pipelines & Storage (25%), a unit of Sempra Energy, and ConocoPhillips (25%) hold the remaining ownership interests in Rockies Express.

Markets. Rockies Express 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. The system’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, the Rockies Express system can deliver gas to our TransColorado pipeline system in northwestern Colorado, which can in turn transport the gas further south for delivery into the San Juan Basin area. In Zone 1, the Rockies Express system 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 system’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 the system’s Zone 2 (Rockies Express-West pipeline segment) and Zone 3 (Rockies Express-East pipeline segment) facilities into other pipeline systems.

The Rockies Express-West facilities extend from the Cheyenne Hub to an interconnect with Panhandle Eastern Pipeline Company in Audrain County, Missouri. Through the Rockies Express-West facilities, the system facilitates the delivery of natural gas into the Mid-Continent region 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), and through a connection with our subsidiary, KMIGT.

The Rockies Express-East facilities extend eastward from the terminus of the Rockies Express-West line. The Rockies Express-East facilities permit natural gas delivery to pipelines and local distribution companies providing service to the midwestern and eastern U.S. markets. The interconnecting interstate pipelines include Missouri Gas Pipeline, NGPL, Midwestern Gas Transmission, Trunkline, Panhandle Eastern Pipeline, ANR, Columbia Gas, Dominion Transmission, Tennessee Gas, Texas Eastern, and Texas Gas Transmission. The local distribution companies include Ameren, Vectren, and Dominion East Ohio .

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

Competition. Capacity on the Rockies Express system is nearly fully contracted under ten year firm service agreements with producers from the Rocky Mountain supply basin. These agreements expire in 2019 and provide the pipeline with fixed monthly reservation revenues for the primary term of such contracts. Although there are other pipeline competitors providing transportation from Rocky Mountain supply basins, the Rockies Express system was designed and constructed to realize economies of scale and offers its shippers competitive fuel rates and variable costs to transport gas supplies from the Rockies to Midwestern and Eastern markets. Other pipelines accessing the Rocky Mountain gas supply basins include Questar Pipeline Company, Wyoming Interstate, Colorado Interstate Gas Company, Kern River Gas Pipeline Company, Northwest Pipeline, Bison Pipeline, and the Ruby Pipeline, a 680-mile natural gas pipeline currently under construction. The Ruby Pipeline will extend from Opal, Wyoming to Malin, Oregon and is estimated to begin service in the spring of 2011.

Central Interstate Natural Gas Pipeline Group

Our Central interstate natural gas pipeline group, which operates primarily in the Mid-Continent region of the United States, consists of the following four natural gas pipeline systems (i) Trailblazer Pipeline; (ii) Kinder Morgan Louisiana Pipeline; (iii) our 50% ownership interest in the Midcontinent Express Pipeline; and (iv) our 50% ownership interest in the Fayetteville Express Pipeline.

Trailblazer Pipeline Company LLC

Our subsidiary, Trailblazer Pipeline Company LLC, referred to in this report as Trailblazer, owns the 436-mile Trailblazer natural gas pipeline system. Our Trailblazer pipeline system 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’s and Northern Natural Gas Company’s pipeline systems. NGPL manages, maintains and operates the Trailblazer system for us, for which it is reimbursed at cost. Trailblazer offers its customers firm and interruptible transportation, and in 2010, it transported an average of approximately 849 million cubic feet per day of natural gas. In 2009, Trailblazer transported an average of approximately 866 million cubic feet per day.

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

Supply. As of December 31, 2010, none of Trailblazer’s firm contracts, by volume, expire before one year and 58%, 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 the Rockies Express pipeline system (discussed above) can transport 1.8 billion cubic feet per day of natural gas from the Rocky Mountain area to Midwest markets. These two systems compete with Trailblazer for natural gas pipeline transportation demand from the Rocky Mountain region. 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.

Kinder Morgan Louisiana Pipeline

Our subsidiary, Kinder Morgan Louisiana Pipeline LLC owns the Kinder Morgan Louisiana natural gas pipeline system. The pipeline system provides 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 system capacity is fully supported by 20 year take-or-pay customer commitments with Chevron and Total that expire in 2029.

The Kinder Morgan Louisiana pipeline system consists of two segments. The first is a 132-mile, 42-inch diameter pipeline with firm capacity of approximately 2.0 billion cubic feet per day of natural gas that extends from the Sabine Pass terminal to a point of interconnection with an existing Columbia Gulf Transmission line in Evangeline Parish, Louisiana (an offshoot consists 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 Florida Gas Transmission Company compressor station located in Acadia Parish, Louisiana). The second segment is a one-mile, 36-inch diameter pipeline with firm capacity of approximately 1.2 billion cubic feet per day that extends from the Sabine Pass terminal and connects to NGPL’s natural gas pipeline.

Midcontinent Express Pipeline LLC

We own a 50% interest in Midcontinent Express Pipeline LLC, the sole owner of the approximate 500-mile Midcontinent Express natural gas pipeline system. We also operate the Midcontinent Express pipeline system. Regency Midcontinent Express Pipeline I LLC and ETC Midcontinent Express Pipeline II L.L.C. own the remaining 49.9% and 0.1%, respectively.

The Midcontinent Express pipeline system originates near Bennington, Oklahoma and extends eastward through Texas, Louisiana, and Mississippi, and terminates at an interconnection with the Transco Pipeline near Butler, Alabama. In June 2010, Midcontinent Express completed two natural gas compression projects that increased Zone 1 capacity from 1.5 to 1.8 billion cubic feet per day, and Zone 2 capacity from 1.0 to 1.2 billion cubic feet per day. The incremental capacity is fully subscribed with ten-year binding shipper agreements with creditworthy shippers.

Competition. Capacity on the Midcontinent Express system is 99% contracted under long-term firm service agreements. The majority of volume is contracted to producers moving supply from the Barnett shale and Oklahoma supply basins. These agreements provide the pipeline with fixed monthly reservation revenues for the primary term of such contracts. Although there are other pipeline competitors providing transportation from these supply basins, the Midcontinent Express system was designed and constructed to realize economies of scale and offers its shippers competitive fuel rates and variable costs to transport gas supplies from these midcontinent supply areas to pipelines serving Eastern markets. Competitors to Midcontinent Express include Gulf Crossing Pipeline, Centerpoint Energy Gas Transmission, and NGPL.

Fayetteville Express Pipeline LLC

We own a 50% interest in Fayetteville Express Pipeline LLC, the sole owner of the Fayetteville Express natural gas pipeline system. The 187-mile Fayetteville Express pipeline system originates in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnect with Trunkline Gas Company’s pipeline in Panola County, Mississippi. The system also interconnects with NGPL’s pipeline in White County, Arkansas, Texas Gas Transmission’s pipeline in Coahoma County, Mississippi, and ANR Pipeline Company’s pipeline in Quitman County, Mississippi. It has a total capacity of two billion cubic feet per day, and has currently secured binding shipper commitments for approximately ten years totaling 1.85 billion cubic feet per day of capacity.

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. Our CO2 business segment produces, transports and markets carbon dioxide for use in enhanced oil recovery operations. It also holds ownership interests in several oil-producing fields and owns a crude oil pipeline, all located in the Permian Basin region of West Texas.

Oil Producing Activities

KMCO2 holds ownership interests in oil-producing fields, including (i) an approximate 97% working interest in the SACROC unit; (ii) an approximate 50% working interest in the Yates unit; (iii) an approximate 21% net profits interest in the H.T. Boyd unit; (iv) an approximate 65% working interest in the Claytonville unit; (v) an approximate 99% working interest in the Katz Strawn unit; and (vi) 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 1.33 billion barrels of oil since discovery. 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 and ultimate oil recovery 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 2010, the average purchased carbon dioxide injection rate at SACROC was 220 million cubic feet per day, down from an average of 253 million cubic feet per day in 2009. The average oil production rate for 2010 was approximately 29,200 barrels of oil per day, down from an average of approximately 30,100 barrels of oil per day during 2009.

Our plan over the last several years has been to maintain overall production levels and increase ultimate 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 2010, the Yates unit produced approximately 24,000 barrels of oil per day, down from an average of approximately 26,500 barrels of oil per day during 2009. Unlike our operations at SACROC, where we use carbon dioxide and water to drive oil to the producing wells, we use carbon dioxide 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 and produce 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 203 barrels of oil per day during 2010, down from an average of 218 barrels of oil per day during 2009. 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 Strawn unit. The Katz Strawn unit is located in the Permian Basin area of West Texas and during 2010, the unit produced 284 barrels of oil per day, down from an average of 380 barrels of oil per day during 2009. The decline was primarily due to transition operations associated with converting from water injection to carbon dioxide injection. In July 2009, we announced major investment plans to further expand our operations in the eastern Permian Basin area of Texas, and further information on this investment is discussed above in “—(a) General Development of Business—Recent Developments—CO2.”

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, 2010. The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. When used with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “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		2,187		1,351		997		738		3		3
Natural Gas		5		2		-		-		-		-
Total Wells		2,192		1,353		997		738		3		3

____________

(a)	Includes active wells and wells temporarily shut-in. As of December 31, 2010, 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 salt water 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, 2010. A development well is a well drilled in an already discovered oil field.

The following table reflects our net productive and dry wells that were completed in each of the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
Productive
Development		70		42		47
Exploratory		-		-		-
Dry
Development		-		-		-
Exploratory		-		-		-
Total Wells		70		42		47

____________

Note:

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, 2010:

	Gross		Net
Developed Acres		74,240		69,558
Undeveloped Acres		8,788		8,129
Total		83,028		77,687

____________

Note:

As of December 31, 2010, we have no material amount of acreage expiring in the next three years.

See Note 20 to our consolidated financial statements included elsewhere 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 natural 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 natural gas. Production of natural gas liquids at the Snyder gasoline plant during December 2010 was approximately 16,100 barrels per day, compared to 14,500 barrels per day in December 2009.

Carbon Dioxide Reserves

We own approximately 45% of, and operate, the McElmo Dome unit in Colorado, which contains more than seven trillion cubic feet of recoverable carbon dioxide. Deliverability and compression capacity exceeds 1,300 million cubic feet per day. The McElmo Dome unit produces approximately 1,200 million cubic feet per day.

We also own approximately 11% of the Bravo Dome unit in New Mexico and approximately 87% of the Doe Canyon Deep unit in Colorado. The Bravo Dome unit contains more than 900 billion cubic feet of recoverable carbon dioxide and produces approximately 300 million cubic feet of carbon dioxide per day; the Doe Canyon Deep unit contains more than 900 billion cubic feet of carbon dioxide and produces approximately 110 million cubic feet per day.

Markets. Our principal market for carbon dioxide is for injection into mature oil fields in the Permian Basin, where industry demand is expected to remain strong for the next several years. We are exploring additional potential markets, including enhanced oil recovery targets in California, Wyoming, Oklahoma, 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. and its parent SandRidge Energy, Inc., which produce waste carbon dioxide from natural gas production in the Val Verde Basin and the Pinion field areas 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 tariffs charged by Cortez Pipeline are not regulated, but are based on a consent decree.

Our Central Basin pipeline consists of approximately 143 miles of mainline pipe and 177 miles of lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas. The pipeline has an ultimate 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 carbon dioxide 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.

Our Eastern Shelf carbon dioxide pipeline, which consists of approximately 91 miles of pipe located in the Permian Basin, begins near Snyder, Texas and ends west of Knox City, Texas. The pipeline extends KMCO2’s 1,300 mile carbon dioxide pipeline system into a new area with a current capacity of 65 million standard cubic feet of carbon dioxide per day, expandable to 200 million standard cubic feet per day in the future. The Eastern Shelf Pipeline system is currently flowing 15 million standard cubic feet per day. The tariffs charged on the Eastern Shelf 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 270 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The Pecos pipeline is a 25-mile carbon dioxide pipeline that runs from McCamey to Iraan, Texas. It has a capacity of approximately 120 million cubic feet per day 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 remain strong 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, Doe Canyon and Bravo Dome for transportation of carbon dioxide to the Denver City, Texas market area.

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 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 diameter pipeline segment that runs from Wink to El Paso has a total capacity of 130,000 barrels of crude oil per day, and it transported approximately 118,100 barrels of oil per day in 2010 and approximately 117,000 barrels of oil per day in 2009. 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 other dry-bulk material services facilities, including all transload, engineering, conveying and other in-plant services. Combined, the segment is composed of approximately 124 owned or operated liquids and bulk terminal facilities and approximately 33 rail transloading and materials handling facilities. Our terminals are located throughout the United States, in portions of Canada, and at a single location in the Netherlands. To help our management evaluate segment performance, make operating decisions, and allocate resources, we group our terminal operations into thirteen regions based on geographic location and/or primary operating function, and we classify our terminal operations based on their handling of either liquids or bulk material products.

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 approximately 25 liquids terminals facilities possess liquids storage capacity of approximately 58.2 million barrels, and in 2010 and 2009, these terminals experienced throughput of approximately 620 million barrels and 604 million barrels, respectively, of petroleum, chemicals and vegetable oil products.

Our major liquids terminal assets include the following:

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the Houston, Texas terminal complex located in Pasadena and Galena Park, Texas, along the Houston Ship Channel. Recognized as a distribution hub for Houston’s refineries situated on or near the Houston Ship Channel, the Pasadena and Galena Park terminals are the western Gulf Coast refining community’s central interchange point. The complex has approximately 26.4 million barrels of capacity and is connected via pipeline to 14 refineries, four petrochemical plants and ten major outbound pipelines. Cross-channel pipelines connect the two facilities, and we have an eight-bay, fully automated truck loading rack located at our Pasadena terminal. At the truck rack, a full range of additive services are provided, including additive systems for biodiesel and ethanol. In addition, the facilities have five ship docks and seven barge docks for inbound and outbound movement of products, and the Galena Park terminal is served by the Union Pacific railroad;

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three liquids facilities in the New York Harbor area: one in Carteret, New Jersey; one in Perth Amboy, New Jersey; and one on Staten Island, New York. Our two New Jersey facilities offer viable alternatives for moving petroleum products between the refineries and terminals throughout the New York Harbor and both are New York Mercantile Exchange delivery points for gasoline and heating oil. Both facilities are connected to the Intra Harbor Transfer Service, an operation that offers direct outbound pipeline connections that allow product to be moved from over 20 harbor delivery points to destinations north and west of New York City.

The Carteret facility is located along the Arthur Kill River just south of New York City and has a capacity of approximately 7.8 million barrels of petroleum and petrochemical products. The facility also has pipeline connections to the Buckeye pipeline system, a major products pipeline serving the East Coast. We are currently expanding the facility, adding over one million barrels of new liquids capacity for a large petroleum customer, and we expect this expansion to come on-line in the second and third quarters of 2011. Our Carteret facility has two ship docks and four barge docks. It is connected to the Colonial, Buckeye, Sun and Harbor pipeline systems, and the CSX and Norfolk Southern railroads service the facility.

The Perth Amboy facility is also located along the Arthur Kill River and has a capacity of approximately 3.5 million barrels of petroleum and petrochemical products. The Perth Amboy terminal provides chemical and petroleum storage and handling, as well as dry-bulk handling of salt. In addition to providing product movement via vessel, truck and rail, Perth Amboy has direct access to the Buckeye and Colonial pipelines. The facility has one ship dock and one barge dock, and is connected to the CSX and Norfolk Southern railroads.

Our Kinder Morgan Staten Island terminal is located on Staten Island, New York. The facility is bounded to the north and west by the Arthur Kill River and covers approximately 200 acres, of which 120 acres are used for site operations. The terminal is connected to the Colonial Pipeline and has a storage capacity of approximately three million barrels for gasoline, diesel fuel and fuel oil. The facility also maintains and operates an above ground piping network to transfer petroleum products throughout the operating portion of the site, and it has a ship berth that accommodates tanker vessels;

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two liquids terminal facilities in the Chicago area: one facility located in Argo, Illinois, approximately 14 miles southwest of downtown Chicago and situated along the Chicago sanitary and ship channel; and the other located in the Port of Chicago along the Calumet River. The Argo facility is a large petroleum product and ethanol blending facility and a major break bulk facility for large chemical manufacturers and distributors. It has approximately 2.7 million barrels of tankage capacity and three barge docks. The facility is connected to the Enterprise and Westshore pipelines, and has a direct connection to Midway Airport. The Canadian National railroad services this facility.

The Port of Chicago facility handles a wide variety of liquid chemicals with a working capacity of approximately 796,000 barrels. The facility provides access to a full slate of transportation options, including a deep water barge/ship berth on Lake Calumet, and offers services including truck loading and off-loading, iso-container handling and drumming. There are two ship docks and four barge docks, and the facility is served by the Norfolk Southern railroad;

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our Port of New Orleans facility located in Harvey, Louisiana. The New Orleans facility handles a variety of liquids products such as chemicals, vegetable oils, animal fats, alcohols and oil field products, and also provides ancillary services including drumming, packaging, warehousing, and cold storage services. It has approximately 3.0 million barrels of tankage capacity, three ship docks, and one barge dock. The Union Pacific railroad provides rail service, and the terminal can be accessed by vessel, barge, tank truck, or rail;

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our Kinder Morgan North 40 terminal located in Strathcona County, just east of Edmonton, Alberta, Canada. The North 40 terminal is a crude oil tank farm that serves as a premier blending and storage hub for Canadian crude oil. The facility has storage for approximately 2.16 million barrels of crude oil and has access to several incoming pipelines and all major outbound systems, including a connection with our Trans Mountain pipeline system. The entire capacity of this terminal is contracted under long-term contracts; and

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our five ethanol handling facilities, consisting of services offered by our unit train terminaling facilities located at Richmond and Lomita, California; Linden, New Jersey; Baltimore, Maryland; and Euless, Texas. In March 2010, we began operations at our newly-built Richmond terminal, which is serviced by the Burlington Northern Santa Fe railroad. Our Lomita facility is a high-volume rail ethanol terminal located on a seven acre site serviced by the Burlington Northern Santa Fe railroad. It offers direct connection to Shell’s Carson, California ethanol terminal, the largest west coast ethanol hub and a major supplier of products to our West Coast Products pipeline system.

We acquired our Linden, Baltimore and Euless facilities in 2010. For more information on these train terminal facilities and other terminal acquisitions during 2010, see “—(a) General Development of Business—Recent Developments—Terminals.”

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, Enterprise, 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, truck-railcar-marine transloading, railcar switching and miscellaneous marine services. We own or operate approximately 99 dry-bulk terminals in the United States, Canada and the Netherlands, and combined, our dry-bulk and material transloading facilities handled approximately 92.4 million tons and 78.0 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2010 and 2009, respectively.

Our major bulk terminal assets include the following:

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our Vancouver Wharves bulk marine terminal, located at Port Metro Vancouver, British Columbia, Canada. We own certain bulk terminal buildings and equipment, and we operate the terminal under a 40-year lease agreement. 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, rail track and transloading systems, and five shiploaders. The terminal can handle over 3.5 million tons of cargo annually. In 2010, we completed a long-term terminal expansion that (i) brought on-line and refurbished additional liquids and biodiesel storage tanks that increased terminal liquids throughput capacity; (ii) installed a new shiploader; (iii) improved marine structures and material handling systems to both increase mineral concentrates operations and significantly improve environmental performance; and (iv) added a rail receiving and storage facility to handle ferrous granule (slag). 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, refined petroleum products and sulfur;

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our petroleum coke or coal terminals that we operate or own. We are the largest independent handler of petroleum coke in the U.S., in terms of volume, and in 2010, we handled approximately 12.6 million tons of petroleum coke, as compared to approximately 12.9 million tons in 2009. Petroleum coke is a by-product of the crude oil refining process and has characteristics similar to coal. It is used as a source of fuel in both industrial kilns and in utilities and industrial steam generation facilities, and is used by the steel and aluminum industries in manufacturing processes. A portion of the petroleum coke we handle is imported from or exported to foreign markets. Most of our customers are large integrated oil companies that choose to outsource the storage and loading of petroleum coke for a fee. Most of our petroleum coke assets are located in the state of Texas, and include facilities at the Port of Houston and various refineries. These facilities may also provide handling and storage services for a variety of other bulk materials.

In 2010, we handled approximately 31.6 million tons of coal, as compared to approximately 27.8 million tons of coal handled in 2009. Coal continues to be the fuel of choice for electric generation plants, accounting for more than 50% of U.S. electric generation feedstock. Current domestic supplies are predicted to last for several hundred years and most coal transloaded through our coal terminals is destined for use in coal-fired electric generation facilities.

Our Cora coal terminal is a high-speed, rail-to-barge coal transfer and storage facility located on approximately 480 acres of land along the upper Mississippi River near Rockwood, Illinois. The terminal sits on the mainline of the Union Pacific Railroad and is strategically positioned to receive coal shipments from the western United States. The majority of the coal arrives at the terminal by rail from the Powder River Basin in Wyoming, and the coal is then transferred out on barges to power plants along the Ohio and Mississippi rivers, although small quantities are shipped overseas. The Cora terminal can receive and dump coal from trains and can load barges at the same time. It has ground capacity to store a total of 1.25 million tons of coal, and maximum throughput at the terminal is approximately 13 million tons annually. This coal storage and transfer capacity provides customers the flexibility to coordinate their supplies of coal with the demand at power plants.

Our Grand Rivers, Kentucky terminal is a coal transloading and storage facility located along the Tennessee River just above the Kentucky Dam. The terminal is operated on land under easements with an initial expiration of July 2014 and has current annual throughput capacity of approximately 12 million tons with a storage capacity of approximately one million tons. Our Grand Rivers Terminal provides easy access to the Ohio-Mississippi River network and the Tennessee-Tombigbee River system. The Paducah & Louisville Railroad, a short line railroad, serves Grand Rivers with connections to seven Class I rail lines including the Union Pacific, CSX, and Burlington Northern Santa Fe.

Our Pier IX terminal located on a 42-acre storage site in Newport News, Virginia. The terminal has the capacity to transload approximately 12 million tons of bulk products per year. The terminal can store approximately one million tons of coal, and offers coal blending services and rail to storage or direct transfer to ship. For other dry bulk products, the terminal offers ship to storage to rail or truck. Our Pier IX terminal exports coal to foreign markets, serves power plants on the eastern seaboard of the United States, and imports cement pursuant to a long-term contract. The Pier IX terminal is served by the CSX Railroad, which transports coal from central Appalachian and other eastern coal basins. Cement imported to the Pier IX terminal primarily originates in Europe; and

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our approximately 47 steel and ores/metals terminals located at strategic locations throughout the United States, which transload and handle steel, ferro chrome, ferro manganese, ferro silicon, silicon metal, scrap, plate, coils, bars, slabs, rail, tubes, pipe and rebar. Our value-added services include canning, drumming, bagging and filling boxes and supersacks. Our handling methods include, but are not limited to, the loading and unloading of barges, ships, rail cars and trucks, and inside and outside storage. Combined, these facilities handled approximately 24.7 million tons and 16.7 million tons of steel and steel-related products in 2010 and 2009, respectively. The 48% increase in year-to-year steel volumes in 2010 versus 2009 was primarily due to the difficult economic environment during 2009. While the operating results of our metal handling terminals are affected by a number of business-specific factors, the primary drivers for our ores/metal volumes are general economic conditions in North America, Europe and China, and the levels of worldwide steel production and consumption.

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 33 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 2010 and 2009, our terminals segment, including all bulk, liquids and materials services operations, handled approximately 229,000 and 227,000 railcars, respectively.

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. The weighted average remaining life of the shipping contracts on these pipelines was approximately four years as of December 31, 2010.

Trans Mountain Pipeline System

Our Trans Mountain common carrier pipeline system originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia. We own a connecting pipeline that delivers crude oil 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. Trans Mountain is the sole pipeline carrying crude oil and refined petroleum products from Alberta to the west coast. We believe these facilities provide us the opportunity to consider capacity expansions to the west coast, either in stages or as one project, as the market for offshore exports continue to develop.

In 2010, deliveries on Trans Mountain averaged 297,000 barrels per day. This was an increase of 6% from average 2009 deliveries of 280,507 barrels per day. The crude oil and refined petroleum products transported through Trans Mountain’s pipeline system originates in Alberta and British Columbia. The refined and partially refined petroleum products transported to Kamloops, British Columbia and Vancouver originates from oil refineries located in Edmonton. Products delivered through Trans Mountain’s pipeline system are used in markets in British Columbia, Washington State and elsewhere offshore.

In the fourth quarter of 2010, Trans Mountain completed negotiations with the Canadian Association of Petroleum Producers for a new negotiated toll settlement effective for the period beginning January 1, 2011 and ending December 31, 2015. Trans Mountain filed the settlement with the National Energy Board of Canada in November 2010 and anticipates approval in the first half of 2011.

Express and Jet Fuel Pipeline Systems

We own a one-third ownership interest in the Express pipeline system, and a subordinated debenture issued by Express US Holdings LP, the partnership that maintains ownership of the U.S. portion of the Express pipeline system. We operate the Express pipeline system and account for our one-third 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. The Express Pipeline has a design capacity of 280,000 barrels per day. Receipts at Hardisty averaged 200,000 barrels per day in 2010, as compared to 208,246 barrels per day in 2009.

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. The Platte Pipeline has a current capacity of approximately 150,000 barrels per day downstream of Casper, Wyoming and approximately 140,000 barrels per day downstream of Guernsey, Wyoming. Platte deliveries averaged 142,400 barrels per day during 2010, as compared to 137,810 barrels per day during 2009.

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. The turbine fuel pipeline is referred to in this report as our Jet Fuel pipeline system. In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in Port Metro Vancouver, our Jet Fuel pipeline system’s operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall capacity of 15,000 barrels.

Competition. Trans Mountain and the Express pipeline system are each one of several pipeline alternatives for western Canadian crude oil and refined petroleum production, and each competes against other pipeline providers.

Major Customers

Our total operating revenues are derived from a wide customer base. For each of the years ended December 31, 2010, 2009 and 2008, 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 2010, 2009 and 2008 accounted for 44.8%, 44.8% and 65.6%, respectively, of our total consolidated revenues. 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 U.S. refined petroleum products and crude oil 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 also may 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. 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, the subject of 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. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.

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 Pipeline. Our subsidiary Trans Mountain Pipeline, L.P. previously had a toll settlement with shippers that defined tolls from 2006 to 2010. The settlement expired on December 31, 2010. In the fourth quarter of 2010, Trans Mountain Pipeline completed negotiations with the Canadian Association of Petroleum Producers for a new negotiated toll settlement for our Trans Mountain Pipeline to be effective for the period starting January 1, 2011 and ending December 31, 2015. Trans Mountain filed the settlement with the NEB in November 2010, and anticipates approval from the NEB in the first half of 2011. 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 Products and Oil Pipeline Rate Regulation – U.S. Operations.”

Express Pipeline. 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 contract 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 Products 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

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.

The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation services, including storage services, under the Natural Gas Act of 1938. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978.

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 governed relationships between regulated interstate natural gas pipelines and all of their energy affiliates. These standards were designed to

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extend standards of conduct regulations to cover an interstate natural gas pipeline’s relationship with energy affiliates that are not marketers;

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prevent interstate natural gas pipelines from giving an undue preference to any of their energy affiliates; and

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ensure that transmission is provided on a nondiscriminatory basis.

On October 16, 2008, the FERC issued a Final Rule in Order No. 717, which revised 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. According to the provisions of Order No. 717, a natural gas 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.

On October 15, 2009, the FERC issued Order No. 717-A, an order on rehearing and clarification regarding FERC’s Affiliate Rule—Standards of Conduct, and on November 16, 2009, the FERC issued Order No. 717-B, an order clarifying what employees should be considered marketing function employees. In both orders, the FERC clarified a lengthy list of issues relating to: the applicability, the definition of transmission function and transmission function employees, the definition of marketing function and marketing function employees, the definition of transmission function information, independent functioning, transparency, training, and North American Energy Standards Board business practice standards. The FERC generally reaffirmed its determinations in Order No. 717, but granted rehearing on and clarified provisions. Order Nos. 717-A and 717-B aim to make the standards of conduct clearer and aim to refocus the rules on the areas where there is the greatest potential for abuse. The rehearing and clarification granted in Order No. 717-A are not anticipated to have a material impact on the operation of our interstate pipelines.

In addition to regulatory changes initiated by the FERC, the U.S. Congress passed the Energy Policy Act of 2005. Among other things, the Energy Policy Act amended the Natural Gas Act to: (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.

California Public Utilities Commission Rate Regulation

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

On September 15, 2010, the secretary of the U.S. DOT sent to the U.S. Congress proposed legislation to provide stronger oversight of the nation's pipelines and to increase the penalties for violations of pipeline safety rules. The proposed legislation entitled “Strengthening Pipeline Safety and Enforcement Act of 2010,” would, among other things, increase the maximum fine for the most serious violations from $1 million to $2.5 million, provide additional resources for the enforcement program, require a review of whether safety requirements for “high consequence areas” should be applied instead to entire pipelines, eliminate exemptions and ensure standards are in place for bio-fuel and carbon dioxide pipelines.

The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication. The Pipeline Safety Improvement 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 exists for refined petroleum products pipelines.

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. Such increases in our expenditures, and the extent to which they might be offset, cannot be accurately estimated at this time.

State and Local Regulation

Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and 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. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. 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. 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 generally accepted accounting principles, 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 in this report as the U.S. EPA, or similar state or Canadian 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. 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. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or distributions to limited partners in any particular reporting period. We have accrued an environmental reserve in the amount of $74.7 million as of December 31, 2010. Our reserve estimates range in value from approximately $74.7 million to approximately $122.7 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 16 to our consolidated financial statements included elsewhere in this report.

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 and Canadian statutes. From time to time, the U.S. EPA and state and Canadian regulators 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 “CERCLA” or the “Superfund” law, and analogous state and Canadian 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 and Canadian statutes and regulations. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. The U.S. EPA has recently adopted new regulations under the Clean Air Act that are to take effect in early 2011 and that establish requirements for the monitoring, reporting, and control of greenhouse gas emissions from stationary sources. 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 and processing facilities, storage facilities, terminals and wells. Depending on the nature of those requirements and any additional requirements that may be imposed by state, local and Canadian regulatory authorities, we may be required to incur 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. At this time, we are unable to fully estimate the effect on earnings or operations or the amount and timing of such required capital expenditures; however, we do not believe that we will be materially adversely affected by any such requirements.

Clean Water Act

Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state and Canadian 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, state or Canadian authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian 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. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, referred to in this report as ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. The U.S. Senate has been working on its own legislation for restricting domestic greenhouse gas emissions, and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. It is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA.

The U.S. EPA announced on December 7, 2009, its finding that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment. This finding by the U.S. EPA allowed the agency to adopt regulations that began restricting emissions of greenhouse gases from certain stationary sources using existing provisions of the federal Clean Air Act on January 2, 2011. Additionally, the U.S. EPA has issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissions that occurred in 2010 from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, like our McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.

Because our operations, including our compressor stations and gas processing plants in our Natural Gas Pipelines segment, emit various types of greenhouse gases, primarily methane and carbon dioxide, such legislation or regulation could increase our costs related to operating and maintaining our facilities and require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, they could be significant. While we may be able to include some or all of such increased costs in the rates charged by our natural gas pipelines, such recovery of costs is uncertain in all cases 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 or other regulations. Any of the foregoing could have adverse effects on our business, financial position, results of operations and prospects.

Because natural gas emits less greenhouse gas emissions per unit of energy than competing fossil fuels, energy legislation or U.S. EPA regulatory initiatives could stimulate demand for natural gas by increasing the relative cost of fuels such as coal and oil. In addition, we anticipate that greenhouse gas regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery operations within our CO2 business segment. However, these positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although the magnitude and direction of these impacts cannot now be predicted, greenhouse gas regulations could have material adverse effects on our business, financial position, results of operations and prospects.

Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions. However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon. Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or prospects.

Department of Homeland Security

In Section 550 of the Homeland Security Appropriations Act of 2007, the U.S. Congress gave the Department of Homeland Security, referred to in this report as the DHS, regulatory authority over security at certain high-risk chemical facilities. Pursuant to its congressional mandate, on April 9, 2007, the DHS promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards. This process includes completing security vulnerability assessments, developing site security plans, and implementing protective measures necessary to meet DHS-defined risk-based performance standards. The 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 be 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

Employees

KMGP Services Company, Inc., KMI 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, 2010, KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. had, in the aggregate, 8,142 full-time employees. Approximately 925 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2011 and 2015. KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. each consider relations with their employees to be good. For more information on our related party transactions, see Note 11 to our consolidated financial statements included elsewhere in this report.

Properties

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, the interests in those properties or the use of such properties in our businesses. Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state, provincial or local government land.

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 that 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 a majority of the 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 also have been obtained from railroad companies to run along or 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 included elsewhere in this report.

(e) Available Information

We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports 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. 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 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 should 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

New regulations, rulemaking and oversight, as well as changes in regulations, by regulatory agencies having jurisdiction over our operations could adversely impact our income and operations.

Our pipelines and storage facilities are subject to regulation and oversight by federal, state and local regulatory authorities, such as the FERC, the CPUC and the NEB. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. Regulation affects almost every part of our business and extends to such matters as (i) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (ii) the types of services we may offer to our customers; (iii) the contracts for service entered into with our customers; (iv) the certification and construction of new facilities; (v) the integrity, safety and security of facilities and operations; (vi) the acquisition of other businesses; (vii) the acquisition, extension, disposition or abandonment of services or facilities; (viii) reporting and information posting requirements; (ix) the maintenance of accounts and records; and (x) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines.

New regulations sometimes arise from unexpected sources. For example, the Department of Homeland Security Appropriation Act of 2007 required 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.” New laws or regulations or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to us or our assets could have a material adverse impact on our business, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Regulation.”

Pending FERC and CPUC 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, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the FERC and the CPUC 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. Further, the FERC has initiated an investigation to determine whether some interstate natural gas pipelines, including our Kinder Morgan Interstate Gas Transmission pipeline, have over-collected on rates charged to shippers. 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 charge on our pipelines. Any successful challenge could materially adversely affect our future earnings, cash flows and financial condition.

Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our 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 serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial 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. Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and earnings while the affected asset is temporarily out of service. In addition, 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.

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

We are subject to extensive laws and regulations related to asset integrity. The U.S. DOT, for example, regulates pipelines and certain terminal facilities in the areas of testing, education, training and communication. The U.S. DOT issued final rules (effective February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as “high consequence areas.” The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of the costs to comply with the rules are associated with asset integrity testing and the repairs found to be necessary. Changes such as advances of inspection tools, identification of additional threats to integrity and changes to the amount of pipeline determined to be located in “high consequence areas” can have a significant impact on the costs to perform integrity testing and repairs. We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future assets as required by the U.S. DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our assets.

Further, 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. There can be no assurance as to the amount or timing of future expenditures for asset integrity regulation, 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 deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

We may face competition from competing pipelines and other forms of transportation into the markets we serve as well as with respect to the supply for our pipeline systems.

Any current or future pipeline system or other form of transportation that delivers crude oil, petroleum products or natural gas into the markets that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. 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 otherwise to retain existing customers could be impaired. We also could experience competition for the supply of crude oil, petroleum products or natural gas from both existing and proposed pipeline systems. Several pipelines access many of the same areas of supply as our pipeline systems and transport to markets not served by us.

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

We recently completed several major expansion and new build projects, including the joint venture projects Rockies Express Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline. We also are conducting what are referred to as “open seasons” to evaluate the potential for new construction, alone or with others, in some areas of shale gas formations. A variety of factors outside of our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction. Significant 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.

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

Consistent with the terms of our partnership agreement, we have distributed most of the cash generated by our operations. As a result, we have relied on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisition and growth capital expenditures. However, to the extent we are unable to continue to finance growth externally, our cash distribution policy will significantly impair our ability to grow. We may need new capital to finance these activities. Limitations on our access to capital will impair our ability to execute this strategy. We historically have funded most of these activities with short-term debt and repaid such debt through the subsequent issuance of equity and long-term debt. An inability to access the capital markets, particularly the equity markets, will impair our ability to execute this strategy and have a detrimental impact on our credit profile.

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 and 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, expansion or completed construction project; (ii) the diversion of 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.

Environmental, health and safety 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 CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act or analogous state or Canadian laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass, also may 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 and/or may not provide sufficient coverage in the event an environmental claim is made against us.

Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our business, financial position, results of operations and prospects. 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 undertake 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. 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. For more information, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters.”

Climate change regulation at the federal, state, provincial or regional levels could result in increased operating and capital costs for us.

Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of natural gas, are examples of greenhouse gases. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases. The U.S. EPA began regulating the greenhouse gas emissions of certain stationary sources on January 2, 2011, and has issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, like our McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.

Because our operations, including our compressor stations and natural gas processing plants in our Natural Gas Pipelines and CO2 business segments, emit various types of greenhouse gases, primarily methane and carbon dioxide, such new legislation or regulation could increase our costs related to operating and maintaining our facilities and require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, they could be significant. Recovery of such increased costs from our customers is uncertain in all cases 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 or other regulations. Any of the foregoing could have adverse effects on our business, financial position, results of operations and prospects. For more information about climate change regulation, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters—Climate Change.”

Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines.

The natural gas industry is increasingly relying on natural gas supplies from unconventional sources, such as shale, tight sands and coal bed methane. Natural gas extracted from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. Recently, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of natural gas gathered, treated, processed and transported on our or our joint ventures’ natural gas pipelines, several of which gather gas from areas in which the use of hydraulic fracturing is prevalent.

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

As of December 31, 2010, we had $11.5 billion of consolidated debt (excluding the value of interest rate swap agreements). 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 or to pay distributions 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.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our indebtedness, or any future indebtedness that we incur, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 8 to our consolidated financial statements included elsewhere in this report.

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

As of December 31, 2010, $5.4 billion (47%) of our total $11.5 billion consolidated debt (excluding the value of interest rate swap agreements) was subject to variable interest rates, either as short-term or long-term debt of variable rate debt obligations or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps. Should interest rates increase, the amount of cash required to service this debt would increase and our earnings could be adversely affected. For more information about 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 our 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.

Future business development of our pipelines is dependent on the supply of and demand for the commodities transported by our pipelines.

Our pipelines depend on production of natural gas, oil and other products in the areas served 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 in the Alberta oil sands. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our gas plants and pipelines may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at a level that encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. More over, we do not have volume commitments from the operators of the acreage that has been dedicated to our gathering systems.

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 oil and natural gas producing areas. In addition, with respect to our CO2 business segment, 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 crude oil, natural gas and refined petroleum products pipelines also may 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, natural gas and refined petroleum products 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, crude oil and refined petroleum products, 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, crude oil and refined petroleum products.

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.

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, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and 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 its oil, natural gas liquids and natural gas properties depend to a large degree on prevailing oil and gas prices. For 2011, we estimate that every $1 change in the average West Texas Intermediate crude oil price per barrel would impact our CO2 segment’s cash flows by approximately $5.5 million. 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 (i) weather conditions and events such as hurricanes in the United States; (ii) the condition of the United States economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political stability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources.

A sharp decline in the price of natural gas, natural gas liquids or oil 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 impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Energy Commodity Market Risk.”

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

We 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 price 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 variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those statements. In addition, it is not always possible for us to engage in hedging transactions that completely mitigate our exposure to commodity prices. Our consolidated 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. For more information about our hedging activities, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities.”

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.

The U.S. Congress recently adopted comprehensive financial reform legislation, known as the Dodd-Frank Act, that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The act also requires the CFTC to institute broad new position limits for futures and options traded on regulated exchanges. As the law favors exchange trading and clearing, the Dodd-Frank Act also may require us to move certain derivatives transactions to exchanges where no trade credit is provided and also comply with margin requirements in connection with our derivatives activities that are not exchange traded, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act also requires many counterparties to our derivatives instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us. The Dodd-Frank Act and any new regulations could (i) significantly increase the cost of derivative contracts (including requirements to post collateral, which could adversely affect our available liquidity); (ii) reduce the availability of derivatives to protect against risks we encounter; and (iii) reduce the liquidity of energy related derivatives.

If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition and results of operations.

Our Kinder Morgan Canada segment is subject to U.S. dollar/Canadian dollar exchange rate fluctuations.

We are a U.S. dollar reporting company. As a result of the operations of our Kinder Morgan Canada business segment, a portion of our consolidated assets, liabilities, revenues and expenses are denominated in Canadian dollars. 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.

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 several industries, including the oil and gas industry, the steel industry and in 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 also may 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 and Canada. 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.

Hurricanes, earthquakes and other natural disasters could have an 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, earthquakes 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. Natural disasters can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially.

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, terminals or storage facilities. Our operations could become subject to increased governmental scrutiny that would require increased security measures. 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.

Risks Related to Our Common Units

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

KMI 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 KMI and our general partner and have fiduciary duties to manage the businesses of KMI in a manner that may not be in the best interests of our unitholders. KMI 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.

Our tax treatment depends on our status as a partnership for U.S. 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 were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our common unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. To maintain our status as a partnership for U.S. 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 of 1986, as amended, which we refer to as the Code. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible under certain circumstances for such an entity to be treated as a corporation for U.S. federal income tax purposes. If we were to be treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders 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 common unitholders, likely causing a substantial reduction in the amount of distributions we pay, and in the value of our common units.

Current law or our business may change, causing us to be treated as a corporation for U.S. federal income tax purposes or otherwise subjecting us to a material amount of entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are now subject to 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 gross income that is apportioned to Texas. This tax reduces, and the imposition of such a tax on us by another state will reduce, the cash available for distribution to our common unitholders.

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 U.S. federal income tax purposes, the minimum quarterly distribution and the target distribution levels will be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Recently, members of the U.S. Congress considered substantive changes to the existing U.S. federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any changes could negatively impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our common unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our common unitholders and our general partner because the costs will reduce our cash available for distribution.

Our common unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our common unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, they are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a common unitholder sells its common units, the common unitholder will recognize a gain or loss equal to the difference between the amount realized and that common unitholder’s adjusted tax basis in those common units. Because distributions in excess of a common unitholder’s allocable share of our net taxable income decrease that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income allocated to that unitholder if the unitholder sells such common units at a price greater than that unitholder’s tax basis in those common units, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a common unitholder's share of our nonrecourse liabilities, if a unitholder sells its common units, such unitholder may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Any tax-exempt entity or non-U.S. person should consult its tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine on the validity of such filing positions. A successful IRS challenge to these positions could adversely affect the amount of tax benefits available to a common unitholder. It could also affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a common unitholder’s tax returns.

We adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the common unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional common 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 common unitholders and our general partner. Our 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 adjustment under Section 743(b) of the Code allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the adjustment under Section 743(b) of the Code 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 common unitholders and our general partner. It also could affect the amount of gain from our common 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 common unitholders’ or our general partner’s tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in a termination of our partnership for U.S. federal income tax purposes.

We will be considered to have terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within any twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income being includable in the common unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

A common unitholder whose common units are loaned to a “short seller” to cover a short sale may be considered as having disposed of those common units. If so, the common unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a common unitholder whose common units are loaned to a “short seller” to cover a short sale may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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

The i-units we issue to KMR generally are not allocated income, gain, loss or deduction for U.S. 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.

As a result of investing in our common units, a common unitholder may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to U.S. federal income taxes, our common unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our common unitholders will likely be required to file foreign, state and local income tax returns and pay foreign, state and local income taxes in some or all of these various jurisdictions. Further, our common unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in numerous states in the United States and in Canada. It is the responsibility of each common unitholder to file all required U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

Risks Related to Ownership of Our Common Units if We or KMI 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 of our general partner if KMI defaults on debt.

KMI indirectly owns all the common stock of our general partner. KMI has operations which provide cash independent of dividends that KMI receives from our general partner. Nevertheless, if KMI or Kinder Morgan Kansas, Inc. defaults on its debt, then the lenders under such debt, in exercising their rights as lenders, could acquire control of our general partner or otherwise influence our general partner through control of KMI or Kinder Morgan Kansas, Inc.

Item 1B. Unresolved Staff Comments.

None.

Item 3. Legal Proceedings.

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

Item 4. (Removed and Reserved)

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		Declared Cash Distributions		i-unit Distributions
2010 First Quarter	$	65.55	$	58.00	$	1.07		0.017863
Second Quarter		69.33		57.40		1.09		0.018336
Third Quarter		69.90		63.15		1.11		0.017844
Fourth Quarter		71.72		68.19		1.13		0.017393

2009 First Quarter	$	51.85	$	40.19	$	1.05		0.025342
Second Quarter		53.11		46.00		1.05		0.022146
Third Quarter		55.00		50.08		1.05		0.021292
Fourth Quarter		61.29		53.02		1.05		0.018430

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 $4.60 per unit for 2011; however, no assurance can be given that we will be able to achieve this level of distribution.

As of January 31, 2011, there were approximately 375,000 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” and Note 12 “Commitments and Contingent Liabilities—Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements included elsewhere in this report.

We did not repurchase any units during the fourth quarter of 2010 or sell any unregistered units in the fourth quarter of 2010.

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,
	2010(f)		2009(f)		2008(f)		2007(g)			2006(h)
	(In millions, except per unit and ratio data)
Income and Cash Flow Data:
Revenues	$	8,077.7	$	7,003.4	$	11,740.3	$	9,217.7		$	9,048.7
Operating income	$	1,605.1	$	1,515.1	$	1,551.5	$	807.7		$	1,291.6
Earnings from equity investments	$	223.1	$	189.7	$	160.8	$	69.7		$	74.0
Income from continuing operations	$	1,327.1	$	1,283.8	$	1,317.2	$	423.4		$	1,005.2
Income (loss) from discontinued operations(a)	$	-	$	-	$	1.3	$	173.9		$	14.3
Net income	$	1,327.1	$	1,283.8	$	1,318.5	$	597.3		$	1,019.5
Limited Partners’ interest in net income (loss)	$	431.4	$	331.7	$	499.0	$	(21.3	)	$	490.8

Basic Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations(b)	$	1.40	$	1.18	$	1.94	$	(0.82	)	$	2.12
Income from discontinued operations		-		-		-		0.73			0.07
Net income (loss) per unit	$	1.40	$	1.18	$	1.94	$	(0.09	)	$	2.19

Diluted Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations(b)	$	1.40	$	1.18	$	1.94	$	(0.82	)	$	2.12
Income from discontinued operations		-		-		-		0.73			0.06
Net income (loss) per unit	$	1.40	$	1.18	$	1.94	$	(0.09	)	$	2.18

Per unit cash distribution declared(c)	$	4.40	$	4.20	$	4.02	$	3.48		$	3.26
Ratio of earnings to fixed charges(d)	$	3.50	$	3.82	$	3.77	$	2.13		$	3.64
Capital expenditures	$	1,000.9	$	1,323.8	$	2,533.0	$	1,691.6		$	1,182.1

Balance Sheet Data (at end of period):
Net property, plant and equipment	$	14,603.9	$	14,153.8	$	13,241.4	$	11,591.3		$	10,106.1
Total assets	$	21,861.1	$	20,262.2	$	17,885.8	$	15,177.8		$	13,542.2
Long-term debt(e)	$	10,277.4	$	9,997.7	$	8,274.9	$	6,455.9		$	4,384.3

____________

(a)	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.
(b)	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.
(c)	Represents the amount of cash distributions declared with respect to that year.
(d)	For the purpose of computing the ratio of earnings to fixed charges, earnings are defined as income from continuing operations before income taxes, 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.
(e)	Excludes value of interest rate swaps. Increases to long-term debt for value of interest rate swaps totaled $604.9 million as of December 31, 2010, $332.5 million as of December 31, 2009, $951.3 million as of December 31, 2008, $152.2 million as of December 31, 2007 and $42.6 million as of December 31, 2006.
(f)	For each of the years 2010, 2009 and 2008, includes results of operations for net assets acquired since effective dates of acquisition. For further information on these acquisitions, see Note 3 to our consolidated financial statements included elsewhere in this report.
(g)	Includes results of operations for the remaining 50.2% interest in the Cochin pipeline system that we did not already own, the Vancouver Wharves bulk marine terminal, and the bulk terminal assets and operations acquired from Marine Terminals, Inc. since effective dates of acquisition. We acquired the remaining interest in Cochin effective January 1, 2007, the Vancouver Wharves terminal effective May 30, 2007, and the assets and operations from Marine Terminals, Inc. effective September 1, 2007. Also includes results of operations for the net assets of Trans Mountain for the four months prior to the acquisition date. We acquired the net assets of Trans Mountain from KMI on April 30, 2007.
(h)	Includes results of operations for the net assets of Trans Mountain since January 1, 2006 (prior to our acquisition date of April 30, 2007). 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.

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 and the notes thereto 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 2010, 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.”

Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management's judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and below in “—Information Regarding Forward-Looking Statements.”

General

Our business model, through our ownership and operation of energy related assets, 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 business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.

Our 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, plus the ownership and/or operation of associated natural gas processing and treating facilities;

▪

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 portions of Canada; 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; (ii) the 33 1/3% interest in the Express crude oil pipeline system, which connects Canadian and U.S. producers to refineries located in the U.S. Rocky Mountain and Midwest regions; and (iii) the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.

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 and a portion of our business portfolio (including our Kinder Morgan Canada business segment, the Canadian portion of our Cochin Pipeline, and our bulk and liquids terminal facilities located in Canada) uses the local Canadian dollar as the functional currency for its Canadian operations and enters into foreign currency-based transactions, both of which affect segment results due to the inherent variability in U.S: Canadian dollar exchange rates. To help understand our reported operating results, all of the following references to “currency translation impacts,” “currency changes” or similar terms in this section represent our estimates of the changes in financial results, in U.S. dollars, resulting from fluctuations in the relative value of the Canadian dollar to the U.S. dollar. The references are made to facilitate period-to-period comparisons of business performance and may not be comparable to similarly titled measures used by other registrants.

The profitability of our refined petroleum products pipeline transportation business is generally driven by the volume of petroleum products that we transport and the prices we receive for our services. Transportation volume levels are primarily driven by the demand for the petroleum products being shipped or stored. Demand for petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined products pipelines located in, or that transport to, stable or growing markets and population centers. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index. The regulatory returns on our products pipelines, like our interstate natural gas pipelines and Canadian pipelines, mitigate the downside of these operations.

With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended 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. These long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and 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. Similarly, in our Texas Intrastate Pipeline business, we have long-term transport and sales requirements with minimum volume payment obligations which secure approximately 75% of our sales and transport margins in that business. Therefore, where we have long-term contracts, we are not exposed to short-term changes in commodity supply or demand. However, as contracts expire, we do have exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2010, the remaining average contract life of our natural gas transportation contracts (including our intrastate pipelines) was approximately nine years.

Our CO2 sales and transportation business, like our natural gas pipelines business, has primarily fixed fee contracts with minimum volume requirements, which as of December 31, 2010, had a remaining average contract life of 4.7 years. On a volume-weighted basis, approximately 76% of our contractual volumes are based on a fixed fee, and 24% fluctuates with the price of oil. In the long-term, our success in this business is driven by the demand for carbon dioxide. However, short-term changes in the demand for carbon dioxide typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In our CO2 segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. In that regard, our production during any period is an important measure. In addition, the revenues we receive from our crude oil, natural gas liquids and carbon dioxide 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, 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. Our realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $59.96 per barrel in 2010, $49.55 per barrel in 2009, and $49.42 per barrel in 2008. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $76.93 per barrel in 2010, $59.02 per barrel in 2009 and $97.70 per barrel in 2008.

The factors impacting our Terminals business segment generally differ depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored. As with our products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, 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. While we handle and store a large variety of products in our bulk terminals, the primary products are coal, petroleum coke, and steel. For the most part, we have contracts for this business that have minimum volume guarantees and are volume based above the minimums. Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions. Our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity. Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts (which is typically approximately three years), 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 that follow (see “—Results of Operations” below), 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. Continuing our history of making accretive acquisitions and economically advantageous expansions of existing businesses, in 2010, we invested approximately $2.5 billion for both strategic business acquisitions and expansions of existing assets. Our capital investments have helped us to achieve compound annual growth rates in cash distributions to our limited partners of 4.8%, 8.1%, and 7.0%, respectively, for the one-year, three-year, and five-year periods ended December 31, 2010.

Thus, the amount that we are able to increase distributions to our unitholders will, to some extent, be a function of our ability to complete successful acquisitions and expansions. We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $1.4 billion for our 2011 capital expansion program, including small acquisitions and investment contributions. Based on our historical record and because there is continued demand for energy infrastructure in the areas we serve, 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 at the right cost, and includes factors over which we have limited or no control. Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates.

In addition, our ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions. As a master limited partnership, we distribute all of our available cash and we access capital markets to fund acquisitions and asset expansions. Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, often doing so during periods of notably tight financial conditions. For example, in December 2008, we raised a combined $675 million in cash from public debt and equity offerings. Although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, our investment grade credit rating, and our historical record of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required. For a further discussion of our liquidity, including our public debt and equity offerings in 2010, please see “—Financial Condition” below.

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 our 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, and 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: (i) the economic useful lives of our assets; (ii) the fair values used to assign purchase price from business combinations, determine possible asset impairment charges, and calculate the annual goodwill impairment test; (iii) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (iv) provisions for uncollectible accounts receivables; (v) exposures under contractual indemnifications; and (vi) 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. Generally, 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. In general, we expense legal costs as incurred; accordingly, 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. 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, 2010, our most significant ongoing litigation proceedings involved our West Coast Products Pipelines. Transportation rates charged by certain of these pipeline systems are subject to proceedings at the FERC and the CPUC involving shipper challenges to the pipelines’ interstate and intrastate (California) rates, respectively. Following the FERC’s approval of a settlement agreement we reached with certain shippers (related to a substantial portion of our historical FERC rate challenges on our SFPP , L.P. pipelines), we made settlement payments totaling $206.3 million in June 2010. A second settlement with the only remaining litigant-shipper was filed at the FERC in February 2011 which will resolve the remaining historical FERC rate challenges on our SFPP, L.P. pipelines. The FERC has not yet acted on the second settlement. For more information on our 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. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate our goodwill for impairment on May 31 of each year. There were no impairment charges resulting from our May 31, 2010 impairment testing, and no event indicating an impairment has occurred subsequent to that date. For more information on our goodwill, see Notes 2 and 7 to our consolidated financial statements included elsewhere in this report.

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 in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets. For more information on our amortizable intangibles, see Note 7 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. For more information on our ownership interests in the net quantities of proved oil and gas reserves, see Note 20 to our consolidated financial statements included elsewhere in this report.

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. 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, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately.

Since it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices—a perfectly 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 the part of such hedging transactions 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. 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; accordingly, our financial statements may reflect some volatility due to these hedges. For more information on our hedging activities, see Note 13 to our consolidated financial statements included elsewhere in this report.

Results of Operations

Consolidated

	Year Ended December 31,
	2010			2009			2008
	(In millions)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(b)	$	504.5		$	584.5		$	546.2
Natural Gas Pipelines(c)		836.3			789.6			760.6
CO2(d)		965.5			782.9			759.9
Terminals(e)		641.3			599.0			523.8
Kinder Morgan Canada(f)		181.6			154.5			141.2
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		3,129.2			2,910.5			2,731.7

Depreciation, depletion and amortization expense		(904.8	)		(850.8	)		(702.7	)
Amortization of excess cost of equity investments		(5.8	)		(5.8	)		(5.7	)
General and administrative expenses(g)		(375.2	)		(330.3	)		(297.9	)
Unallocable interest expense, net of interest income(h)		(506.4	)		(431.3	)		(397.6	)
Unallocable income tax expense		(9.9	)		(8.5	)		(9.3	)
Net income		1,327.1			1,283.8			1,318.5
Net income attributable to noncontrolling interests(i)		(10.8	)		(16.3	)		(13.7	)
Net income attributable to Kinder Morgan Energy Partners, L.P.	$	1,316.3		$	1,267.5		$	1,304.8

____________

(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, and taxes, other than income taxes.
(b)	2010 amount includes (i) a $172.0 million increase in expense associated with rate case liability adjustments; (ii) an $18.0 million decrease in income associated with combined property environmental expenses and the demolition of physical assets in preparation for the sale of our Gaffey Street, California land; (iii) a $2.5 million increase in expense associated with environmental liability adjustments; (iv) an $8.8 million gain from the sale of a 50% ownership interest in the Cypress pipeline system and the revaluation of our remaining interest to fair value; and (v) a $0.7 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions. 2009 amount includes (i) a $23.0 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries; (ii) an $18.0 million increase in expense associated with rate case and other legal liability adjustments; (iii) an $11.5 million increase in expense associated with environmental liability adjustments; (iv) a $1.7 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions; and (v) a $0.2 million increase in income from hurricane casualty gains. 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 combined $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.
(c)	2010 amount includes a $0.4 million increase in income from certain measurement period adjustments related to our October 1, 2009 natural gas treating business acquisition. 2009 amount includes (i) a $7.8 million increase in income from hurricane casualty gains; (ii) a decrease in income of $5.6 million resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas; and (iii) a $0.1 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries. 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) an increase in income of $5.6 million 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.
(d)	2010 amount includes a $5.3 million unrealized gain on derivative contracts used to hedge forecasted crude oil sales. 2009 amount includes a $13.5 million unrealized loss on derivative contracts used to hedge forecasted crude oil sales. 2008 amount includes a $0.3 million increase in expense associated with environmental liability adjustments.
(e)	2010 amount includes (i) a combined $7.4 million decrease in income from casualty insurance deductibles and the write-off of assets related to casualty losses; (ii) a combined $4.1 million decrease in income from the amounts previously reported in our 2010 fourth quarter earnings release issued on January 19, 2011, associated with a write-down of the carrying value of net assets to be sold to their estimated fair values as of December 31, 2010; (iii) a $0.6 million increase in expense related to storm and flood clean-up and repair activities; (iv) a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminals; and (v) a $0.2 million decrease in expense from certain measurement period adjustments related to our March 5, 2010 Slay Industries terminal acquisition. 2009 amount includes (i) a $24.0 million increase in income from hurricane and fire casualty gains and clean-up and repair activities; (ii) a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal; (iii) a $0.9 million increase in expense associated with environmental liability adjustments; and (iv) a $0.7 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries. 2008 amount includes (i) a combined $7.2 million decrease in income related to fire damage and repair activities; (ii) a combined $5.7 million decrease in income related to hurricane clean-up and repair activities; (iii) a combined $2.8 million increase in expense from both 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.
(f)	2009 amount includes a $14.9 million increase in expense primarily due to certain non-cash regulatory accounting adjustments to Trans Mountain’s carrying amount of the previously established deferred tax liability, and a $3.7 million decrease in expense due to a certain non-cash accounting adjustment related to book tax accruals made by the Express pipeline system. 2008 amount includes a $19.3 million decrease in expense associated with favorable changes in Canadian income tax rates, and a combined $18.9 million increase in expense due to certain non-cash Trans Mountain regulatory accounting adjustments.
(g)	Includes unallocated litigation and environmental expenses. 2010 amount includes (i) a $4.6 million increase in non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $4.2 million increase in expense for certain asset and business acquisition costs; (iii) a $1.6 million increase in legal expense associated with items disclosed in these footnotes such as legal settlements and pipeline failures; and (iv) a $0.2 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season. 2009 amount includes (i) a $5.7 million increase in non-cash compensation expense, allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $2.3 million increase in expense for certain asset and business acquisition costs, which under prior accounting standards would have been capitalized; (iii) a $1.3 million increase in expense for certain land transfer taxes associated with our April 30, 2007 Trans Mountain acquisition; and (iv) a $2.7 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season. 2008 amount includes (i) a $5.6 million increase in non-cash compensation expense, allocated to us from KMI (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 increase in expense resulting from the write-off of certain third-party acquisition costs, which under prior accounting standards would have been capitalized; (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.
(h)	2010 and 2009 amounts include increases in imputed interest expense of $1.1 million and $1.6 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition. 2008 amount includes (i) a $7.1 million decrease in interest expense 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.
(i)	2010, 2009 and 2008 amounts include decreases of $4.6 million, $0.7 million and $0.4 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2010, 2009 and 2008 items previously disclosed in these footnotes.

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.

In 2010, total segment earnings before depreciation, depletion and amortization increased $218.7 million (8%) compared to 2009, and the overall increase included a $132.2 million decrease in earnings from the effect of the certain items described in the footnotes to the table above (combining to decrease total segment EBDA by $182.5 million and $50.3 million in 2010 and 2009, respectively). The remaining $350.9 million (12%) increase in total segment earnings before depreciation, depletion and amortization in 2010 versus 2009 resulted from better performance from all five of our reportable business segments, mainly due to increases attributable to our CO2 and Terminals business segments.

During 2010, we benefitted from (i) higher revenues from crude oil, natural gas liquids and carbon dioxide sales, due largely to the positive impact of higher energy prices—primarily in the last six months of the year—relative to 2009; (ii) incremental earnings from the shale gas gathering and treating services offered by our Kinder Morgan Natural Gas Treating operations and our 50%-owned KinderHawk Field Services; (iii) higher revenues from refined petroleum products delivery revenues by our West Coast products pipelines and higher earnings from ethanol related handling activities at our West Coast and Southeast products terminal operations; (iv) the positive impact from a full year of operations from our Kinder Morgan Louisiana and our 50%-owned Midcontinent Express natural gas pipeline systems; and (v) incremental earnings from both newly acquired and expanded bulk and liquids terminal operations.

In 2009, our total segment earnings before depreciation, depletion and amortization increased by 7% both before and after taking into the effect of the certain items described in the footnotes to the table above (combined, the certain items described in the footnotes to the table above decreased segment EBDA by $50.3 million and $26.5 million in 2009 and 2008, respectively). The overall increase in segment earnings before depreciation, depletion and amortization consisted of year-to-year increases from all five of our business segments, with the strongest growth coming from our Terminals and Products Pipelines business segments.

During 2009, we benefitted from (i) reduced operating expenses (including lower fuel and power expenses), due in part from ongoing weak economic conditions during the year which decreased total bulk tonnage and refined petroleum products delivery volumes; (ii) higher ethanol storage and blending revenues at existing and expanded refined petroleum products terminal facilities; (iii) the start-up of our Kinder Morgan Louisiana, 50%-owned Midcontinent Express, and 50%-owned Rockies Express-East natural gas pipelines; and (iv) a full year of operations from our 50%-owned Rockies Express-West natural gas pipeline.

Products Pipelines

	Year Ended December 31,
	2010			2009			2008
	(In millions, except operating statistics)
Revenues(a)	$	883.0		$	826.6		$	815.9
Operating expenses(b)		(414.6	)		(269.5	)		(291.0	)
Other expense(c)		(4.2	)		(0.6	)		(1.3	)
Earnings from equity investments(d)		33.1			29.0			24.4
Interest income and Other, net-income(e)		16.4			12.4			2.0
Income tax expense(f)		(9.2	)		(13.4	)		(3.8	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	504.5		$	584.5		$	546.2

Gasoline (MMBbl)(g)		403.5			400.1			398.4
Diesel fuel (MMBbl)		148.3			143.2			157.9
Jet fuel (MMBbl)		106.2			111.4			117.3
Total refined product volumes (MMBbl)		658.0			654.7			673.6
Natural gas liquids (MMBbl)		25.2			26.5			27.3
Total delivery volumes (MMBbl)(h)		683.2			681.2			700.9
Ethanol (MMBbl)(i)		29.9			23.1			18.7

__________

(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)	2010, 2009 and 2008 amounts include increases in expense of $2.5 million, $11.5 million and $9.2 million, respectively, associated with environmental liability adjustments. 2010 amount also includes a $172.0 million increase in expense associated with rate case liability adjustments, and a $14.1 million increase in expense associated with environmental clean-up expenses and the demolition of physical assets in preparation for the sale of our Gaffey Street, California land. 2009 amount also includes a $23.0 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries, and an $18.0 million increase in expense associated with rate case and other legal 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.
(c)	2010 amount includes disposal losses of $3.9 million related to the retirement of our Gaffey Street, California land. 2009 amount includes a gain of $0.2 million from hurricane casualty indemnifications. 2008 amount includes a gain of $1.3 million from the 2007 sale of our North System, and 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.
(e)	2010, 2009 and 2008 amounts include a $0.7 million increase in income, a $1.7 million increase in income, and a $3.6 million decrease in income, respectively, resulting from unrealized foreign currency gains and losses on long-term debt transactions. 2010 amount also includes an $8.8 million gain from the sale of a 50% ownership interest in the Cypress pipeline system and the revaluation of our remaining interest to fair value.
(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).
(g)	Volumes include ethanol pipeline volumes.
(h)	Includes Pacific, Plantation, Calnev, Central Florida, Cochin, and Cypress pipeline volumes.
(i)	Represents total ethanol volumes, including ethanol pipeline volumes.

Combined, the certain items described in the footnotes to the table above decreased segment earnings before depreciation, depletion and amortization expenses by $183.0 million in 2010, $50.6 million in 2009, and $25.3 million in 2008, and decreased revenues by $5.1 million in 2008. Following is information related to the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses; and (ii) operating revenues in both 2010 and 2009, when compared to the respective prior year:

Year Ended December 31, 2010 versus Year Ended December 31, 2009

	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Pacific operations	$	40.0		15	%	$	49.9		13	%
Southeast Terminals		14.9		28	%		12.0		15	%
West Coast Terminals		10.5		16	%		10.7		12	%
Plantation Pipeline		3.2		8	%		(0.3	)	(1	)%
Central Florida Pipeline		2.9		6	%		1.4		2	%
Cochin Pipeline		(20.4	)	(38	)%		(16.6	)	(27	)%
All others (including eliminations)		1.3		1	%		(0.7	)	(1	)%
Total Products Pipelines	$	52.4		8	%	$	56.4		7	%

__________

The primary increases and decreases in our Products Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in 2010 compared to 2009 were attributable to the following:

▪

a $40.0 million (15%) increase in earnings from our Pacific operations—due largely to a $49.9 million (13%) increase in operating revenues, consisting of a $32.1 million (11%) increase in mainline delivery revenues and a $17.8 million (17%) increase in fee-based terminal revenues. The increase in pipeline delivery revenues was attributable to higher average tariff rates in 2010 (due in part to FERC-approved rate increases) and to military tender rate increases. Overall mainline delivery volumes were essentially flat across both years. The increase in terminal revenues was mainly attributable to incremental ethanol handling services that were due in part to mandated increases in ethanol blending rates in California since the end of 2009. For all segment assets combined, ethanol volumes handled increased 29% in 2010;

▪

a $14.9 million (28%) increase in earnings from our Southeast terminal operations—due to both increased ethanol throughput, driven by continued high demand in the ethanol and biofuels markets, and higher product inventory gains relative to the prior year;

▪

a $10.5 million (16%) increase in earnings from our West Coast terminal operations—driven by higher warehousing revenues and incremental customers at our combined Carson/Los Angeles Harbor terminal system, incremental biodiesel revenues from our liquids facilities located in Portland, Oregon, and incremental earnings contributions from the terminals’ Portland, Oregon Airport pipeline, which was acquired on July 31, 2009;

▪

a $3.2 million (8%) increase in earnings from our 51%-owned Plantation Pipe Line Company—due to higher net income earned by Plantation in 2010. The increase in Plantation’s earnings (on a 100% basis) was driven by both higher products transportation revenues and higher oil loss allowance revenues. The increase in transportation revenues was due to an overall 2% increase in pipeline throughput volumes in 2010, due in part to an upgrade at a refinery in Louisiana and to mainline allocation on a competing pipeline. The increase in oil loss allowance revenues was associated with the increase in volumes and an increase in products prices, relative to the prior year;

▪

a $2.9 million (6%) increase in earnings from our Central Florida Pipeline—due mainly to incremental product inventory gains and partly to higher ethanol handling revenues; and

▪

a $20.4 million (38%) decrease in earnings from our Cochin pipeline system—attributable to a $16.6 million (27%) drop in revenues and a $3.8 million (35%) increase in operating expenses. The lower revenues reflected a 32% decline in system delivery volumes, which resulted mainly from lower propane volumes due to milder weather, a drop in grain drying demand, and to the negative impacts from unfavorable tariff changes in 2010. The decrease in earnings from higher operating expenses was primarily related to favorable settlements reached in the first quarter of 2009 with the seller of the remaining approximate 50.2% interest in the Cochin pipeline system that we purchased on January 1, 2007.

Year Ended December 31, 2009 versus Year Ended December 31, 2008

	EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)
Pacific operations	$	21.2	8	%	$	4.2		1	%
West Coast Terminals		13.4	25	%		12.8		16	%
Central Florida Pipeline		9.2	22	%		10.7		20	%
Transmix operations		7.7	26	%		6.2		15	%
Plantation Pipeline		3.8	10	%		(24.9	)	(57	)%
Calnev Pipeline		3.3	6	%		(0.2	)	-
All others (including eliminations)		5.0	5	%		(3.2	)	(2	)%
Total Products Pipelines	$	63.6	11	%	$	5.6		1	%

__________

All of the assets and operations included in our Products Pipelines business segment reported higher earnings before depreciation, depletion and amortization expenses in 2009, when compared to 2008, and the primary increases and decreases in earnings were attributable to the following:

▪

a $21.2 million (8%) increase in earnings from our Pacific operations—driven by an $18.8 million decrease in combined operating expenses and a $4.2 million increase in total operating revenues, relative to 2008. The decrease in operating expenses was primarily due to (i) overall cost reductions (due in part to a 4% decrease in overall mainline delivery volumes) and delays in certain non-critical spending; (ii) lower fuel and power, and outside services expenses; (iii) higher product gains; (iv) lower right-of-way and environmental expenses; and (v) lower legal expenses (due in part to incremental expenses associated with certain litigation settlements reached in 2008). The increase in revenues was driven by higher delivery revenues to U.S. military customers, due to both military tender increases and 2009 tariff rate increases which positively impacted our California products delivery revenues, and higher terminal revenues, primarily related to incremental ethanol handling services;

▪

a $13.4 million (25%) increase in earnings from our West Coast terminal operations—largely revenue related, and due in part to the completion of a number of capital expansion projects that modified and upgraded terminal infrastructure since the end of 2008. Revenues at our combined Carson/Los Angeles Harbor terminal complex increased $8.8 million, due mainly to increased warehouse charges (escalated warehousing contract rates resulting from customer contract revisions made since the end of 2008) and to year-over-year customer growth (including incremental terminaling for U.S. defense fuel services). Revenues from our remaining West Coast facilities increased $4.0 million, due mostly to additional throughput and storage services associated with renewable fuels (both ethanol and biodiesel);

▪

a $9.2 million (22%) increase in earnings from our Central Florida Pipeline—driven by incremental ethanol revenues and higher refined products delivery revenues. The increase from ethanol handling resulted from completed capital expansion projects that provided ethanol storage and terminal service beginning in mid-April 2008 at our Tampa and Orlando terminals. The increase in pipeline delivery revenues was driven by higher average transportation rates that reflect two separate mid-year tariff rate increases that became effective July 1, 2009 and 2008;

▪

a $7.7 million (26%) increase in earnings from our transmix operations—mainly due to a combined $8.0 million increase in revenues, recognized in August 2009, that was associated with certain true-ups related to transmix settlement gains (including tank gains and incremental loss allowance gains);

▪

a $3.8 million (10%) increase in earnings from our equity ownership in Plantation Pipe Line Company. Plantation’s net income (on a 100% basis) increased in 2009 as a result of both higher pipeline transportation revenues and higher other non-operating income. The increase in transportation revenues was due to higher volumes and higher average tariffs, and the increase in other income was due largely to insurance reimbursements related to the settlement of certain previous environmental matters. The overall $24.9 million (57%) decrease in revenues associated with our investment in Plantation was mainly due to a restructuring of the Plantation operating agreement between ExxonMobil and us. On January 1, 2009, both parties agreed to reduce the fixed operating fees we earn from operating the pipeline and to charge pipeline operating expenses directly to Plantation. The change had a minimal impact to our earnings, as the drop in revenues was more than offset by a corresponding $26.9 million decrease in combined operating expenses; and

▪

a $3.3 million (6%) increase in earnings from our Calnev Pipeline—driven by a $2.9 million reduction in combined fuel and power expenses. The drop in fuel and power expenses was due primarily to an overall 8% decrease in refined products delivery volumes in 2009, chiefly due to lower diesel volumes.

Natural Gas Pipelines

	Year Ended December 31,
	2010			2009			2008
	(In millions, except operating statistics)
Revenues(a)	$	4,416.5		$	3,806.9		$	8,422.0
Operating expenses(b)		(3,750.3	)		(3,193.0	)		(7,804.0	)
Other income(c)		-			7.8			2.7
Earnings from equity investments		169.1			141.8			113.4
Interest income and Other, net-income(d)		4.3			31.8			29.2
Income tax expense		(3.3	)		(5.7	)		(2.7	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	836.3		$	789.6		$	760.6

Natural gas transport volumes (Bcf)(e)		2,584.2			2,285.1			2,008.6
Natural gas sales volumes (Bcf)(f)		797.9			794.5			866.9

__________

(a)	2010 amount includes a $0.4 million increase in revenues from certain measurement period adjustments related to our October 1, 2009 natural gas treating business acquisition.
(b)	2009 and 2008 amounts include a $5.6 million decrease in income and a $5.6 million increase in income, respectively, resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas. Beginning in the second quarter of 2008, our Casper and Douglas gas processing operations discontinued hedge accounting, and the last of the related derivative contracts expired in December 2009. 2009 amount also includes a $0.1 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries. 2008 amount also includes a $5.0 million increase in expense related to hurricane clean-up and repair activities, a $0.3 million increase in expense associated with legal liability adjustments, and a $0.5 million decrease in expense associated with environmental liability adjustments.
(c)	2009 amount represents gains from hurricane casualty indemnifications.
(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, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana 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 above increased segment earnings before depreciation, depletion and amortization expenses by $0.4 million in 2010, $2.1 million in 2009, and $13.8 million in 2008, and increased revenues by $0.4 million in 2010. Following is information related to the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses; and (ii) operating revenues in both 2010 and 2009, when compared to the respective prior year.

Year Ended December 31, 2010 versus Year Ended December 31, 2009

	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Kinder Morgan Natural Gas Treating	$	33.8		360	%	$	48.1		339	%
KinderHawk Field Services(a)		19.5		n/a			-		-
Midcontinent Express Pipeline(a)		15.4		105	%		-		-
Kinder Morgan Louisiana Pipeline		14.1		34	%		42.5		167	%
Casper and Douglas Natural Gas Processing		8.8		71	%		30.5		41	%
Kinder Morgan Interstate Gas Transmission		(17.2	)	(14	)%		3.8		2	%
Texas Intrastate Natural Gas Pipeline Group		(16.0	)	(4	)%		487.6		14	%
Rockies Express Pipeline(a)		(10.0	)	(10	)%		-		-
All others (including eliminations)		-		-			(3.3	)	(3	)%
Total Natural Gas Pipelines	$	48.4		6	%	$	609.2		16	%

__________

(a)	Equity investments. We record earnings under the equity method of accounting, but we receive distributions in amounts essentially equal to equity earnings plus depreciation and amortization expenses less sustaining capital expenditures.

The overall increase in our Natural Gas Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in 2010 compared to 2009 was driven by incremental contributions from both our Kinder Morgan Natural Gas Treating operations and our 50%-owned KinderHawk Field Services LLC, and by the inclusion of a full year of operations from both our 50%-owned Midcontinent Express pipeline system and our fully-owned Kinder Morgan Louisiana pipeline system.

We acquired the majority of our Kinder Morgan Natural Gas Treating operations from CrossTex Energy, Inc. on October 1, 2009, and we acquired the remaining portio