form10k_2010.htm

10-K 1 form10k_2010.htm KMP 10K 2010 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.

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

▪

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;

▪

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;

▪

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;

▪

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;

▪

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;

▪

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

▪

Natural Gas Pipelines

▪

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;

▪

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;”

▪

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;

▪

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;

▪

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;

▪

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;”

▪

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

▪

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

▪

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

▪

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

▪

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;

▪

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;

▪

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;

▪

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;

▪

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);

▪

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;

▪

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;

▪

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

▪

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

▪

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

▪

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;

▪

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;

▪

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

▪

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

▪

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

▪

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:

▪

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

▪

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

▪

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

▪

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:

▪

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;

▪

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;

▪

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;

▪

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

▪

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:

▪

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;

▪

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;

▪

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;

▪

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;

▪

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

▪

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:

▪

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;

▪

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

▪

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

▪

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

▪

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

▪

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 portion from Gas-Chill, Inc. on September 1, 2010. The business consists of multiple natural gas treating plants, predominantly located in Texas and Louisiana, which are used to remove impurities and liquids from natural gas in order to meet pipeline quality specifications. Combined, the acquired treating assets contributed incremental earnings before depreciation, depletion and amortization of $33.8 million, revenues of $48.1 million and operating expenses of $14.1 million in 2010.

We acquired our 50% ownership interest in KinderHawk Field Services LLC on May 21, 2010. The joint venture gathers and treats natural gas originating from the Haynesville shale gas formation located in northwest Louisiana. Petrohawk Energy Corporation owns the remaining 50% ownership interest. The increase in earnings from our equity investment in the Midcontinent Express pipeline system was due to the inclusion of a full year of operations in 2010 and to an expansion of natural gas transportation service since the end of 2009. Midcontinent Express system initiated interim natural gas transportation service for its Zone 1 pipeline segment on April 10, 2009, achieved full Zone 1 service on May 21, 2009, and achieved full Zone 2 service on August 1, 2009. In addition, 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.

We commenced limited natural gas transportation service on our Kinder Morgan Louisiana natural gas pipeline system in April 2009, and we completed construction and began full transportation service on the system’s remaining portions on June 21, 2009. For the comparable periods of 2010 and 2009, the increase in earnings consisted of a $36.6 million increase in system operating income (revenues less operating expenses), due mainly to incremental transportation service, and a $22.5 million decrease in non-operating other income, primarily due to higher non-operating other income realized in 2009 pursuant to FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance).

Other year-to-year increases and decreases in segment earnings before depreciation, depletion and amortization in 2010 versus 2009 included the following:

▪

an $8.8 million (71%) increase in earnings from our Casper Douglas gas processing operations—primarily attributable to higher natural gas processing spreads, resulting from higher percentage increases in natural gas liquids prices (impacting sales) relative to percentage increases in natural gas prices (impacting costs of sales). The $30.5 million (41%) year-to-year increase in revenues was driven by both a 4% increase in natural gas liquids sales volumes and a 41% increase in average natural gas liquids sales prices, when compared to 2009;

▪

a $17.2 million (14%) decrease in earnings from our Kinder Morgan Interstate Gas Transmission pipeline system—driven by a $7.2 million decrease due to lower margins on operational sales of natural gas, and a $6.8 million decrease due to lower pipeline net fuel recoveries. Both decreases in earnings were due mainly to lower average natural gas prices in 2010. KMIGT’s operational gas sales are primarily made possible by both collection of fuel in kind pursuant to its currently effective gas transportation tariff, and by recoveries of cushion gas;

▪

a $16.0 million (4%) overall decrease in earnings from our Texas intrastate natural gas pipeline group—driven by (i) a $15.8 million decrease in earnings from overall storage activities (primarily due to lower price spreads due to unfavorable market conditions relative to 2009); (ii) a $3.5 million decrease from lower interest income, due to a one-time natural gas loan to a single customer in 2009; (iii) a $3.4 million decrease due to lower natural gas gains (primarily due to 2009 volume measurement gains related to the normal tracking of natural gas throughout the pipeline system); and (iv) a $2.8 million decrease in natural gas sales margins, largely attributable to higher costs of natural gas supplies relative to sales prices and less favorable market conditions. The overall decrease in earnings in 2010 versus 2009 was partially offset by a $9.5 million increase in earnings due to higher natural gas processing margins, due mainly to higher natural gas liquids prices relative to 2009, and a $3.1 million increase in earnings due to incremental equity earnings from our 40%-owned Endeavor Gathering LLC, acquired effective November 1, 2009; and

▪

a $10.0 million (10%) decrease in earnings from our 50%-owned Rockies Express pipeline system—reflecting lower net income earned by Rockies Express Pipeline LLC. Compared to the prior year, Rockies Express’ net income (on a 100% basis) dropped $18.1 million (9%) in 2010, when compared to 2009. The overall decrease in earnings consisted of (i) a $70.3 million decrease primarily related to higher interest expenses, net of interest income; and (ii) a $52.2 million increase from higher system operating income.

The increase in interest expenses was due to higher non-cash allowances for borrowed funds used during construction in 2009 (which reduces interest expenses), and to debt obligations shifting from short-term to long-term at higher interest rates in 2010. The increase in operating income was driven by incremental transportation service revenues related to the completion and start-up of the Rockies Express-East pipeline segment, the third and final phase of the Rockies Express system. Rockies Express-East began initial pipeline service on June 29, 2009 and began full operations on November 12, 2009.

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

	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Kinder Morgan Louisiana Pipeline	$	30.2		n/a		$	25.3		n/a
Midcontinent Express Pipeline(a)		14.1		n/a			-		-
Rockies Express Pipeline(a)		13.2		16	%		-		-
Kinder Morgan Interstate Gas Transmission		9.6		8	%		(24.6	)	(4	)%
Kinder Morgan Gas Treating		9.4		n/a			14.2		n/a
TransColorado Pipeline		(3.5	)	(6	)%		(2.6	)	(4	)%
Texas Intrastate Natural Gas Pipeline Group		(34.0	)	(9	)%		(4,580.7	)	(57	)%
All others (including eliminations)		1.7		2	%		(46.7	)	(25	)%
Total Natural Gas Pipelines	$	40.7		5	%	$	(4,615.1	)	(55	)%

__________

(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 the segment’s earnings before depreciation, depletion and amortization expenses in 2009 compared to 2008 was driven by incremental contributions from our Kinder Morgan Louisiana pipeline system and our equity investments in the Midcontinent Express and Rockies Express pipeline systems. For the Kinder Morgan Louisiana and Midcontinent Express pipelines, the year-to-year increases in earnings were due mainly to the commencement and/or expansion of natural gas transportation service since the end of 2008, as described above.

For Rockies Express, the increase in earnings was driven by higher equity earnings from both the completion and start-up of the Rockies Express-East pipeline segment, described above, and the inclusion of a full year of operations from the Rockies Express-West pipeline segment, which began initial pipeline service on January 12, 2008, and began full operations on May 20, 2008. The overall increase in earnings in 2009 versus 2008 was partly offset by a decrease in equity earnings due to approximately 60 miles of the Rockies Express-East pipeline segment being shutdown due to a pipeline girth weld failure that occurred on November 14, 2009. The Rockies Express-East line was repaired (following coordination with the U.S. Department of Transportation) and the affected segment returned to reduced capacity on January 27, 2010. Rockies Express-East returned to full service on February 6, 2010, and we estimate the negative impact on our equity earnings from the pipeline’s failure in the fourth quarter of 2009 was approximately $16 million.

Following is information on other year-over-year increases and decreases in segment earnings before depreciation, depletion and amortization expenses in 2009 compared to 2008:

▪

a $9.6 million (8%) increase in earnings from our Kinder Morgan Interstate Gas Transmission pipeline system— driven by higher margins on operational gas sales, higher firm transportation demand fees (resulting from both system expansions and incremental ethanol customers), and higher pipeline fuel recoveries. The system’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and its recovery of storage cushion gas volumes;

▪

incremental earnings of $9.4 million from our Kinder Morgan Natural Gas Treating operations—acquired effective October 1, 2009 and discussed above;

▪

a $3.5 million (6%) decrease in earnings from our TransColorado pipeline system—primarily due to a $2.6 million (4%) drop in natural gas transportation revenues, and partly due to increases in both pipeline remediation expenses and property tax expenses. The decrease in transportation revenues related primarily to the negative impact caused by the increased transportation service offered by a competing pipeline in 2009; and

▪

a $34.0 million (9%) decrease in earnings from our Texas intrastate natural gas pipeline group—mainly attributable to (i) lower margins from natural gas sales, primarily due to lower sales volumes and higher average supply prices relative to average sales prices. The increase in supply prices resulted from a decline in field volumes being replaced with more expensive supplies from more liquid supply locations in 2009; (ii) lower natural gas processing margins, due to unfavorable gross processing spreads as a result of significantly lower average natural gas liquids prices; and (iii) higher system operating expenses, due primarily to higher pipeline integrity expenses. The overall decrease in earnings was partially offset by higher natural gas storage margins, which resulted from favorable proprietary and fee based storage activities and from the leasing of additional storage capacity to customers due to completed capital expansion projects since the end of 2008.

The overall changes in both segment revenues and segment operating expenses (which include natural gas costs of sales) in both pairs of comparable years primarily relate to the natural gas purchase and sale activities of our Texas intrastate natural gas pipeline group, with the variances from year-to-year in both revenues and operating expenses mainly due to corresponding changes in the intrastate group’s average prices and volumes for natural gas purchased and sold. Our intrastate group both purchases and sells significant volumes of natural gas, which is often stored and/or transported on its pipelines, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases and decreases in its natural gas sales revenues are largely offset by corresponding increases and decreases in its natural gas purchase costs. Our intrastate group accounted for 88%, 89% and 95%, respectively, of the segment’s revenues in 2010, 2009 and 2008, and 94%, 95% and 97%, respectively, of the segment’s operating expenses in 2010, 2009 and 2008.

CO2

	Year Ended December 31,
	2010			2009			2008
	(In millions, except operating statistics)
Revenues(a)	$	1,245.7		$	1,035.7		$	1,133.0
Operating expenses(b)		(308.1	)		(271.1	)		(391.8	)
Earnings from equity investments		22.5			22.3			20.7
Interest income and Other, net-income		4.5			-			1.9
Income tax benefit (expense)		0.9			(4.0	)		(3.9	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	965.5		$	782.9		$	759.9

Carbon dioxide delivery volumes (Bcf)(c)		753.3			774.0			732.1
SACROC oil production (gross)(MBbl/d)(d)		29.2			30.1			28.0
SACROC oil production (net)(MBbl/d)(e)		24.3			25.1			23.3
Yates oil production (gross)(MBbl/d)(d)		24.0			26.5			27.6
Yates oil production (net)(MBbl/d)(e)		10.7			11.8			12.3
Natural gas liquids sales volumes (net)(MBbl/d)(e)		10.0			9.5			8.4
Realized weighted average oil price per Bbl(f)(g)	$	59.96		$	49.55		$	49.42
Realized weighted average natural gas liquids price per Bbl(g)(h)	$	51.03		$	37.96		$	63.00

__________

(a)	2010 and 2009 amounts include unrealized gains of $5.3 million (from increases in revenues) and unrealized losses of $13.5 million (from decreases in revenues), respectively, on derivative contracts used to hedge forecasted crude oil sales.
(b)	2008 amount includes a $0.3 million increase in expense associated with environmental liability adjustments.
(c)	Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline, Eastern Shelf and Pecos pipeline volumes.
(d)	Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit and an approximately 50% working interest in the Yates unit.
(e)	Net to us, after royalties and outside working interests.
(f)	Includes all of our crude oil production properties.
(g)	Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
(h)	Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

Our CO2 segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO2) and crude oil, and the production and marketing of natural gas and natural gas liquids. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and Sales and Transportation Activities.

Combined, the certain items described in the footnotes to the table above increased both segment revenues and segment earnings before depreciation, depletion and amortization expenses by $5.3 million in 2010, decreased both revenues and earnings by $13.5 million in 2009, and decreased earnings by $0.3 million in 2008. For each of the segment’s two primary businesses, 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)
Oil and Gas Producing Activities	$	114.7	20	%	$	160.5		19	%
Sales and Transportation Activities		49.1	23	%		38.0		15	%
Intrasegment Eliminations		-	-			(7.3	)	(16	)%
Total CO2	$	163.8	21	%	$	191.2		18	%

__________

The segment’s overall increase in earnings before depreciation, depletion and amortization expenses in 2010 compared to 2009 was due to higher earnings from both its oil and gas producing activities and its sales and transportation activities. The year-over-year increase in earnings from oil and gas producing activities, which include the operations associated with ownership interests in oil-producing fields and natural gas processing plants, was due mainly to the following:

▪

a $160.5 million (19%) increase due to higher operating revenues—driven by a $154.4 million (19%) increase in combined crude oil and natural gas plant product sales revenues, due largely to increases of 21% and 34% in our realized weighted average price per barrel of crude oil and natural gas liquids, respectively, and partly to a 5% increase in natural gas liquids sales volumes. The overall increase in sales revenues was somewhat offset by a 5% decline in crude oil sales volumes in 2010; and

▪

a $46.8 million (18%) decrease due to higher combined operating expenses—driven by a $29.7 million (326%) increase in tax expenses, other than income tax expenses, and a $14.4 million (8%) increase in operating and maintenance expenses. The increase in other tax expenses, relative to 2009, was due primarily to a $30.3 million reduction in severance tax expenses in 2009 due to prior year overpayments. The increase in operating expenses was mainly due to higher natural gas processing costs related to an increase in processing volumes, and to higher carbon dioxide purchase costs related to higher rates.

Similarly, the year-over-year increase in earnings from the segment’s sales and transportation activities in 2010 was also primarily revenue related, chiefly due to a $37.5 million (22%) increase in carbon dioxide sales revenues. The increase was mainly price-related, driven by a 22% increase in the average sales price for carbon dioxide. Although our carbon dioxide sales volumes were essentially unchanged across both years, we benefitted from higher average carbon dioxide sales prices in 2010 versus 2009 due to both continued strong customer demand for carbon dioxide’s use in oil recovery projects throughout the Permian Basin area and to the positive impact on the portion of our carbon dioxide sales contracts that are tied to crude oil prices, which increased since the end of 2009.

Pipeline revenues from transporting both carbon dioxide and crude oil were essentially flat across 2010 and 2009, and for our CO2 segment combined, total carbon dioxide delivery volumes decreased almost 3% in 2010 versus 2009. The decrease in delivery volumes was mainly due to our lower consumption of new carbon dioxide at both the SACROC and Yates field units; however, carbon dioxide production from our southwest Colorado source fields increased in 2010, and carbon dioxide delivery volumes on our 50%-owned Cortez Pipeline increased by 0.5% in 2010, both reflecting a slight increase in third-party sales compared to 2009. Our sales and transportation activities also benefitted from a $5.0 million (123%) decrease in income tax expenses in 2010 versus 2009, primarily due to favorable adjustments to the segment’s accrued Texas margin tax liabilities due to prior year overpayments.

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

	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	120.6		26	%	$	(44.5	)	(5	)%
Sales and Transportation Activities		(84.4	)	(28	)%		(78.2	)	(23	)%
Intrasegment Eliminations		-		-			38.9		46	%
Total CO2	$	36.2		5	%	$	(83.8	)	(7	)%

__________

Higher year-over-year earnings from the segment’s oil and gas producing activities in 2009 more than offset lower earnings from its sales and transportation activities. Generally, earnings from oil and gas producing activities align closely with revenues earned from both crude oil and natural gas plant products sales, but the $120.6 million (26%) increase in earnings in 2009 was primarily due to the following:

▪

a $166.1 million (39%) increase from lower operating expenses—consisting of (i) a $103.6 million (29%) decrease in oil and gas related field operating and maintenance expenses, costs of sales and fuel and power expenses; and (ii) a $62.5 million (87%) decrease in taxes, other than income tax expenses. The decrease in operating expenses was primarily due to (i) lower prices charged by the industry’s material and service providers (for items such as outside services, maintenance, and well workover services), which impacted rig costs, other materials and services, and capital and exploratory costs; (ii) lower fuel and utility rates; and (iii) the successful negotiation and renewal of lower priced service and supply contracts since the end of 2008. The decrease in other tax expenses was driven by a decrease in severance tax expenses, related both to lower revenues (discussed following) and favorable adjustments in 2009 to accrued severance tax liabilities, due to prior year overpayments; and

▪

a $44.5 million (5%) decrease from lower oil and gas related revenues—due primarily to a $61.2 million (32%) decrease in natural gas liquids sales revenues and a $22.9 million (3%) increase in crude oil sales revenues. The overall decrease in natural gas liquids sales revenues resulted from a 40% decrease in the realized weighted average price per barrel of liquids in 2009, partly offset by an increase in revenues resulting from a 13% increase in natural gas liquids sales volumes. The year-over-year volume increase was due in part to the negative impact on sales volumes in 2008 from Hurricane Ike. Hurricane Ike, which made landfall at Galveston, Texas on September 13, 2008, temporarily shut-down third-party fractionation facilities, which caused a decline in natural gas liquids production volumes in and around the Permian Basin area through the end of November 2008.

The $22.9 million (3%) increase in crude oil sales revenues in 2009 versus 2008 was driven by a corresponding 3% increase in crude oil sales volumes. As a result of our hedging activity, our realized weighted average price per barrel of oil was essentially flat across both 2009 and 2008, although average industry price levels for crude oil increased during 2009.

The $84.4 million (28%) decrease in the segment’s sales and transportation earnings in 2009 compared to 2008 was driven by a $78.2 million (23%) drop in revenues, including both a $65.4 million (28%) decrease in carbon dioxide sales revenues and a $9.7 million (11%) decrease in carbon dioxide and crude oil pipeline transportation revenues. The decrease in carbon dioxide sales revenues was entirely price related, as the segment’s average price received from carbon dioxide sales in 2009 decreased 36% compared to the prior year, reducing revenues by $95.8 million. The decrease resulting from the unfavorable price change more than offset a $30.4 million increase in carbon dioxide sales revenues resulting from higher sales volumes. Total carbon dioxide sales volumes increased by 13% in 2009, due both to carbon dioxide expansion projects completed since the end of 2008, and to continued strong demand for carbon dioxide from tertiary oil recovery projects.

The decrease in carbon dioxide and crude oil pipeline transportation revenues in 2009 versus 2008 was mainly due to lower carbon dioxide transportation revenues from our Central Basin Pipeline, and lower crude oil transportation revenues from our Wink Pipeline. Central Basin’s revenues were negatively impacted by lower weighted average transportation rates, due partly to the fact that a portion of its carbon dioxide transportation contracts is indexed to oil prices, which were lower in 2009. Wink’s drop in revenues in 2009 was primarily due to lower pipeline loss allowance revenues, also resulting from lower market prices for crude oil relative to 2008.

For more information on our ownership interests in the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see Note 20 to our consolidated financial statements included elsewhere in this report.

Terminals

	Year Ended December 31,
	2010			2009			2008
	(In millions, except operating statistics)
Revenues	$	1,265.1		$	1,109.0		$	1,173.6
Operating expenses(a)		(629.2	)		(536.8	)		(631.8	)
Other income (expense)(b)		4.3			27.6			(2.7	)
Earnings from equity investments		1.7			0.7			2.7
Other, net-income (expense)		4.7			3.7			1.7
Income tax benefit (expense)(c)		(5.3	)		(5.2	)		(19.7	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	641.3		$	599.0		$	523.8

Bulk transload tonnage (MMtons)(d)		92.4			83.0			103.0
Ethanol (MMBbl)		57.9			32.6			30.7
Liquids leaseable capacity (MMBbl)		58.2			56.4			54.2
Liquids utilization %		96.2			96.6			97.5

__________

(a)	2010 amount includes (i) a $6.4 million increase in expense from casualty insurance deductibles and the write-off of assets related to casualty losses; (ii) a $0.6 million increase in expense related to storm and flood clean-up and repair activities; and (iii) 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 $0.9 million increase in expense associated with environmental liability adjustments; (ii) a $0.7 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries; (iii) a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal; and (iv) a $0.3 million decrease in expense related to hurricane clean-up and repair activities. 2008 amount includes (i) a $5.3 million increase in expense related to hurricane clean-up and repair activities; (ii) 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; (iii) a $1.9 million increase in expense related to fire damage and repair activities; and (iv) a $0.6 million decrease in expense associated with environmental liability adjustments.
(b)	2010 amount includes (i) a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal; (ii) a combined $5.5 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; and (iii) a $1.0 million casualty loss related to the write-off of assets. 2009 amount includes gains of $24.6 million from hurricane and fire casualty indemnifications. 2008 amount includes losses of $5.3 million from asset write-offs related to fire damage, and losses of $0.8 million from asset write-offs related to hurricane damage.
(c)	2010 amount includes a $1.4 million decrease in expense reflecting the tax effect (savings) on the decrease in income from the amounts previously reported in our 2010 fourth quarter earnings release issued on January 19, 2011,described in footnote (b). 2009 amount includes a $0.9 million increase in expense related to hurricane casualty gains. 2008 amount includes a decrease in expense (reflecting tax savings) of $0.4 million related to hurricane clean-up and repair expenses and casualty losses.
(d)	Volumes for acquired terminals are included for all periods.

Our Terminals business segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities. Combined, the certain items described in the footnotes to the table above decreased segment earnings before depreciation, depletion and amortization expenses by $5.2 million in 2010, increased earnings by $22.9 million in 2009, and decreased earnings by $15.1 million in 2008. In addition, in each of the years 2010, 2009 and 2008, we have made terminal acquisitions in order to gain access to new markets and to complement and/or enlarge our existing terminal operations. Combined, these acquired operations contributed incremental earnings before depreciation, depletion and amortization of $32.2 million, revenues of $59.2 million, and operating expenses of $27.3 million in 2010, and incremental earnings before depreciation, depletion and amortization of $4.6 million, revenues of $16.1 million, and operating expenses of $11.5 million in 2009. All of the incremental 2010 and 2009 amounts listed above represent the earnings, revenues and expenses from acquired terminals’ operations during the additional months of ownership in 2010 and 2009, respectively, and do not include increases or decreases during the same months we owned the assets in the respective prior year. For more information on our acquisitions, see Note 3 to our consolidated financial statements included elsewhere in this report.

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. The changes represent increases and decreases in terminal results at various locations for all terminal operations owned during identical periods in both pairs of comparable years. We group our bulk and liquids terminal operations into regions based on geographic location and/or primary operating function. This structure allows our management to organize and evaluate segment performance and to help make operating decisions and allocate resources.

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

	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Gulf Coast	$	15.9		11	%	$	18.5		10	%
West		13.8		28	%		28.1		31	%
Southeast		7.2		17	%		11.1		12	%
Mid-River		5.1		27	%		19.7		34	%
Ohio Valley		4.0		23	%		9.7		17	%
Ethanol		3.6		75	%		4.2		65	%
Lower River (Louisiana)		(6.3	)	(13	)%		(0.7	)	(1	)%
All others (including intrasegment eliminations and unallocated income tax expenses)		(5.1	)	(2	)%		6.3		1	%
Total Terminals	$	38.2		7	%	$	96.9		9	%

__________

The earnings increase in 2010 compared to 2009 from our Gulf Coast terminals were driven by higher liquids warehousing revenues, mainly due to new and incremental customer agreements (at higher rates), and to the completion of various terminal expansion projects that increased liquids tank capacity since the end of 2009. For all liquids terminals combined, we increased our liquids leasable capacity by 1.8 million barrels (3.2%) during 2010 and, at the same time, our overall liquids utilization capacity rate (the ratio of our actual leased capacity to our estimated potential capacity) at the end of 2010 decreased by only 0.4% since the prior year-end.

The increase in earnings from our West region terminals was driven by incremental contributions from (i) our Vancouver Wharves bulk marine terminal, located on the north shore of Vancouver, British Columbia, Canada’s main harbor; (ii) our Kinder Morgan North 40 terminal, the crude oil tank farm we constructed near Edmonton, Alberta, Canada; (iii) our Washington State terminals located in Vancouver and Longview, Washington; and (iv) our Portland, Oregon bulk terminal. The combined increase in earnings was mainly due to higher transfer volumes of agricultural products and other bulk and liquids commodities, higher rate tonnage, and for our two Canadian terminals, favorable currency translation impacts from a strengthening of the Canadian dollar since the end of 2009.

Earnings from our Southeast, Mid-River, and Ohio Valley terminals, which are located in the Southeast and Central regions of the U.S., also increased in 2010, due largely to increased steel volumes from rebounding steel consumption consistent with the ongoing economic recovery. For our Terminals segment combined, total steel tonnage increased by 8.0 million tons (48%) in 2010, when compared with the previous year.

The increase in earnings from our Ethanol terminals was driven by incremental services offered by our unit train terminaling facilities located at Richmond and Lomita, California. In March 2010, we began operations at our newly-built Richmond terminal, which is serviced by the Burlington Northern Santa Fe railroad. The increase in earnings from our Lomita rail ethanol terminal was driven by incremental offloading and distribution volumes, driven by California’s growing demand for reformulated fuel blend ethanol. For our Terminals segment combined, ethanol volumes increased by 25.3 million barrels (78%) in 2010, primarily due to the growth in demand from the state of California and to the incremental handling activities from the terminal assets we acquired from US Development Group LLC in January 2010.

For 2010, earnings from our Lower River (Louisiana) terminal operations decreased compared to the prior year. The decrease in earnings from our Lower River terminals was primarily due to lower earnings from both our International Marine Terminals facility, a multi-product, import-export facility located in Port Sulphur, Louisiana and owned 66 2/3% by us, and our Westwego, Louisiana liquids terminal. The decrease in IMT’s earnings was due to both a general loss in business in 2010, and a $3.2 million property casualty gain, recognized in 2009, on a vessel dock that was damaged in March 2008. In September 2010, IMT experienced a catastrophic failure of its shiploader, which negatively impacted its ability to load vessels. The decrease in earnings from our Westwego facility was primarily due to lower revenues resulting from a drop in petroleum fuel storage.

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

	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Lower River (Louisiana)	$	24.8		106	%	$	(9.5	)	(9	)%
Gulf Coast		16.6		12	%		18.5		11	%
West		10.4		27	%		7.5		9	%
Texas Petcoke		4.1		6	%		(10.2	)	(7	)%
Mid-River		(10.2	)	(35	)%		(32.4	)	(36	)%
Ohio Valley		(7.7	)	(36	)%		(16.9	)	(26	)%
Materials Management (rail transloading)		(4.4	)	(24	)%		(12.8	)	(26	)%
All others (including intrasegment eliminations and unallocated income tax expenses)		(1.0	)	-	%		(24.9	)	(5	)%
Total Terminals	$	32.6		6	%	$	(80.7	)	(7	)%

__________

The increase in earnings before depreciation, depletion and amortization expenses from our Lower River (Louisiana) terminals in 2009 compared to 2008 was due mainly to lower income tax expenses, related to overall lower taxable income in many of our tax paying terminal subsidiaries, and higher earnings realized from both our International Marine Terminals facility and our Geismar, Louisiana drumming facility. The increase in earnings from IMT was largely due to both lower year-over-year operating expenses in 2009, which more than offset corresponding drops in revenues resulting from less dockage, fleeting and barge services, and, as discussed above, a $3.2 million property casualty gain in the second quarter of 2009. The increase in earnings from our Geismar facility was due to incremental terminal operations that began in the first quarter of 2009.

Similar to the 2010 increase, the increase in earnings from our Gulf Coast terminals in 2009 compared to 2008 was driven by higher liquids warehousing revenues, additional liquids storage capacity, and additional ancillary terminal services. Combined, our Pasadena and Galena Park terminals brought an incremental 1.85 million barrels of liquids tankage capacity (including incremental truck loading capacity) online during 2009.

For all terminals combined, total liquids throughput volumes in 2009 were 1% higher than 2008, primarily due to both completed expansion projects and continued strong demand for distillate and ethanol volumes. Expansion projects completed since the end of 2008 increased our liquids terminals’ leasable capacity to 56.4 million barrels at the end of 2009, up 4% from a capacity of 54.2 million barrels at the end of 2008. In addition, our overall liquids utilization capacity rate at the end of 2009 decreased by only 1%, when compared to the prior year-end.

The increase in earnings in 2009 from our West region terminals was driven by incremental earnings from our North 40 and Vancouver Wharves terminals. We completed construction and placed our North 40 terminal into service in the second quarter of 2008. The increase in earnings from our Vancouver Wharves terminal was chiefly due to higher liquids revenues, due in part to expanded liquids facilities that began operating in April 2009, and to continued strong ship traffic during 2009 at Port Metro Vancouver.

The increase in earnings from our Texas petroleum coke operations was driven by higher earnings realized from our Port of Houston, Port of Beaumont and Houston Refining operations. The combined earnings increase from these operations was driven by higher petroleum coke throughput and production volumes, and by higher handling rates in 2009. The increase in volumes was due in part to a new petroleum coke customer contract that boosted volume at our Port of Houston bulk facility, and in part to the negative impacts caused by Hurricane Ike in the third quarter of 2008.

The overall increase in segment earnings before depreciation, depletion and amortization in 2009 compared to 2008 from terminals owned in both comparable years was partly offset by lower earnings from our Mid-River, Ohio Valley and Materials Management terminals. The decreases in earnings from these facilities were due primarily to lower import/export activity and lower overall business activity at various rail and terminal sites primarily involved in the handling and storage of steel and alloy products.

Due to the economic downturn that intensified in the last half of 2008, we experienced significant year-over-year volume and revenue declines at various owned and/or operated terminal facilities in 2009, when compared to 2008. For our Terminals segment combined, bulk traffic tonnage decreased by 25.0 million tons (24%) in 2009 versus 2008, and revenues from terminals owned in both years decreased by $80.7 million (7%). However, while the overall volume and revenue declines in 2009 were generally broad-based across all of our bulk terminals, the rate of decline in 2009 compared to 2008 slowed during the year. Also, beginning at the start of 2009, the segment undertook various actions to manage costs and increase productivity, and for all terminals owned in both years, combined operating expenses decreased $97.9 million (16%) in 2009 compared to 2008. In addition to the effects from the declines in bulk tonnage volumes described above, the expense reduction was generated by a combination of aggressive cost management actions related to operating expenses, certain productivity initiatives at various terminal sites, and year-over-year declines in commodity and fuel costs.

Kinder Morgan Canada

	Year Ended December 31,
	2010			2009			2008
	(In millions, except operating statistics)
Revenues	$	268.5		$	226.1		$	196.7
Operating expenses		(91.6	)		(72.5	)		(67.9	)
Earnings from equity investments		(3.3	)		(4.1	)		(0.4	)
Interest income and Other, net-income (expense)(a)		15.8			23.9			(6.2	)
Income tax benefit (expense)(b)		(7.8	)		(18.9	)		19.0
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	181.6		$	154.5		$	141.2

Transport volumes (MMBbl)(c)		108.4			102.5			86.7

__________

(a)	2008 amount includes a $12.3 million decrease in other non-operating income, due to certain non-cash Trans Mountain regulatory accounting adjustments.
(b)	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 $6.6 million increase in expense due to certain non-cash Trans Mountain regulatory accounting adjustments.
(c)	Represents Trans Mountain pipeline system volumes.

Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems and our one-third ownership interest in the Express crude oil pipeline system. Effective August 28, 2008, we acquired from KMI our equity investment in the approximate 1,700-mile Express pipeline system, a C$113.6 million long-term investment in a fixed rate debt security issued by Express, and the approximate 25-mile Jet Fuel pipeline system.

Combined, the certain items described in the footnotes to the table above decreased segment earnings before depreciation, depletion and amortization expenses by $11.2 million in 2009, and increased segment earnings before depreciation, depletion and amortization by $0.4 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)
Trans Mountain Pipeline	$	9.8		6	%	$	41.1	19	%
Express Pipeline		7.3		96	%		-	-
Jet Fuel Pipeline		(1.2	)	(25	)%		1.3	31	%
Total Kinder Morgan Canada	$	15.9		10	%	$	42.4	19	%

__________

The increase in our Kinder Morgan Canada business segment’s earnings before depreciation, depletion and amortization expenses in 2010 compared to 2009 was driven by higher earnings from our Trans Mountain pipeline system and our investment in the Express pipeline system. The overall $9.8 million (6%) increase in Trans Mountain’s earnings in 2010 consisted of a $22.8 million (15%) increase due to higher operating income (revenues less operating expenses), and a combined $13.0 million (373%) decrease due to both lower income from foreign currency transactions (included in non-operating other income) and higher income tax expenses.

The increase in operating income (and related income tax expenses) was driven by higher crude oil volumes moving across Trans Mountain’s marine dock located in Port Metro Vancouver—system throughput volumes increased by 6% overall compared to 2009. The decrease in income from foreign currency transactions was primarily attributable to lower currency gains on Trans Mountain’s outstanding, short-term, intercompany interest obligations payable in U.S. dollars. Although the Canadian dollar did strengthen during 2010, gains from the revaluation of U.S.-based interest liabilities were lower in 2010 because the impact was not as favorable as in 2009.The increase in earnings from our investment in the Express pipeline system was largely due to a $5.5 million decrease in year-over-year income tax expenses in 2010, and a $1.2 million increase in the interest income we earn from our long-term debt investment in Express. The drop in income tax expense in 2010 compared to 2009 was mainly due to a valuation allowance release on previously established deferred tax balances, and the increase in interest income was due to favorable currency translation impacts in 2010 (described above).

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

	EBDA increase/(decrease)				Revenues increase/(decrease)
	(In millions, except percentages)
Trans Mountain Pipeline	$	18.1	13	%	$	26.1	13	%
Jet Fuel Pipeline		4.4	812	%		3.3	354	%
Express Pipeline		2.4	48	%		-	-
Total Kinder Morgan Canada	$	24.9	18	%	$	29.4	15	%

__________

The $18.1 million (13%) increase in Trans Mountain’s earnings before depreciation, depletion and amortization expenses in 2009 compared to 2008 was driven primarily by a $26.1 million (13%) increase in operating revenues, and partly by higher net currency gains relative to 2008. The increase in revenues reflected higher pipeline transportation revenues, due largely to an 18% increase in mainline delivery volumes resulting from both a significant increase in ship traffic during 2009 at Port Metro Vancouver and the completion of the Trans Mountain Pipeline Anchor Loop expansion project in October 2008. The overall increase in Trans Mountain’s earnings was partially offset by higher year-over-year income tax expenses and lower income from allowances for capital funds used for pipeline system construction costs.

The $6.8 million increase in earnings from our combined Express and Jet Fuel pipeline operations in 2009 compared to 2008 consisted of (i) incremental earnings of $10.1 million during the periods we owned the assets in 2009 only (January through August); and (ii) lower earnings of $3.3 million during the period we owned the assets in both years (September through December). The lower earnings for the same comparable periods in 2009 and 2008 was driven by a $3.4 million decrease in equity earnings in 2009 from our investment in Express, due to lower year-over-year revenues, higher power expenses and higher income tax expenses in the Express operating companies, when compared to the same periods in 2008.

Other

	Year Ended December 31,
	2010			2009			2008
	(In millions-income (expense)
General and administrative expenses(a)	$	(375.2	)	$	(330.3	)	$	(297.9	)

Unallocable interest expense, net of interest income(b)	$	(506.4	)	$	(431.3	)	$	(397.6	)

Unallocable income tax expense	$	(9.9	)	$	(8.5	)	$	(9.3	)

Net income attributable to noncontrolling interests(c)	$	(10.8	)	$	(16.3	)	$	(13.7	)

__________

(a)	Includes such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services. 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.
(b)	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.
(c)	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 the footnotes to the tables included in “—Results of Operations.”

Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense, and net income attributable to noncontrolling interests. Our general and administrative expenses include such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services—including accounting, information technology, human resources and legal services. Combined, the certain items described in footnote (a) to the table above increased our general and administrative expenses by $10.2 million in 2010, $6.6 million in 2009, and $5.0 million in 2008.

For 2010 compared to 2009, the remaining $41.3 million (13%) increase in expenses included increases of (i) $21.9 million from higher employee benefit and payroll tax expenses; (ii) $5.7 million from higher overall corporate insurance expenses; and (iii) $5.2 million from higher unallocated legal expenses. The increase in benefit and payroll tax expenses was mainly due to the overall variability in year-over-year health and medical costs, higher wage rates and a larger year-over-year labor force. The increase in insurance expenses was primarily due to higher expense accruals in 2010, related mainly to year-over-year increases in commercial property and liability insurance costs, and partly to incremental premium taxes. The increase in legal expenses was primarily due to higher outside legal services.

The remaining $30.8 million (11%) increase in general and administrative expenses in 2009 compared to 2008 included a combined $15.8 million increase due to higher employee benefits and payroll tax expenses, and a $10.7 million increase due to a drop in capitalized overhead expenses (other than benefits and payroll taxes). The increase in benefits and payroll taxes was due mainly to cost inflation increases on work-based health and insurance benefits, lower returns on our pension plan assets, higher wage rates in 2009, and a larger labor force relative to the prior year. The increase in expense due to lower capitalized expenses was due to lower capital spending in 2009 and to fewer overhead expenses meeting the criteria for capitalization.

We report our interest expense as “net,” meaning that we have subtracted unallocated interest income from our total interest expense to arrive at one interest amount, and after taking into effect the certain items described in footnote (b) to the table above, our unallocable interest expense increased $75.6 million (18%) in 2010 compared to 2009, and increased $27.2 million (7%) in 2009 compared to 2008. For both pairs of comparable years, the increase in interest expense was attributable to higher average borrowings, and partly offset by lower effective interest rates.

Our average debt balances increased 16% in 2010 and 23% in 2009, when compared to the respective prior year. The increases in average borrowings were largely due to the capital expenditures, investment contributions, and external business acquisitions we have made since the beginning of 2008. For more information on our capital expenditures, capital contributions, and acquisition expenditures, see “—Liquidity and Capital Resources.”

The weighted average interest rate on all of our borrowings decreased 5% in 2010 compared to 2009, and decreased 16% in 2009 compared to 2008. The decreases were due primarily to a general drop in variable interest rates since the beginning of 2008, including decreases in the variable interest rate we paid on the borrowings made under our revolving bank credit facility, and in 2010, under our commercial paper program.

We use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt, and in periods of falling interest rates, these swaps result in year-to-year decreases in our interest expense. As of December 31, 2010 and 2009, approximately 47% and 53%, respectively, of our consolidated debt balances (excluding the value of interest rate swap agreements) was subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 13 to our consolidated financial statements included elsewhere in this report.

Unallocable income tax expenses relate to corporate income tax accruals for the Texas margin tax, an entity-level tax imposed on the amount of our total revenue that is apportioned to the state of Texas. Both the increase in expense, in 2010, and the decrease in expense, in 2009, was due to lower margin tax expense accruals in 2009, relative to both 2010 and 2008.

Net income attributable to noncontrolling interests, which represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our operating limited partnerships and their consolidated subsidiaries that are not held by us, decreased in 2010 and increased in 2009, when compared to the respective prior year. Both the decrease in 2010 and the increase in 2009 was chiefly due to the higher net income allocated to the 33 1/3% noncontrolling interest in the International Marine Terminals facility in 2009, discussed above in “—Terminals.”

Liquidity and Capital Resources

General

As of December 31, 2010, we believe our balance sheet and liquidity position remained strong. We had $129.1 million of cash and cash equivalents on hand and we had approximately $1.2 billion of borrowing capacity available under our $2.0 billion senior unsecured revolving bank credit facility (discussed below in “—Short-term Liquidity”). We believe our cash position and our remaining borrowing capacity allow us to manage our day-to-day cash requirements and any anticipated obligations, and currently, we believe our liquidity to be adequate.

Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures (defined as capital expenditures which do not increase the capacity of an asset), expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder and general partner.

In general, we expect to fund:

▪

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

▪

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

▪

interest payments with cash flows from operating activities; and

▪

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

In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.”

Credit Ratings and Capital Market Liquidity

As part of our financial strategy, we try to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional limited partner units in connection with our acquisitions and expansion activities in order to maintain acceptable financial ratios. Currently, our long-term corporate debt credit rating is BBB (stable), Baa2 (negative) and BBB (stable), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch Inc., respectively.

On February 25, 2010, Standard & Poor’s revised its outlook on our long-term credit rating to stable from negative, affirmed our long-term credit rating at BBB, and raised our short-term credit rating to A-2 from A-3. The rating agency’s revisions reflected its expectations that our financial profile will improve due to lower guaranteed debt obligations and higher expected cash flows associated with the completion and start-up of the Rockies Express, Midcontinent Express and Kinder Morgan Louisiana natural gas pipeline systems. As a result of this upward revision to our short-term rating, we currently have additional access to the commercial paper market that was not available prior to this rating change. Therefore, we expect that our short-term liquidity needs will be met through borrowings made under our bank credit facility and our commercial paper program. Nevertheless, our ability to satisfy our financing requirements or fund our planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the energy and terminals industries and other financial and business factors, some of which are beyond our control.

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

Short-term Liquidity

Our principal sources of short-term liquidity are (i) our $2.0 billion senior unsecured revolving bank credit facility that matures June 23, 2013; (ii) our $2.0 billion short-term commercial paper program (which is supported by our bank credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings); and (iii) cash from operations (discussed below in “—Operating Activities”). The loan commitments under our bank credit facility can be used to fund borrowings for general partnership purposes and as a backup for our $2.0 billion commercial paper program. The facility can be amended to allow for borrowings of up to $2.3 billion. For additional information on our credit facility, see Note 8 to our consolidated financial statements included elsewhere in this report.

As discussed above in “—General,” we provide for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our bank credit facility. After reduction for (i) our letters of credit and (ii) borrowings under our commercial paper program, the remaining available borrowing capacity under our credit facility was $1,241.1 million as of December 31, 2010. Additionally, (i) we have consistently generated strong cash flow from operations, providing a source of funds of $2,419.0 million in 2010 and $2,117.1 million in 2009; and (ii) we terminated certain existing fixed-to-variable interest rate swap agreements in both 2010 and 2009 having combined notional principal amounts of $825 million and $300 million, respectively, and we received combined proceeds of $157.6 million and $144.4 million, respectively, from the early termination of these swap agreements.

Our outstanding short-term debt as of December 31, 2010 was $1,262.4 million, primarily consisting of (i) $700.0 million in principal amount of 6.75% senior notes that mature March 15, 2011 and (ii) $522.1 million of commercial paper borrowings. We intend to refinance our current short-term debt through a combination of long-term debt, equity, and/or the issuance of additional commercial paper or additional bank credit facility borrowings to replace maturing commercial paper and current maturities of long-term debt.

Our outstanding short-term debt as of December 31, 2009 was $594.7 million, primarily consisting of $300.0 million in outstanding borrowings under our bank credit facility and $250.0 million in principal amount of 7.50% senior notes that matured on November 1, 2010. There were no borrowings under our commercial paper program as of December 31, 2009.

We had working capital deficits (current assets minus current liabilities) of $1,477.5 million as of December 31, 2010 and $772.9 million as of December 31, 2009. The unfavorable change from year-end 2009 was primarily due to $700.0 million in principal amount of 6.75% senior notes due March 15, 2011 being reclassified from long-term to short-term debt. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts and changes in cash and cash equivalent balances as a result of debt or equity issuances (discussed below in “—Long-term Financing”). As a result, our working capital balance could return to a surplus in future periods. A working capital deficit is not unusual for us or for other companies similar in size and scope to us, and we believe that our working capital deficit does not indicate a lack of liquidity as we continue to maintain adequate current assets and committed lines of credit to satisfy current liabilities and maturing obligations when they come due.

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

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

Long-term Financing

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

Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares). As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations, and we are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors. For more information on our 2010 and 2009 equity issuances, including cash proceeds received from both public offerings of common units and our equity distribution agreement, see Note 10 to our consolidated financial statements included elsewhere in this report.

From time to time we issue long-term debt securities, often referred to as our senior notes. Our senior notes issued to date, other than those issued by our subsidiaries and operating partnerships, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. Our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. For additional information on our debt securities and on our 2010 and 2009 debt related transactions, including our issuances of senior notes, see Note 8 to our consolidated financial statements included elsewhere in this report.

As of December 31, 2010 and 2009, the net carrying value of the various series of our senior notes was $10,876.7 million and $10,125.3 million, respectively, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $141.0 million and $167.1 million, respectively. To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives.

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

Capital Structure

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

With respect to our debt, we target a debt mixture of approximately 50% fixed and 50% variable interest rates. We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate payments.

Capital Expenditures

We define sustaining capital expenditures as capital expenditures which do not increase the capacity of an asset, and for the year ended December 31, 2010 our sustaining capital expenditures were $179.2 million. This amount included $0.2 million for our proportionate share of the sustaining capital expenditures of (i) Rockies Express Pipeline LLC; (ii) Midcontinent Express Pipeline LLC; (iii) KinderHawk Field Services LLC; (iv) Cypress Interstate Pipeline LLC; and (v) Fayetteville Express Pipeline LLC. For the year ended December 31, 2009, our sustaining capital expenditures totaled $172.2 million (including $0.2 million for our proportionate share of Rockies Express’ sustaining capital expenditures). Our forecasted expenditures for 2011 for sustaining capital expenditures are approximately $224.8 million (including $6.9 million for our proportionate shares of Rockies Express, Midcontinent Express, KinderHawk, Cypress, and Fayetteville Express).

Generally, we fund our sustaining capital expenditures with existing cash or from cash flows from operations. In addition to utilizing cash generated from their own operations, both Rockies Express and Midcontinent Express can each fund their own cash requirements for expansion capital expenditures through borrowings under their own credit facilities, issuing their own long-term notes, or with proceeds from contributions received from their member owners. Similarly, KinderHawk Field Services can fund its cash requirements for expansion capital expenditures with cash generated from its own operations, through borrowings under its own credit facility, or with proceeds from contributions received from its two member owners. We have no contingent debt obligation with respect to either Rockies Express Pipeline LLC or KinderHawk Field Services LLC; however, we guarantee both 50% of Midcontinent Express Pipeline LLC’s bank credit facility borrowings and 50% of Fayetteville Express Pipeline LLC’s bank credit facility borrowings. For information on our contingent debt obligations, see Note 12 to our consolidated financial statements included elsewhere in this report.

All of our capital expenditures, with the exception of sustaining capital expenditures, are classified as discretionary. Our discretionary capital expenditures for each of the two years ended December 31, 2010 and 2009 were $821.9 million and $1,151.8 million, respectively. The year-to-year decrease in discretionary capital expenditures was largely due to the higher investment undertaken in 2009 to construct our Kinder Morgan Louisiana natural gas pipeline system and to expand and improve our Products Pipelines and Terminals business segments. Generally, we initially fund our discretionary capital expenditures through borrowings under our bank credit facility or our commercial paper program until the amount borrowed is of a sufficient size to cost effectively offer either debt, or equity, or both. We have forecasted $795.6 million for discretionary capital expenditures in our 2011 budget. This amount does not include forecasted capital contributions to our equity investees or forecasted expenditures for asset acquisitions.

Capital Contributions

In addition to our discretionary capital expenditures, we contributed a combined $299.3 million to our equity investees in 2010. In 2009, we made equity investment contributions of $2,051.8 million. The decrease in contributions in 2010 was driven by the incremental contributions we made in 2009 to Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Express Pipeline LLC (all three reported as investments on our balance sheet and accounted for under the equity method of accounting). Combined, we contributed $2,040.8 million in 2009 to partially fund (i) the respective Rockies Express, Midcontinent Express, and Fayetteville Express pipeline construction and/or pre-construction costs; and (ii) the repayment of senior notes by Rockies Express in August 2009.

Our 2010 contributions primarily consisted of a combined $216.5 million contributed to Rockies Express Pipeline LLC and Midcontinent Express Pipeline LLC. Fayetteville Express Pipeline LLC funded its 2010 pipeline construction costs with borrowings under its own $1.1 billion, unsecured revolving bank credit facility that is due in May 2012. Generally, we fund our equity investment contributions through borrowings under our bank credit facility or our commercial paper program. To the extent these sources of funding are not sufficient, we generally fund additional amounts through the issuance of long-term notes or common units for cash.

Capital Requirements for Recent Transactions

For each of the years ended December 31, 2010 and 2009, our net cash outlays for the acquisition of assets and investments totaled $1,213.2 million and $328.9 million, respectively. Our 2010 cash outlays for strategic business acquisitions primarily consisted of (i) $921.4 million for a 50% equity ownership interest in Petrohawk Energy Corporation’s natural gas gathering and treating business (now KinderHawk Field Services LLC); (ii) $114.3 million for three unit train ethanol handling terminals acquired from US Development Group LLC; and (iii) $97.0 million for terminal assets and investments acquired from Slay Industries. With the exception of the terminal assets acquired from US Development Group LLC, which was partially acquired by the issuance of additional common units, we utilized our commercial paper program to fund our 2010 acquisitions and then reduced our short-term borrowings with the proceeds from our 2010 equity issuances and our May 2010 issuance of long-term senior notes. Including both the value of common units we issued as consideration in the acquisition of assets and the cash related to acquisitions that we placed in escrow as of December 31, 2010, our outlays for the acquisition of assets and investments totaled $1,344.9 million in 2010.

Our cash payments for acquired assets and investments in 2009 included $265.3 million for our acquisition of the natural gas treating business from Crosstex Energy L.P. and Crosstex Energy, Inc., and $36.0 million for our 40% membership interest in Endeavor Gathering LLC. We utilized our bank credit facility to fund our significant 2009 acquisitions and then reduced our short-term borrowings with the proceeds from our 2009 issuances of common units and senior notes. All of our significant 2010 and 2009 acquisitions are discussed further in Note 3 to our consolidated financial statements included elsewhere in this report.

Off Balance Sheet Arrangements

We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 12 to our consolidated financial statements included elsewhere in this report. Additional information regarding the nature and business purpose of our investments is included in Note 6 to our consolidated financial statements included elsewhere in this report.

Contractual Obligations and Commercial Commitments

	Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In millions)
Contractual Obligations:
Debt borrowings-principal payments	$	11,563.1	$	1,262.4	$	1,975.6	$	800.8	$	7,524.3

Interest payments(a)		9,588.0		667.3		1,216.3		1,095.3		6,609.1
Lease obligations(b)		155.3		43.5		55.2		30.7		25.9
Pension and postretirement welfare plans(c)		75.0		5.5		12.3		14.0		43.2
Other obligations(d)		15.0		10.0		3.3		0.6		1.1
Total	$	21,396.4	$	1,988.7	$	3,262.7	$	1,941.4	$	14,203.6

Other commercial commitments:
Standby letters of credit(e)	$	317.2	$	317.2	$	-	$	-	$	-
Capital expenditures(f)	$	303.4	$	303.4	$	-	$	-	$	-

____________

(a)	Interest payment obligations exclude adjustments for interest rate swap agreements.
(b)	Represents commitments pursuant to the terms of operating lease agreements.
(c)	Represents expected benefit payments from pension and postretirement welfare plans as of December 31, 2010.
(d)	For the Less than 1 year column, represents (i) $5.0 million due under casualty insurance deductibles; (ii) $3.7 million due under carbon dioxide take-or-pay contracts; and (iii) $1.3 million due pursuant to our purchase and sale agreement with Gas-Chill, Inc. for the acquisition of certain natural gas treating assets effective September 1, 2010. For the 1-3 years column, represents (i) $2.0 million due pursuant to our purchase and sale agreement with Slay Industries for the acquisition of certain bulk and liquid terminal assets effective March 5, 2010; and (ii) $1.3 million due pursuant to our purchase and sale agreement with Gas-Chill, Inc. For the 3-5 years column, represents amounts due pursuant to our purchase and sale agreement with Slay Industries. For the More than 5 years column, represents amounts due pursuant to our purchase and sale agreement with Slay Industries.
(e)	The $317.2 million in letters of credit outstanding as of December 31, 2010 consisted of the following: (i) a $100 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a $55.0 million letter of credit supporting our pipeline and terminal operations in Canada; (iii) our $30.3 million guarantee under letters of credit totaling $45.5 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (iv) a $25.4 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (v) a $24.1 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (vi) a $18.3 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; (vii) a $16.2 million letter of credit supporting debt securities issued by the Express pipeline system; (viii) a $16.1 million letter of credit supporting our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (ix) a combined $16.6 million in eight letters of credit supporting environmental and other obligations of us and our subsidiaries.
(f)	Represents commitments for the purchase of plant, property and equipment as of December 31, 2010.

Operating Activities

Net cash provided by operating activities was $2,419.0 million in 2010, versus $2,117.1 million in 2009. The overall year-to-year increase of $301.9 million (14%) in cash flows from operations primarily consisted of:

▪

a $218.1 million increase in cash from overall higher partnership income from our five reportable business segments—after adjusting for the following seven non-cash items: (i) depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments); (ii) undistributed earnings from equity investees; (iii) income from the allowance for equity funds used during construction; (iv) income from the sale or casualty of property, plant and equipment and other net assets; (v) a $154.0 million increase in expense from the combined effect of rate case liability adjustments (which increased expenses by $172.0 million in 2010 and by $18.0 million in 2009, respectively); (vi) a $23.9 million decrease in expense due to lower ineffectiveness on crude oil price hedges, and to lower expenses from the discontinuance of hedge accounting on certain energy commodity derivative contracts; and (vii) a $23.8 million decrease in expense associated with adjustments to long-term receivables for environmental cost recoveries that increased operating expenses in 2009. The year-to-year increase in partnership income in 2010 versus 2009 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes);

▪

a $230.7 million increase in cash relative to net changes in working capital items, primarily due to (i) a $138.9 million increase in cash from the collection and payment of trade and related party receivables and payables (including collections and payments on natural gas transportation and exchange imbalance receivables and payables), due primarily to the timing of invoices received from customers and paid to vendors and suppliers; and (ii) an $84.0 million increase in cash from higher payments in 2009 for natural gas storage on our Kinder Morgan Texas Pipeline system;

▪

a $47.8 million increase in cash attributable to higher net cash inflows from transportation and dock premiums received from Trans Mountain pipeline system customers; and

▪

a $190.8 million decrease in cash attributable to higher payments made in 2010 for transportation rate settlements, refunds and reparations made pursuant to certain legal settlements reached with various shippers on our Pacific operations’ refined products pipelines. In June 2010, we paid $206.3 million to eleven of twelve shippers regarding the settlement of various transportation rate challenges filed with the FERC dating back as early as 1992. In May 2009, we made refund and settlement payments totaling $15.5 million to various shippers in connection with certain East Line rate settlement agreements.

Investing Activities

Net cash used in investing activities was $2,314.5 million for the year ended December 31, 2010, compared to $3,454.0 million for the prior year. The year-to-year $1,139.5 million (33%) increase in cash due to lower cash expended for investing activities was primarily attributable to the following:

▪

a $1,752.5 million increase in cash due to lower contributions to equity investees, as described above in “—Capital Contributions;”

▪

a $322.9 million increase in cash due to lower capital expenditures, as described above in “—Capital Expenditures;”

▪

a $77.8 million increase in cash due to higher capital distributions (distributions in excess of cumulative earnings) received in 2010 from equity investees, primarily related to the combined $179.2 million in capital distributions we received from Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC and KinderHawk Field Services LLC in 2010, versus the $112.0 million of capital distributions received in 2009 from Fayetteville Express Pipeline LLC. Current accounting practice requires us to classify and report cumulative cash distributions in excess of cumulative equity earnings as a return of capital, however, this change in classification does not impact our cash available for distribution.

Our 2010 returns of capital represent distributions paid out by our equity investees in excess of the income they generated. Our 2009 return of capital from Fayetteville Express represents a reimbursement to us for prior contributions we made to fund its pre-construction costs for the Fayetteville Express pipeline system. In November 2009, Fayetteville Express Pipeline LLC entered into and then made borrowings under a new $1.1 billion unsecured revolving credit facility due in May 2012. It then made distributions to its two member owners (Energy Transfer Partners, L.P. and us) to reimburse them for prior contributions;

▪

an $884.3 million decrease in cash due to higher acquisitions of assets and investments, as described above in “—Capital Requirements for Recent Transactions;” and

▪

a $109.6 million decrease in cash due to the full repayment received in 2009 of a loan we made in December 2008 to a single customer of our Texas intrastate natural gas pipeline group.

Financing Activities

Net cash used in financing activities amounted to $124.3 million in 2010; however, in 2009, we generated $1,415.0 million in cash from our financing activities. The $1,539.3 million overall decrease in cash inflows provided by financing activities in 2010 versus 2009 was mainly due to:

▪

a $1,091.3 million decrease in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The decrease was primarily due to (i) a $987.6 million decrease in cash due to lower net issuances and repayments of senior notes; (ii) a $600.0 million decrease in cash from lower net borrowings under our bank credit facility; and (iii) a $522.1 million increase in cash due to net commercial paper borrowings in 2010 (we had no commercial paper borrowings as of December 31, 2009). The largely offsetting increases and decreases in cash from our commercial paper and credit facility borrowings, respectively, were related in part to our short-term credit rating upgrade discussed above in “—Credit Ratings and Capital Market Liquidity.” All of our 2010 and 2009 senior note offerings and repayments are discussed in Note 8 to our consolidated financial statements included elsewhere in this report;

▪

a $396.9 million decrease in cash from lower partnership equity issuances. The decrease relates to the combined $758.7 million we received, after commissions and underwriting expenses, from the sales of additional common units in 2010, compared to the $1,155.6 million we received in 2009. All of our 2010 and 2009 equity issuances are discussed in Note 10 to our consolidated financial statements included elsewhere in this report; and

▪

a $54.7 million decrease in cash due to higher partnership distributions paid in 2010. Distributions to all partners, consisting of our common and Class B unitholders, our general partner and our noncontrolling interests, totaled $1,826.6 million in 2010, versus $1,771.9 million in 2009. For further information regarding our 2010 and 2009 partnership distributions, see Notes 10 and 11 to our consolidated financial statements included elsewhere in this report.

Recent Accounting Pronouncements

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

Information Regarding Forward-Looking Statements

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

▪

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

▪

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

▪

changes in our tariff rates implemented by the Federal Energy Regulatory Commission, California Public Utilities Commission, Canada’s National Energy Board or another regulatory agency;

▪

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

▪

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

▪

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

▪

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

▪

changes in crude oil and natural gas production from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the U.S. Rocky Mountains, areas of shale gas formation and the Alberta oil sands;

▪

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

▪

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

▪

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

▪

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

▪

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

▪

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

▪

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

▪

capital and credit markets conditions, inflation and interest rates;

▪

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

▪

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

▪

our ability to achieve cost savings and revenue growth;

▪

foreign exchange fluctuations;

▪

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

▪

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

▪

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

▪

the uncertainty inherent in estimating future oil and natural gas production or reserves that we may experience;

▪

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

▪

the timing and success of our business development efforts; and

▪

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

The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.

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

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

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

Energy Commodity Market Risk

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

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

Our policies require that we only enter into derivative contracts with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future. The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Ratings Services):

	Credit Rating
J. Aron & Company / Goldman Sachs	A
Morgan Stanley	A
Deutsche Bank	A+

As discussed above, our principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids and crude oil. Using derivative contracts for this purpose helps provide us increased certainty with regard to our operating cash flows and helps us undertake further capital improvement projects, attain budget results and meet distribution targets to our partners. We categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain. Cash flow hedges are defined as hedges made with the intention of decreasing the variability in cash flows related to future transactions, as opposed to the value of an asset, liability or firm commitment, and we are allowed special hedge accounting treatment for such derivative contracts.

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

All remaining gains and losses on the derivative contracts (the ineffective portion) are included in current net income. The ineffective portion of the gain or loss on the derivative contracts is the difference between the gain or loss from the change in value of the derivative contract and the effective portion of that gain or loss. In addition, when the hedged forecasted transaction does take place and affects earnings, the effective part of the hedge is also recognized in the income statement, and the earlier recognized effective amounts are removed from “Accumulated other comprehensive loss” (and “Noncontrolling interests”) and are transferred to the income statement as well, effectively offsetting the changes in cash flows stemming from the hedged risk. If the forecasted transaction results in an asset or liability, amounts should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc. For more information on our other comprehensive income (loss) and our “Accumulated other comprehensive loss,” see Notes 2 and 13 to our consolidated financial statements included elsewhere in this report.

We measure the risk of price changes in the natural gas, natural gas liquids and crude oil markets utilizing a value-at-risk model. Value-at-risk is a statistical measure estimating the probability of portfolio losses over a given holding period, within a certain level of statistical confidence. We utilize a closed form model to evaluate risk on a quarterly basis. Our value-at-risk computations utilize a confidence level of 97.7% for the resultant price movement, and we choose a holding period of one day for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the value-at-risk number presented. For each of the years ended December 31, 2010 and 2009, our value-at-risk reached a high of $6.9 million and $10.4 million, respectively, and a low of $2.5 million and $2.6 million, respectively. Value-at-risk as of December 31, 2010 was $2.5 million, and averaged $4.6 million for 2010. Value-at-risk as of December 31, 2009 was $10.1 million, and averaged $7.6 million for 2009.

Our calculated value-at-risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our combined portfolio of derivative contracts (including commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options) and corresponding physical commodities assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.

In addition, as discussed above, we enter into our derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore both in the value-at-risk calculation and in reality, the change in the market value of our derivative contracts portfolio is offset largely by changes in the value of the underlying physical transactions. For more information on our energy commodity risk management activities, see Note 13 to our consolidated financial statements included elsewhere in this report.

Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

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

As of December 31, 2010 and 2009, the carrying values of our fixed rate debt were $10,929.0 million and $10,198.4 million, respectively. These amounts compare to, as of December 31, 2010 and 2009, fair values of $11,832.6 million and $10,871.7 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2010 and 2009, would result in changes of approximately $466.4 million and $448.3 million, respectively, in the fair values of these instruments. The carrying value and fair value of our variable rate debt, including associated accrued interest and excluding the value of interest rate swap agreements (discussed following), was $611.1 million as of December 31, 2010 and $394.2 million as of December 31, 2009.

As of December 31, 2010 and 2009, we were a party to interest rate swap agreements with notional principal amounts of $4.8 billion and $5.2 billion, respectively. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal. A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 43 basis points in 2010 and 46 basis points in 2009), when applied to our outstanding balance of variable rate debt as of December 31, 2010 and 2009, including adjustments for the notional swap amounts described above, would result in changes of approximately $23.4 million and $25.6 million, respectively, in our 2010 and 2009 annual pre-tax earnings.

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

As of both December 31, 2010 and 2009, all of our interest rate swap agreements represented fixed-for-variable rate swaps, where we agreed to pay our counterparties a variable rate of interest on a notional principal amount, comprised of principal amounts from various series of our long-term fixed rate senior notes. In exchange, our counterparties agreed to pay us a fixed rate of interest, thereby allowing us to transform our fixed rate liabilities into variable rate obligations without the incurrence of additional loan origination or conversion costs.

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

As of December 31, 2010 and 2009, our cash and investment portfolio included $8.2 million and $13.2 million, respectively, in fixed-income debt securities. These amounts are included within “Investments” in our accompanying consolidated balance sheets at each reporting date and are not material to our consolidated balance sheets.

See Note 8 to our consolidated financial statements included elsewhere in this report for additional information related to our debt instruments; for more information on our interest rate risk management and on our interest rate swap agreements, see Note 13 to our consolidated financial statements included elsewhere in this report.

Item 8. Financial Statements and Supplementary Data.

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

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

None.

Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2010, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2010.

The effectiveness of our internal control over financial reporting as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their attestation report which appears herein.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Directors and Executive Officers of our General Partner and its Delegate

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

Name	Age	Position with our General Partner and KMR
Richard D. Kinder	66	Director, Chairman and Chief Executive Officer
C. Park Shaper	42	Director and President
Steven J. Kean	49	Executive Vice President and Chief Operating Officer
Gary L. Hultquist	67	Director
C. Berdon Lawrence	68	Director
Perry M. Waughtal	75	Director
Kimberly A. Dang	41	Vice President and Chief Financial Officer
Jeffrey R. Armstrong	42	Vice President (President, Terminals)
Thomas A. Bannigan	57	Vice President (President, Products Pipelines)
Richard T. Bradley	55	Vice President (President, CO2)
David D. Kinder	36	Vice President, Corporate Development and Treasurer
Joseph Listengart	42	Vice President, General Counsel and Secretary
Thomas A. Martin	49	Vice President (President, Natural Gas Pipelines)
James E. Street	54	Vice President, Human Resources and Administration

Richard D. Kinder is Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of KMR since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan Kansas, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected President of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in July 2004 and served as President until May 2005. He also served as Chief Manager, and as a member of the Board of Managers, of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Chairman and Chief Executive Officer of KMI upon its conversion. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mr. Kinder's experience as Chief Executive Officer of KMR and of Kinder Morgan G.P., Inc., provide him with a familiarity with our strategy, operations and finances that can be matched by no one else. In addition, we believe that with Mr. Kinder's significant direct and indirect equity ownership in us, his economic interests are aligned with those of our other equity investors.

C. Park Shaper is Director and President of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mr. Shaper was elected President of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in May 2005. He served as Executive Vice President of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. from July 2004 until May 2005. Mr. Shaper was elected Director of KMR and Kinder Morgan G.P., Inc. in January 2003 and of Kinder Morgan Kansas, Inc. in May of 2007. He was elected Vice President, Treasurer and Chief Financial Officer of KMR upon its formation in February 2001, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Kansas, Inc. in January 2000, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as its Treasurer until January 2004 and its Chief Financial Officer until May 2005. He also served as President, and as a member of the Board of Managers, of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Director and President of KMI upon its conversion. He received a Masters of Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University. Mr. Shaper is also a trust manager of Weingarten Realty Investors. Mr. Shaper’s experience as President of KMR and Kinder Morgan G.P., Inc., together with his experience as an executive officer of various Kinder Morgan entities, provide him valuable management and operational expertise and intimate knowledge of our business operations, finances and strategy.

Steven J. Kean is Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mr. Kean was elected Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in January 2006. He also served as President, Natural Gas Pipelines of KMR and Kinder Morgan G.P., Inc. from July 2008 to November 2009. He served as Executive Vice President, Operations of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. from May 2005 to January 2006. He served as President, Texas Intrastate Pipeline Group from June 2002 until May 2005. He served as Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. He also served as Chief Operating Officer, and as a member of the Board of Managers, of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Director, Executive Vice President and Chief Operating Officer upon its conversion. Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State University in May 1982.

Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of KMR upon its formation in February 2001. He was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory firm. Since 2009, Mr. Hultquist has also been Chairman of the board of directors of Prairie Bankers, LLC, a data center development company, and a Principal of NewCap Partners Inc., a FINRA-registered broker-dealer and investment bank, specializing in technology, mergers and acquisitions. Mr. Hultquist has over 20 years of experience as an investment banker and over 15 years experience practicing law. This combination of experience provides him an understanding of the business and legal risks applicable to us.

C. Berdon Lawrence is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Lawrence was elected Director of KMR and Kinder Morgan G.P., Inc. in January 2009. Since October 1999, Mr. Lawrence has served Kirby Corporation, a publicly traded inland tank barge operator, as Chairman of the Board. Prior to that, he served for 30 years as President of Hollywood Marine, an inland tank barge company of which he was the founder. Mr. Lawrence holds an M.B.A. degree and a B.B.A. degree in business administration from Tulane University. Mr. Lawrence has over 40 years of experience as an executive in the inland tank barge business, giving him both experience heading a publicly traded company and a thorough knowledge of the transportation business in which we are engaged.

Perry M. Waughtal is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of KMR upon its formation in February 2001. Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal was a director of HealthTronics, Inc. from 2004 to 2009. We believe Mr. Waughtal's 30 years of experience with Hines Interests Limited Partnership, a privately owned, international real estate firm, including as Vice Chairman of development and operations and Chief Financial Officer, and 15 years of experience as Chairman of Songy Partners Limited provide him with planning, management, finance and accounting experience with, and an understanding of, large organizations with capital-intensive projects analogous to the types in which we typically engage, thereby qualifying him to serve as a director.

Kimberly A. Dang is Vice President and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mrs. Dang was elected Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in May 2005. She served as Treasurer of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. from January 2004 to May 2005. She was elected Vice President, Investor Relations of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in July 2002 and served in that role until January 2009. From November 2001 to July 2002, she served as Director, Investor Relations of KMR, Kinder Morgan G.P. Inc., and Kinder Morgan Kansas, Inc. She also served as Chief Financial Officer of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Vice President and Chief Financial Officer upon its conversion. Mrs. Dang received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University and a Bachelor of Business Administration degree in accounting from Texas A&M University.

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

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

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

David D. Kinder is Vice President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mr. Kinder was elected Treasurer of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in May 2005. He was elected Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in October 2002. He served as manager of corporate development for Kinder Morgan Kansas, Inc. and Kinder Morgan G.P., Inc. from January 2000 to October 2002. He also served as Treasurer of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Vice President, Corporate Development and Treasurer upon its conversion. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.

Joseph Listengart is Vice President, General Counsel and Secretary of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mr. Listengart was elected Vice President, General Counsel and Secretary of KMR upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of Kinder Morgan Kansas, Inc. in October 1999. Mr. Listengart was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been an employee of Kinder Morgan G.P., Inc. since March 1998. He also served as General Counsel and Secretary of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Vice President, General Counsel and Secretary upon its conversion. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990.

Thomas A. Martin is Vice President (President, Natural Gas Pipelines) of KMR and Kinder Morgan G.P., Inc. Mr. Martin was elected Vice President (President, Natural Gas Pipelines) of KMR and Kinder Morgan G.P., Inc. in November 2009. Mr. Martin served as President, Texas Intrastate Pipeline Group from May 2005 until November 2009. From April 2003 to May 2005 he served as Vice President of Storage and Optimization for our Texas Intrastate Pipeline Group. Mr. Martin received a Bachelor of Business Administration degree from Texas A&M University.

James E. Street is Vice President, Human Resources and Administration of KMR, Kinder Morgan G.P., Inc., KMI and Kinder Morgan Kansas, Inc. Mr. Street was elected Vice President, Human Resources and Administration of KMR upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Kinder Morgan Kansas, Inc. in August 1999. He has been Vice President, Human Resources and Administration of KMI since February 2011. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.

Corporate Governance

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

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

We make available free of charge within the “Investors” information section of our Internet website, at www.kindermorgan.com, the governance guidelines, the charters of the audit committee, compensation committee and nominating and governance committee, and our code of business conduct and ethics (which applies to senior financial and accounting officers and the chief executive officer, among others). We intend to disclose any amendments to our code of business conduct and ethics that would otherwise be disclosed on Form 8-K and any waiver from a provision of that code granted to our executive officers or directors that would otherwise be disclosed on Form 8-K on our Internet website within four business days following such amendment or waiver. The information contained on or connected to our Internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

Interested parties may contact our lead director (Mr. Lawrence, discussed in Item 13), the chairpersons of any of the board’s committees, the independent directors as a group or the full board by mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, Attention: General Counsel, or by e-mail within the “Contact Us” section of our Internet website, at www.kindermorgan.com. Any communication should specify the intended recipient.

Section 16(a) Beneficial Ownership Reporting Compliance

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

Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2010, other than a Form 4 filed on October 25, 2010 by Mr. Lawrence to report a transaction that occurred on June 16, 2010.

Item 11. Executive Compensation.

As is commonly the case for publicly traded limited partnerships, we have no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as our general partner, is to direct, control and manage all of our activities. Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has delegated to KMR the management and control of our business and affairs to the maximum extent permitted by our partnership agreement and Delaware law, subject to our general partner’s right to approve certain actions by KMR. The executive officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities for KMR, and certain of those executive officers also serve as executive officers of KMI and of Kinder Morgan Kansas, Inc.

Except as indicated otherwise, all information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for services rendered to us, our subsidiaries and our affiliates, including KMI and Kinder Morgan Kansas, Inc. In this Item 11, “we,” “our” or “us” refers to Kinder Morgan Energy Partners, L.P. and, where appropriate, Kinder Morgan G.P., Inc., KMR, KMI and Kinder Morgan Kansas, Inc.

Compensation Discussion and Analysis

Program Objectives

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

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

Our executive compensation program is principally composed of the following two elements: (i) base cash salary; and (ii) possible annual cash bonus (reflected in the Summary Compensation Table below as Non-Equity Incentive Plan Compensation). We pay our executive officers a base salary not to exceed $300,000, which we believe is below annual base salaries for comparable positions in the marketplace. In addition, we believe that the compensation of our Chief Executive Officer, Chief Financial Officer and the executives named in the Summary Compensation Table below (collectively referred to in this Item 11 as our named executive officers), should be directly and materially tied to the financial performance of Kinder Morgan Kansas, Inc. and us, and should be aligned with the interests of our unitholders. Therefore, the majority of our named executive officers’ compensation is allocated to the “at risk” portion of our compensation program—the annual cash bonus. Accordingly, for 2010, our executive compensation was weighted toward the cash bonus, payable on the basis of the achievement of (i) a free cash flow target (described more fully below) by Kinder Morgan Kansas, Inc.; and (ii) a cash distribution per common unit target by us.

Our compensation is determined independently without the use of any compensation surveys. Nevertheless, we annually compare our executive compensation components with market information, consisting of third-party surveys in which we participate. The surveys we use in reviewing our executive compensation consist of the Towers Executive Survey, in which approximately 300 to 400 companies participate, the Hewitt Executive Survey, in which approximately 400 companies participate, and the Natural Gas Transmission Industries Survey, in which companies in the natural gas industry participate. The purpose of this comparison is to ensure that our total compensation package operates effectively, remains both reasonable and competitive with the energy industry, and is generally comparable to the compensation offered by companies of similar size and scope as us. We also keep abreast of current trends, developments, and emerging issues in executive compensation, and if appropriate, will obtain advice and assistance from outside legal, compensation or other advisors.

We have endeavored to design our executive compensation program and practices with appropriate consideration of all tax, accounting, legal and regulatory requirements. Section 162(m) of the Internal Revenue Code limits the deductibility of certain compensation for executive officers to $1.0 million of compensation per year; however, if specified conditions are met, certain compensation may be excluded from consideration of the $1.0 million limit. Since the bonuses paid to our executive officers were paid under Kinder Morgan Kansas, Inc.’s Annual Incentive Plan as a result of reaching designated financial targets established by Richard D. Kinder and KMR’s compensation committee, we expect that all compensation paid to our executives would qualify for deductibility under federal income tax rules. Though we are advised that limited partnerships, such as us, and private companies, such as Kinder Morgan Kansas, Inc. prior to KMI’s initial public offering, are not subject to section 162(m), we and Kinder Morgan Kansas, Inc. have chosen to generally operate as if this code section does apply to us and Kinder Morgan Kansas, Inc. as a measure of appropriate governance.

Behaviors Designed to Reward

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

Unlike many companies, we have no executive perquisites, supplemental executive retirement, non-qualified supplemental defined benefit/contribution, deferred compensation or split dollar life insurance programs for our executive officers. We have no executive company cars or executive car allowances nor do we pay for financial planning services. Additionally, we do not own any corporate aircraft, and we do not pay for executives to fly first class. We believe that this area of our existing executive compensation package is below competitive levels for comparable companies; however, we have no current plans to change our policy of not offering such executive benefits or perquisite programs.

We do not have employment agreements (other than with Richard D. Kinder) or change of control agreements with our executive officers, although the KMI Class B shares held by our executive officers will fully vest upon a change of control. In connection with KMI’s initial public offering, one of our affiliated companies entered into severance agreements with 11 of our executive officers. See “—Other Compensation—Other Potential Post-Employment Benefits.”

At his request, Richard D. Kinder receives $1 of base salary per year from Kinder Morgan Kansas, Inc. Additionally, Mr. Kinder has requested that he receive no annual bonus or other compensation from us or any of our affiliates (other than the KMI Class B unit awards that he received in 2007 in connection with the going-private transaction). Mr. Kinder does not have any deferred compensation, supplemental retirement or any other special benefit, compensation or perquisite arrangement with us, and each year, Mr. Kinder reimburses us for his portion of health care premiums and parking expenses.

Elements of Compensation

As outlined above, our executive compensation program is principally composed of the following two elements: (i) a base cash salary; and (ii) a possible annual cash bonus. With respect to our named executive officers other than our Chief Executive Officer, KMR’s compensation committee and Richard D. Kinder review and approve annually the financial goals and objectives of both us and Kinder Morgan Kansas, Inc. that are relevant to the compensation of our named executive officers.

The KMR compensation committee solicits information from Richard D. Kinder and James E. Street (Vice President, Human Resources and Administration), with respect to the performance of C. Park Shaper (President) and Steven J. Kean (Executive Vice President and Chief Operating Officer). Similarly, the compensation committee solicits information from Messrs. Kinder, Shaper, Kean and Street with respect to the performance of the other named executive officers. The compensation committee also obtains information from Mr. Street with respect to compensation of comparable positions of responsibility at comparable companies. All of this information is taken into account by the compensation committee, which makes final determinations regarding compensation of the named executive officers. No named executive officer reviews his or her own performance or approves his or her own compensation.

Additionally, if any of our general partner’s or KMR’s executive officers is also an executive officer of Kinder Morgan Kansas, Inc., the compensation determination or recommendation (i) may be with respect to the aggregate compensation to be received by such officer from Kinder Morgan Kansas, Inc., KMR, and our general partner that is to be allocated among them; or alternatively (ii) may be with respect to the compensation to be received by such executive officers from Kinder Morgan Kansas, Inc., KMR or our general partner, as the case may be, in which case such compensation will be allocated among Kinder Morgan Kansas, Inc., on the one hand, and KMR and our general partner, on the other hand.

Base Salary

Base salary is paid in cash. The base salary cap for our executive officers, with the exception of our Chairman and Chief Executive Officer who receives $1 of base salary per year as described above, is an annual amount not to exceed $300,000. Prior to October 2008, the salary cap was $200,000 per year. Generally, we believe that our executive officers’ base salaries are below base salaries for executives in similar positions and with similar responsibilities at companies of comparable size and scope, based upon independent salary surveys in which we participate.

Possible Annual Cash Bonus (Non-Equity Cash Incentive)

For the 2009 and 2008 bonus years, our possible annual cash bonuses were provided for under Kinder Morgan Kansas, Inc.’s Annual Incentive Plan, which became effective January 18, 2005. For the 2010 bonus year, Kinder Morgan Kansas, Inc.’s Board of Directors approved a new Annual Incentive Plan (referred to in this Item 11 as the plan) mirroring the previous plan. The overall purpose of the plan is to increase our executive officers’ and our employees’ personal stake in the continued success of Kinder Morgan Kansas, Inc., and us, by providing to them additional incentives through the possible payment of annual cash bonuses. Under the plan, a budget amount is established for annual cash bonuses at the beginning of each year that may be paid to our executive officers and other employees depending on whether Kinder Morgan Kansas, Inc. and its subsidiaries (including us) meet certain financial performance objectives (as discussed below). The amount included in our budget for bonuses is not allocated between our executive officers and non-executive officers. Assuming the financial performance objectives are met, the budgeted pool of bonus dollars is further assessed and potentially increased if we exceed the financial performance objectives. The budget for bonuses also may be adjusted upward or downward based on Kinder Morgan Kansas, Inc.’s and its subsidiaries’ overall performance in other areas, including but not limited to safety and environmental goals and regulatory compliance.

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

The plan consists of two components: the executive plan component and the non-executive plan component. Our Chairman and Chief Executive Officer, and all employees who report directly to the Chairman, including all of the named executive officers, are eligible for the executive plan component; however, as stated elsewhere in this “Compensation Discussion and Analysis,” Richard D. Kinder has elected to not participate under the plan. As of December 31, 2010, excluding Mr. Kinder, eleven of our executive officers were eligible to participate in the executive plan component. All other U.S. and Canadian eligible employees were eligible for the non-executive plan component.

At or before the start of the calendar year (or later, to the extent allowed under Internal Revenue Code regulations), financial performance objectives based on one or more of the criteria set forth in the plan are established by KMR’s compensation committee. Two financial performance objectives were set for 2010 under both the executive plan component and the non-executive plan component. The two financial performance objectives were:

▪

$4.40 in cash distributions per common unit by us (the same as our previously disclosed 2010 budget expectations); and

▪

$757 million of free cash flow for Kinder Morgan Kansas, Inc., which consists of distributions received from us (including value received in the form of i-units we distribute to KMR) and NGPL less cash taxes, cash interest, general and administrative expenses, and capital expenditures.

A third objective which could potentially decrease or increase the budgeted pool of bonus dollars for 2010 was a goal to improve our environmental, health, and safety performance by (i) beating industry average incident rates; and (ii) improving our incident rates compared to our previous three year averages.

At the end of 2010, the extent to which the financial performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by KMR’s compensation committee was determined. For 2010:

▪

we distributed $4.40 in cash per common unit—generating enough cash from operations in 2010 to fully cover our cash distributions; however, we fell short (approximately $23 million) of meeting our budgeted excess cash coverage above that distribution target; and

▪

Kinder Morgan Kansas, Inc. generated $795.7 million in free cash flow—not including a $170.0 million reduction in cash ($109.0 million reduction after tax) due to a portion of our partnership distributions for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations (our partnership distributions are discussed further in Notes 10 and 11 to our consolidated financial statements included elsewhere in this report).

Based on the above, the KMR compensation committee recommended that 93.65% of the 2010 budgeted cash bonus opportunity be earned and funded under the plan. Notwithstanding, the named executive officers were awarded less than 93.65% of what they otherwise would have been awarded for 2010 had 100% of the budgeted cash bonus opportunity been earned and funded.

In addition to determining the financial performance objectives under the plan, at or before the start of each calendar year, the compensation committee sets the bonus opportunities available to each executive officer. The table below sets forth the maximum bonus opportunities that could have been payable by Kinder Morgan Kansas, Inc. and us collectively to the named executive officers for achievement of the threshold, target and maximum 2010 financial performance objectives established under the plan. If neither of the financial performance objectives was met, no bonus opportunity would be available to the named executive officers. The maximum payout to any individual under the plan for any year is $3.0 million. The compensation committee may reduce the amount of the bonus actually paid to any executive officer from the amount of any bonus opportunity open to such executive officer. Because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established each year for eligible executive officers chosen to participate for that year, it is not possible to accurately predict any amounts that will actually be paid under the executive portion of the plan over the life of the plan. The compensation committee set maximum bonus opportunities under the plan for 2010 for the executive officers at dollar amounts in excess of that which were expected to actually be paid under the plan. In fact, while achievement of the financial performance objectives sets the maximum bonus opportunity for each executive officer, the compensation committee has never awarded the maximum bonus opportunity to a current named executive officer. The actual payout amounts under the Non-Equity Incentive Plan Awards made for 2010 (paid in 2011) are set forth in the Summary Compensation Table in the column entitled “Non-Equity Incentive Plan Compensation.”

Kinder Morgan Kansas, Inc. Annual Incentive Plan Bonus Opportunities for 2010
Name	Threshold (1)		Target (2)		Maximum (3)
Richard D. Kinder (4)	$	–	$	–	$	–
Kimberly A. Dang		500,000		1,000,000		1,500,000
Steven J. Kean		750,000		1,500,000		3,000,000
Joseph Listengart		500,000		1,000,000		1,500,000
C. Park Shaper		750,000		1,500,000		3,000,000

__________

(1)	Represents the maximum bonus opportunity available to the executive officer if one of the financial performance objectives was met.
(2)	Represents the maximum bonus opportunity available to the executive officer if both of the financial performance objectives were met.
(3)	Represents the maximum bonus opportunity available to the executive officer if both of the financial performance objectives were exceeded by 10% or more.
(4)	Declined to participate.

The 2010 bonuses for our executive officers were overwhelmingly based on whether the established financial performance objectives were met. The compensation committee also considered, in a purely subjective manner, how well the executive officer performed his or her duties during the year. Information was solicited from relevant members of senior management regarding the performance of our named executive officers (described following), and determinations and recommendations were made at the regularly scheduled first quarter board and compensation committee meetings held in January 2011. Other factors considered by the compensation committee primarily consisted of the amount of the bonus paid to the executive officer in the prior year and market data about compensation of comparable positions of responsibility at comparable companies, consisting of the compensation surveys referred to above. With respect to using these other factors in assessing performance, KMR’s compensation committee did not find it practicable to, and did not, use a “score card,” or quantify or assign relative weight to the specific criteria considered. The amount of a downward adjustment, subject to the maximum bonus opportunity that was established at the beginning of the year, was not subject to a formula. Specific aspects of an individual’s performance were not identified in advance. Rather, adjustments were based on KMR’s compensation committee’s judgment, giving consideration to the totality of the record presented, including the individual’s performance and the magnitude of any other positive or negative factors.

Compensation Related to the Going Private Transaction

In connection with Kinder Morgan Kansas, Inc.’s going Private Transaction, members of our management were awarded Kinder Morgan Holdco LLC Class A-1 and Class B units. In accordance with generally accepted accounting principles, we are required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units. The Class A-1 and Class B units awarded to members of our management may be viewed as a replacement of restricted stock awards made by Kinder Morgan Kansas, Inc. prior to the going private transaction as a component of long-term executive compensation.

Comparison of Class B Units to Class B Shares. The Class B units were converted into Class B shares in connection with KMI’s initial public offering. The Class B Shares are intended to substantially preserve the economic rights of the Class B units in Kinder Morgan Holdco LLC but differ from the Class B units in certain respects, including the following:

▪

Class B units were subject to time vesting, with one-third vesting on the third, fourth and fifth anniversaries of the date of their issuance. All distributions with respect to the non-vested portion of such Class B units were held in escrow pending the vesting or forfeiture of such Class B units. Class B shares are not subject to time vesting. As a result, holders of Class B shares will be entitled to receive and retain any distributions on, and shares of KMI common stock issued upon conversion of, such Class B shares;

▪

the amount of Class B units forfeited upon termination of a holder’s employment depended on the reason for such termination and other factors such as time vesting and the level of cumulative distributions made by KMI as of a relevant date. Prior to a change of control, all non-time-vested Class B units were forfeited upon termination of a holder’s employment for any reason. With respect to time-vested Class B units, all such Class B units were forfeited upon termination of a holder’s employment for cause, no Class B units were forfeited upon termination of a holder’s employment for death or disability and all or a portion of Class B units were forfeited upon termination of a holder’s employment for other reasons based on the level of cumulative distributions made by KMI as of the date of termination. The amount of Class B shares forfeited will be based solely on the reason for the termination of employment. No Class B shares will be forfeited upon termination of a holder’s employment for death or disability. Half of a holder’s Class B shares will be forfeited upon termination of a holder’s employment by such holder for good reason or termination of a holder’s employment by us without cause. All Class B shares will be forfeited upon termination of a holder’s employment for any other reason, including termination for cause;

▪

amounts in respect of forfeited Class B units were transferred to an incentive pool and could be paid to other members of management (excluding Mr. Kinder) in the discretion of the chief manager and subject to certain unitholder approvals. Forfeited Class B shares will automatically become treasury shares, and KMI will transfer the forfeited Class B shares into a trust. Any property in the trust, including dividends, proceeds or earnings received with respect to such Class B shares, may be distributed to new or existing members of management (excluding Mr. Kinder) in any proportion at the election of KMI’s chief executive officer and subject to approval by certain of KMI’s directors;

▪

holders of forfeited Class B units that were time-vested could receive certain levels of distributions even after such holder’s termination of employment depending on the level of cumulative distributions made by KMI as of the date of termination. Under specified circumstances, a holder of Class B shares who otherwise would forfeit such Class B shares upon such holder’s termination of employment will retain his or her Class B shares until such holder has received a specified amount of total value, even if distributed after such holder’s termination;

▪

if a holder of Class B units was terminated for any reason, KMI could repurchase his or her Class B units generally at fair market value. KMI does not have a right of repurchase with respect to the Class B shares; and

▪

Class B units would fully vest upon a change of control. Class B shares are not subject to forfeiture after a change of control.

Comparison of Class A-1 Units to Class C Shares. The Class A-1 units converted into the Class C shares in connection with KMI’s initial public offering. The Class C shares are intended to substantially preserve the economic rights of the Class A-1 units in Kinder Morgan Holdco LLC but differ from the Class A-1 units in certain respects, including the following:

▪

Class A-1 units were subject to forfeiture if a holder was terminated for cause. Class C shares are not subject to forfeiture; and

▪

if the employment of a holder of Class A-1 units was terminated for any reason, KMI could repurchase his or her Class A-1 units generally at fair market value. KMI does not have a right of repurchase with respect to the Class C shares.

Class B Share Plan and Class B Share Trust. The Class B shares may be forfeited by our management under the circumstances described above. All forfeited Class B shares will automatically become treasury shares, and KMI will transfer the forfeited Class B shares to a trust established solely to hold these Class B shares, together with any dividends, proceeds received in respect of these Class B shares, shares of KMI common stock issued in connection with the conversion of these Class B shares or earnings with respect to such property. KMI has established the Class B share plan, which is a long-term compensation plan, to govern the terms of awards in respect of forfeited Class B shares and related property in the Class B share trust. Pursuant to the Class B share plan and KMI’s shareholders agreement, each item of property in the trust may be distributed separately from the underlying Class B shares to members of new or existing management (other than Richard D. Kinder), as designated by KMI’s chief executive officer and approved by certain members of KMI’s board of directors. All property held in the trust on May 31, 2015 will be distributed proportionally to the holders of Class B shares as of May 31, 2015. KMI has agreed to pay the costs of the Class B share trust, including the fees of the independent trustee. KMI does not expect these costs to be material.

Other Compensation

Kinder Morgan Kansas, Inc. Savings Plan. The Kinder Morgan Kansas, Inc. Savings Plan is a defined contribution 401(k) plan. The savings plan permits all full-time employees of Kinder Morgan Kansas, Inc. and those of KMGP Services Company, Inc., including the named executive officers, to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. For more information on this savings plan, see Note 9 “Employee Benefits—Kinder Morgan Savings Plan” to our consolidated financial statements included elsewhere in this report. As a result of a cost savings effort in 2009, all officers with the position of vice president or higher, including our named executive officers, were suspended from receiving any company contributions commencing February 15, 2009. Company contributions for these employees were reinstated effective February 1, 2010.

Kinder Morgan Kansas, Inc. Cash Balance Retirement Plan. Employees of Kinder Morgan Kansas, Inc. and KMGP Services Company, Inc., including the named executive officers, are also eligible to participate in the Kinder Morgan Kansas, Inc. Retirement Plan, referred to as the Cash Balance Retirement Plan, a cash balance plan. Employees accrue benefits through a Personal Retirement Account, referred to as the PRA, in the Cash Balance Retirement Plan. We allocate contribution credits equivalent to 3% of eligible compensation every pay period to participants’ PRA. For plan years prior to 2011, interest was credited to the PRA at the 30-year U.S. Treasury bond rate published in the Internal Revenue Bulletin for the November of the prior year. Beginning January 1, 2011, interest is credited to the PRA at the 5-year U.S. Treasury bond rate published in the Internal Revenue Bulletin for the November of the prior year, plus 0.25%. Employees become 100% vested in the plan after three years and may take a lump sum distribution upon termination of employment or retirement. As a result of a cost savings effort in 2009, all company contributions to the plan were suspended from April 12, 2009 through December 31, 2009. Company contributions were reinstated effective January 1, 2010.

The following table sets forth the estimated actuarial present value of each named executive officer’s accumulated pension benefit as of December 31, 2010, under the provisions of the Cash Balance Retirement Plan. With respect to our named executive officers, the benefits were computed using the same assumptions used for financial statement purposes, assuming current remuneration levels without any salary projection, and assuming participation until normal retirement at age 65. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.

Pension Benefits
Name	Plan Name	Current Credited Yrs of Service	Present Value of Accumulated Benefit (a)			Contributions During 2010
Richard D. Kinder	Cash Balance	10		$	-		$	-
Kimberly A. Dang	Cash Balance	9			53,480			7,350
Steven J. Kean	Cash Balance	9			65,220			7,350
Joseph Listengart	Cash Balance	10			75,873			7,350
C. Park Shaper	Cash Balance	10			75,873			7,350

__________

(a)

The present values in the Pension Benefits table are based on certain assumptions, including a 5.0% discount rate, 5.0% cash balance interest crediting rate, and a lump sum calculated using the IRS 2010 Mortality Tables. We assumed benefits would commence at normal retirement age, which is 65. No death or turnover was assumed prior to retirement date.

Potential Payments Upon Termination or Change-in-Control. Our named executive officers (excluding Richard D. Kinder) are entitled to certain benefits in the event their employment is terminated by KMI without cause or by them with good reason, whether or not related to a change in control. See “—Other Potential Post-Employment Benefits—Severance Agreements” below for a description of the terms. Mr. Kinder is also entitled to certain benefits under his employment agreement upon his termination by us without cause or by him with good reason, whether or not related to a change in control. See “Other Potential Post-Employment Benefits—Employment Agreement” below for a description of the terms. Upon termination of employment of a named executive officer due to death or disability (as determined in accordance with our long-term disability plan covering such employee), all of his or her KMI Class B shares will no longer be subject to forfeiture. In the event of a termination of employment of a named executive officer by us without “cause” or by a named executive officer with “good reason” (as each such term is defined in KMI’s shareholders agreement and described under “—Severance Agreements”), 50% of his or her KMI Class B shares will no longer be subject to forfeiture. In addition, all unvested KMI Class B shares will no longer be subject to forfeiture upon a change of control (as defined in KMI’s shareholders agreement).

The following tables list separately the potential payments and benefits upon a change in control of KMI and the potential payments and benefits upon a termination of employment for our named executive officers. The tables assume the triggering event for the payments or provision of benefits occurred on December 31, 2010. Actual amounts payable to each executive listed below upon termination can only be determined definitively at the time of each executive’s actual departure. Amounts in the tables for the acceleration of the vesting of KMI Class B shares are calculated based on the estimated value of a KMI Class B unit as of December 31, 2010. In addition to the amounts shown in the tables below, each executive would receive payments for amounts of base salary and vacation time accrued through the date of termination and payment for any reimbursable business expenses incurred prior to the date of termination.

Potential Payments Upon Termination of Employment or Change in Control for Richard D. Kinder
	Termination Payment			Benefit Continuation			Acceleration of Vesting of KMI Class B Shares
Termination without “cause” or “good reason” or due to “change in duties”(1)(3)		$	2,250,000		$	34,896		$	-
Termination due to death or “disability”(1)(2)			750,000			-			-
Upon a change in control			N/A			N/A			-

__________

(1)	As such terms are defined in Mr. Kinder’s employment agreement and described under “—Other Potential Post-Employment Benefits—Employment Agreement.”
(2)	If Mr. Kinder becomes disabled, he is eligible for the same medical benefits as most other employees.
(3)	With respect to KMI Class B shares, as the terms “cause” and “good reason” are defined in KMI’s shareholders agreement and described under “—Other Potential Post-Employment Benefits—Severance Agreements.”

Potential Payments Upon Termination of Employment or Change in Control for Other Named Executive Officers
	Termination Without Cause or Good Reason				Acceleration of Vesting of KMI Class B Shares
Name	Salary Continuation		Benefit Continuation		Upon Change in Control or Termination due to Death or Disability		Upon Termination Without Cause or for Good Reason
Kimberly A. Dang	$	300,000	$	14,818	$	-	$	-
Steven J. Kean		300,000		18,190		-		-
Joseph Listengart		300,000		18,410		-		-
C. Park Shaper		600,000		18,410		-		-

Other Potential Post-Employment Benefits

Employment Agreement. On October 7, 1999, Richard D. Kinder entered into an employment agreement with Kinder Morgan Kansas, Inc. pursuant to which he agreed to serve as its Chairman and Chief Executive Officer. His employment agreement provides for a term of three years and one year extensions on each anniversary of October 7th. Mr. Kinder, at his initiative, accepted an annual salary of $1 to demonstrate his belief in our and Kinder Morgan Kansas, Inc.’s long-term viability. Mr. Kinder continues to accept an annual salary of $1, and he receives no other compensation from us.

Kinder Morgan Kansas, Inc. believes that Mr. Kinder’s employment agreement contains provisions that are beneficial to Kinder Morgan Kansas, Inc. and its subsidiaries and accordingly, Mr. Kinder’s employment agreement is extended annually at the request of Kinder Morgan Kansas, Inc.’s and KMR’s Boards of Directors. For example, with limited exceptions, Mr. Kinder is prevented from competing in any manner with Kinder Morgan Kansas, Inc. or any of its subsidiaries, while he is employed by Kinder Morgan Kansas, Inc. and for 12 months following the termination of his employment with Kinder Morgan Kansas, Inc. The employment agreement provides that he will receive a severance payment equal to $2.25 million in the event his employment is terminated without “cause” (as defined in the employment agreement) or in the event he is subject to a “change in duties” (as defined in the employment agreement) without his consent. His employment agreement also provides that in the event of his death or termination due to his total and permanent disability, he or his estate will receive an amount equal to the greater of his annual salary ($1) or $750,000, and in the case of his total and permanent disability, such amount will be an annual amount until the effective date of termination of employment. In addition, under the terms of KMI’s shareholders agreement, Mr. Kinder also has agreed not to compete with KMI or any of its subsidiaries for an additional period of one year and not to solicit KMI’s or any of its subsidiaries’ employees or interfere with certain of its business relationships during the term of his employment and for two years thereafter.

100

Upon a change in control and a termination of Mr. Kinder’s employment by KMI or by Mr. Kinder, certain payments made to him could be subject to the excise tax imposed on “excess parachute payments” by the Internal Revenue Code. Pursuant to his employment agreement, Mr. Kinder is entitled to have his compensation “grossed up” for all such excise taxes and any federal, state and local taxes applicable to such gross-up payment (including any penalties and interest). We estimate the amount of such gross up payment for Mr. Kinder’s termination payment and benefits to be approximately $1.05 million. The estimate of “excess parachute payments” for purposes of these calculations does not take into account any mitigation for payments which could be shown (under the facts and circumstances) not to be contingent on a change in control or for any payments being made in consideration of non-competition agreements or as reasonable compensation. The gross-up calculations assume an excise tax rate of 20%, a statutory federal income tax rate of 35%, and a Medicare tax rate of 1.45%. If upon a change in control Mr. Kinder’s employment does not terminate, he would only be entitled to the immediate vesting of any KMI Class B shares.

Severance Agreements. In connection with the going-private transaction, KMI established a severance policy covering some of its employees, including our executive officers, that provides salary and benefits during a non-compete period ranging up to two years depending on the reason for such employee’s termination of employment. All of our executive officers who are subject to this policy continue to be employed by KMI or its subsidiaries as of the date of this report. In connection with KMI’s initial public offering, a subsidiary of KMI entered into severance agreements with respect to 11 of our executive officers (including our named executive officers other than Richard D. Kinder) that provide severance in the amount of the executive’s salary plus benefits during the executive’s non-compete period, ranging from one to two years following the executive’s termination of employment, if the executive voluntarily terminates his or her employment for “good reason” (as defined in the severance agreements) or the executive’s employment with KMI and its subsidiaries is terminated “without cause” (as defined in the severance agreements). The other employees who did not enter into severance agreements with KMI are eligible for the same severance policy as all regular full time U.S.-based employees not covered by a bargaining agreement, which caps severance payments at an amount equal to six months of salary.

Summary Compensation Table

The following table shows compensation paid or otherwise awarded to (i) our principal executive officer; (ii) our principal financial officer; and (iii) our three most highly compensated executive officers (other than our principal executive officer and principal financial officer) serving at fiscal year end 2010 (collectively referred to as the “named executive officers”) for services rendered to us, our subsidiaries or our affiliates, including KMI and Kinder Morgan Kansas, Inc. (collectively referred to as the KMI affiliated entities), during fiscal years 2010, 2009 and 2008. The amounts in the columns below represent the total compensation paid or awarded to the named executive officers by all the KMI affiliated entities, and as a result, the amounts are in excess of the compensation expense allocated to, recognized and paid by us for services rendered to us.

						(a)		(b)		(c)
Name and Principal Position	Year	Salary		Bonus		Non-Equity Incentive Plan Compensation		Change in Pension Value		All Other Compensation		Total
Richard D. Kinder	2010	$	1	$	-	$	-	$	-	$	-	$	1
Director, Chairman and	2009		1		-		-		-		-		1
Chief Executive Officer	2008		1		-		-		-		-		1

Kimberly A. Dang	2010		294,444		-		500,000		9,544		11,704		815,692
Vice President and	2009		257,692		-		550,000		4,243		3,115		815,050
Chief Financial Officer	2008		223,077		-		440,000		8,285		11,863		683,225

Steven J. Kean	2010		294,444		-		1,000,000		10,058		13,247		1,317,749
Executive Vice President	2009		257,692		-		1,250,000		4,683		4,251		1,516,626
and Chief Operating Officer	2008		223,077		-		1,150,000		8,755		13,007		1,394,839

Joseph Listengart	2010		294,444		-		749,000		10,524		11,665		1,065,633
Vice President, General	2009		257,692		-		925,000		5,082		2,866		1,190,640
Counsel and Secretary	2008		223,077		-		900,000		9,188		11,629		1,143,894

C. Park Shaper	2010		294,444		-		1,040,000		10,524		12,925		1,357,893
Director and President	2009		257,692		-		1,300,000		5,082		3,971		1,566,745
	2008		223,077		-		1,200,000		9,188		12,769		1,445,034

__________

101

(a)	Represents amounts paid according to the provisions of the Kinder Morgan Kansas, Inc. Annual Incentive Plan. Amounts were earned in the fiscal year indicated but were paid in the next fiscal year.

(b)

Represents the 2010, 2009 and 2008, as applicable, change in the actuarial present value of accumulated defined pension benefit (including unvested benefits) according to the provisions of Kinder Morgan Kansas, Inc.’s Cash Balance Retirement Plan.

(c)

Amounts include value of contributions to the Kinder Morgan Kansas, Inc. Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000, and taxable parking subsidy. For 2010 and 2009, Mrs. Dang also had imputed income from a company provided cell phone. Amounts in 2010, 2009 and 2008 representing the value of contributions to the Kinder Morgan Kansas, Inc. Savings Plan are $11,022, $2,308 and $11,154, respectively.

Grants of Plan-Based Awards

The following supplemental compensation table shows compensation details on the value of all non-guaranteed and non-discretionary incentive awards granted during 2010 to our named executive officers. The table includes awards made during or for 2010. The information in the table under the caption “Estimated Future Payouts Under Non-Equity Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the Kinder Morgan Kansas, Inc. Annual Incentive Plan for performance in 2010. Amounts actually paid under that plan for 2010 are set forth in the Summary Compensation Table (above) under the caption “Non-Equity Incentive Plan Compensation.” There will not be any additional payouts under the Annual Incentive Plan for 2010.

	Estimated Future Payouts Under Non-Equity Incentive Plan Awards(a)
Name	Threshold		Target		Maximum
Richard D. Kinder	$	-	$	-	$	-
Kimberly A. Dang		500,000		1,000,000		1,500,000
Steven J. Kean		750,000		1,500,000		3,000,000
Joseph Listengart		500,000		1,000,000		1,500,000
C. Park Shaper		750,000		1,500,000		3,000,000

__________

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

Outstanding Equity Awards at Fiscal Year-End

The only unvested equity awards outstanding at the end of fiscal 2010 were the Class B units of Kinder Morgan Holdco LLC, which we refer to as the “KMI Class B units.” The KMI Class B units were awarded in 2007, in connection with the going-private transaction, by Kinder Morgan Holdco LLC to members of Kinder Morgan Kansas, Inc.’s management in consideration of their services to or for the benefit of Kinder Morgan Holdco LLC, now KMI. As a subsidiary of KMI, we are allocated a portion of the compensation expense recognized by KMI with respect to such units, although none of us or any of our subsidiaries has any obligation, nor do we expect, to pay any amounts in respect of such units.

Stock Awards

Name

Type of Units

Number of units

Vested during 2010(a)

Number of units

that have not vested(a)

Market value of

units of stock that

have not vested(b)

Richard D. Kinder

Class B units

263,801,817

527,603,635

N/A

Kimberly A. Dang

Class B units

16,487,614

32,975,227

N/A

Steven J. Kean

Class B units

52,760,363

105,520,727

N/A

Joseph Listengart

Class B units

26,380,182

52,760,363

N/A

C. Park Shaper

Class B units

72,545,500

145,090,999

N/A

__________

(a)

As reflected in “Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” pursuant to the plan of conversion, effective February 10, 2011, the KMI Class B units reflected in this table were converted to KMI Class B shares. The KMI Class B units were subject to time based vesting only (not performance based), and with respect to any holder thereof, vested 33 1/3% on each of the third, fourth and fifth year anniversary of the issuance of such Class B units to such holder.

(b)

Because as of December 31, 2010 the Class B units were equity interests of Kinder Morgan Holdco LLC, a private limited liability company, the market value of such interests was not readily determinable. None of our named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated, nor do we expect, to pay any amounts in respect of such units.

102

Risks Associated with Compensation Practices

KMGP Services Company, Inc., Kinder Morgan Kansas, Inc., and Kinder Morgan Canada Inc. employ all persons necessary for the operation of our business, and in our opinion, our compensation policies and practices for all persons necessary for the operation of our business do not create risks that are reasonably likely to have a material adverse effect on our business, financial position, results of operations or cash flows. Our belief is based on the fact that our employee compensation—primarily consisting of annual salaries and cash bonuses—is based on performance that does not reward risky behavior and is not tied to entering into transactions that pose undue risks to us.

Director Compensation

Compensation Committee Interlocks and Insider Participation.

The compensation committee of KMR functions as our compensation committee. KMR’s compensation committee is comprised of Mr. Gary L. Hultquist, Mr. C. Berdon Lawrence, and Mr. Perry M. Waughtal. KMR’s compensation committee makes compensation decisions regarding the executive officers of our general partner and its delegate, KMR. Mr. Richard D. Kinder, Mr. James E. Street, Mr. C. Park Shaper and Mr. Steven J. Kean, who are executive officers of KMR, participate in the deliberations of the KMR compensation committee concerning executive officer compensation. None of the members of KMR’s compensation committee is or has been one of our officers or employees, and none of our executive officers served during 2010 on a board of directors or compensation committee of another entity which has employed any of the members of KMR’s board of directors or compensation committee.

Directors Fees

Awards under our Common Unit Compensation Plan for Non-Employee Directors serve as compensation for each of KMR’s three non-employee directors. This plan is described in Note 12 “—Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements included elsewhere in this report. Directors of KMR who are also employees of Kinder Morgan Kansas, Inc. (Messrs. Richard D. Kinder and C. Park Shaper) do not receive compensation in their capacity as directors.

On April 1, 2003, KMR’s compensation committee established our Directors’ Unit Appreciation Rights Plan, and pursuant to this plan, each of KMR’s then three non-employee directors received common unit appreciation rights. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors; however, all unexercised awards made under the plan remain outstanding. For more information on this plan, see Note 12 “—Directors’ Unit Appreciation Rights Plan” to our consolidated financial statements included elsewhere in this report.

The following table discloses the compensation earned by each of KMR’s three non-employee directors for board service during fiscal year 2010. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. Directors of KMR who are also employees of KMI do not receive compensation in their capacity as directors.

Name	Fees Earned or Paid in Cash		Common Unit Awards(a)		All Other Compensation(b)		Total
Gary L. Hultquist	$	160,000	$	-	$	-	$	160,000
C. Berdon Lawrence		505		159,495		5,194		165,194
Perry M. Waughtal		160,000		-		162,400		322,400

__________

(a)

For Mr. Lawrence, represents the value of cash compensation received in the form of our common units according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors. Value computed as the number of common units elected to be received in lieu of cash (2,450) multiplied by the closing price on the day cash compensation is approved ($65.10 on January 19, 2010).

(b)

For Mr. Lawrence, amount represents distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors. For Mr. Waughtal, amount represents the unrealized value of common unit appreciation rights earned according to the provisions of our Directors’ Unit Appreciation Rights Plan for Non-Employee Directors and determined according to the share-based payment provisions of generally accepted accounting principles— for 17,500 common unit appreciation rights, equal to the increase in value of a corresponding common unit from December 31, 2009 ($60.98) to December 31, 2010 ($70.26).

103

Compensation Committee Report

Throughout fiscal 2010, the compensation committee of KMR’s board of directors was comprised of Mr. Gary L. Hultquist, Mr. C. Berdon Lawrence, and Mr. Perry M. Waughtal, each of whom the KMR board of directors has determined meets the criteria for independence under KMR’s governance guidelines and the New York Stock Exchange rules.

The KMR compensation committee has discussed and reviewed the above Compensation Discussion and Analysis for fiscal year 2010 with management. Based on this review and discussion, the KMR compensation committee recommended to its board of directors, that this Compensation Discussion and Analysis be included in this annual report on Form 10-K for the fiscal year 2010.

KMR Compensation Committee:

Gary L. Hultquist

C. Berdon Lawrence

Perry M. Waughtal

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

The following tables set forth information as of February 11, 2011, regarding (i) the beneficial ownership of (a) our common and Class B units, (b) KMR shares and (c) KMI shares by all directors of our general partner and KMR, its delegate, by each of the named executive officers identified in Item 11 “Executive Compensation” and by all directors and executive officers as a group; and (ii) the beneficial ownership of our common and Class B units and KMR shares by all persons known by our general partner to own beneficially at least 5% of such units or shares. Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002.

Amount and Nature of Beneficial Ownership(a)
	Common Units					Class B Units					Kinder Morgan Management Shares
Name	Number of Units(b)		Percent of Class			Number of Units(c)		Percent of Class			Number of Shares(d)		Percent of Class
Richard D. Kinder(e)		315,979		*			-		-			217,324		*
C. Park Shaper		4,000		*			-		-			33,632		*
Gary L. Hultquist		2,000		*			-		-			-		-
C. Berdon Lawrence(f)		9,664		*			-		-			-		-
Perry M. Waughtal		46,918		*			-		-			58,590		*
Steven J. Kean		1,780		*			-		-			2,274		*
Joseph Listengart		5,498		*			-		-			2,546		*
Kimberly A. Dang		121		*			-		-			558		*
Directors and Executive Officers as a group (14 persons)(g)		399,239		*			-		-			341,158		*
Kinder Morgan, Inc.(h)		16,370,428		7.48	%		5,313,400		100.00	%		13,113,531		14.27	%
Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne(i)		-		-			-		-			6,751,569		7.35	%
Janus Capital Management LLC(j)		-		-			-		-			5,843,116		6.36	%
Tortoise Capital Advisors, L.L.C.(k)		-		-			-		-			4,930,629		5.36	%

____________

* Less than 1%.

104

(a)	Except as noted otherwise, each beneficial owner has sole voting power and sole investment power over the units and shares listed.
(b)	As of February 11, 2011, we had 218,993,455 common units issued and outstanding.
(c)	As of February 11, 2011, we had 5,313,400 Class B units issued and outstanding.
(d)	Represent the limited liability company shares of KMR. As of February 11, 2011, there were 91,907,987 issued and outstanding KMR shares, including two voting shares owned by our general partner. In all cases, our i-units will be voted in proportion to the affirmative and negative votes, abstentions and non-votes of owners of KMR shares. Through the provisions in our partnership agreement and KMR’s limited liability company agreement, the number of outstanding KMR shares, including voting shares owned by our general partner, and the number of our i-units will at all times be equal.
(e)	Includes 7,879 common units and 1,072 KMR shares owned by Mr. Kinder’s spouse. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these common units and shares.
(f)	Includes 2,450 restricted common units.
(g)	Includes 2,450 restricted common units. Also includes 9,090 common units and 1,072 KMR shares owned by executives’ spouses and 842 KMR shares held by an executive for his children. The respective executives disclaim any beneficial ownership in 9,090 common units and 1,914 KMR shares.
(h)	Includes common units owned by KMI and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(i)	As reported on the Schedule 13G/A filed February 14, 2011 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors, L.P. reported that in regard to KMR shares, it had sole voting power over 0 shares, shared voting power over 6,751,134 shares, sole disposition power over 0 shares and shared disposition power over 6,751,134 shares. Mr. Kayne reports that in regard to KMR shares, he had sole voting power over 435 shares, shared voting power over 6,751,134 shares, sole disposition power over 435 shares and shared disposition power over 6,751,134 shares. Kayne Anderson Capital Advisors, L.P.’s and Richard A. Kayne’s address is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067.
(j)	As reported on the Schedule 13G/A filed February 14, 2011 by Janus Capital Management LLC. Janus Capital Management reported that in regard to KMR shares, it has sole voting power over 5,749,019 shares, shared voting power over 94,097 shares, sole disposition power over 5,749,019 shares and shared disposition power over 94,097 shares. Janus Capital Management LLC’s address is 151 Detroit Street, Denver, Colorado, 80206.
(k)	As reported on the Schedule 13G/A filed February 11, 2011 by Tortoise Capital Advisors, L.L.C. Tortoise Capital Advisors reported that in regard to KMR shares, it has sole voting power over 0 shares, shared voting power over 4,813,902 shares, sole disposition power over 0 shares and shared disposition power over 4,930,629 shares. Tortoise Capital Advisors, L.L.C.’s address is 11550 Ash Street, Suite 300, Leawood, Kansas, 66211.

____________

Amount and Nature of Beneficial Ownership(a)
Name	KMI Common Shares(b)		% of Common Shares(b)		KMI Class B Shares		% of Class B Shares(c)		KMI Class C Shares		% of Class C Shares(d)
Richard D. Kinder(e)		216,538,834		30.6		40,000,000		40.0		–		–
C. Park Shaper(f)		1,214,796		*		11,000,000		11.0		696,763		28.3
Gary L. Hultquist		–		-		–		-		–		-
C. Berdon Lawrence		–		-		–		-		–		-
Perry M. Waughtal		–		-		–		-		–		-
Steven J. Kean		597,103		*		8,000,000		8.0		342,477		13.9
Joseph Listengart		541,298		*		4,000,000		4.0		310,469		12.6
Kimberly A. Dang(g)		67,001		*		2,500,000		2.5		38,429		1.6
Directors and Executive Officers as a group (14 persons)		219,853,478		31.1		83,200,000		83.2		1,901,162		77.2

____________

* Less than 1%.

105

(a)	Except as noted otherwise, each beneficial owner has sole voting power and sole investment power over the shares listed.
(b)	As of February 11, 2011, KMI had 707,000,000 shares of common stock issued and outstanding on a fully-converted basis. As of that date, none of our directors or executive officers owned any shares of KMI common stock. However, they do own KMI Class A shares, which initially are convertible on a one-for-one basis into shares of common stock. Therefore, the amounts in this column represent the number of shares of KMI common stock of which the individuals have beneficial ownership, assuming the Class A shares are converted into the maximum number of shares of KMI common stock and that the KMI Class B shares and Class C shares are converted into zero shares of common stock.
(c)	As of February 11, 2011, KMI had 100,000,000 Class B shares issued and outstanding.
(d)	As of February 11, 2011, KMI had 2,462,927 Class C shares issued and outstanding.
(e)	Includes 46,664 Class A shares owned by Mr. Kinder’s wife. Mr. Kinder disclaims any and all beneficial or pecuniary interest in the Class A units held by his wife. Also includes 13,333,333 Class B shares that Mr. Kinder transferred to a limited partnership. Mr. Kinder may be deemed to be the beneficial owner of these transferred Class B shares because he controls the voting and disposition power of these Class B shares, but he disclaims 99% of any beneficial and pecuniary interest in them.
(f)	Includes 11,000,000 Class B shares that Mr. Shaper transferred to a limited partnership. Mr. Shaper may be deemed to be the beneficial owner of these transferred Class B shares because he controls the voting and disposition power of these Class B shares, but he disclaims 21% of any beneficial and pecuniary interest in them.
(g)	Includes 2,500,000 Class B shares that Mrs. Dang transferred to a limited partnership. Mrs. Dang may be deemed to be the beneficial owner of these transferred Class B shares because she has voting and disposition power of these Class B shares, but she disclaims 10% of any beneficial and pecuniary interest in them.

Equity Compensation Plan Information

The following table sets forth information regarding our equity compensation plans as of December 31, 2010. Specifically, the table provides information regarding our Common Unit Compensation Plan for Non-Employee Directors, described in Item 11 “Executive Compensation—Director Compensation—Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors,” and Note 12 to our consolidated financial statements included elsewhere in this report.

Plan Category	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders		-
Equity compensation plans not approved by security holders		72,232
Total		72,232

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

Related Transactions

Our policy is that (i) employees must obtain authorization from the appropriate business unit president of the relevant company or head of corporate function, and (ii) directors, business unit presidents, executive officers and heads of corporate functions must obtain authorization from the non-interested members of the audit committee of the applicable board of directors, for any business relationship or proposed business transaction in which they or an immediate family member has a direct or indirect interest, or from which they or an immediate family member may derive a personal benefit (a “related party transaction”). When deciding whether to authorize a related party transaction, our business unit presidents and the non-interested members of the audit committee of the applicable board of directors, consider, among other things, the nature of the transaction and the relationship, the dollar amount involved, and the availability of reasonable alternatives.

The maximum dollar amount of related party transactions that may be approved as described above in this paragraph in any calendar year is $1.0 million. Any related party transactions that would bring the total value of such transactions to greater than $1.0 million must be referred to the audit committee of the appropriate board of directors for approval or to determine the procedure for approval.

For further information regarding our related party transactions, see Note 11 to our consolidated financial statements included elsewhere in this report.

106

Director Independence

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

The board has adopted governance guidelines for the board and charters for the audit committee, nominating and governance committee and compensation committee. The governance guidelines and the rules of the New York Stock Exchange require that a majority of the directors be independent, as described in those guidelines, the committee charters and rules, respectively. Copies of the guidelines and committee charters are available on our Internet website at www.kindermorgan.com.

As described above, each of Mr. Hultquist, Mr. Lawrence and Mr. Waughtal is also an independent director of our general partner. Further, in January 2011, the son of Mr. Lawrence formed a new company with an unrelated third party. Mr. Lawrence’s son is an executive officer of the new company and owns 90% of its voting stock, while the third party owns the other 10% of the voting stock. Mr. Lawrence owns non-voting, non-participating, fixed dividend preferred stock of the new company. Mr. Lawrence is neither an officer, director or employee of the new company and has no other relationship with it. The new company acquired the assets of a company that had previously provided tank painting and coating services for one of our subsidiaries. Neither Mr. Lawrence nor his son had any relationship with the seller. The new company may in the future provide tank painting and coating services to one or more of our subsidiaries. Any such transaction would be subject to the approval of the disinterested members of the audit committee as described above. Messrs. Hultquist, Lawrence and Waughtal have no other relationships with us, KMR or our general partner.

The board considered the foregoing and affirmatively determined that Messrs. Hultquist, Lawrence and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the New York Stock Exchange rules. In conjunction with all regular quarterly and certain special board meetings, these three non-management directors also meet in executive session without members of management. In January 2011, Mr. Lawrence was elected for a one year term to serve as lead director to develop the agendas for and preside at these executive sessions of independent directors.

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

Item 14. Principal Accounting Fees and Services

The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2010 and 2009 (in dollars):

	Year Ended December 31,
	2010			2009
Audit fees(a)		$	2,187,638		$	2,421,145
Tax fees(b)			2,426,521			2,303,427
Total		$	4,614,159		$	4,724,572

____________

(a)

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

(b)

For 2010 and 2009, amounts include fees of $1,863,233 and $2,231,537, respectively, billed for professional services rendered for tax processing and preparation of Forms K-1 for our unitholders; and fees of $45,405 and $71,890, respectively, billed for professional services rendered for Internal Revenue Service assistance, tax function effectiveness, and for general state, local and foreign tax compliance and consulting services. For 2010 only, amount also includes fees of $495,000 billed for accounting methods/inventory accounting solutions and fees of $22,883 billed for self-charged items of interest income and deduction.

107

All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and were pre-approved by the audit committee of KMR and our general partner. Pursuant to the charter of the audit committee of KMR, the delegate of our general partner, the committee’s primary purposes include the following: (i) to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; (ii) to pre-approve all audit and non-audit services, including tax services, to be provided, consistent with all applicable laws, to us by our external auditors; and (iii) to establish the fees and other compensation to be paid to our external auditors. The audit committee has reviewed the external auditors’ fees for audit and non audit services for fiscal year 2010. The audit committee has also considered whether such non audit services are compatible with maintaining the external auditors’ independence and has concluded that they are compatible at this time.

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

108

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

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

(a)(3) Exhibits

	*3.1 —	Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended June 30, 2001, filed on August 9, 2001).
	*3.2 —	Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed November 22, 2004).
	*3.3 —	Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed May 5, 2005).
	*3.4 —	Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed April 21, 2008).
	*4.1 —	Form of certificate evidencing Common Units representing the common units of Kinder Morgan Energy Partners, L.P. (included as Exhibit A to Third Amended and Restated Agreement of Limited Partnership, filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2001 File No. 1701930, filed August 9, 2001).
	*4.2 —	Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed February 16, 1999, File No. 1-11234 (the “February 16, 1999 Form 8-K”)).
	*4.3 —	Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2001 (File No. 1-11234)).
	*4.4 —	Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2000).
	*4.5 —	Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Subordinated Debt Securities (including form of Subordinated Debt Securities) (filed as Exhibit 4.12 to Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2000).
	*4.6 —	Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).
	*4.7 —	Specimen of 6.75% Notes due March 15, 2011 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).
	*4.8 —	Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).

109

	*4.9 —	Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended March 31, 2002, filed on May 10, 2002).
	*4.10—	Specimen of 7.125% Notes due March 15, 2012 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended March 31, 2002, filed on May 10, 2002).
	*4.11—	Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended March 31, 2002, filed on May 10, 2002).
	*4.12—	Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (File No. 333-100346) filed on October 4, 2002 (the “October 4, 2002 Form S-4”)).
	*4.13—	First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to the October 4, 2002 Form S-4).
	*4.14—	Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the October 4, 2002 Form S-4 (File No. 333-102961)).
	*4.15—	Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 (File No. 333-102961) filed on February 4, 2003 (the “February 4, 2003 Form S-3”)).
	*4.16—	Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the February 4, 2003 Form S-3).
	*4.17—	Subordinated Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.4 to the February 4, 2003 Form S-3).
	*4.18—	Form of Subordinated Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Subordinated Indenture filed as Exhibit 4.4 to the February 4, 2003 Form S-3 (File No. 333-102961)).
	*4.19—	Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.00% Notes due December 15, 2013 (filed as Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004 (File No. 001-11234)).
	*4.20—	Certificate of Executive Vice President and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.125% Notes due November 15, 2014 (filed as Exhibit 4.27 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2004 filed March 4, 2005 (File No. 1-11234)).
	*4.21—	Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2005, filed on May 6, 2005 (File No. 1-11234)).
	*4.22—	Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2006 filed March 1, 2007).

110

	*4.23—	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2007 filed August 8, 2007).
	*4.24—	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.85% Senior Notes due 2012 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended September 30, 2007 filed November 9, 2007).
	*4.25—	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2007 filed February 26, 2008).
	*4.26—	Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2008 filed February 23, 2009).
	*4.27—	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.625% Senior Notes due 2015, and the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2009 filed August 3, 2009).
	*4.28—	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended September 30, 2009 filed October 30, 2009).
	*4.29—	Registration Rights Agreement, dated as of January 15, 2010, between US Development Group LLC and Kinder Morgan Energy Partners, L.P. (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed January 19, 2010).
	*4.30—	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2010 filed July 30, 2010).
	4.31—	Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
	*10.1 —	Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234)).
	*10.2 —	Amendment No. 1 to Delegation of Control Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K on July 20, 2007).
	*10.3 —	Kinder Morgan Energy Partners, L.P. Directors’ Unit Appreciation Rights Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004 (File No. 1-11234)).

111

	*10.4 —	Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors’ Unit Appreciation Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004 (File No. 1-11234)).
	*10.5 —	Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005 (File No. 1-11234)).
	*10.6 —	Form of Common Unit Compensation Agreement entered into with Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005 (File No. 1-11234)).
	*10.7 —	Three-Year Credit Agreement dated as of June 23, 2010 among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. (“B”), the lenders party thereto, Wells Fargo Bank, National Association as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A., and DnB NOR Bank ASA (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K, filed on June 24, 2010).
	*10.8 —	Form of Severance Agreement with C. Park Shaper (filed as Exhibit 10.61 to Amendment No. 3 to Kinder Morgan Holdco LLC Registration Statement on Form S-1 filed January 26, 2011 (File No. 333-170773)).
	*10.9 —	Form of Severance Agreement with Steven J. Kean (filed as Exhibit 10.62 to Amendment No. 3 to Kinder Morgan Holdco LLC Registration Statement on Form S-1 filed January 26, 2011 (File No. 333-170773)).
	*10.10—	Form of Severance Agreement with Kimberly A. Dang (filed as Exhibit 10.63 to Amendment No. 3 to Kinder Morgan Holdco LLC Registration Statement on Form S-1 filed January 26, 2011 (File No. 333-170773)).
	*10.11—	Form of Severance Agreement with Joseph Listengart (filed as Exhibit 10.64 to Amendment No. 3 to Kinder Morgan Holdco LLC Registration Statement on Form S-1 filed January 26, 2011 (File No. 333-170773)).
	11.1 —	Statement re: computation of per share earnings.
	12.1 —	Statement re: computation of ratio of earnings to fixed charges.
	21.1 —	List of Subsidiaries.
	23.1 —	Consent of PricewaterhouseCoopers LLP.
	23.2 —	Consent of Netherland, Sewell and Associates, Inc.
	31.1 —	Certification by CEO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2 —	Certification by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1 —	Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2 —	Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

112

	99.1 —	Estimates of the net reserves and future net revenues, as of December 31, 2010, related to Kinder Morgan CO2 Company, L.P.’s interest in certain oil and gas properties located in the state of Texas.
	101 —	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008; (iii) our Consolidated Balance Sheets as of December 31, 2010 and 2009; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; (v) our Consolidated Statements of Partners’ Capital for the years ended December 31, 2010, 2009 and 2008; and (vi) the notes to our Consolidated Financial Statements.

__________

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

113

INDEX TO FINANCIAL STATEMENTS

	Page Number
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm	115


Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008	116


Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008	117


Consolidated Balance Sheets as of December 31, 2010 and 2009	118


Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008	119


Consolidated Statements of Partners’ Capital for the years ended December 31, 2010, 2009 and 2008	121


Notes to Consolidated Financial Statements	123

114

Report of Independent Registered Public Accounting Firm

To the Partners of

Kinder Morgan Energy Partners, L.P.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of partners' capital and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (the "Partnership") at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing in Item 9A of the Partnership's 2010 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

Houston, Texas

February 18, 2011

115

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2010			2009			2008
Revenues	(In millions except per unit amounts)
Natural gas sales	$	3,614.4		$	3,137.2		$	7,705.2
Services		3,024.7			2,739.1			2,770.3
Product sales and other		1,438.6			1,127.1			1,264.8
Total Revenues		8,077.7			7,003.4			11,740.3

Operating Costs, Expenses and Other
Gas purchases and other costs of sales		3,606.3			3,068.8			7,716.1
Operations and maintenance		1,415.0			1,136.2			1,282.8
Depreciation, depletion and amortization		904.8			850.8			702.7
General and administrative		375.2			330.3			297.9
Taxes, other than income taxes		171.4			137.0			186.7
Other expense (income)		(0.1	)		(34.8	)		2.6
Total Operating Costs, Expenses and Other		6,472.6			5,488.3			10,188.8

Operating Income		1,605.1			1,515.1			1,551.5

Other Income (Expense)
Earnings from equity investments		223.1			189.7			160.8
Amortization of excess cost of equity investments		(5.8	)		(5.8	)		(5.7	)
Interest expense		(507.6	)		(431.5	)		(398.2	)
Interest income		22.7			22.5			10.0
Other, net		24.2			49.5			19.2
Total Other Income (Expense)		(243.4	)		(175.6	)		(213.9	)

Income from Continuing Operations Before Income Taxes		1,361.7			1,339.5			1,337.6

Income Taxes		(34.6	)		(55.7	)		(20.4	)

Income from Continuing Operations		1,327.1			1,283.8			1,317.2

Discontinued Operations (Note 3):
Gain on disposal of North System		-			-			1.3
Income from Discontinued Operations		-			-			1.3

Net Income		1,327.1			1,283.8			1,318.5

Net Income Attributable to Noncontrolling Interests		(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

Calculation of Limited Partners’ Interest in Net Income Attributable to Kinder Morgan Energy Partners, L.P.:
Income from Continuing Operations	$	1,316.3		$	1,267.5		$	1,303.5
Less: General Partner’s interest		(884.9	)		(935.8	)		(805.8	)
Limited Partners’ interest		431.4			331.7			497.7
Add: Limited Partners’ interest in discontinued operations		-			-			1.3
Limited Partners’ Interest in Net Income	$	431.4		$	331.7		$	499.0

Limited Partners’ Net Income per Unit:
Income from continuing operations	$	1.40		$	1.18		$	1.94
Income from discontinued operations		-			-			-
Net Income	$	1.40		$	1.18		$	1.94

Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income Per Unit		307.1			281.5			257.2

Per Unit Cash Distribution Declared	$	4.40		$	4.20		$	4.02

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

116

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2010			2009			2008
	(In millions)
Net Income	$	1,327.1		$	1,283.8		$	1,318.5

Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes		(76.1	)		(458.2	)		658.0
Reclassification of change in fair value of derivatives to net income		188.4			100.3			670.5
Foreign currency translation adjustments		100.6			252.2			(333.2	)
Adjustments to pension and other postretirement benefit plan liabilities		(2.3	)		(2.5	)		3.7
Total Other Comprehensive Income (Loss)		210.6			(108.2	)		999.0

Comprehensive Income		1,537.7			1,175.6			2,317.5
Comprehensive Income Attributable to Noncontrolling Interests		(13.0	)		(15.2	)		(23.8	)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	1,524.7		$	1,160.4		$	2,293.7

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

117

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	(Dollars in millions)
ASSETS
Current assets
Cash and cash equivalents	$	129.1		$	146.6
Restricted deposits		50.0			15.2
Accounts, notes and interest receivable, net		951.8			902.1
Inventories		92.0			71.9
Gas in underground storage		2.2			43.5
Fair value of derivative contracts		24.0			20.8
Other current assets		37.6			44.6
Total current assets		1,286.7			1,244.7

Property, plant and equipment, net		14,603.9			14,153.8
Investments		3,886.0			2,845.2
Notes receivable		115.0			190.6
Goodwill		1,233.6			1,149.2
Other intangibles, net		302.2			218.7
Fair value of derivative contracts		260.7			279.8
Deferred charges and other assets		173.0			180.2
Total Assets	$	21,861.1		$	20,262.2

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	1,262.4		$	594.7
Cash book overdrafts		32.5			34.8
Accounts payable		630.9			614.8
Accrued interest		239.6			222.4
Accrued taxes		44.7			57.8
Deferred revenues		96.6			76.0
Fair value of derivative contracts		281.5			272.0
Accrued other current liabilities		176.0			145.1
Total current liabilities		2,764.2			2,017.6

Long-term liabilities and deferred credits
Long-term debt
Outstanding		10,277.4			9,997.7
Value of interest rate swaps		604.9			332.5
Total Long-term debt		10,882.3			10,330.2
Deferred income taxes		248.3			216.8
Fair value of derivative contracts		172.2			460.1
Other long-term liabilities and deferred credits		501.6			513.4
Total long-term liabilities and deferred credits		11,804.4			11,520.5

Total Liabilities		14,568.6			13,538.1

Commitments and contingencies (Notes 8, 12 and 16)
Partners’ Capital
Common units (218,880,103 and 206,020,826 units issued and outstanding as of December 31, 2010 and 2009, respectively)		4,282.2			4,057.9
Class B units (5,313,400 and 5,313,400 units issued and outstanding as of December 31, 2010 and 2009, respectively)		63.1			78.6
i-units (91,907,987 and 85,538,263 units issued and outstanding as of December 31, 2010 and 2009, respectively)		2,807.5			2,681.7
General partner		244.3			221.1
Accumulated other comprehensive loss		(186.4	)		(394.8	)
Total Kinder Morgan Energy Partners, L.P. partners’ capital		7,210.7			6,644.5
Noncontrolling interests		81.8			79.6
Total Partners’ Capital		7,292.5			6,724.1
Total Liabilities and Partners’ Capital	$	21,861.1		$	20,262.2

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

118

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2010			2009			2008
	(In millions)
Cash Flows From Operating Activities
Net Income	$	1,327.1		$	1,283.8		$	1,318.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		904.8			850.8			702.7
Amortization of excess cost of equity investments		5.8			5.8			5.7
Income from the allowance for equity funds used during construction		(0.7	)		(22.7	)		(10.6	)
Income from the sale or casualty of property, plant and equipment and other net assets		(8.9	)		(34.8	)		(11.7	)
Earnings from equity investments		(223.1	)		(189.7	)		(160.8	)
Distributions from equity investments		219.8			234.5			158.4
Proceeds from termination of interest rate swap agreements		157.6			144.4			194.3
Changes in components of working capital:
Accounts receivable		17.7			54.5			105.4
Inventories		(20.8	)		(20.0	)		(7.3	)
Other current assets		31.6			(75.9	)		(9.1	)
Accounts payable		(9.4	)		(184.6	)		(100.6	)
Accrued interest		17.1			50.2			41.1
Accrued taxes		(12.9	)		5.3			(22.3	)
Accrued liabilities		12.8			(24.1	)		57.4
Rate reparations, refunds and other litigation reserve adjustments		(34.3	)		2.5			(13.7	)
Other, net		34.8			37.1			(11.5	)
Net Cash Provided by Operating Activities		2,419.0			2,117.1			2,235.9

Cash Flows From Investing Activities
Acquisitions of equity investments		(925.7	)		(36.0	)		-
Acquisitions of assets		(287.5	)		(292.9	)		(40.2	)
Repayment (Payment) for Trans Mountain Pipeline		-			-			23.4
Repayments (Loans) from customers		-			109.6			(109.6	)
Capital expenditures		(1,000.9	)		(1,323.8	)		(2,533.0	)
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs		34.3			47.4			47.8
(Investments in) Net proceeds from margin and restricted deposits		(32.2	)		(18.5	)		71.0
Contributions to investments		(299.3	)		(2,051.8	)		(366.7	)
Distributions from equity investments in excess of cumulative earnings		189.8			112.0			89.1
Other, net		7.0			-			(7.2	)
Net Cash Used in Investing Activities		(2,314.5	)		(3,454.0	)		(2,825.4	)

Cash Flows From Financing Activities
Issuance of debt		7,140.1			6,891.9			9,028.6
Payment of debt		(6,186.4	)		(4,857.1	)		(7,525.0	)
Repayments from related party		2.7			3.7			1.8
Debt issue costs		(22.9	)		(13.7	)		(12.7	)
(Decrease) Increase in cash book overdrafts		(2.2	)		(8.0	)		23.8
Proceeds from issuance of common units		758.7			1,155.6			560.9
Contributions from noncontrolling interests		12.5			15.4			9.3
Distributions to partners and noncontrolling interests:
Common units		(918.7	)		(809.2	)		(684.5	)
Class B units		(22.9	)		(22.3	)		(20.7	)
General Partner		(861.7	)		(918.4	)		(764.7	)
Noncontrolling interests		(23.3	)		(22.0	)		(18.8	)
Other, net		(0.2	)		(0.9	)		3.3
Net Cash (Used in) Provided by Financing Activities		(124.3	)		1,415.0			601.3

Effect of Exchange Rate Changes on Cash and Cash Equivalents		2.3			6.0			(8.2	)

Net (decrease) increase in Cash and Cash Equivalents		(17.5	)		84.1			3.6
Cash and Cash Equivalents, beginning of period		146.6			62.5			58.9
Cash and Cash Equivalents, end of period	$	129.1		$	146.6		$	62.5

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

119

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

	Year Ended December 31,
	2010			2009		2008
	(In millions)
Noncash Investing and Financing Activities
Assets acquired by the issuance of units	$	81.7		$	5.0	$	-
Related party assets acquired by the issuance of units	$	-		$	-	$	116.0
Assets acquired by the assumption or incurrence of liabilities	$	13.8		$	7.7	$	4.8
Contribution of net assets to investments	$	20.0		$	-	$	-

Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	472.8		$	400.3	$	373.3
Cash (received) paid during the period for income taxes	$	(2.2	)	$	3.4	$	35.7

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

120

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	2010					2009					2008
	Units		Amount			Units		Amount			Units		Amount
	(Dollars in millions)
Common Units:
Beginning Balance		206,020,826	$	4,057.9			182,969,427	$	3,458.9			170,220,396	$	3,048.4
Net income		-		299.5			-		229.0			-		343.4
Units issued as consideration pursuant to common unit compensation plan for non-employee directors		2,450		0.2			3,200		0.2			4,338		0.3
Units issued as consideration in the acquisition of assets		1,287,287		81.7			105,752		5.0			2,014,693		116.0
Units issued for cash		11,569,540		758.7			22,942,447		1,155.6			10,730,000		560.9
Adjustments to capital resulting from related party
acquisitions		-		-			-		15.5			-		69.1
Distributions		-		(918.7	)		-		(809.2	)		-		(684.5	)
Other Adjustments		-		2.9			-		2.9			-		5.3
Ending Balance		218,880,103		4,282.2			206,020,826		4,057.9			182,969,427		3,458.9

Class B Units:
Beginning Balance		5,313,400		78.6			5,313,400		94.0			5,313,400		102.0
Net income		-		7.4			-		6.3			-		10.4
Adjustments to capital resulting from related party
acquisitions		-		-			-		0.5			-		2.1
Distributions		-		(22.9	)		-		(22.3	)		-		(20.7	)
Other Adjustments		-		-			-		0.1			-		0.2
Ending Balance		5,313,400		63.1			5,313,400		78.6			5,313,400		94.0

i-Units:
Beginning Balance		85,538,263		2,681.7			77,997,906		2,577.1			72,432,482		2,400.8
Net income		-		124.5			-		96.4			-		145.2
Adjustments to capital resulting from related party
Acquisitions		-		-			-		6.6			-		28.6
Distributions		6,369,724		-			7,540,357		-			5,565,424		-
Other Adjustments		-		1.3			-		1.6			-		2.5
Ending Balance		91,907,987		2,807.5			85,538,263		2,681.7			77,997,906		2,577.1

General Partner:
Beginning Balance		-		221.1			-		203.3			-		161.1
Net income		-		884.9			-		935.8			-		805.8
Adjustments to capital resulting from related party
acquisitions		-		-			-		0.3			-		1.0
Distributions		-		(861.7	)		-		(918.4	)		-		(764.7	)
Other Adjustments		-		-			-		0.1			-		0.1
Ending Balance		-		244.3			-		221.1			-		203.3

Accumulated other comprehensive loss:
Beginning Balance		-		(394.8	)		-		(287.7	)		-		(1,276.6	)
Change in fair value of derivatives utilized for hedging purposes		-		(75.3	)		-		(453.6	)		-		651.4
Reclassification of change in fair value of derivatives to net income		-		186.5			-		99.3			-		663.7
Foreign currency translation adjustments		-		99.5			-		249.7			-		(329.8	)
Adjustments to pension and other postretirement benefit plan liabilities		-		(2.3	)		-		(2.5	)		-		3.6
Ending Balance		-		(186.4	)		-		(394.8	)		-		(287.7	)

Total Kinder Morgan Energy Partners, L.P. Partners’ Capital		316,101,490	$	7,210.7			296,872,489	$	6,644.5			266,280,733	$	6,045.6

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

121

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (continued)

	2010					2009					2008
	Units		Amount			Units		Amount			Units		Amount
	(Dollars in millions)
Noncontrolling interests:
Beginning Balance		-	$	79.6			-	$	70.7			-	$	54.2
Net income		-		10.8			-		16.3			-		13.7
Adjustments to capital resulting from related party
acquisitions		-		-			-		0.3			-		2.2
Contributions		-		12.5			-		15.4			-		9.2
Distributions		-		(23.3	)		-		(22.0	)		-		(18.8	)
Change in fair value of derivatives utilized for hedging purposes		-		(0.8	)		-		(4.6	)		-		6.6
Reclassification of change in fair value of derivatives to net income		-		1.9			-		1.0			-		6.8
Foreign currency translation adjustments		-		1.1			-		2.5			-		(3.4	)
Adjustments to pension and other postretirement benefit plan liabilities		-		-			-		-			-		0.1
Other Adjustments		-		-			-		-			-		0.1
Ending Balance		-		81.8			-		79.6			-		70.7

Total Partners’ Capital		316,101,490	$	7,292.5			296,872,489	$	6,724.1			266,280,733	$	6,116.3

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

122

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. General

Organization

Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August 1992. Unless the context requires otherwise, references to “we,” “us,” “our,” “KMP,” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries. We own and manage a diversified portfolio of energy transportation and storage assets and presently conduct our business through five reportable business segments.

These segments and the activities performed to provide services to our customers and create value for our unitholders are as follows:

▪

Products Pipelines - transporting, storing and processing refined petroleum products;

▪

Natural Gas Pipelines - transporting, storing, buying, selling, gathering, treating and processing natural gas;

▪

CO2 – transporting oil, producing, transporting and selling carbon dioxide, commonly called CO2, for use in, and selling crude oil, natural gas and natural gas liquids produced from, enhanced oil recovery operations;

▪

Terminals - transloading, storing and delivering a wide variety of bulk, petroleum, petrochemical and other liquid products at terminal facilities located across the United States and portions of Canada; and

▪

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

We focus on providing fee-based services to customers, generally avoiding near-term commodity price risks and taking advantage of the tax benefits of a limited partnership structure. We trade on the New York Stock Exchange under the symbol “KMP,” and we conduct our operations through the following five limited partnerships: (i) Kinder Morgan Operating L.P. “A”; (ii) Kinder Morgan Operating L.P. “B”; (iii) Kinder Morgan Operating L.P. “C”; (iv) Kinder Morgan Operating L.P. “D”; and (v) Kinder Morgan CO2 Company, L.P.

Combined, the five limited partnerships are referred to as our operating partnerships, and we are the 98.9899% limited partner and our general partner is the 1.0101% general partner in each. Both we and our operating partnerships are governed by Amended and Restated Agreements of Limited Partnership, as amended, and certain other agreements that are collectively referred to in this report as the partnership agreements.

Kinder Morgan, Inc., Kinder Morgan Kansas, Inc. and Kinder Morgan G.P., Inc.

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., a Delaware corporation; 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. 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.

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. 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.

123

Kinder Morgan Management, LLC

Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company that was formed on February 14, 2001. Its shares represent limited liability company interests and are traded on the New York Stock Exchange under the symbol “KMR.” 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 manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR’s activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries. As of December 31, 2010, KMR owned approximately 29.1% of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR).

2. Summary of Significant Accounting Policies

Basis of Presentation

Our accounting records are maintained in United States dollars, and all references to dollars are United States dollars, except where stated otherwise. Canadian dollars are designated as C$.

Our accompanying consolidated financial statements include our accounts and those of our operating partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. Our accompanying consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States, and certain amounts from prior years have been reclassified to conform to the current presentation. Effective September 30, 2009, the Financial Accounting Standards Boards’ Accounting Standards Codification became the single source of generally accepted accounting principles, and in this report, we refer to the Financial Accounting Standards Board as the FASB and the FASB Accounting Standards Codification as the Codification.

Additionally, our financial statements are consolidated into the consolidated financial statements of KMI; however, our financial statements reflect amounts on a historical cost basis, and, accordingly, do not reflect any purchase accounting adjustments related to KMI’s May 30, 2007 going-private transaction (discussed above in Note 1). Also, except for the related party transactions described in Note 11 “Related Party Transactions—Asset Acquisitions and Sales,” KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability. Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

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

124

Cash Equivalents

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Restricted Deposits

Cash held in escrow is restricted cash and as of December 31, 2010, we deposited $50.0 million into a third-party escrow account to comply with contractual stipulations related to an equity investment in Watco Companies, LLC. In January 2011, the funds were released from escrow and we used the cash for our investment. For additional information on this investment, see Note 3 “Acquisitions and Divestitures—Acquisition Subsequent to December 31, 2010.” As of December 31, 2009, our restricted deposits totaled $15.2 million and consisted of cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners.

Accounts Receivable

The amounts reported as “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheets as of December 31, 2010 and 2009 primarily consist of amounts due from third party payors (unrelated entities). For information on receivables due to us from related parties, see Note 11.

Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The following table shows the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2010, 2009 and 2008 (in millions):

Valuation and Qualifying Accounts

Allowance for doubtful accounts	Balance at beginning of period		Additions charged to costs and expenses		Additions charged to other accounts		Deductions(a)			Balance at end of period

Year ended December 31, 2010	$	5.4	$	2.3	$	-	$	(0.9	)	$	6.8

Year ended December 31, 2009	$	6.1	$	0.5	$	-	$	(1.2	)	$	5.4

Year ended December 31, 2008	$	7.0	$	0.6	$	-	$	(1.5	)	$	6.1

____________

(a)	Deductions represent the write-off of receivables and currency translation adjustments.

In addition, the balances of “Accrued other current liabilities” in our accompanying consolidated balance sheets include amounts related to customer prepayments of approximately $7.1 million as of December 31, 2010 and $10.9 million as of December 31, 2009.

Inventories

Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market, and in December 2008, we recognized a lower of cost or market adjustment of $12.9 million in our CO2 business segment. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

As of December 31, 2010 and 2009, the value of natural gas in our underground storage facilities under the weighted-average cost method was $2.2 million and $43.5 million, respectively, and we reported these amounts separately as “Gas in underground storage” in our accompanying consolidated balance sheets.

125

Gas Imbalances

We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market, per our quarterly imbalance valuation procedures. Gas imbalances represent the difference between customer nominations and actual gas receipts from, and gas deliveries to, our interconnecting pipelines and shippers under various operational balancing and shipper imbalance agreements. Natural gas imbalances are either settled in cash or made up in-kind subject to the pipelines’ various tariff provisions. As of December 31, 2010 and 2009, our gas imbalance receivables—including both trade and related party receivables—totaled $18.8 million and $14.0 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2010 and 2009, our gas imbalance payables—including both trade and related party payables—totaled $7.7 million and $7.4 million, respectively, and we included these amounts within “Accrued other current liabilities” on our accompanying consolidated balance sheets.

Property, Plant and Equipment

Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. As discussed below, for assets used in our oil and gas producing activities or in our unregulated bulk and liquids terminal activities, the cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition, and we record any related gains and losses from sales or retirements to income or expense accounts. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.

We generally compute depreciation using the straight-line method based on estimated economic lives; however, for certain depreciable assets, we employ the composite depreciation method, applying a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 1.6% to 12.5%, excluding certain short-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates included changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.

A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the maket value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset.

126

In addition, we engage in enhanced recovery techniques in which carbon dioxide is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the carbon dioxide associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost associated with pressure maintenance operations for reservoir management is expensed when it is injected. When carbon dioxide is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production rate is determined by field.

As discussed in “—Inventories” above, we own and maintain natural gas in underground storage as part of our inventory. This component of our inventory represents the portion of gas stored in an underground storage facility generally known as working gas, and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal. In addition to this working gas, underground gas storage reservoirs contain injected gas which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as cushion gas, is divided into the categories of recoverable cushion gas and unrecoverable cushion gas, based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of the cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself (thus, part of our “Property, plant and equipment, net” balance in our accompanying consolidated balance sheets), and this unrecoverable portion is depreciated over the facility’s estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

Impairments

We measure long-lived assets that are to be disposed of by sale at the lower of book value or fair value less the cost to sell, and we review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. For the purpose of impairment testing, we use the forward curve prices as observed at the test date; however, due to differences between the forward curve and spot prices, the forward curve cash flows may differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in Note 20.

Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment. Due to the decline in crude oil and natural gas prices during 2008, on December 31, 2008, we conducted an impairment test on our oil and gas producing properties in our CO2 business segment and determined that no impairment was necessary.

Allowance for Funds Used During Construction/Capitalized Interest

Included in the cost of our qualifying property, plant and equipment is (i) an allowance for funds used during construction (AFUDC) or upgrade for assets regulated by the Federal Energy Regulatory Commission; or (ii) capitalized interest. The primary difference between AFUDC and capitalized interest is that AFUDC may include a component for equity funds, while capitalized interest does not. AFUDC on debt, as well as capitalized interest, represents the estimated cost of capital, from borrowed funds, during the construction period that is not immediately expensed, but instead is treated as an asset (capitalized) and amortized to expense over time in our income statements. Total AFUDC on debt and capitalized interest in 2010, 2009 and 2008 was $12.5 million, $32.9 million and $48.6 million, respectively. Similarly, AFUDC on equity represents an estimate of the cost of capital funded by equity contributions, and in the years ended December 31, 2010, 2009 and 2008, we also capitalized approximately $0.7 million, $22.7 million and $10.6 million, respectively, of equity AFUDC.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. ] ] [ For more information on our asset retirement obligations, see Note 5 “Property, Plant and Equipment—Asset Retirement Obligations.”

127

Equity Method of Accounting

We account for investments greater than 20% in affiliates—which we do not control but do have the ability to exercise significant influence—by the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.

Goodwill

Goodwill represents the excess of the cost of an acquisition price over the fair value of acquired net assets, and such amounts are reported separately as “Goodwill” on our accompanying consolidated balance sheets. Our total goodwill was $1,233.6 million as of December 31, 2010, and $1,149.2 million as of December 31, 2009. Goodwill cannot be amortized, but instead 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 perform our goodwill impairment test on May 31 of each year. There were no impairment charges resulting from our May 31, 2010, 2009 or 2008 impairment testing, and no event indicating an impairment has occurred subsequent to May 31, 2010. For more information on our goodwill, see Note 7.

Revenue Recognition Policies

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We generally sell natural gas under long-term agreements, generally based on Houston Ship Channel index posted prices. In some cases, we sell natural gas under short-term agreements at prevailing market prices. In all cases, we recognize natural gas sales revenues when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies. We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and generally, our natural gas marketing revenues are recorded gross, not net of cost of gas sold.

In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers. The natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities; and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities.

In other cases, generally described as interruptible service, there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to our firm and interruptible transportation services, we also provide natural gas balancing services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized based on the terms negotiated under these contracts.

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

We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. Liquids terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product.

128

Revenues from the sale of crude oil, natural gas liquids and natural gas production are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer. As a result, we maintain a minimum amount of product inventory in storage.

Environmental Matters

We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. For more information on our environmental disclosures, see Note 16.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for such amounts. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. In general, we expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. For more information on our legal disclosures, see Note 16.

Pensions and Other Postretirement Benefits

We fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and postretirement benefit plans as either assets or liabilities on our balance sheet. A plan’s funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—in accumulated other comprehensive income, until they are amortized to expense. For more information on our pension and postretirement benefit disclosures, see Note 9.

Noncontrolling Interests

Noncontrolling interests represents the outstanding ownership interests in our five operating limited partnerships and their consolidated subsidiaries that are not owned by us. In our accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net income attributable to noncontrolling interests.” In our accompanying consolidated balance sheets, noncontrolling interests represents the ownership interests in our consolidated subsidiaries’ net assets held by parties other than us. It is presented separately as “Noncontrolling interests” within “Partners’ Capital.”

As of December 31, 2010, our noncontrolling interests consisted of the following: (i) the 1.0101% general partner interest in each of our five operating partnerships; (ii) the 0.5% special limited partner interest in SFPP, L.P.; (iii) the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.; (iv) the 33 1/3% interest in International Marine Terminals Partnership, a Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P. “C”; (v) the approximate 31% interest in the Pecos Carbon Dioxide Company, a Texas general partnership owned approximately 69% and controlled by Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries; and (vi) the 35% interest in Guilford County Terminal Company, LLC, a limited liability company owned 65% and controlled by Kinder Morgan Southeast Terminals LLC.

129

Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner’s tax attributes in us.

Some of our corporate subsidiaries and corporations in which we have an equity investment do pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. For more information on our income tax disclosures, see Note 4.

Foreign Currency Transactions and Translation

Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which our reporting subsidiary operates, also referred to as its functional currency. Transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary; and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary. In our accompanying consolidated income statements, gains and losses from our foreign currency transactions are included within “Other Income (Expense)—Other, net.”

We translate the assets and liabilities of each of our consolidating foreign subsidiaries that have a local functional currency to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and partners’ capital equity accounts are translated by using historical exchange rates. Translation adjustments result from translating all assets and liabilities at current year-end rates, while partners’ capital equity is translated by using historical and weighted-average rates. The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive loss” within “Partners’ Capital” in our consolidated balance sheets.

Comprehensive Income

For each of the years ended December 31, 2010, 2009 and 2008, the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts utilized for hedging our exposure to fluctuating expected future cash flows produced by both energy commodity price risk and interest rate risk; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 13.

Cumulative revenues, expenses, gains and losses that under generally accepted accounting principals are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Partners’ Capital” in our consolidated balance sheets. The following table summarizes changes in the amount of our “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets for each of the two years ended December 31, 2010 and 2009 (in millions):

130

	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjs.			Total Accumulated other comprehensive income/(loss)
December 31, 2008	$	(64.6	)	$	(217.3	)	$	(5.8	)	$	(287.7	)
Change for period		(354.3	)		249.7			(2.5	)		(107.1	)
December 31, 2009		(418.9	)		32.4			(8.3	)		(394.8	)
Change for period		111.2			99.5			(2.3	)		208.4
December 31, 2010	$	(307.7	)	$	131.9		$	(10.6	)	$	(186.4	)

Limited Partners’ Net Income per Unit

We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period. The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income per Unit are made in accordance with the “Earnings per Share” Topic of the Codification.

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. If the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from fair value accounting and is accounted for using traditional accrual accounting.

Furthermore, changes in our derivative contracts’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative contract meets those criteria, the contract’s gains and losses is allowed to offset related results on the hedged item in our income statement, and we are required to both formally designate the derivative contract as a hedge and document and assess the effectiveness of the contract associated with the transaction that receives hedge accounting. Only designated qualifying items that are effectively offset by changes in fair value or cash flows during the term of the hedge are eligible to use the special accounting for hedging.

Our derivative contracts that hedge our energy commodity price risks involve our normal business activities, which include the sale of natural gas, natural gas liquids and crude oil, and we have designated these derivative contracts as cash flow hedges—derivative contracts that hedge exposure to variable cash flows of forecasted transactions—and the effective portion of these derivative contracts’ gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. See Note 13 for more information on our risk management activities and disclosures.

Accounting for Regulatory Activities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. The amount of regulatory assets and liabilities reflected within “Deferred charges and other assets” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets as of December 31, 2010 and 2009 are not material to our consolidated balance sheets.

3. Acquisitions and Divestitures

Acquisitions from Unrelated Entities

During 2010, 2009 and 2008, we completed the following acquisitions from unrelated entities. For each of these acquisitions, we recorded all the acquired assets and assumed liabilities at their estimated fair market values (not the acquired entity’s book values) as of the acquisition date. The results of operations from these acquisitions accounted for as business combinations are included in our consolidated financial statements from the acquisition date.

131

						Assignment of Purchase Price
						(in millions)
Ref.			Date		Acquisition	Purchase Price		Current Assets		Property Plant & Equipment		Deferred Charges & Other		Goodwill
	(1	)		8/08	Wilmington, North Carolina Liquids Terminal	$	12.7	$	-	$	5.9	$	-	$	6.8
	(2	)		12/08	Phoenix, Arizona Products Terminal		27.5		-		27.5		-		-
	(3	)		4/09	Megafleet Towing Co., Inc. Assets		21.7		-		7.1		4.0		10.6
	(4	)		7/09	Portland Airport Pipeline		9.0		-		9.0		-		-
	(5	)		10/09	Crosstex Energy, L.P. Natural Gas Treating Business		270.7		15.0		181.7		25.4		48.6
	(6	)		11/09	Endeavor Gathering LLC		36.0		-		-		36.0		-
	(7	)		1/10	USD Terminal Acquisition		201.1		-		43.1		100.0		58.0
	(8	)		3/10	Mission Valley, California Products Terminal		13.5		-		13.5		-		-
	(9	)		3/10	Slay Industries Terminal Acquisition		101.6		-		67.9		32.8		0.9
	(10	)		5/10	KinderHawk Field Services LLC		917.4		-		-		917.4		-
	(11	)		7/10	Direct Fuels Terminal Acquisition		16.0		-		5.3		-		10.7
	(12	)		9/10	Gas-Chill, Inc. Natural Gas Treating Assets		13.1		-		8.0		5.1		-
	(13	)		10/10	Allied Concrete Terminal Acquisition		8.6		-		3.9		4.7		-
	(14	)		10/10	Chevron Refined Products Terminals		32.3		-		32.1		0.2		-

(1) Wilmington, North Carolina Liquids Terminal

On August 15, 2008, we purchased certain terminal assets from Chemserve, Inc. for an aggregate consideration of $12.7 million, consisting of $11.8 million in cash and $0.9 million in assumed liabilities. The liquids terminal facility is located in Wilmington, North Carolina and stores petroleum products and chemicals. The acquisition both expanded and complemented our existing Southeast region terminal operations, and all of the acquired assets are included in our Terminals business segment. We assigned $6.8 million of our purchase price to “Goodwill,” and the entire amount is expected to be deductible for tax purposes. We believe this acquisition resulted in the recognition of goodwill primarily because of certain advantageous factors (including the synergies provided by increasing our liquids storage capacity in the Southeast region of the U.S.) that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.

(2) Phoenix, Arizona Products Terminal

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

(3) Megafleet Towing Co., Inc. Assets

Effective April 23, 2009, we acquired certain terminals assets from Megafleet Towing Co., Inc. for an aggregate consideration of approximately $21.7 million. Our consideration included $18.0 million in cash and an obligation to pay additional cash consideration on April 23, 2014 (five years from the acquisition date) contingent upon the purchased assets providing us an agreed-upon amount of earnings, as defined by the purchase and sale agreement, during the five year period. The contingent consideration had a fair value of $3.7 million as of the acquisition date.

The acquired assets primarily consisted of nine marine vessels that provide towing and harbor boat services along the Gulf coast, the intracoastal waterway, and the Houston Ship Channel, and the acquisition complemented and expanded our existing Gulf Coast and Texas petroleum coke terminal operations. We assigned $10.6 million of our purchase price to “Goodwill,” and we expect that approximately $5.0 million of goodwill will be deductible for tax purposes. We believe the primary item that generated the goodwill is the value of the synergies created between the acquired assets and our pre-existing terminal assets (resulting from the increase in services now offered by our Texas petroleum coke operations). In February 2010, the JR Nicholls, one of the acquired vessels, overturned and sank in the Houston Ship Channel. For further information about the JR Nicholls incident, see Note 16. For information about events occurring subsequent to December 31, 2010, see “—Divestiture Subsequent to December 31, 2010” below.

(4) Portland Airport Pipeline

On July 31, 2009, we acquired a refined products pipeline, as well as associated valves, equipment and other fixtures, from Chevron Pipe Line Company for $9.0 million in cash. The approximate 8.5 mile, 8-inch diameter pipeline is located in Multnomah County, Oregon. The line transports commercial jet fuel from our Willbridge liquids terminal facility to the Portland International Airport, both located in Portland, Oregon. It has an estimated system capacity of approximately 26,000 barrels per day. The acquisition enhanced our West Coast terminal operations, and the acquired assets are included in our Products Pipelines business segment.

132

(5) Crosstex Energy, L.P. Natural Gas Treating Business

On October 1, 2009, we acquired the natural gas treating business from Crosstex Energy, L.P. and Crosstex Energy, Inc. for an aggregate consideration of $270.7 million, consisting of $265.3 million in cash and assumed liabilities of $5.4 million. The acquired assets primarily consisted of approximately 290 natural gas amine-treating and hydrocarbon dew-point control plants and related equipment, and are used to remove impurities and liquids from natural gas in order to meet pipeline quality specifications. The assets are predominantly located in Texas and Louisiana, with additional facilities located in Mississippi, Oklahoma, Arkansas and Kansas. The acquisition complemented and expanded the existing natural gas treating operations offered by our Texas intrastate natural gas pipeline group, and all of the acquired assets are included in our Natural Gas Pipelines business segment.

We measured the identifiable intangible assets acquired at fair value on the acquisition date, and accordingly, we recognized $25.4 million in “Deferred charges and other assets,” representing the purchased fair value of separate and identifiable relationships with existing natural gas producing customers. We estimate the remaining useful life of these existing customer relationships to be between approximately eight and nine years. After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $48.6 million of “Goodwill,” an intangible asset representing the future economic benefits expected to be derived from this acquisition that are not assigned to other identifiable, separately recognizable assets acquired. We believe the primary item that generated the goodwill is our ability to grow the business by leveraging our pre-existing natural gas operations (resulting from the increase in services now offered by our natural gas processing and treating operations in the state of Texas), and we believe that this value contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill. Furthermore, this entire amount of goodwill is expected to be deductible for tax purposes.

(6) Endeavor Gathering LLC

On November 1, 2009, we acquired a 40% membership interest in Endeavor Gathering LLC for $36.0 million in cash. Endeavor Gathering LLC owns the natural gas gathering and compression business previously owned by GMX Resources Inc. and its wholly-owned subsidiary, Endeavor Pipeline, Inc. 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. The remaining 60% interest in Endeavor Gathering LLC is owned by GMX Resources, Inc., and Endeavor Pipeline Inc. remained operator of the business. The acquired investment complemented our existing natural gas gathering and transportation business located in the state of Texas. We account for this investment under the equity method of accounting, and the investment is included in our Natural Gas Pipelines business segment. For more information on our investments, see Note 6.

(7) USD Terminal Acquisition

Based on our measurement of fair values for all of the identifiable tangible and intangible assets acquired and liabilities assumed on the acquisition date, we assigned $94.6 million of our combined purchase price to “Other intangibles, net,” and a combined $5.4 million to “Other current assets” and “Deferred charges and other assets.” The acquired intangible amount represented the fair value of customer relationships, and we estimated the remaining useful life of these customer relationships to be 10 years. After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $58.0 million of “Goodwill,” an intangible asset representing the future economic benefits expected to be derived from this acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated the goodwill are the value of the synergies created between the acquired assets and our pre-existing ethanol handling assets, and our expected ability to grow the business by leveraging our pre-existing experience in ethanol handling operations. We expect that the entire amount of goodwill will be deductible for tax purposes.

133

(8) Mission Valley Terminal Acquisition

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 included 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 under a long-term terminaling agreement with Tesoro Refining and Marketing Company. The acquisition enhanced our Pacific operations and complemented our existing West Coast terminal operations, and the acquired assets are included in our Products Pipelines business segment.

(9) Slay Industries Terminal Acquisition

On March 5, 2010, we acquired certain 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 included (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. The acquisition complemented and expanded our pre-existing Midwest terminal operations by adding a diverse mix of liquid and bulk capabilities, and all of the acquired assets are included in our Terminals business segment.

Based on our measurement of fair values for all of the identifiable tangible and intangible assets acquired and liabilities assumed, we assigned $24.6 million of our combined purchase price to “Other intangibles, net” (representing customer contracts with an estimated remaining useful life of 20 years), and $8.2 million to “Investments.” We also recorded $0.9 million of our combined purchase price as “Goodwill,” representing certain advantageous factors that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets. In the aggregate, these factors represented goodwill, and we expect to deduct the entire amount of goodwill for tax purposes.

(10) KinderHawk Field Services LLC

During a short transition period, Petrohawk continued to operate the business, and effective 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. The acquisition complemented and expanded our existing natural gas gathering and treating businesses, and we assigned our entire purchase price to “Investments” (including $144.8 million of equity method goodwill, representing the excess of our investment cost over our proportionate share of the fair value of the joint venture’s identifiable net assets). Our investment and our pro rata share of the joint venture’s operating results are included as part of our Natural Gas Pipelines business segment.

(11) Direct Fuels Terminal Acquisition

On July 22, 2010, we acquired a terminal with ethanol tanks, a truck rack and additional acreage in Dallas, 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 in “—(7) USD Terminal Acquisition). All of the acquired assets are included in our Terminals business segment. After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $10.7 million of “Goodwill,” an intangible asset representing the future economic benefits expected to be derived from the acquisition that was not assigned to other identifiable, separately recognizable assets acquired. We believe the primary items that generated the goodwill are the value of the synergies created between the acquired assets and our pre-existing ethanol handling assets, and our expected ability to grow the business by leveraging our pre-existing experience in ethanol handling operations. We expect that the entire amount of goodwill will be deductible for tax purposes.

134

(12) Gas-Chill, Inc. Asset Acquisition

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 natural gas hydrocarbon dew point control units that are used to remove hydrocarbon liquids from natural gas streams prior to entering transmission pipelines. The acquisition complemented and expanded the existing natural gas treating operations offered by our Texas intrastate natural gas pipeline group, and all of the acquired assets are included in our Natural Gas Pipelines business segment. We assigned $8.0 million of our purchase price to “Property, Plant and Equipment, net” and the remaining $5.1 million to “Other intangibles, net” (representing both a technology-based asset and customer-related contract values).

(13) Allied Concrete Bulk Terminal Assets

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 complemented the bulk commodity handling operations at our nearby Elizabeth River terminal, also located in Chesapeake, and all of the acquired assets are included in our Terminals business segment. We assigned $3.9 million of our purchase price to “Property, Plant and Equipment, net” and the remaining $4.7 million to “Other intangibles, net” (representing customer-related contract values).

(14) Chevron Refined Products Terminal Assets

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 terminal product at the terminals. The acquisition complemented and expanded our existing refined petroleum products assets, and all of the acquired assets are included in our Products Pipelines business segment. We assigned $32.1 million of our purchase price to “Property, Plant and Equipment, net” and the remaining $0.2 million to “Deferred charges and other assets” (representing the fair value of petroleum pipeline product additives).

Pro Forma Information

Pro forma consolidated income statement information that gives effect to all of the acquisitions we have made and all of the joint ventures we have entered into since January 1, 2009 as if they had occurred as of January 1, 2009 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

Acquisitions from KMI

According to the provisions of the Codification’s “Control of Partnerships and Similar Entities” Subtopic, effective January 1, 2006, KMI (which indirectly owns all the common stock of our general partner) was deemed to have control over us and no longer accounted for its investment in us under the equity method of accounting. Instead, as of this date, KMI included our accounts, balances and results of operations in its consolidated financial statements.

Accordingly, we accounted for each of the two separate acquisitions discussed below as transfers of net assets between entities under common control. When accounting for transfers of net assets between entities under common control, the acquisition cost provisions (as they relate to purchase business combinations involving unrelated entities) explicitly do not apply; instead, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. That is, no recognition is made for a purchase premium or discount representing any difference between the consideration paid and the book value of the net assets acquired.

135

Therefore, for each of the two separate acquisitions from KMI discussed below, we recognized the assets and liabilities acquired at their carrying amounts (historical cost) in the accounts of KMI (the transferring entity) at the date of transfer. Description of the consideration we paid or received for these net assets is also described below.

Trans Mountain Pipeline System

On April 30, 2007, we acquired the Trans Mountain pipeline system from KMI for $549.1 million in cash. The Trans Mountain pipeline system transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington. In April 2008, as a result of finalizing certain “true-up” provisions in our acquisition agreement related to Trans Mountain pipeline expansion spending, we received a cash contribution of $23.4 million from KMI. Pursuant to the accounting provisions concerning transfers of net assets between entities under common control, and consistent with our treatment of cash payments made to KMI for Trans Mountain net assets in 2007, we accounted for this 2008 cash contribution as an adjustment to equity—primarily as an increase in “Partners’ Capital”—and we also included this $23.4 million receipt as a cash inflow item from investing activities in our accompanying consolidated statement of cash flows.

Express and Jet Fuel Pipeline Systems

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

We operate the Express pipeline system, and we account for our 33 1/3% ownership in the system under the equity method of accounting. In addition to our 33 1/3% equity ownership, our investment in Express includes an investment in unsecured debenture bonds denominated in Canadian dollars and issued by Express Holdings U.S. L.P., the partnership that maintains ownership of the U.S. portion of the Express pipeline system. For more information on this long-term note receivable, see Note 11 “Related Party Transactions—Notes Receivable.”

Additionally, based upon our management’s consideration of all of the quantitative and qualitative aspects of the transfer of the interests in the Express and Jet Fuel pipeline system net assets from KMI to us, we determined that the presentation of combined financial statements which include the financial information of the Express and Jet Fuel pipeline systems would not be materially different from financial statements which did not include such information and accordingly, we elected not to include the financial information of the Express and Jet Fuel pipeline systems in our consolidated financial statements for any periods prior to the transfer date of August 28, 2008. Our consolidated financial statements and all other financial information included in this report therefore, have been prepared assuming that the transfer of both the 33 1/3% interest in the Express pipeline system net assets and the Jet Fuel pipeline system net assets from KMI to us had occurred at the date of transfer (August 28, 2008).

Divestitures

North System Natural Gas Liquids Pipeline System – Discontinued Operations

On July 2, 2007, we announced that we entered into an agreement to sell the North System natural gas liquids pipeline and our 50% ownership interest in the Heartland Pipeline Company (collectively referred to in this report as our North System) to ONEOK Partners, L.P. for approximately $298.6 million in cash. Our investment in net assets, including all transaction related accruals, was approximately $145.8 million, most of which represented property, plant and equipment, and we recognized approximately $152.8 million of gain in the fourth quarter of 2007 from the sale of these net assets.

136

In the first half of 2008, following final account and inventory reconciliations, we paid a net amount of $2.4 million to ONEOK to fully settle amounts related to (i) working capital items; (ii) total physical product liquids inventory and inventory obligations for certain liquids products; and (iii) the allocation of pre-acquisition investee distributions. Based primarily upon these adjustments, which were below the amounts reserved, we recognized an additional gain of $1.3 million in 2008. We accounted for the North System business as a discontinued operation and we reported the gain amount separately as “Gain on disposal of North System” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2008. Prior to the sale, we included the financial results of the North System within our Products Pipelines business segment and, because the sale of the North System did not change the structure of our internal organization in a manner that caused a change to our reportable business segments, we included the incremental gain within our Products Pipelines business segment disclosures for 2008.

Thunder Creek Gas Services, LLC

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

Cypress Interstate Pipeline LLC

Effective October 1, 2010, Westlake Petrochemicals LLC, a wholly-owned subsidiary of Westlake Chemical Corporation, exercised an option it held to purchase a 50% ownership interest in our Cypress Pipeline. Accordingly, we sold a 50% interest in our subsidiary, Cypress Interstate Pipeline LLC, to Westlake and we received proceeds of $10.2 million. At the time of the sale, the carrying value of the net assets of Cypress Interstate Pipeline LLC totaled $20.0 million and consisted mostly of property, plant and equipment. In the fourth quarter of 2010, we recognized an $8.8 million gain from this sale, including an $8.6 million gain amount related to the remeasurement of our retained investment to its fair value. Due to the loss of control of Cypress Interstate Pipeline LLC, we recognized the retained investment at its fair value, and the gain amount related to remeasurement represents the excess of the fair value of our retained investment ($18.6 million as of October 1, 2010) over its carrying value ($10.0 million). This fair value of our retained investment was determined by applying a multiple to the future annual cash flows expected from our retained 50% interest. The $10.2 million value of the transaction with Westlake Chemical Corporation was based on a contract price and does not represent the fair value of a 50% interest in the Cypress Pipeline in an orderly transaction between market participants. We now account for our retained investment under the equity method of accounting. We included the entire gain within the caption “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2010.

Acquisition Subsequent to December 31, 2010

On January 3, 2011, we purchased 50,000 Class A preferred shares of Watco Companies, LLC for $50.0 million in cash in a private transaction. In connection with our purchase of these preferred shares, the most senior equity security of Watco, we entered into a limited liability company agreement with Watco that provides us certain priority and participating cash distribution and liquidation rights. We will receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and we will participate partially in additional profit distributions at a rate equal to 0.5%. The preferred shares have no conversion features and hold no voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers. As of December 31, 2010, we placed our $50.0 million investment in a cash escrow account and we included this amount within “Restricted Deposits” on our accompanying balance sheet. The acquired investment complements our existing rail transload operations and we will account for our investment under the equity method of accounting and include it in our Terminals business segment.

Watco Companies, LLC is a privately owned, Pittsburg, Kansas based transportation company that was formed in 1983. It is the largest privately held short line railroad company in the United States, operating 22 short line railroads on approximately 3,500 miles of leased and owned track. Its services include (i) rail freight transportation; (ii) industrial switching services; (iii) railcar and locomotive repair; (iv) track construction, maintenance and repair; (v) freight railroad specific transloading and intermodal services; (vi) freight railroad specific warehouse logistics activities; and (vii) port terminal freight railroads and associated operations.

137

Divestiture Subsequent to December 31, 2010

On February 9, 2011, we sold a marine vessel to Kirby Inland Marine, L.P., and additionally, we and Kirby formed a joint venture named Greens Bayou Fleeting, LLC. Pursuant to the joint venture agreement, we both sold a 51% ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009 (discussed above in “—Acquisitions from Unrelated Entities—(3) Megafleet Towing Co., Inc. Assets”) to the joint venture for $4.1 million in cash, and we contributed the remaining business to the joint venture for a 49% ownership interest. Kirby then made cash contributions to the joint venture in exchange for the remaining 51% ownership interest. Related to the above transactions, in the fourth quarter of 2010, we recorded a combined loss amount of $5.5 million to write down the carrying value of the net assets to be sold to their estimated fair values as of December 31, 2010. We included this loss within the caption “Other expense (income)” in our accompanying consolidated statement of income for the year ended December 31, 2010.

4. Income Taxes

Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Taxes current expense:
Federal	$	4.8		$	2.7		$	24.4
State		1.2			6.7			8.5
Foreign		3.6			(1.0	)		(4.5	)
Total		9.6			8.4			28.4
Taxes deferred expense:
Federal		4.7			7.3			6.0
State		9.7			9.4			1.5
Foreign		10.6			30.6			(15.5	)
Total		25.0			47.3			(8.0	)
Total tax provision	$	34.6		$	55.7		$	20.4
Effective tax rate		2.5	%		4.2	%		1.5	%

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

	Year Ended December 31,
	2010			2009			2008
Federal income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) as a result of:
Partnership earnings not subject to tax		(35.0	) %		(35.0	) %		(35.0	) %
Corporate subsidiary earnings subject to tax		-	%		-	%		1.6	%
Income tax expense attributable to corporate equity earnings		0.7	%		0.8	%		0.6	%
Income tax expense attributable to foreign corporate earnings		1.0	%		2.2	%		(1.2	) %
State taxes		0.8	%		1.2	%		0.5	%
Effective tax rate		2.5	%		4.2	%		1.5	%

Our deferred tax assets and liabilities as of December 31, 2010 and 2009 resulted from the following (in millions):

	December 31,
	2010		2009
Deferred tax assets:
Book accruals	$	2.1	$	16.6
Net Operating Loss/Alternative minimum tax credits		17.8		11.4
Other		1.3		1.3
Total deferred tax assets		21.2		29.3

Deferred tax liabilities:
Property, plant and equipment		263.9		239.3
Other		5.6		6.8
Total deferred tax liabilities		269.5		246.1
Net deferred tax liabilities	$	248.3	$	216.8

138

We account for uncertainty in income taxes in accordance with the “Income Taxes” Topic of the Codification. Pursuant to these provisions, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also on the past administrative practices and precedents of the taxing authority. The tax benefits recognized in our financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation of our beginning and ending gross unrecognized tax benefits for each of the years ended December 31, 2010 and 2009 is as follows (in millions):

	Year Ended December 31,
	2010			2009
Balance at beginning of period	$	23.3		$	14.9
Additions based on current year tax positions		-			-
Additions based on prior year tax positions		10.2			8.5
Reductions based on settlements with taxing authority		-			-
Reductions due to lapse in statute of limitations		(0.1	)		(0.1	)
Balance at end of period	$	33.4		$	23.3

Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2010, we recognized a reduction in interest expense of approximately $0.5 million, and during each of the years ended December 31, 2009 and 2008, we recognized approximately $1.1 million and $0.5 million, respectively, in interest expense.

As of December 31, 2010 (i) we had $1.8 million of accrued interest and no accrued penalties; (ii) we believe it is reasonably possible that our $33.4 million liability for unrecognized tax benefits will increase by approximately $7.6 million during the next twelve months; and (iii) we believe the full amount of $33.4 million of unrecognized tax benefits, if recognized, would favorably affect our effective income tax rate in future periods. As of December 31, 2009, we had $2.3 million of accrued interest and no accrued penalties. In addition, we have U.S. and state tax years open to examination for the periods 2006 through 2010.

5. Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2010 and 2009, our property, plant and equipment consisted of the following (in millions):

	December 31,
	2010			2009
Natural gas, liquids, crude oil and carbon dioxide pipelines	$	7,071.1		$	6,883.3
Natural gas, liquids, carbon dioxide, and terminals station equipment.		8,976.2			8,131.9
Natural gas, liquids (including linefill), and transmix processing		233.7			220.3
Other		1,322.7			1,113.0
Accumulated depreciation, depletion, and amortization		(4,150.6	)		(3,365.6	)
		13,453.1			12,982.9
Land and land right-of-way		638.5			596.6
Construction work in process		512.3			574.3
Property, plant and equipment, net	$	14,603.9		$	14,153.8

Depreciation, depletion, and amortization expense charged against property, plant and equipment was $852.8 million in 2010, $829.6 million in 2009 and $684.2 million in 2008.

Asset Retirement Obligations

As of December 31, 2010 and 2009, we recognized asset retirement obligations in the aggregate amount of $122.0 million and $100.9 million, respectively. The majority of our asset retirement obligations are associated with our CO2 business segment, where we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. We have included $2.5 million of our total asset retirement obligations as of both December 31, 2010 and 2009 within “Accrued other current liabilities” in our accompanying consolidated balance sheets. The remaining amounts are included within “Other long-term liabilities and deferred credits” at each reporting date.

139

A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the years ended December 31, 2010 and 2009 is as follows (in millions):

	Year Ended December 31,
	2010			2009
Balance at beginning of period	$	100.9		$	76.5
Liabilities incurred/revised		23.7			26.0
Liabilities settled		(9.1	)		(6.2	)
Accretion expense		6.5			4.6
Balance at end of period	$	122.0		$	100.9

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

6. Investments

We reported a combined $3,886.0 million as “Investments” in our accompanying consolidated balance sheet as of December 31, 2010. As of December 31, 2009, our investments totaled $2,845.2 million. Our investments primarily consist of equity investments where we hold significant influence over investee actions and which we account for under the equity method of accounting.

As of December 31, 2010 and 2009, our investments consisted of the following (in millions):

	December 31,
	2010		2009
Rockies Express Pipeline LLC	$	1,703.0	$	1,693.4
KinderHawk Field Services LLC		924.6		-
Midcontinent Express Pipeline LLC		706.4		662.3
Plantation Pipe Line Company		190.3		197.3
Red Cedar Gathering Company		163.2		145.8
Express pipeline system		68.5		68.0
Endeavor Gathering LLC		36.1		36.2
Eagle Ford Gathering LLC		29.9		-
Cortez Pipeline Company		9.9		11.2
All others		45.9		17.8
Total equity investments		3,877.8		2,832.0
Bond investments		8.2		13.2
Total investments	$	3,886.0	$	2,845.2

The increase in the carrying amount of our equity investments since December 31, 2009 was primarily due to our acquisition of a 50% ownership interest in KinderHawk Field Services LLC in May 2010. For further information pertaining to our KinderHawk acquisition, see Note 3 “Acquisitions and Divestitures—Acquisitions from Unrelated Entities—(10) KinderHawk Field Services LLC.”

As shown in the table above, in addition to our investment in KinderHawk Field Services LLC, our significant equity investments as of December 31, 2010 consisted of the following:

▪

Rockies Express Pipeline LLC—we operate and own a 50% ownership interest in Rockies Express Pipeline LLC, the sole owner of the Rockies Express natural gas pipeline system. The Rockies Express pipeline system began full operations on November 12, 2009 following the completion of its final pipeline segment, Rockies Express-East. The remaining ownership interests in Rockies Express Pipeline LLC are owned by subsidiaries of Sempra Energy and ConocoPhillips.

140

Effective December 1, 2009, our ownership interest in Rockies Express Pipeline LLC was reduced to 50% (from 51%), ConocoPhillips’ interest was increased to 25% (from 24%), and minimum voting requirements for most matters was increased to 75% (from 51%) of the member interests. We received $31.9 million for the 1% reduction in our ownership interest and we included this amount within “Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs” on our accompanying consolidated statement of cash flows for the year ended December 31, 2009. Sempra Energy continues to own the remaining 25% ownership interest in Rockies Express Pipeline LLC.

Additionally, in 2010 and 2009, we made capital contributions of $130.5 million and $1,273.1 million, respectively, to Rockies Express Pipeline LLC, and we received cash distributions of $208.6 million and $148.8 million, respectively. Our 2009 contributions were primarily made to partially fund both the construction costs for the Rockies Express pipeline system and the repayment of senior notes (which matured in August 2009);

▪

Midcontinent Express Pipeline LLC—we operate and own a 50% ownership interest in Midcontinent Express Pipeline LLC. It is the sole owner of the Midcontinent Express natural gas pipeline system. The remaining ownership interests in Midcontinent Express Pipeline LLC are owned by Regency Energy Partners LP and Energy Transfer Partners, L.P. Effective May 26, 2010, Energy Transfer Partners, L.P. transferred to Regency Energy Partners LP (i) a 49.9% ownership interest in Midcontinent Express Pipeline LLC; and (ii) a one-time right to purchase its remaining 0.1% ownership interest in Midcontinent Express Pipeline LLC on May 26, 2011. As a result of this transfer, Energy Transfer Partners, L.P. now owns a 0.1% ownership interest in Midcontinent Express Pipeline LLC. We continue to own the remaining 50% ownership interest in Midcontinent Express Pipeline LLC, and since there was no change in our ownership interest, we did not record any equity method adjustments as a result of the ownership change between Regency Energy Partners LP and Energy Transfer Partners, L.P.

Additionally, in 2010 and 2009, we made capital contributions of $86.0 million and $664.5 million, respectively, to Midcontinent Express Pipeline LLC to partially fund its pipeline construction and expansion costs. In 2010 and 2009, we also received, from Midcontinent Express Pipeline LLC, cash distributions of $72.0 million and $16.2 million, respectively;

▪

Plantation Pipe Line Company—we operate and own a 51.17% ownership interest in Plantation Pipe Line Company, the sole owner of the Plantation refined petroleum products pipeline system. An affiliate of ExxonMobil owns the remaining interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered participating rights; therefore, we do not control Plantation Pipe Line Company, and we account for our investment under the equity method;

▪

Red Cedar Gathering Company—we own a 49% ownership interest in the Red Cedar Gathering Company. The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe. Red Cedar is the sole owner of the Red Cedar natural gas gathering, compression and treating system;

▪

Express pipeline system—we acquired a 33 1/3% ownership interest in the Express pipeline system from KMI effective August 28, 2008 (discussed in Note 3 “Acquisitions and Divestitures—Acquisitions from KMI—Express and Jet Fuel Pipeline Systems”);

▪

Endeavor Gathering LLC—we acquired a 40% ownership interest in Endeavor Gathering LLC from GMX Resources Inc. effective November 1, 2009 (discussed in Note 3 “Acquisitions and Divestitures—Acquisitions from Unrelated Entities—(6) Endeavor Gathering LLC”); and

▪

Eagle Ford Gathering LLC—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 formation in south Texas. We named the joint venture Eagle Ford Gathering LLC, and we own a 50% member interest in Eagle Ford Gathering LLC. Copano owns the remaining 50% interest and serves as operator and managing member of Eagle Ford Gathering LLC. For more information on our investment in Eagle Ford, see Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments—Natural Gas Pipelines” included in our Annual Report on Form 10-K for the year ended December 31, 2010; and

▪

Cortez Pipeline Company—we operate and own a 50% ownership interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. A subsidiary of Exxon Mobil Corporation owns a 37% ownership interest and Cortez Vickers Pipeline Company owns the remaining 13% ownership interest.

141

We also own a 50% ownership interest in Fayetteville Express Pipeline LLC, which was formed in August 2008. Fayetteville Express Pipeline LLC is the sole owner of the Fayetteville Express natural gas pipeline system. Energy Transfer Partners, L.P. operates the Fayetteville Express pipeline system and owns the remaining 50% ownership interest in Fayetteville Express Pipeline LLC. The Fayetteville Express system began interim transportation service on October 12, 2010, and began full operations on January 1, 2011. In 2009, we made capital contributions of $103.2 million to Fayetteville Express Pipeline LLC to partially fund its pipeline construction costs. As of December 31, 2010 and 2009, however, we had no material net investment in Fayetteville Express Pipeline LLC because in November 2009, Fayetteville Express Pipeline LLC established and made borrowings under its own revolving bank credit facility in order to fund its pipeline development and construction costs and to make distributions to its member owners to reimburse them for prior contributions (including contributions made in 2008). Accordingly, we received cash distributions of $115.6 million from Fayetteville Express Pipeline LLC in 2009.

In addition to the investments listed above, our significant equity investments included a 25% ownership interest in Thunder Creek Gas Services, LLC, until we sold our ownership interest to PVR Midstream LLC on April 1, 2008. The divestiture of our investment in Thunder Creek is discussed in Note 3 “Acquisitions and Divestitures—Divestitures—Thunder Creek Gas Services, LLC.”

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

	Year Ended December 31,
	2010			2009			2008
Rockies Express Pipeline LLC	$	87.6		$	98.5		$	84.9
Plantation Pipe Line Company		30.3			26.8			22.3
Midcontinent Express Pipeline LLC		30.1			14.7			0.5
Red Cedar Gathering Company		28.7			24.9			26.7
Cortez Pipeline Company		22.5			22.3			20.8
KinderHawk Field Services LLC		19.5			-			-
Endeavor Gathering LLC		3.2			0.1			-
Express pipeline system		(3.3	)		(4.1	)		(0.5	)
Eagle Ford Gathering LLC		-			-			-
Thunder Creek Gas Services, LLC		-			-			1.3
All others		4.5			6.5			4.8
Total	$	223.1		$	189.7		$	160.8
Amortization of excess costs	$	(5.8	)	$	(5.8	)	$	(5.7	)

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

	Year Ended December 31,
Income Statement	2010		2009		2008
Revenues	$	1,654.2	$	1,216.6	$	1,015.0
Costs and expenses		1,215.1		832.6		681.6
Earnings before extraordinary items and cumulative effect of a change in accounting principle		439.1		384.0		333.4
Net income	$	439.1	$	384.0	$	333.4

	December 31,
Balance Sheet	2010		2009
Current assets	$	485.2	$	294.3
Non-current assets		11,807.6		9,895.9
Current liabilities		599.4		2,162.6
Non-current liabilities		4,510.9		2,905.9
Partners’/Owners’ equity		7,182.5		5,121.7

For information on regulatory matters affecting certain of our equity investments, see Note 17.

As of December 31, 2010 and 2009, our investment amounts also included bond investments totaling $8.2 million and $13.2 million, respectively. These bond investments consisted of certain tax exempt, fixed-income development revenue bonds we acquired in the fourth quarter of 2008. Because we have both the ability and the intent to hold these debt securities to maturity, we account for these investments at historical cost. We acquired our bond investments by issuing notes under the Gulf Opportunity Zone Act of 2005, which are further discussed in Note 8 “Debt—Subsidiary Debt—Gulf Opportunity Zone Bonds.”

142

7. Goodwill and Other Intangibles

Goodwill and Excess Investment Cost

We record the excess of the cost of an acquisition price over the fair value of acquired net assets as an asset on our balance sheet. This amount is referred to and reported separately as “Goodwill” in our accompanying consolidated balance sheets. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount.

We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines; (iv) CO2; (v) Terminals; and (vi) Kinder Morgan Canada. 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.

The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using market multiples between six and ten times cash flows) discounted at a rate of 9.0%. The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date.

Changes in the gross amounts of our goodwill and accumulated impairment losses for each of the two years ended December 31, 2010 and 2009 are summarized as follows (in millions):

	Products Pipelines		Natural Gas Pipelines		CO2		Terminals		Kinder Morgan Canada			Total

Historical Goodwill.	$	263.2	$	288.4	$	46.1	$	257.6	$	580.7		$	1,436.0
Accumulated impairment losses(a).		-		-		-		-		(377.1	)		(377.1	)
Balance as of December 31, 2008		263.2		288.4		46.1		257.6		203.6			1,058.9
Acquisitions and purchase price adjs.		-		48.6		-		9.3		-			57.9
Currency translation adjustments		-		-		-		-		32.4			32.4
Balance as of December 31, 2009	$	263.2	$	337.0	$	46.1	$	266.9	$	236.0		$	1,149.2
Acquisitions.		-		-		-		71.0		-			71.0
Currency translation adjustments		-		-		-		-		13.4			13.4
Balance as of December 31, 2010	$	263.2	$	337.0	$	46.1	$	337.9	$	249.4		$	1,233.6

__________

(a)

On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from KMI, and we completed this transaction on April 30, 2007. Following the provisions of generally accepted accounting principles, the consideration of this transaction caused KMI to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired. Based on this determination, KMI recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007, and because we have included all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006, this impairment is now included in our accumulated impairment losses. We have no other goodwill impairment losses.

For more information on our accounting for goodwill, see Note 2 “Summary of Significant Accounting Policies—Goodwill.”

With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to acquire our share of the net assets of such equity investees; or (ii) the revaluation of our share of the net assets of any retained noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidating subsidiary, thereby losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets. This differential consists of two pieces. First, an amount related to the difference between the investee’s recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (referred to as equity method goodwill) we paid to acquire the investment. We include both amounts within “Investments” on our accompanying consolidated balance sheets.

143

The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $166.0 million and $163.2 million as of December 31, 2010 and 2009, respectively. In almost all instances, this differential, relating to the discrepancy between our share of the investee’s recognized net assets at book values and at current fair values, represents our share of undervalued depreciable assets, and since those assets (other than land) are subject to depreciation, we amortize this portion of our investment cost against our share of investee earnings. As of December 31, 2010, this excess investment cost is being amortized over a weighted average life of approximately 27.6 years.

The second differential, representing total unamortized excess cost over underlying fair value of net assets acquired (equity method goodwill) was $283.0 million as of December 31, 2010 and $138.2 million as of December 31, 2009. This differential is not subject to amortization but rather to impairment testing. Accordingly, in addition to our annual impairment test of goodwill, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives. Our impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. As of December 31, 2010, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted.

Other Intangibles

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, technology-based assets, and lease value. These intangible assets have definite lives and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets. Following is information, as of December 31, 2010 and 2009, related to our intangible assets subject to amortization (in millions):

	December 31,
	2010			2009
Customer relationships, contracts and agreements
Gross carrying amount	$	399.8		$	273.0
Accumulated amortization		(112.0	)		(67.1	)
Net carrying amount		287.8			205.9

Technology-based assets, lease value and other
Gross carrying amount		17.9			15.7
Accumulated amortization		(3.5	)		(2.9	)
Net carrying amount		14.4			12.8

Total Other intangibles, net	$	302.2		$	218.7

Our customer relationships, contracts and agreements relate primarily to our Terminals business segment, and include relationships and contracts for handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, coal, petroleum coke, fertilizer, steel and ores. The values of these intangible assets were determined by us (often in conjunction with third party valuation specialists) by first, estimating the revenues derived from a customer relationship or contract (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate. The increase in the carrying amount of our customer relationships, contracts and agreements since December 31, 2009 was mainly due to the acquisition of intangibles included in our purchase of terminal assets from US Development Group LLC and Slay Industries, discussed in Note 3.

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new technology, and competition. For each of the years ended December 31, 2010, 2009 and 2008, the amortization expense on our intangibles totaled $45.5 million, $16.5 million and $14.7 million, respectively. These expense amounts primarily consisted of amortization of our customer relationships, contracts and agreements. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2011 – 2015) is approximately $39.3 million, $33.9 million, $30.0 million, $26.6 million and $23.7 million, respectively.

The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. As of December 31, 2010, the weighted average amortization period for our intangible assets was approximately 13.8 years.

144

8. Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our consolidated statements of income. The net carrying amount of our debt (including both short-term and long-term amounts and excluding the value of interest rate swap agreements) as of December 31, 2010 and 2009 was $11,539.8 million and $10,592.4 million, respectively. The weighted average interest rate on all of our borrowings was approximately 4.35% during 2010 and 4.57% during 2009.

Short-Term Debt

Our outstanding short-term debt as of December 31, 2010 was $1,262.4 million. The balance consisted of (i) $700.0 million in principal amount of 6.75% senior notes due March 15, 2011; (ii) $522.1 million of commercial paper borrowings; (iii) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, but are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (our subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds); (iv) a $9.4 million portion of a 5.40% long-term note payable (our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note); and (v) a $7.2 million portion of 5.23% long-term senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes).

Our outstanding short-term debt as of December 31, 2009 was $594.7 million. The balance consisted of (i) $300 million in outstanding borrowings under our bank credit facility (discussed following); (ii) $250 million in principal amount of 7.50% senior notes that matured on November 1, 2010; (iii) $23.7 million in principal amount of tax-exempt bonds due from our subsidiary Kinder Morgan Operating L.P. “B”; (iv) an $8.9 million portion of the 5.40% long-term note payable due from our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company; (v) a $6.8 million portion of the 5.23% senior notes due from our subsidiary Kinder Morgan Texas Pipeline, L.P.; and (vi) $5.3 million in principal amount of adjustable rate industrial development revenue bonds that matured on January 1, 2010 (the bonds were issued by the Illinois Development Finance Authority and our subsidiary Arrow Terminals L.P. is the obligor on the bonds).

Credit Facility

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 facility, our $2.0 billion credit facility is with a syndicate of financial institutions, and the facility permits us to obtain bids for fixed rate loans from members of the lending syndicate. 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 commercial paper program. We had no borrowings under the credit facility as of December 31, 2010. As of December 31, 2009, the outstanding balance under our previous $1.79 billion credit facility was $300 million, and the weighted average interest rate on these borrowings was 0.59%.

The covenants of our $2.0 billion, senior unsecured revolving credit facility are substantially similar to the covenants of our previous facility; however, the interest rates for borrowings under this facility have increased from our previous facility. Interest on the credit facility accrues at our option at a floating rate equal to either (i) the administrative agent’s base rate (but not less than the Federal Funds Rate, plus 0.5%); or (ii) LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt. The credit facility can be amended to allow for borrowings of up to $2.3 billion.

As of December 31, 2010, the amount available for borrowing under our credit facility was reduced by a combined amount of $758.9 million, consisting of $522.1 million of commercial paper borrowings and $236.8 million of letters of credit, consisting of: (i) a $100.0 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined $87.9 million in three letters of credit that support tax-exempt bonds; (iii) a $16.2 million letter of credit that supports debt securities issued by the Express pipeline system; (iv) a $16.1 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (v) a combined $16.6 million in other letters of credit supporting other obligations of us and our subsidiaries.

145

Additionally, our $2.0 billion credit facility included the following restrictive covenants as of December 31, 2010:

▪

total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed:

▪ 5.5, in the case of any such period ended on the last day of (i) a fiscal quarter in which we make any Specified Acquisition (as defined in the credit facility), or (ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or

▪ 5.0, in the case of any such period ended on the last day of any other fiscal quarter;

▪

certain limitations on entering into mergers, consolidations and sales of assets;

▪

limitations on granting liens; and

▪

prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.

In addition to normal repayment covenants, under the terms of our credit facility, the occurrence at any time of any of the following would constitute an event of default (i) our failure to make required payments of any item of indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million; (ii) our general partner’s failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million; (iii) adverse judgments rendered against us for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed; and (iv) voluntary or involuntary commencements of any proceedings or petitions seeking our liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.

Other than the relatively non-restrictive negative covenants and events of default in our credit facility, there are no provisions protecting against a situation where we are unable to terminate an agreement with a counterparty who is facing an impending financial collapse and such collapse may be hastened due to cross-defaults. Also, the credit facility does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin we will pay with respect to borrowings, and the facility fee that we will pay on the total commitment, will vary based on our senior debt credit rating. None of our debt is subject to payment acceleration as a result of any change to our credit ratings.

Commercial Paper Program

Our commercial paper program provides for the issuance of $2 billion of commercial paper. On October 13, 2008, Standard & Poor’s Ratings Services lowered our short-term credit rating to A-3 from A-2, and on May 6, 2009, Moody’s Investors Service, Inc. downgraded our commercial paper rating to Prime-3 from Prime-2 and assigned a negative outlook to our long-term credit rating. As a result of these revisions and the commercial paper market conditions, we were unable to access commercial paper borrowings throughout 2009.

However, on February 25, 2010, Standard & Poor’s revised its outlook on our long-term credit rating to stable from negative, affirmed our long-term credit rating at BBB, and raised our short-term credit rating to A-2 from A-3. The rating agency’s revisions reflected its expectations that our financial profile will improve due to lower guaranteed debt obligations and higher expected cash flows associated with the completion and start-up of our 50%-owned Rockies Express and Midcontinent Express natural gas pipeline systems and our fully-owned Kinder Morgan Louisiana natural gas pipeline system. Due to this favorable change in our short-term credit rating, we resumed issuing commercial paper in March 2010, and as of December 31, 2010, we had $522.1 million of commercial paper outstanding with an average interest rate of 0.67%. In the near term, we expect that our short-term liquidity and financing needs will be met through a combination of borrowings made under our bank credit facility and our commercial paper program.

146

Long-Term Debt

Our outstanding long-term debt, excluding the value of interest rate swaps, as of December 31, 2010 and 2009 was $10,277.4 million and $9,997.7 million, respectively. The balances consisted of the following (in millions):

	December 31,
	2010			2009
Kinder Morgan Energy Partners, L.P. borrowings:
7.50% senior notes due November 1, 2010	$	-		$	250.0
6.75% senior notes due March 15, 2011		700.0			700.0
7.125% senior notes due March 15, 2012		450.0			450.0
5.85% senior notes due September 15, 2012		500.0			500.0
5.00% senior notes due December 15, 2013		500.0			500.0
5.125% senior notes due November 15, 2014		500.0			500.0
5.625% senior notes due February 15, 2015		300.0			300.0
6.00% senior notes due February 1, 2017		600.0			600.0
5.95% senior notes due February 15, 2018		975.0			975.0
9.00% senior notes due February 1, 2019(a)		500.0			500.0
6.85% senior notes due February 15, 2020		700.0			700.0
5.30% senior notes due September 15, 2020		600.0			-
5.80% senior notes due March 1, 2021		400.0			400.0
7.40% senior notes due March 15, 2031		300.0			300.0
7.75% senior notes due March 15, 2032		300.0			300.0
7.30% senior notes due August 15, 2033		500.0			500.0
5.80% senior notes due March 15, 2035		500.0			500.0
6.50% senior notes due February 1, 2037		400.0			400.0
6.95% senior notes due January 15, 2038		1,175.0			1,175.0
6.50% senior notes due September 1, 2039		600.0			600.0
6.55% senior notes due September 15, 2040		400.0			-
Commercial paper borrowings		522.1			-
Bank credit facility borrowings		-			300.0
Subsidiary borrowings:
Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010		-			5.3
Kinder Morgan Louisiana Pipeline LLC-6.0% LA Development Revenue note due Jan. 1, 2011		-			5.0
Kinder Morgan Operating L.P. “A”-5.40% BP note, due March 31, 2012		10.2			14.9
Kinder Morgan Canada Company-5.40% BP note, due March 31, 2012		9.0			13.2
Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014		23.6			30.5
Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018		25.0			25.0
Kinder Morgan Columbus LLC-5.50% MS Development Revenue note due Sept. 1, 2022		8.2			8.2
Kinder Morgan Operating L.P. “B”-Jackson-Union Cos. IL Revenue Bonds due April 1, 2024		23.7			23.7
International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025		40.0			40.0
Other miscellaneous subsidiary debt		1.3			1.3
Unamortized debt discount on senior notes		(23.3	)		(24.7	)
Current portion of long-term debt		(1,262.4	)		(594.7	)
Total long-term debt	$	10,277.4		$	9,997.7

__________

(a)

We issued our $500 million in principal amount of 9.00% senior notes due February 1, 2019 in December 2008. Each holder of the notes has the right to require us to repurchase all or a portion of the notes owned by such holder on February 1, 2012 at a purchase price equal to 100% of the principal amount of the notes tendered by the holder plus accrued and unpaid interest to, but excluding, the repurchase date. On and after February 1, 2012, interest will cease to accrue on the notes tendered for repayment. A holder’s exercise of the repurchase option is irrevocable.

Kinder Morgan Energy Partners, L.P. Senior Notes

As of December 31, 2010 and 2009, the net carrying value of the various series of our senior notes was $10,876.7 million and $10,125.3 million, respectively. For a listing of the various outstanding series of our senior notes, see the table above included in “—Long-Term Debt.” All of our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.

147

On May 19, 2010, we completed a public offering of senior notes. 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 received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $993.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

In addition, on November 1, 2010, we paid $250 million to retire the principal amount of our 7.50% senior notes that matured on that date. We borrowed the necessary funds under our commercial paper program.

During 2009, we completed two separate public offerings of senior notes. With regard to these offerings, we received proceeds, net of underwriting discounts and commissions, as follows (i) $993.3 million from a May 14, 2009 public offering of a total of $1 billion in principal amount of senior notes, consisting of $300 million of 5.625% notes due February 15, 2015, and $700 million of 6.85% notes due February 15, 2020; and (ii) $987.4 million from a September 16, 2009 public offering of a total of $1 billion in principal amount of senior notes, consisting of $400 million of 5.80% notes due March 1, 2021 and $600 million of 6.50% notes due September 1, 2039. We used the proceeds from all of our 2009 debt offerings to reduce the borrowings under our bank credit facility.

In addition, on February 1, 2009, we paid $250 million to retire the principal amount of our 6.30% senior notes that matured on that date. We borrowed the necessary funds under our bank credit facility.

Interest Rate Swaps

Information on our interest rate swaps is contained in Note 13 “Risk Management—Interest Rate Risk Management.”

Subsidiary Debt

Our subsidiaries are obligors on the following debt. The agreements governing these obligations contain various affirmative and negative covenants and events of default. We do not believe that these provisions will materially affect distributions to our partners.

Arrow Terminals L.P. Debt

On January 1, 2010, our subsidiary Arrow Terminals L.P. paid the $5.3 million outstanding principal amount of its Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority that matured on that date, and following its repayment, Arrow Terminals L.P. had no outstanding debt.

Kinder Morgan Operating L.P. “A” Debt

Effective January 1, 2007, we acquired the remaining approximately 50.2% interest in the Cochin pipeline system that we did not already own. As part of our purchase price consideration, two of our subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. We valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%. Our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note, and the principal amount of the note, along with interest, is due in five annual installments of $10.0 million beginning March 31, 2008. We paid the third installment on March 31, 2010, and as of December 31, 2010, the net present value of the note (representing the outstanding balance included as debt on our accompanying consolidated balance sheet) was $19.2 million. As of December 31, 2009, the net present value of the note was $28.1 million.

Kinder Morgan Texas Pipeline, L.P. Debt

Our subsidiary, Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes, which were assumed on August 1, 2005 when we acquired a natural gas storage facility located in Liberty County, Texas from a third party. The notes have a fixed annual stated interest rate of 8.85%; however, we valued the debt equal to the present value of amounts to be paid determined using an approximate interest rate of 5.23%. The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million, and the final payment is due January 2, 2014. During 2010, we paid a combined principal amount of $6.9 million, and as of December 31, 2010 and 2009, Kinder Morgan Texas Pipeline L.P.’s outstanding balance under the senior notes was $23.6 million and $30.5 million, respectively. Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million and at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid.

148

Kinder Morgan Liquids Terminals LLC Debt

Our subsidiary Kinder Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. These bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2010, the interest rate was 0.29%. We have an outstanding letter of credit issued by Citibank in the amount of $25.4 million that backs-up the $25.0 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 46 days computed at 12% on a per annum basis on the principal thereof.

Kinder Morgan Operating L.P. “B” Debt

Our subsidiary Kinder Morgan Operating L.P. “B” is the obligor of a principal amount of $23.7 million of tax-exempt bonds due April 1, 2024. The bonds were issued by the Jackson-Union Counties Regional Port District, a political subdivision embracing the territories of Jackson County and Union County in the state of Illinois. These variable rate demand bonds bear interest at a weekly floating market rate and are backed-up by a letter of credit issued by Wells Fargo. The bond indenture also contains certain standby purchase agreement provisions which allow investors to put (sell) back their bonds at par plus accrued interest. As of December 31, 2010, the interest rate on these bonds was 0.38%. Our outstanding letter of credit issued by Wells Fargo totaled $24.1 million, which backs-up a principal amount of $23.7 million and $0.4 million of interest on the bonds for up to 55 days computed at 12% per annum on the principal amount thereof.

International Marine Terminals Debt

We own a 66 2/3% interest in the International Marine Terminals (IMT) partnership. The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40.0 million Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. As of December 31, 2010, the interest rate on these bonds was 1.20%.

On March 15, 2005, these bonds were refunded and the maturity date was extended from March 15, 2006 to March 15, 2025. No other changes were made under the bond provisions. The bonds are backed by two letters of credit issued by Wells Fargo. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees.

Gulf Opportunity Zone Bonds

To help fund our business growth in the states of Mississippi and Louisiana, we completed the purchase of a combined $13.2 million in principal amount of tax exempt revenue bonds in two separate transactions in December 2008. To acquire our investment, two of our subsidiaries issued notes with identical terms under the Gulf Opportunity Zone Act of 2005. The notes consisted of the following: (i) $8.2 million in principal amount of 5.5% Development Revenue Bonds issued by the Mississippi Business Finance Corporation (MBFC), a public, non-profit corporation that coordinates a variety of resources used to assist business and industry in the state of Mississippi; and (ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued by the Louisiana Community Development Authority (LCDA), a political subdivision of the state of Louisiana.

The Mississippi revenue bonds mature on September 1, 2022, and both principal and interest is due in full at maturity. We also hold an option to redeem in full (and settle the note payable to MBFC) the principal amount of bonds held by us without penalty after one year. We redeemed the Louisiana revenue bonds in December 2010 (by settling our $5.0 million note payable to LCDA), and we replaced this investment with a new investment of $100.0 million in principal amount of Development Revenue Bonds that mature on December 1, 2040 and pay interest at a rate equal to one-month LIBOR plus 1.75%. We paid for this investment by issuing a $100.0 million note payable to LCDA with identical terms, and for this bond issuance, we elected to offset our borrowing against the investment we acquired.

149

Maturities of Debt

The scheduled maturities of our outstanding debt, excluding the value of interest rate swaps, as of December 31, 2010, are summarized as follows (in millions):

Year	Commitment
2011	$	1,262.4
2012		1,467.0
2013		507.1
2014		500.5
2015		299.9
Thereafter		7,502.9
Total	$	11,539.8

Subsequent Event

In January 2011, we terminated a previously issued $55.0 million letter of credit issued by Deutsche Bank to support our pipeline and terminal operations in Canada. Specifically, this letter of credit supported the operations of our Kinder Morgan Canada business segment owned by our subsidiary KMEP Canada ULC. To replace this letter of credit, on January 6, 2011, we entered into a credit agreement with The Toronto-Dominion Bank that allows us to obtain the issuance of letters of credit up to a limit of C$70.0 million to support our Canadian operations. Each letter of credit issued pursuant to this credit agreement will expire one year after issuance or, in the case of any renewal or extension, one year after such renewal or extension. As of February 14, 2011, letters of credit having a combined face amount of C$50.7 million have been issued pursuant to this credit agreement.

9. Employee Benefits

Pension and Postretirement Benefit Plans

In connection with our acquisition of the Trans Mountain pipeline system in 2007 from KMI, we acquired certain liabilities for pension and postretirement benefits. Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline L.P.) are sponsors of pension plans for eligible Trans Mountain employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excess of statutory limits), and defined contributory plans. We also provide postretirement benefits other than pensions for retired employees.

Our combined net periodic benefit costs for these Trans Mountain pension and postretirement benefit plans for 2010, 2009 and 2008 were approximately $3.9 million, $2.9 million, and $3.5 million, respectively, recognized ratably over each year. As of December 31, 2010, we estimate our overall net periodic pension and postretirement benefit costs for these plans for the year 2011 will be approximately $6.6 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. We expect to contribute approximately $7.1 million to these benefit plans in 2011.

Additionally, in connection with our acquisition of SFPP, L.P. in 1998, we acquired certain liabilities for pension and postretirement benefits. We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP. We also provide the same benefits to former salaried employees of SFPP and we will continue to fund these costs for those employees currently in the plan during their retirement years.

SFPP’s postretirement benefit plan is frozen and no additional participants may join the plan. Benefits under the SFPP postretirement benefit plan are provided by the Burlington Northern Santa Fe railroad and we reimburse BNSF for the costs of the plan. As of the date of this report, we have not received our 2010 actuarial valuation report for the SFPP postretirement benefit plan; however, in 2010, we recorded a credit of less than $0.1 million for net periodic benefit costs related to this plan, and for each of the years ended December 31, 2009 and 2008, our net periodic benefit cost for the SFPP postretirement benefit plan was a credit of less than $0.1 million. The credits in all three years resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost. As of December 31, 2010, we estimate our overall net periodic postretirement benefit cost for the SFPP postretirement benefit plan for the year 2011 will again be a credit of less than $0.1 million; however, this estimate could change if a future significant event would require a remeasurement of liabilities. In addition, we expect to contribute approximately $0.3 million to this postretirement benefit plan in 2011.

As of December 31, 2010 and 2009, the recorded value of our pension and postretirement benefit obligations for both the Trans Mountain pension and postretirement benefit plans and the SFPP postretirement benefit plan was a combined $44.8 million and $37.4 million, respectively. We consider our overall pension and postretirement benefit liability exposure and the fair value of our pension and postretirement plan assets to be minimal in relation to the value of our total consolidated assets and net income.

150

Multiemployer Plans

As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans for each of the years ended December 31, 2010, 2009 and 2008 were approximately $10.3 million, $8.4 million and $7.8 million, respectively.

Kinder Morgan Savings Plan

The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of KMI and KMGP Services Company, Inc. to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. As an additional benefit to all participants, an option also exits to make after-tax “Roth” contributions (Roth 401(k) option) to a separate Savings Plan participant account, and certain employees’ contributions are based on collective bargaining agreements. Our general partner contributes an amount equal to 4% of base compensation per year for most plan participants and in addition, may make special discretionary contributions (described below). The contributions are made each pay period on behalf of each eligible employee.

Participants may direct the investment of their contributions and all employer contributions, including discretionary contributions, into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. The total amount charged to expense for the Kinder Morgan Savings Plan was $13.3 million during 2010, $12.1 million during 2009, and $13.3 million during 2008.

Employer contributions for employees vest on the second anniversary of the date of hire. Effective October 1, 2005, for new employees of our Terminals segment, a tiered employer contribution schedule was implemented. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for services between two and five years, and 4% for service of five years or more. All employer contributions for Terminals employees hired after October 1, 2005 vest on the third anniversary of the date of hire.

At its July 2010 meeting, Mr. Richard D. Kinder and KMR’s compensation committee approved a special contribution of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2010 and continuing through the last pay period of July 2011. The additional 1% contribution does not change or otherwise impact the annual 4% contribution that eligible employees currently receive, and it vests according to the same vesting schedule described in the preceding paragraph. During the first quarter of 2011, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2010.

At its January 2011 meeting, Mr. Richard D. Kinder and KMR’s compensation committee decided to make this special contribution of an additional 1% of base pay a permanent contribution into the Savings Plan for each eligible employee. Accordingly, beginning with the first pay period of August 2011, our general partner will contribute an amount equal to 5% of base compensation per year on behalf of each eligible employee. This change was made to assist employees in providing financial security for retirement without the risk of the 1% variable factor. For employees of our Terminals business segment, the tiered employer contributions described above will also increase by 1% beginning with the first pay period of August 2011.

Cash Balance Retirement Plan

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

151

In February 2009, KMI amended the plan in order to reduce its rate of future benefit accruals effective April 12, 2009. Beginning on that date, and continuing through the last pay period of December 2009, KMI ceased making contribution credits to the accounts of all participating employees of KMGP Services, Inc. and KMI under the cash balance portion of the plan, except to the extent the terms of an applicable collective bargaining agreement required contribution credits be made. KMI continued to credit interest to employees’ personal retirement accounts as described above. Effective January 1, 2010, all contribution credits on behalf of participating employees resumed.

Effective January 1, 2011, KMI amended the plan and began crediting each participating employee’s personal retirement account for interest at a rate equal to the five-year U.S. Treasury note rate plus 0.25%. This interest rate credit change allows KMI to invest the plan’s assets in a manner that preserves capital and controls volatility. The new interest rate complies with the safe harbor regulations as defined by the U.S. Department of Labor and is expected to reduce the plan’s long-term cost. KMI continues to credit 3% of employees’ eligible compensation to their personal retirement accounts.

10. Partners’ Capital

Limited Partner Units

As of December 31, 2010 and 2009, our partners’ capital included the following limited partner units:

	December 31,
	2010		2009
Common units		218,880,103		206,020,826
Class B units		5,313,400		5,313,400
i-units		91,907,987		85,538,263
Total limited partner units		316,101,490		296,872,489

The total limited partner units represent our limited partners’ interest and an effective 98% interest in us, exclusive of our general partner’s incentive distribution rights. Our general partner has an effective 2% interest in us, excluding its incentive distribution rights.

As of December 31, 2010, our total common units consisted of 202,509,675 units held by third parties, 14,646,428 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner. As of December 31, 2009, our total common units consisted of 189,650,398 units held by third parties, 14,646,428 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner.

The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. All of our Class B units were issued to a wholly-owned subsidiary of KMI in December 2000.

On both December 31, 2010 and 2009, all of our i-units were held by KMR. Our i-units are a separate class of limited partner interests in us and are not publicly traded. In accordance with its limited liability company agreement, KMR’s activities are restricted to being a limited partner in us, and to controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR’s limited liability company agreement, the number of outstanding KMR shares and the number of our i-units will at all times be equal.

Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns.

Based on the preceding, during the year ended December 31, 2010, KMR received distributions of 6,369,724 i-units. These additional i-units distributed were based on the $4.32 per unit distributed to our common unitholders during 2010. During the year ended December 31, 2009, KMR received distributions of 7,540,357 i-units. These additional i-units distributed were based on the $4.20 per unit distributed to our common unitholders during 2009. During the year ended December 31, 2008, KMR received distributions of 5,565,424 i-units. These additional i-units distributed were based on the $3.89 per unit distributed to our common unitholders during 2008.

152

Equity Issuances

2010 Issuances

On January 16, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS). According to the provisions of this agreement, which was amended and restated on October 1, 2009, we may offer and sell from time to time common units having an aggregate offering value of up to $600 million through UBS, as sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions or as otherwise agreed between us and UBS. Under the terms of this agreement, we also may sell common units to UBS as principal for its own account at a price agreed upon at the time of the sale. Any sale of common units to UBS as principal would be pursuant to the terms of a separate agreement between us and UBS.

This equity distribution agreement provides us the right, but not the obligation, to sell common units in the future, at prices we deem appropriate. We retain at all times complete control over the amount and the timing of each sale, and we will designate the maximum number of common units to be sold through UBS, on a daily basis or otherwise as we and UBS agree. UBS will then use its reasonable efforts to sell, as our sales agent and on our behalf, all of the designated common units. We may instruct UBS not to sell common units if the sales cannot be effected at or above the price designated by us in any such instruction. Either we or UBS may suspend the offering of common units pursuant to the agreement by notifying the other party.

In 2010, we issued 3,902,225 of our common units pursuant to our equity distribution agreement. After commissions of $2.0 million, we received net proceeds from the issuance of these common units of $266.3 million. We used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

We also completed the following equity issuances in 2010:

▪

On January 15, 2010, we issued 1,287,287 common units—valued at $81.7 million—as a portion of our purchase price for additional ethanol handling terminal assets we acquired from US Development Group LLC (for more information on this acquisition, see Note 3 “Acquisitions and Divestitures—Acquisitions from Unrelated Entities—(7) USD Terminal Acquisition;”

▪

On May 7, 2010, we issued, in a public offering, 6,500,000 of our common units at a price of $66.25 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $417.4 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility; and

▪

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. We received net proceeds of $75.0 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

2009 Issuances

In 2009, we issued 5,488,947 of our common units pursuant to our equity distribution agreement with UBS. After commissions of $4.0 million, we received net proceeds from the issuance of these common units of $281.2 million. We used the proceeds to reduce the borrowings under our bank credit facility.

We also completed three separate underwritten public offerings of our common units in 2009—receiving net proceeds of $874.4 million as discussed following—and in April 2009, we issued 105,752 common units—valued at $5.0 million—as the purchase price for additional ownership interests in certain oil and gas properties.

In our first 2009 underwritten public offering, completed in March, we issued 5,666,000 of our common units at a price of $46.95 per unit, less underwriting commissions and expenses. We received net proceeds of $258.0 million for the issuance of these common units. In our second offering, completed in July, we issued 6,612,500 common units at a price of $51.50 per unit, less underwriting commissions and expenses, and we received net proceeds of $329.9 million. In our final 2009 public offering, completed in December, we issued 5,175,000 common units at a price of $57.15 per unit, less underwriting commissions and expenses, and we received net proceeds of $286.5 million for the issuance of these common units. We used the proceeds from each of these three public offerings to reduce the borrowings under our bank credit facility.

153

Income Allocation and Declared Distributions

For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed, and we determine the allocation of incentive distributions to our general partner by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement.

For each of the years ended December 31, 2010, 2009 and 2008, we declared distributions of $4.40, $4.20 and $4.02 per unit, respectively. Cash distributions paid to all partners, consisting of our common and Class B unitholders, our general partner and noncontrolling interests, totaled $1,826.6 million in 2010, $1,771.9 million in 2009 and $1,488.7 million in 2008. In addition, we made distributions of additional i-units in each of these years to KMR as discussed under “—Limited Partner Units” above. Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year. The year-to-year increases in distributions paid reflect the increase in amounts distributed per unit as well as the issuance of additional units; however, the overall increase in distributions paid in 2010 versus 2009 was partially offset by a decrease in incentive distributions paid to our general partner, as discussed following.

Our general partner’s incentive distribution that we declared for each of the years 2010, 2009 and 2008 was $880.5 million, $932.3 million and $800.8 million, respectively, while the incentive distribution we paid to our general partner during 2010, 2009 and 2008 was $848.2 million, $906.5 million and $754.6 million, respectively. The general partner’s incentive distribution we paid in 2010 was affected by (i) a reduced incentive amount of $168.3 million 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 (including the general partner’s 2% general partner interest, its total cash distributions were reduced by $170.0 million); and (ii) a waived incentive amount equal to $11.1 million related to common units issued to finance a portion of our acquisition of a 50% interest in KinderHawk Field Services LLC joint venture (our general partner has agreed not to take incentive distributions related to this acquisition through year-end 2011).

Our distribution of cash for the second quarter of 2010 (which we paid in the third quarter of 2010) from interim capital transactions totaled $177.1 million (approximately $0.56 per limited partner unit). As provided in our partnership agreement, our general partner receives no incentive distribution on distributions of cash from interim capital transactions; accordingly, this distribution from interim capital transactions helped preserve our cumulative excess cash coverage. Cumulative excess cash coverage is cash from operations generated since our inception in excess of cash distributions paid.

In addition, there was no practical impact to our limited partners from this distribution of cash from interim capital transactions because (i) the cash distribution to our limited partners for the quarter did not change; (ii) fewer dollars in the aggregate were distributed (because there was no incentive distribution paid to our general partner related to the portion of the quarterly distribution that was a distribution of cash from interim capital transactions); and (iii) our general partner, in this instance, agreed to waive any resetting of the incentive distribution target levels, as would otherwise occur according to our partnership agreement.

For further information on our partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions.”

Subsequent Events

In early January 2011, we issued 110,902 of our common units for the settlement of sales made on or before December 31, 2010 pursuant to our equity distribution agreement with UBS. After commissions of $0.1 million, we received net proceeds of $7.7 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.

154

On January 19, 2011, we declared a cash distribution of $1.13 per unit for the quarterly period ended December 31, 2010. This distribution was paid on February 14, 2011, to unitholders of record as of January 31, 2011. Our common unitholders and our Class B unitholder received cash. KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $1.13 distribution per common unit. The number of i-units distributed was 1,598,556. For each outstanding i-unit that KMR held, a fraction of an i-unit (0.017393) was issued. The fraction was determined by dividing:

▪

$1.13, the cash amount distributed per common unit

▪

$64.969, the average of KMR’s limited liability shares’ closing market prices from January 12-26, 2011, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.

This February 14, 2011 distribution included an incentive distribution to our general partner in the amount of $274.6 million. Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2010 balance sheet as a distribution payable.

11. Related Party Transactions

General and Administrative Expenses

KMGP Services Company, Inc., a subsidiary of our general partner, provides employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides centralized payroll and employee benefits services to (i) us; (ii) our operating partnerships and subsidiaries; (iii) our general partner; and (iv) KMR (collectively referred to in this note as the Group). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of KMI, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures.

The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to our limited partnership agreement, we provide reimbursement for our share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, we reimburse KMR with respect to costs incurred or allocated to KMR in accordance with our limited partnership agreement, the delegation of control agreement among our general partner, KMR, us and others, and KMR’s limited liability company agreement.

The named executive officers of our general partner and KMR and other employees that provide management or services to both KMI and the Group are employed by KMI. Additionally, other KMI employees assist in the operation of certain of our assets (discussed below in “—Operations”). These employees’ expenses are allocated without a profit component between KMI on the one hand, and the appropriate members of the Group, on the other hand.

Additionally, for accounting purposes, KMI was required to allocate to us a portion of its 2007 going-private transaction-related amounts, and it is required to recognize compensation expense in connection with their Class A-1 and Class B units over the expected life of such units and allocate to us a portion of these going-private transaction-related amounts. These units were issued prior to the conversion of Kinder Morgan Holdco LLC to KMI. As a subsidiary of KMI, we are required to recognize the allocated amounts as expense on our income statements; however, we have no obligation and we do not expect to pay any amounts related to these going-private transaction-related expenses. Accordingly, we recognize the unpaid amounts as contributions to “Total Partners’ Capital” on our balance sheet. For each of the years 2010, 2009 and 2008, we recognized non-cash compensation expense of $4.6 million, $5.7 million and $5.6 million, respectively, due to certain going-private transaction expenses allocated to us from KMI in connection with KMI’s May 2007 going-private transaction.

155

Partnership Interests and Distributions

General

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

Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for the proper conduct of our business, which might include reserves for matters such as future operating expenses, debt service, sustaining capital expenditures and rate refunds, and for distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

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

Pursuant to our partnership agreement, distributions to unitholders are characterized either as distributions of cash from operations or as distributions of cash from interim capital transactions. This distinction affects the distributions to owners of common units, Class B units and i-units relative to the distributions to our general partner.

Cash from Operations. Cash from operations generally refers to our cash balance on the date we commenced operations, plus all cash generated by the operation of our business, after deducting related cash expenditures, net additions to or reductions in reserves, debt service and various other items.

Cash from Interim Capital Transactions. Cash from interim capital transactions will generally result only from distributions that are funded from borrowings, sales of debt and equity securities and sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets and assets disposed of in the ordinary course of business.

Rule for Characterizing Distributions. Generally, all available cash distributed by us from any source will be treated as distributions of cash from operations until the sum of all available cash distributed equals the cumulative amount of cash from operations actually generated from the date we commenced operations through the end of the calendar quarter prior to that distribution. Any distribution of available cash which, when added to the sum of all prior distributions, is in excess of the cumulative amount of cash from operations, will be considered a distribution of cash from interim capital transactions until the initial common unit price is fully recovered as described below under “—Allocation of Distributions from Interim Capital Transactions.” For purposes of calculating the sum of all distributions of available cash, the total equivalent cash amount of all distributions of i-units to KMR, as the holder of all i-units, will be treated as distributions of available cash, even though the distributions to KMR are made in additional i-units rather than cash and we retain this cash and use it in our business. To date, all of our available cash distributions, other than a $177.1 million distribution of cash from interim capital transactions for the second quarter of 2010 (paid in the third quarter of 2010), have been treated as distributions of cash from operations.

Allocation of Distributions from Operations. Cash from operations for each quarter will be distributed effectively as follows:

▪

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

▪

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

▪

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

▪

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

156

Allocation of Distributions from Interim Capital Transactions. Any distribution by us of available cash that would constitute cash from interim capital transactions would be distributed effectively as follows:

▪

98% to all owners of common units and Class B units pro rata in cash and to the holders of i-units in equivalent i-units; and

▪

2% to our general partner, until we have distributed cash from this source in respect of a common unit outstanding since our original public offering in an aggregate amount per unit equal to the initial common unit price of $5.75, as adjusted for splits.

As cash from interim capital transactions is distributed, it would be treated as if it were a repayment of the initial public offering price of the common units. To reflect that repayment, the first three distribution target levels of cash from operations (described above) would be adjusted downward proportionately by multiplying each distribution target level amount by a fraction, the numerator of which is the unrecovered initial common unit price immediately after giving effect to that distribution and the denominator of which is the unrecovered initial common unit price immediately prior to giving effect to that distribution. When the initial common unit price is fully recovered, then each of the first three distribution target levels will have been reduced to zero, and thereafter, all distributions of available cash from all sources will be treated as if they were cash from operations and available cash will be distributed 50% to all classes of units pro rata (with the distribution to i-units being made instead in the form of i-units), and 50% to our general partner. With respect to the portion of our distribution of available cash for the second quarter of 2010 that was from interim capital transactions, our general partner waived this resetting of the distribution target levels.

Kinder Morgan G.P., Inc.

Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to our partnership agreement, our general partner’s interests represent a 1% ownership interest in us, and a direct 1.0101% ownership interest in each of our five operating partnerships. Collectively, our general partner owns an effective 2% interest in our operating partnerships, excluding incentive distributions rights as follows:

▪

its 1.0101% direct general partner ownership interest (accounted for as a noncontrolling interest in our consolidated financial statements); and

▪

its 0.9899% ownership interest indirectly owned via its 1% ownership interest in us.

As of December 31, 2010, our general partner owned 1,724,000 common units, representing approximately 0.55% of our outstanding limited partner units. For information on distributions paid to our general partner, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions.”

Kinder Morgan, Inc.

KMI remains the sole indirect common stockholder of our general partner. Also, as of December 31, 2010, KMI directly owned 10,852,788 common units, indirectly owned 5,313,400 Class B units and 5,517,640 common units through its consolidated affiliates (including our general partner), and owned 13,113,533 KMR shares, representing an indirect ownership interest of 13,113,533 i-units. Together, these units represented approximately 11.0% of our outstanding limited partner units.

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% attributable to its general partner interest and the remaining 7% attributable to its limited partner interest. 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. The actual level of distributions KMI will receive in the future will vary with the level of distributions to our limited partners determined in accordance with our partnership agreement.

Kinder Morgan Management, LLC

As of December 31, 2010, KMR, our general partner’s delegate, remained the sole owner of our 91,907,987 i-units.

157

Asset Acquisitions and Sales

In March 2008, our subsidiary Kinder Morgan CO2 Company, L.P. sold certain pipeline meter equipment to Cortez Pipeline Company, its 50% equity investee, for its current fair value of $5.7 million. The meter equipment is still being employed in conjunction with our CO2 business segment.

From time to time in the ordinary course of business, we buy and sell pipeline and related services from KMI and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with our policies governing such transactions. In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; and (ii) all of the ownership interest in TransColorado Gas Transmission Company LLC from two wholly-owned subsidiaries of KMI on November 1, 2004, KMI agreed to indemnify us and our general partner with respect to approximately $733.5 million of our debt. KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets were insufficient to satisfy our obligations.

Operations

Natural Gas Pipelines and Products Pipelines Business Segments

KMI (or its subsidiaries) operates and maintain for us the assets comprising our Natural Gas Pipelines business segment. KMI operates Trailblazer Pipeline Company LLC’s assets, which is part of our Natural Gas Pipelines business segment, under a long-term contract pursuant to which Trailblazer (i) incurs the costs and expenses related to KMI’s operating and maintaining the assets; and (ii) provides the funds for its own capital expenditures. KMI does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company LLC’s assets.

The remaining assets comprising our Natural Gas Pipelines business segment, as well as our Products Pipelines business segment’s 50%-owned Cypress Pipeline (we sold a 50% ownership interest in the Cypress Pipeline on October 1, 2010, described in Note 3 “Acquisitions and Divestitures—Divestitures—Cypress Interstate Pipeline LLC”), are operated under other agreements between KMI and us. Pursuant to the applicable underlying agreements, we pay (reimburse) KMI for the actual corporate general and administrative expenses incurred in connection with the operation of these assets. The combined amounts paid to KMI for corporate general and administrative costs incurred, including amounts related to Trailblazer Pipeline Company LLC, were $55.6 million for 2010, $46.5 million for 2009 and $45.0 million for 2008. We believe the amounts paid to KMI for the services it provided each year fairly reflect the value of the services performed; however, due to the nature of the allocations, these reimbursements may not exactly match the actual time and overhead spent. We also reimburse KMI for operating and maintenance costs and capital expenditures incurred with respect to our assets.

Our subsidiary Kinder Morgan NatGas Operator LLC operates the Rockies Express and the Midcontinent Express natural gas pipeline systems pursuant to two separate operating agreements. It entered into the Rockies Express agreement in April 2008, and according to the provisions of the agreement, it is reimbursed for its costs and it receives a management fee of 1%, based on Rockies Express’ operating income, less all depreciation, depletion and amortization expenses. In 2010 and 2009, it received management fees of $5.4 million and $4.0 million, respectively. Kinder Morgan NatGas Operator LLC operates the Midcontinent Express pipeline system according to the provisions of an operating agreement entered into in March 2007. It is reimbursed for its operating costs; however, it receives no special management fees according to this agreement.

In addition, we purchase natural gas transportation and storage services from Natural Gas Pipeline Company of America LLC and certain affiliates, collectively referred to in this report as NGPL. KMI owns a 20% ownership interest in NGPL and accounts for its investment under the equity method of accounting. Pursuant to the provisions of a 15-year operating agreement that was entered into in 2008, KMI continues to operate NGPL’s assets. For each of the years 2010, 2009 and 2008, expenses related to NGPL totaled $7.8 million, $8.8 million and $8.1 million, respectively, and we included these expense amounts within the caption “Gas purchases and other costs of sales” in our accompanying consolidated statements of income.

158

CO2 Business Segment

During 2010, Kinder Morgan Power Company, a subsidiary of KMI, operated and maintained for us the power plant we constructed at the SACROC oil field unit, located in the Permian Basin area of West Texas. The power plant provides nearly half of SACROC’s current electricity needs. Pursuant to the contract, Kinder Morgan Power Company incurred the costs and expenses related to operating and maintaining the power plant for the production of electrical energy at the SACROC field. Such costs included supervisory personnel and qualified operating and maintenance personnel in sufficient numbers to accomplish the services provided in accordance with good engineering, operating and maintenance practices. Our subsidiary Kinder Morgan Production Company fully reimbursed Kinder Morgan Power Company’s expenses, including all agreed-upon labor costs.

In addition, Kinder Morgan Production Company was responsible for processing and directly paying invoices for fuels utilized by the plant. Other materials, including but not limited to lubrication oil, hydraulic oils, chemicals, ammonia and any catalyst were purchased by Kinder Morgan Power Company and invoiced monthly as provided by the contract, if not paid directly by Kinder Morgan Production Company. The amounts paid to Kinder Morgan Power Company in 2010, 2009 and 2008 for operating and maintaining the power plant were $7.6 million, $5.4 million and $3.1 million, respectively. Furthermore, we believe the amounts paid to Kinder Morgan Power Company for the services they provided each year fairly reflected the value of the services performed. Our operating contract with Kinder Morgan Power Company expired on December 31, 2010, and effective January 1, 2011, Kinder Morgan Production Company fully operates the power plant.

Terminals Business Segment

Mr. C. Berdon Lawrence, a non-management director on the boards of our general partner and KMR, is also Chairman of the Board of Kirby Corporation. For services in the ordinary course of Kirby Corporation’s and our Terminals segment’s businesses, Kirby Corporation received payments from our subsidiaries totaling $39,828, $18,878 and $430,835 in 2010, 2009 and 2008, respectively, and Kirby made payments, in 2008, to our subsidiaries totaling $144,300.

Subsequent Event

On February 9, 2011, we sold a marine vessel to Kirby Corporation’s subsidiary Kirby Inland Marine, L.P., and additionally, we and Kirby Inland Marine L.P. formed a joint venture named Greens Bayou Fleeting, LLC. For more information about these transactions, see Note 3 “Acquisitions and Divestitures—Divestiture Subsequent to December 31, 2010.”

Risk Management

Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. We also have exposure to interest rate risk as a result of the issuance of our fixed rate debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to these risks and protect our profit margins.

Our commodity-related risk management activities are monitored by our risk management committee, which is a separately designated standing committee whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Our risk management committee is charged with the review and enforcement of our management’s risk management policy. The committee is comprised of 18 executive-level employees of KMI or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of our businesses. The committee is chaired by our President and is charged with the following three responsibilities: (i) establish and review risk limits consistent with our risk tolerance philosophy; (ii) recommend to the audit committee of our general partner’s delegate any changes, modifications, or amendments to our risk management policy; and (iii) address and resolve any other high-level risk management issues.

For more information on our risk management activities see Note 13.

KM Insurance, Ltd.

KM Insurance, Ltd. is a Bermuda insurance company and wholly-owned subsidiary of KMI. KM Insurance, Ltd. was formed during the second quarter of 2005 as a Class 2 Bermuda insurance company, the sole business of which is to issue policies for KMI and us to secure the deductible portion of our workers compensation, automobile liability, and general liability policies placed in the commercial insurance market. We accrue for the cost of insurance and include these costs within our related party general and administrative expenses. For each of the years 2010, 2009 and 2008, these expenses totaled $8.6 million, $8.4 million and $7.6 million, respectively.

159

Derivative Counterparties

As a result of KMI’s going-private transaction in May 2007, a number of individuals and entities became significant investors in KMI, and by virtue of the size of its ownership interest in KMI, one of those investors—Goldman Sachs Capital Partners and certain of its affiliates—remains a “related party” (as that term is defined in authoritative accounting literature) to us as of December 31, 2010. Goldman Sachs has also acted in the past, and may act in the future, as an underwriter for equity and/or debt issuances for us, and Goldman Sachs effectively owned 49% of the terminal assets we acquired from US Development Group LLC in January 2010.

In addition, we conduct energy commodity risk management activities in the ordinary course of implementing our risk management strategies in which the counterparty to certain of our derivative transactions is an affiliate of Goldman Sachs, and in conjunction with these activities, we are a party (through one of our subsidiaries engaged in the production of crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs. The hedging facility requires us to provide certain periodic information, but does not require the posting of margin. As a result of changes in the market value of our derivative positions, we have created both amounts receivable from and payable to Goldman Sachs affiliates.

The following table summarizes the fair values of our energy commodity derivative contracts that are (i) associated with commodity price risk management activities with J. Aron & Company/Goldman Sachs; and (ii) included within “Fair value of derivative contracts” on our accompanying consolidated balance sheets as of December 31, 2010 and 2009 (in millions):

	December 31, 2010			December 31, 2009
Derivatives – asset/(liability)
Current assets	$	-		$	4.3
Noncurrent assets	$	12.7		$	18.4
Current liabilities	$	(221.4	)	$	(96.8	)
Noncurrent liabilities	$	(57.5	)	$	(190.8	)

Notes Receivable

Plantation Pipe Line Company

We have a long-term note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, our 51.17%-owned equity investee. The note provides for semiannual payments of principal and interest on June 30 and December 31 each year, with a final principal payment due July 20, 2011. We received principal repayment amounts of $2.7 million in 2010. As of December 31, 2010, the outstanding note receivable balance was $82.1 million, and we included this amount within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheet. As of December 31, 2009, the note receivable balance was $84.8 million, and we included $2.6 million within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet, and the remaining outstanding balance within “Notes receivable.”

Express US Holdings LP

In conjunction with the acquisition of our 33 1/3% equity ownership interest in the Express pipeline system from KMI on August 28, 2008, we acquired a long-term investment in a C$113.6 million debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system. The debenture is denominated in Canadian dollars, due in full on January 9, 2023, bears interest at the rate of 12.0% per annum, and provides for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year. As of December 31, 2010 and 2009, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $114.2 million and $108.1 million, respectively, and we included these amounts within “Notes receivable” on our accompanying consolidated balance sheets.

160

Other Receivables and Payables

As of December 31, 2010 and 2009, our related party receivables (other than notes receivable discussed above in “—Notes Receivable”) totaled $15.4 million and $13.8 million, respectively. The December 31, 2010 receivables amount consisted of (i) $8.2 million included within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet; and (ii) $7.2 million of natural gas imbalance receivables included within “Other current assets.” The $8.2 million amount primarily related to accounts and interest receivables due from (i) the Express pipeline system; (ii) NGPL; and (iii) Plantation Pipe Line Company. Our related party natural gas imbalance receivables consisted of amounts due from NGPL. The December 31, 2009 amount consisted of (i) $10.7 million included within “Accounts, notes and interest receivable, net” and primarily related to receivables due from the Express pipeline system and NGPL; and (ii) $3.1 million of natural gas imbalance receivables included within “Other current assets” and consisting primarily of amounts due from NGPL.

As of December 31, 2010 and 2009, our related party payables totaled $8.8 million and $13.4 million, respectively. The December 31, 2010 amount consisted of (i) $5.1 million included within “Accounts payable” and primarily related to amounts due to KMI; and (ii) $3.7 million of natural gas imbalance payables included within “Accrued other current liabilities” and consisting of amounts due to the Rockies Express pipeline system. The December 31, 2009 related party payable amounts are included within “Accounts payable” on our accompanying balance sheet, and primarily consisted of amounts we owed to KMI.

Other

Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders. Our general partner owns all of KMR’s voting securities and elects all of KMR’s directors. KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner, and the officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the owners of KMI. Accordingly, certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us.

The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty. The partnership agreements also provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. The duty of the officers of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The audit committee of KMR’s board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.

12. Commitments and Contingent Liabilities

Leases

The table below depicts future gross minimum rental commitments under our operating leases as of December 31, 2010 (in millions):

Year	Commitment
2011	$	43.5
2012		32.1
2013		23.1
2014		17.5
2015		13.2
Thereafter		25.9
Total minimum payments	$	155.3

The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to 38 years. We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $0.6 million. Total lease and rental expenses were $64.4 million for 2010, $55.6 million for 2009 and $61.7 million for 2008. The amount of capital leases included within “Property, Plant and Equipment, net” in our accompanying consolidated balance sheets as of December 31, 2010 and 2009 are not material to our consolidated balance sheets.

161

Directors’ Unit Appreciation Rights Plan

On April 1, 2003, KMR’s compensation committee established our Directors’ Unit Appreciation Rights Plan. Pursuant to this plan, and on this date of adoption, each of KMR’s then three non-employee directors was granted 7,500 common unit appreciation rights. In addition, 10,000 common unit appreciation rights were granted to each of KMR’s then three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors (discussed following); however, all unexercised awards made under the plan remain outstanding.

Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement. All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised.

In 2008, Mr. Hultquist exercised his remaining 10,000 unit appreciation rights at an aggregate fair value of $60.32 per unit, and he received a cash amount of $123,100. In 2009, Mr. Gaylord’s estate exercised his 17,500 unit appreciation rights at an aggregate fair value of $53.75 per unit, and it received a cash amount of $179,275 (Mr. Edward O. Gaylord served as a KMR director until his death on September 28, 2008). As of December 31, 2010, 17,500 unit appreciation rights had been granted, vested and remained outstanding.

Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors

On January 18, 2005, KMR’s compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan. The plan is administered by KMR’s compensation committee and KMR’s board has sole discretion to terminate the plan at any time. The primary purpose of this plan is to promote our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders’ interests. Further, since KMR’s success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR’s shareholders.

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

The elections under this plan for 2008 were made effective January 16, 2008. The elections for 2009 were made effective January 21, 2009 by Messrs. Hultquist and Waughtal, and January 28, 2009 by Mr. Lawrence. The elections for 2010 and 2011 were made effective January 20, 2010, and January 18, 2011, respectively.

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

162

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

On January 16, 2008, each of KMR’s then three non-employee directors was awarded cash compensation of $160,000 for board service during 2008; however, during a plan audit it was determined that each director was inadvertently paid an additional dividend in 2007. As a result, each director’s cash compensation for service during 2008 was adjusted downward to reflect this error. The correction results in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr. Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal. Effective January 16, 2008, two of the three non-employee directors elected to receive certain amounts of compensation in the form of our common units and each was issued common units pursuant to the plan and its agreements (based on the $55.81 closing market price of our common units on January 16, 2008, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive compensation of $84,831.20 in the form of our common units and was issued 1,520 common units; and Mr. Waughtal elected to receive compensation of $157,272.58 in the form of our common units and was issued 2,818 common units. All remaining cash compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00 to Mr. Hultquist) was paid to each of the non-employee directors as described above, and no other compensation was paid to the non-employee directors during 2008.

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

On January 20, 2010, each of KMR’s three non-employee directors was awarded cash compensation of $160,000 for board service during 2010. Effective January 20, 2010, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only. Mr. Lawrence elected to receive compensation of $159,495.00 in the form of our common units and was issued 2,450 common units. His remaining compensation ($505.00) was paid in cash as described above. No other compensation was paid to the non-employee directors during 2010.

On January 18, 2011, each of KMR’s three non-employee directors was awarded cash compensation of $180,000 for board service during 2011. Effective January 18, 2011, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only. Mr. Lawrence elected to receive compensation of $176,963.50 in the form of our common units and was issued 2,450 common units. His remaining compensation ($3,036.50) will be paid in cash as described above. No other compensation will be paid to the non-employee directors during 2011.

163

Contingent Debt

Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote. Most of these agreements are with entities that are not consolidated in our financial statements; however, we have invested in and hold equity ownership interests in these entities.

As of December 31, 2010, our contingent debt obligations with respect to these investments, as well as our obligations with respect to related letters of credit, are summarized below (dollars in millions):

Entity	Our Ownership Interest			Investment Type	Total Entity Debt			Our Contingent Share of Entity Debt		(a)
Fayetteville Express Pipeline LLC(b)		50	%	Limited Liability	$	940.0	(c)	$	470.0

Cortez Pipeline Company(d)		50	%	General Partner	$	142.4	(e)	$	87.3	(f)

Midcontinent Express Pipeline LLC(g)		50	%	Limited Liability	$	799.0	(h)	$	16.7	(i)

Nassau County, Florida Ocean Highway and Port Authority(j)		N/A		N/A		N/A		$	18.3	(k)

_________

(a)	Represents the portion of the entity’s debt that we may be responsible for if the entity cannot satisfy its obligations.
(b)	Fayetteville Express Pipeline LLC is a limited liability company and the owner of the Fayetteville Express natural gas pipeline system. The remaining limited liability company member interest in Fayetteville Express Pipeline LLC is owned by Energy Transfer Partners, L.P.
(c)	Amount represents borrowings under a $1.1 billion, unsecured revolving bank credit facility that is due May 11, 2012.
(d)	Cortez Pipeline Company is a Texas general partnership that owns and operates a common carrier carbon dioxide pipeline system. The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil Corporation, and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated.
(e)	Amount consists of (i) $32.1 million of fixed rate Series D notes due May 15, 2013 (interest on the Series D notes is paid annually and based on an average interest rate of 7.14% per annum); (ii) $100.0 million of variable rate Series E notes due December 11, 2012 (interest on the Series E notes is paid quarterly and based on an interest rate of three-month LIBOR plus a spread); and (iii) $10.3 million of outstanding borrowings under a $40.0 million committed revolving bank credit facility that is also due December 11, 2012.
(f)	We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt ($71.2 million). In addition, as of December 31, 2010, Shell Oil Company shares our several guaranty obligations jointly and severally for $32.1 million of Cortez’s debt balance related to the Series D notes; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty. Accordingly, as of December 31, 2010, we have a letter of credit in the amount of $16.1 million issued by JP Morgan Chase, in order to secure our indemnification obligations to Shell for 50% of the Cortez debt balance of $32.1 million related to the Series D notes. Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation. The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement.
(g)	Midcontinent Express Pipeline LLC is a limited liability company and the owner of the Midcontinent Express natural gas pipeline system. The remaining limited liability company member interests in Midcontinent Express Pipeline LLC are owned by Regency Energy Partners, L.P. and Energy Transfer Partners, L.P.
(h)	Amount consists of an aggregate carrying value of $799.0 million in fixed rate senior notes issued by Midcontinent Express Pipeline LLC in a private offering in September 2009. All payments of principal and interest in respect of these senior notes are the sole obligation of Midcontinent Express. Noteholders have no recourse against us or the other member owners of Midcontinent Express Pipeline LLC for any failure by Midcontinent Express to perform or comply with its obligations pursuant to the notes or the indenture.
(i)	As of December 31, 2010, Midcontinent Express had no outstanding borrowings under its $175.4 million, unsecured revolving bank credit facility that is due February 28, 2011. However, its credit facility can be used for the issuance of letters of credit to support the operation of its pipeline system, and as of December 31, 2010, a letter of credit having a face amount of $33.3 million was issued under the credit facility by the Bank of Tokyo-Mitsubishi UFJ, Ltd. Our contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).

(j)	Arose from our Vopak terminal acquisition in July 2001. Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida.
(k)	We have posted a letter of credit as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority. The bonds were issued for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. Our subsidiary, Nassau Terminals LLC is the operator of the marine port facilities. The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020. Principal payments on the bonds are made on the first of December each year, and corresponding reductions are made to the letter of credit. As of December 31, 2010, this letter of credit had a face amount of $18.3 million.

164

We also hold a 50% equity ownership interest in Rockies Express Pipeline LLC, a limited liability company and the owner of the Rockies Express natural gas pipeline system. Subsidiaries of Sempra Energy and ConocoPhillips own the remaining member interests, and pursuant to certain guaranty agreements remaining in effect on December 31, 2009, all three member owners of Rockies Express Pipeline LLC had agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Rockies Express Pipeline LLC, borrowings under its $2.0 billion five-year, unsecured revolving bank credit facility that is due April 28, 2011. On April 8, 2010, Rockies Express Pipeline LLC amended its bank credit facility to allow for borrowings up to $200 million (a reduction from $2.0 billion), and on this same date, each of its three member owners were released from their respective debt obligations under the previous guaranty agreements. Accordingly, we no longer have a contingent debt obligation with respect to Rockies Express Pipeline LLC.

We account for our investments in Fayetteville Express Pipeline LLC, Cortez Pipeline Company, and Midcontinent Express Pipeline LLC under the equity method of accounting. For the year ended December 31, 2010, our share of earnings, based on our ownership percentage and before amortization of excess investment cost, if any, was $22.5 million from Cortez Pipeline Company and $30.1 million from Midcontinent Express Pipeline LLC. We had no equity earnings from our investment in Fayetteville Express Pipeline LLC during 2010.

13. Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil. We also have exposure to interest rate risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.

Energy Commodity Price Risk Management

We are exposed to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil as a result of the forecasted purchase or sale of these products. Specifically, these risks are primarily associated with price volatility related to (i) pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas purchases; and (iii) natural gas system use and storage. Price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations.

Our principal use of energy commodity derivative contracts is to mitigate the risk associated with unfavorable market movements in the price of energy commodities. Our energy commodity derivative contracts act as a hedging (offset) mechanism against the volatility of energy commodity prices by allowing us to transfer this price risk to counterparties who are able and willing to bear it.

For derivative contracts that are designated and qualify as cash flow hedges pursuant to generally accepted accounting principles, the portion of the gain or loss on the derivative contract that is effective in offsetting the variable cash flows associated with the hedged forecasted transaction is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are commodity sales). The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), is recognized in earnings during the current period. The effectiveness of hedges using an option contract may be assessed based on changes in the option’s intrinsic value with the change in the time value of the contract being excluded from the assessment of hedge effectiveness. Changes in the excluded component of the change in an option’s time value are included currently in earnings. During 2010, we recognized a net gain of $5.3 million related to crude oil and natural gas hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing. During 2009, we recognized a net loss of $13.5 million from crude oil hedges that resulted from hedge ineffectiveness and amounts excluded from effectiveness testing.

165

Additionally, during each of the two years ended December 31, 2010 and 2009, we reclassified losses of $188.4 million and $100.3 million, respectively, from “Accumulated other comprehensive loss” into earnings. No material amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was probable that the original forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather, were reclassified as a result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchase actually occurred). The proceeds or payments resulting from the settlement of our cash flow hedges are reflected in the operating section of our statement of cash flows as changes to net income and working capital.

The “Accumulated other comprehensive loss” balance included in our Partners’ Capital was $186.4 million as of December 31, 2010, and $394.8 million as of December 31, 2009. These totals included “Accumulated other comprehensive loss” amounts associated with energy commodity price risk management activities of $307.1 million as of December 31, 2010 and $418.2 million as of December 31, 2009. Approximately $248.5 million of the total loss amount associated with energy commodity price risk management activities and included in our Partners’ Capital as of December 31, 2010 is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), and as of December 31, 2010, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2015.

As of December 31, 2010, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil	(23.2) million barrels
Natural gas fixed price	(19.0) billion cubic feet
Natural gas basis	(13.9) billion cubic feet
Derivatives not designated as hedging contracts
Natural gas basis	0.5 billion cubic feet

For derivative contracts that are not designated as a hedge for accounting purposes, all realized and unrealized gains and losses are recognized in the statement of income during the current period. These types of transactions include basis spreads, basis-only positions and gas daily swap positions. We primarily enter into these positions to economically hedge an exposure through a relationship that does not qualify for hedge accounting. Until settlement occurs, this will result in non-cash gains or losses being reported in our operating results.

Interest Rate Risk Management

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. We use interest rate swap agreements to manage the interest rate risk associated with the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve our desired mix of fixed and variable rate debt.

Since the fair value of fixed rate debt varies inversely with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest in order to convert the interest expense associated with certain of our senior notes from fixed rates to variable rates, resulting in future cash flows that vary with the market rate of interest. These swaps, therefore, hedge against changes in the fair value of our fixed rate debt that result from market interest rate changes. For derivative contracts that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings.

As of December 31, 2010 and 2009, we had a combined notional principal amount of $4,775 million and $5,200 million, respectively, of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2010, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through January 15, 2038.

166

In May 2010, we entered into three separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $400 million. Each agreement effectively converts a portion of the interest expense associated with our 5.30% senior notes due September 15, 2020 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread. In November 2010, we terminated five of our existing fixed-to-variable swap agreements in 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.

Fair Value of Derivative Contracts

The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” on our accompanying consolidated balance sheets. The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of December 31, 2010 and 2009 (in millions):

Fair Value of Derivative Contracts

		Asset derivatives				Liability derivatives
		December 31,		December 31,		December 31,			December 31,
		2010		2009		2010			2009
	Balance sheet location	Fair value		Fair value		Fair value			Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current	$	20.1	$	19.1	$	(275.9	)	$	(270.8	)
	Non-current		43.1		57.3		(103.0	)		(241.5	)
Subtotal			63.2		76.4		(378.9	)		(512.3	)

Interest rate swap agreements	Non-current		217.6		222.5		(69.2	)		(218.6	)
Total			280.8		298.9		(448.1	)		(730.9	)

Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current		3.9		1.7		(5.6	)		(1.2	)
Total			3.9		1.7		(5.6	)		(1.2	)

Total derivatives		$	284.7	$	300.6	$	(453.7	)	$	(732.1	)

____________

The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Value of interest rate swaps” on our accompanying consolidated balance sheets, which also includes any unamortized portion of proceeds received from the early termination of interest rate swap agreements. As of December 31, 2010 and 2009, this unamortized premium totaled $456.5 million and $328.6 million, respectively, and as of December 31, 2010, the weighted average amortization period for this premium was approximately 17.1 years.

Effect of Derivative Contracts on the Income Statement

The following three tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the years ended December 31, 2010 and 2009 (in millions):

Derivatives in fair value hedging relationships	Location of gain/(loss) recognized in income on derivative	Amount of gain/(loss) recognized in income on derivative(a)					Hedged items in fair value hedging relationships	Location of gain/(loss) recognized in income on related hedged item	Amount of gain/(loss) recognized in income on related hedged items(a)
		Year Ended December 31,							Year Ended December 31,
		2010		2009					2010			2009
Interest rate swap agreements	Interest, net – income/(expense)	$	302.0	$	(598.7	)	Fixed rate debt	Interest, net – income/(expense)	$	(302.0	)	$	598.7
Total		$	302.0	$	(598.7	)	Total		$	(302.0	)	$	598.7

____________

167

(a)

Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt which exactly offset each other as a result of no hedge ineffectiveness. Amounts do not reflect the impact on interest expense from the interest rate swap agreements under which we pay variable rate interest and receive fixed rate interest.

Derivatives in cash flow hedging relationships	Amount of gain/(loss) recognized in OCI on derivative (effective portion)								Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)								Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Year Ended December 31,									Year Ended December 31,									Year Ended December 31,
	2010				2009					2010				2009					2010			2009
Energy commodity derivative contracts		$	(76.1	)		$	(458.2	)	Revenues-natural gas sales		$	8.2			$	14.9		Revenues		$	5.3		$	(13.5	)
									Revenues-product sales and other			(211.3	)			(139.2	)
									Gas purchases and other costs of sales			14.7				24.0		Gas purchases and other costs of sales			-			-
Total		$	(76.1	)		$	(458.2	)	Total		$	(188.4	)		$	(100.3	)	Total		$	5.3		$	(13.5	)

____________

Derivatives not designated as hedging contracts	Location of gain/(loss) recognized in income on derivative	Amount of gain/(loss) recognized in income on derivative
		Year Ended December 31,
		2010		2009
Energy commodity derivative contracts	Gas purchases and other costs of sales	$	2.3	$	(4.2	)
Total		$	2.3	$	(4.2	)

Credit Risks

We have counterparty credit risk as a result of our use of financial derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings); (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

Our over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

The maximum potential exposure to credit losses on our derivative contracts as of December 31, 2010 was (in millions):

	Asset position
Interest rate swap agreements	$	217.6
Energy commodity derivative contracts		67.1
Gross exposure		284.7
Netting agreement impact		(58.8	)
Net exposure	$	225.9

168

In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2010, we had no outstanding letters of credit supporting our hedging activities; however, as of December 31, 2009, we had outstanding letters of credit totaling $55.0 million in support of our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.

Additionally, as of December 31, 2010, our counterparties associated with our energy commodity contract positions and over-the–counter swap agreements had margin deposits with us totaling $2.4 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet. As of December 31, 2009, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $15.2 million, and we reported this amount as “Restricted deposits” in our accompanying consolidated balance sheet.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating. Based on contractual provisions as of December 31, 2010, we estimate that if our credit rating was downgraded, we would have the following additional collateral obligations (in millions):

Credit ratings downgraded (a)	Incremental obligations		Cumulative obligations(b)
One notch to BBB-/Baa3	$	-	$	-

Two notches to below BBB-/Baa3 (below investment grade)	$	65.2	$	65.2

_________

(a)	If there are split ratings among the independent credit rating agencies, most counterparties use the higher credit rating to determine our incremental collateral obligations, while the remaining use the lower credit rating. Therefore, a two notch downgrade to below BBB-/Baa3 by one agency would not trigger the entire $65.2 million incremental obligation.
(b)	Includes current posting at current rating.

14. Fair Value

The Codification emphasizes that fair value is a market-based measurement that should be determined based on assumptions (inputs) that market participants would use in pricing an asset or liability. Inputs may be observable or unobservable, and valuation techniques used to measure fair value should maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Accordingly, the Codification establishes a hierarchal disclosure framework that ranks the quality and reliability of information used to determine fair values. The hierarchy is associated with the level of pricing observability utilized in measuring fair value and defines three levels of inputs to the fair value measurement process—quoted prices are the most reliable valuation inputs, whereas model values that include inputs based on unobservable data are the least reliable. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.

The three broad levels of inputs defined by the fair value hierarchy are as follows:

▪

Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

▪

Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

▪

Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

169

Fair Value of Derivative Contracts

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of December 31, 2010 and 2009, based on the three levels established by the Codification (in millions). The fair value measurements as of December 31, 2009 in the two tables below do not include our cash margin deposits of $15.2 million, which are reported separately as “Restricted deposits” in our accompanying consolidated balance sheet.

	Asset fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
As of December 31, 2010
Energy commodity derivative contracts(a)	$	67.1	$	-	$	23.5	$	43.6
Interest rate swap agreements	$	217.6	$	-	$	217.6	$	-

As of December 31, 2009
Energy commodity derivative contracts(a)	$	78.1	$	-	$	14.4	$	63.7
Interest rate swap agreements	$	222.5	$	-	$	222.5	$	-

____________

	Liability fair value measurements using
	Total			Quoted prices in active markets for identical liabilities (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
As of December 31, 2010
Energy commodity derivative contracts(b)	$	(384.5	)	$	-	$	(359.7	)	$	(24.8	)
Interest rate swap agreements	$	(69.2	)	$	-	$	(69.2	)	$	-

As of December 31, 2009
Energy commodity derivative contracts(b)	$	(513.5	)	$	-	$	(462.8	)	$	(50.7	)
Interest rate swap agreements	$	(218.6	)	$	-	$	(218.6	)	$	-

____________

(a)	Level 2 consists primarily of OTC natural gas hedges that are settled on NYMEX. Level 3 consists primarily of natural gas options and West Texas Intermediate options.
(b)	Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX. Level 3 consists primarily of natural gas basis swaps and West Texas Intermediate options.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the years ended December 31, 2010 and 2009 (in millions):

Significant unobservable inputs (Level 3)

	Year Ended December 31,
	2010			2009
Derivatives-net asset (liability)
Beginning of period	$	13.0		$	44.1
Realized and unrealized net gains (losses)		1.7			(48.4	)
Purchases and settlements		4.1			17.3
Transfers in (out) of Level 3		-			-
End of period	$	18.8		$	13.0

Change in unrealized net losses relating to contracts still held at end of period	$	(10.7	)	$	(42.1	)

170

Fair Value of Financial Instruments

Fair value as used in the disclosure of financial instruments represents the amount at which an instrument could be exchanged in a current transaction between willing parties. As of each reporting date, the estimated fair value of our outstanding publicly-traded debt is based upon quoted market prices, if available, and for all other debt, fair value is based upon prevailing interest rates currently available to us. In addition, we adjust (discount) the fair value measurement of our long-term debt for the effect of credit risk.

The estimated fair value of our outstanding debt balance as of December 31, 2010 and 2009 (both short-term and long-term, but excluding the value of interest rate swaps), is disclosed below (in millions):

	December 31, 2010				December 31, 2009
	Carrying Value		Estimated fair value		Carrying Value		Estimated fair value
Total debt	$	11,539.8	$	12,443.4	$	10,592.4	$	11,265.7

15. Reportable Segments

We divide our operations into five reportable business segments. These segments and their principal source of revenues are as follows:

▪

Products Pipelines— the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids;

▪

Natural Gas Pipelines—the sale, transport, processing, treating, storage and gathering of natural gas;

▪

CO2—the production and sale of crude oil from fields in the Permian Basin of West Texas and the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields;

▪

Terminals—the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals; and

▪

Kinder Morgan Canada—the transportation of crude oil and refined products 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.

We evaluate performance principally based on each segments’ earnings before depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income, and unallocable income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are based on the way our chief operating decision maker organizes the operations within our enterprise for assessing performance and allocating resources. Each segment is managed separately because each segment involves different products and marketing strategies.

171

Financial information by segment follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Revenues
Products Pipelines
Revenues from external customers	$	883.0		$	826.6		$	815.9
Intersegment revenues		-			-			-
Natural Gas Pipelines
Revenues from external customers		4,416.5			3,806.9			8,422.0
Intersegment revenues		-			-			-
CO2
Revenues from external customers		1,245.7			1,035.7			1,133.0
Intersegment revenues		-			-			-
Terminals
Revenues from external customers		1,264.0			1,108.1			1,172.7
Intersegment revenues		1.1			0.9			0.9
Kinder Morgan Canada
Revenues from external customers		268.5			226.1			196.7
Intersegment revenues		-			-			-
Total segment revenues		8,078.8			7,004.3			11,741.2
Less: Total intersegment revenues		(1.1	)		(0.9	)		(0.9	)
Total consolidated revenues	$	8,077.7		$	7,003.4		$	11,740.3

Operating expenses(a)
Products Pipelines	$	414.6		$	269.5		$	291.0
Natural Gas Pipelines		3,750.3			3,193.0			7,804.0
CO2		308.1			271.1			391.8
Terminals		629.2			536.8			631.8
Kinder Morgan Canada		91.6			72.5			67.9
Total segment operating expenses		5,193.8			4,342.9			9,186.5
Less: Total intersegment operating expenses		(1.1	)		(0.9	)		(0.9	)
Total consolidated operating expenses	$	5,192.7		$	4,342.0		$	9,185.6

Other expense (income)
Products Pipelines	$	4.2		$	0.6		$	1.3
Natural Gas Pipelines		-			(7.8	)		(2.7	)
CO2		-			-			-
Terminals		(4.3	)		(27.6	)		2.7
Kinder Morgan Canada		-			-			-
Total segment Other expense (income)		(0.1	)		(34.8	)		1.3
Less: Discontinued operations(b)		-			-			1.3
Total consolidated Other expense (income)	$	(0.1	)	$	(34.8	)	$	2.6

Depreciation, depletion and amortization
Products Pipelines	$	100.7	$	94.1	$	89.4
Natural Gas Pipelines		124.2		93.4		68.5
CO2		452.9		487.9		385.8
Terminals		184.1		136.9		122.6
Kinder Morgan Canada		42.9		38.5		36.4
Total consol. depreciation, depletion and amortization	$	904.8	$	850.8	$	702.7

Earnings from equity investments
Products Pipelines	$	33.1		$	29.0		$	24.4
Natural Gas Pipelines		169.1			141.8			113.4
CO2		22.5			22.3			20.7
Terminals		1.7			0.7			2.7
Kinder Morgan Canada		(3.3	)		(4.1	)		(0.4	)
Total consolidated equity earnings.	$	223.1		$	189.7		$	160.8

172

	Year Ended December 31,
	2010		2009		2008
Amortization of excess cost of equity investments
Products Pipelines	$	3.4	$	3.4	$	3.3
Natural Gas Pipelines		0.4		0.4		0.4
CO2		2.0		2.0		2.0
Terminals		-		-		-
Kinder Morgan Canada		-		-		-
Total consol. amortization of excess cost of equity investments	$	5.8	$	5.8	$	5.7

Interest income
Products Pipelines	$	4.0	$	4.1	$	4.3
Natural Gas Pipelines		2.3		6.2		1.2
CO2		2.0		-		-
Terminals		-		-		-
Kinder Morgan Canada		13.2		12.0		3.9
Total segment interest income		21.5		22.3		9.4
Unallocated interest income		1.2		0.2		0.6
Total consolidated interest income	$	22.7	$	22.5	$	10.0

Other, net-income (expense)
Products Pipelines	$	12.4	$	8.3	$	(2.3	)
Natural Gas Pipelines		2.0		25.6		28.0
CO2		2.5		-		1.9
Terminals		4.7		3.7		1.7
Kinder Morgan Canada		2.6		11.9		(10.1	)
Total consolidated other, net-income (expense)	$	24.2	$	49.5	$	19.2

Income tax benefit (expense)
Products Pipelines	$	(9.2	)	$	(13.4	)	$	(3.8	)
Natural Gas Pipelines		(3.3	)		(5.7	)		(2.7	)
CO2		0.9			(4.0	)		(3.9	)
Terminals		(5.3	)		(5.2	)		(19.7	)
Kinder Morgan Canada		(7.8	)		(18.9	)		19.0
Total segment income tax benefit (expense)		(24.7	)		(47.2	)		(11.1	)
Unallocated income tax benefit (expense)		(9.9	)		(8.5	)		(9.3	)
Total consolidated income tax benefit (expense)	$	(34.6	)	$	(55.7	)	$	(20.4	)

Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(c)
Products Pipelines	$	504.5		$	584.5		$	546.2
Natural Gas Pipelines		836.3			789.6			760.6
CO2		965.5			782.9			759.9
Terminals		641.3			599.0			523.8
Kinder Morgan Canada		181.6			154.5			141.2
Total segment earnings before DD&A		3,129.2			2,910.5			2,731.7
Total segment depreciation, depletion and amortization		(904.8	)		(850.8	)		(702.7	)
Total segment amortization of excess cost of equity investments.		(5.8	)		(5.8	)		(5.7	)
General and administrative expenses		(375.2	)		(330.3	)		(297.9	)
Unallocable interest expense, net of interest income		(506.4	)		(431.3	)		(397.6	)
Unallocable income tax expense		(9.9	)		(8.5	)		(9.3	)
Total consolidated net income	$	1,327.1		$	1,283.8		$	1,318.5

173

	Year Ended December 31,
	2010		2009		2008
Capital expenditures(d)
Products Pipelines	$	144.2	$	199.8	$	221.7
Natural Gas Pipelines		135.4		372.0		946.5
CO2		372.8		341.8		542.6
Terminals		326.3		378.2		454.1
Kinder Morgan Canada		22.2		32.0		368.1
Total consolidated capital expenditures	$	1,000.9	$	1,323.8	$	2,533.0

Investments at December 31
Products Pipelines	$	215.6	$	203.7	$	202.6
Natural Gas Pipelines		3,563.3		2,542.9		654.0
CO2		9.9		11.2		13.6
Terminals		27.4		18.7		18.6
Kinder Morgan Canada		69.8		68.7		65.5
Total consolidated investments	$	3,886.0	$	2,845.2	$	954.3

Assets at December 31
Products Pipelines	$	4,369.1	$	4,299.0	$	4,183.0
Natural Gas Pipelines		8,809.7		7,772.7		5,535.9
CO2		2,141.2		2,224.5		2,339.9
Terminals		4,138.6		3,636.6		3,347.6
Kinder Morgan Canada		1,870.0		1,797.7		1,583.9
Total segment assets		21,328.6		19,730.5		16,990.3
Corporate assets(e)		532.5		531.7		895.5
Total consolidated assets	$	21,861.1	$	20,262.2	$	17,885.8

____________

(a)	Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes.
(b)	As discussed in Note 3, due to the October 2007 sale of our North System, we accounted for the North System business as a discontinued operation. In 2008, we recorded incremental gain adjustments of $1.3 million related to our sale of the North System, and consistent with the management approach of identifying and reporting discrete financial information on operating segments, we have included this gain within our Products Pipelines business segment disclosures for 2008. Except for this gain adjustment on our disposal of the North System, we recorded no other financial results from the operations of the North System during 2008.
(c)	Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(d)	Sustaining capital expenditures, including our share of the sustaining capital expenditures of the following four joint ventures: Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, KinderHawk Field Services LLC and Cypress Interstate Pipeline LLC, totaled $179.2 million in 2010, $172.2 million in 2009 and $180.6 million in 2008. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.
(e)	Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to the fair value of interest rate swaps.

174

We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2010, 2009 and 2008, we reported total consolidated interest expense of $507.6 million, $431.5 million and $398.2 million, respectively.

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

	Year Ended December 31,
	2010		2009		2008
Revenues from external customers
United States	$	7,701.7	$	6,680.5	$	11,452.0
Canada		356.5		301.9		267.0
Mexico and other(a)		19.5		21.0		21.3
Total consolidated revenues from external customers.	$	8,077.7	$	7,003.4	$	11,740.3

Long-lived assets at December 31(b)	2010		2009		2008
United States	$	16,929.5	$	15,556.6	$	13,563.2
Canada		1,908.5		1,813.6		1,547.6
Mexico and other(a)		86.4		89.1		87.8
Total consolidated long-lived assets	$	18,924.4	$	17,459.3	$	15,198.6

____________

(a)	Includes operations in Mexico and the Netherlands.
(b)	Long-lived assets exclude (i) goodwill; (ii) other intangibles, net; and (iii) long-term note receivables from related parties.

175

16. Litigation, Environmental and Other Contingencies

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during 2010. This note also contains a description of any material legal proceedings that were initiated against us during 2010, and a description of any material events occurring subsequent to December 31, 2010 but before the filing of this report.

In this note, we refer to our subsidiary SFPP, L.P. as SFPP; our subsidiary Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; BP West Coast Products, LLC as BP; ConocoPhillips Company as ConocoPhillips; Tesoro Refining and Marketing Company as Tesoro; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; ExxonMobil Oil Corporation as ExxonMobil; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airlines; our subsidiary Kinder Morgan CO2 Company, L.P. (the successor to Shell CO2 Company, Ltd.) as Kinder Morgan CO2; the United States Court of Appeals for the District of Columbia Circuit as the D.C. Circuit; the Federal Energy Regulatory Commission as the FERC; the California Public Utilities Commission as the CPUC; the United States Department of the Interior, Minerals Management Service as the MMS; the Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company) as UPRR; the Texas Commission of Environmental Quality as the TCEQ; The Premcor Refining Group, Inc. as Premcor; Port Arthur Coker Company as PACC; our subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; our subsidiary Kinder Morgan Liquids Terminals LLC as KMLT; Rockies Express Pipeline LLC as Rockies Express; and Plantation Pipe Line Company as Plantation. “OR” dockets designate complaint proceedings, and “IS” dockets designate protest proceedings.

Federal Energy Regulatory Commission Proceedings

The tariffs and rates charged by SFPP and Calnev are subject to numerous ongoing proceedings at the FERC, including the shippers' complaints and protests regarding interstate rates on the pipeline systems listed below. These complaints and protests have been filed over numerous years beginning in 1992 through and including 2009. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable. If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach up to two years prior to the filing of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.

As to SFPP, the issues involved in these proceedings include, among others: (i) whether certain of our Pacific operations’ rates are “grandfathered” under the Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) whether indexed rate increases are justified; and (iv) the appropriate level of return and income tax allowance we may include in our rates. The issues involving Calnev are similar.

SFPP

As a result of FERC’s approval in May 2010 of a settlement agreement with eleven of twelve shipper litigants, a wide range of rate challenges dating back to 1992 were resolved (Historical Cases Settlement). The Historical Cases Settlement resolved all but two of the cases outstanding between SFPP and the eleven shippers, and SFPP does not expect any material adverse impacts from the remaining two unsettled cases with the eleven shippers.

The Historical Cases Settlement and other legal reserves related to SFPP rate litigation resulted in a $158.0 million charge to earnings in the first quarter of 2010, and in June 2010, we made settlement payments of $206.3 million to the eleven shippers. However, because a portion of our partnership distributions for the second quarter of 2010 (which we paid in August 2010) was a distribution of cash from interim capital transactions (rather than a distribution of cash from operations) our general partner’s cash distributions for the second quarter of 2010 were reduced by $170.0 million. We expect that our second quarter 2010 interim capital transaction distribution will allow us to resolve our remaining FERC rate cases (discussed above) and CPUC rate cases (discussed below) without impacting future distributions, and due to the support of our general partner, we still distributed $4.40 in distributions per unit to our limited partners for 2010.

Furthermore, (i) our declared cash distributions for both the third and fourth quarters of 2010 contain no distributions of cash from interim capital transactions, but instead consist entirely of distributions of cash from operations; and (ii) we recognized a $14.0 million increase in expense in December 2010 associated with overall adjustments to our rate case liabilities. For more information on our partnership distributions, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions.”

Chevron is the only shipper who was not a party to the Historical Cases Settlement. In December 2010, an agreement in principle was reached with Chevron, and in February 2011, an uncontested settlement was filed at the FERC which the chief judge certified to the FERC. The FERC has not yet acted on the certified settlement. Upon approval by the FERC, the settlement will resolve the following dockets now pending only as to Chevron:

▪

FERC Docket Nos. OR92-8, et al. (West and East Line Rates)—Chevron protests of compliance filings pending with FERC and appeals pending at the D.C. Circuit;

▪

FERC Docket Nos. OR96-2, et al. (All SFPP Rates)—Chevron (as a successor-in-interest to Texaco) protests of compliance filings pending with FERC;

▪

FERC Docket No. OR02-4 (All SFPP Rates)—Chevron appeal of complaint dismissal pending at the D.C. Circuit;

▪

FERC Docket No. OR03-5 (West, East, North, and Oregon Line Rates)—Chevron exceptions to initial decision pending at FERC;

▪

FERC Docket No. OR07-4 (All SFPP Rates)—Chevron complaint held in abeyance;

▪

FERC Docket No. OR09-8 (consolidated) (2008 Index Increases)—Hearing regarding Chevron complaint held in abeyance pending settlement discussions;

▪

FERC Docket No. IS98-1 (Sepulveda Line Rates)—Chevron protests to compliance filing pending at FERC;

▪

FERC Docket No. IS05-230 (North Line Rates)—Chevron exceptions to initial decision pending at FERC;

▪

FERC Docket No. IS07-116 (Sepulveda Line Rates)—Chevron protest subject to resolution of IS98-1 proceeding;

▪

FERC Docket No. IS08-137 (West and East Line Rates)—Chevron protest subject to resolution of the OR92-8/OR96-2 proceeding;

▪

FERC Docket No. IS08-302 (2008 Index Rate Increases)—Chevron protest subject to the resolution of proceedings regarding the West, North and Sepulveda Lines; and

▪

FERC Docket No. IS09-375 (2009 Index Rate Increases)—Chevron protest subject to resolution of proceedings regarding the North, West and Sepulveda Lines.

176

The following dockets, which pertain to all protesting shippers, are either pending or recently resolved, as noted below:

▪

FERC Docket No. IS08-390 (West Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the Airlines—Status: FERC order issued on February 17, 2011. While the order made certain findings that were adverse to SFPP, it ruled in favor of SFPP on many significant issues. SFPP will file a rehearing request on certain adverse findings. It is not possible to predict the outcome of the FERC review of the rehearing request or appellate review of this order; and

▪

FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero, Chevron, Western Refining, and Southwest Airlines—Status: Initial decision issued on February 10, 2011. A FERC administrative law judge generally made findings adverse to SFPP, found that East Line rates should have been lower, and recommended that SFPP pay refunds for alleged over-collections. SFPP will file a brief with the FERC taking exception to these and other portions of the initial decision. The FERC will review the initial decision, and while the initial decision is inconsistent with a number of the issues ruled on in FERC’s February 17, 2011 Order on IS08-390, it is not possible to predict the outcome of FERC or appellate review.

Calnev

▪

FERC Docket Nos. OR07-7, OR07-18, OR07-19 & OR07-22 (not consolidated) (Calnev Rates)—Complainants: Tesoro, Airlines, BP, Chevron, ConocoPhillips and Valero Marketing—Status: Complaint amendments pending before FERC;

▪

FERC Docket No. IS09-377 (2009 Index Rate Increases)—Protestants: BP, Chevron, and Tesoro—Status: Requests for rehearing of FERC dismissal pending before FERC;

▪

FERC Docket Nos. OR09-11/OR09-14 (not consolidated) (2007 and 2008 Page 700 Audit Request)—Complainants: BP/Tesoro—Status: BP petition for review at D.C. Circuit dismissed, mandate issued in June 2010;

▪

FERC Docket Nos. OR09-15/OR09-20 (not consolidated) (Calnev Rates)—Complainants: Tesoro/BP—Status: Complaints pending at FERC; and

▪

FERC Docket Nos. OR09-18/OR09-22 (not consolidated) (2009 Index Increases)—Complainants: Tesoro/BP—Status: BP petition for review at D.C. Circuit dismissed, mandate issued in June 2010.

Trailblazer Pipeline Company LLC

On July 7, 2010, our subsidiary Trailblazer Pipeline Company LLC refunded a total of approximately $0.7 million to natural gas shippers covering the period January 1, 2010 through May 31, 2010 as part of a settlement reached with shippers to eliminate the December 1, 2009 rate filing obligation contained in its Docket No. RP03-162 rate case settlement. As part of the agreement with shippers, Trailblazer commenced billing reduced tariff rates as of June 1, 2010 with an additional reduction in tariff rates to take effect January 1, 2011.

Kinder Morgan Interstate Gas Transmission LLC Section 5 Proceeding

On November 18, 2010, our subsidiary Kinder Morgan Interstate Gas Transmission LLC (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 rates, which were approved by the FERC in KMIGT’s last transportation rate case settlement, remain just and reasonable. The FERC made no findings in its order as to what would constitute just and reasonable rates or a reasonable return for KMIGT. A proceeding under Section 5 of the Natural Gas Act is prospective in nature and any potential change in rates charged customers by KMIGT can only occur after the FERC has issued a final order. Prior to that, an Administrative Law Judge will preside over an evidentiary hearing and make an initial decision (which the FERC has directed to be issued within 47 weeks). The final FERC decision will be based on the record developed before the Administrative Law Judge. We do not believe that this investigation will have a material adverse impact on us.

California Public Utilities Commission Proceedings

SFPP has previously reported ratemaking and complaint proceedings pending with the CPUC. The ratemaking and complaint cases generally involve challenges to rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and request prospective rate adjustments and refunds with respect to tariffed and previously untariffed charges for certain pipeline transportation and related services. These matters have been consolidated and assigned to two administrative law judges.

177

On April 6, 2010, a CPUC administrative law judge issued a proposed decision in several intrastate rate cases involving SFPP and a number of its shippers. The proposed decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance and allocation of environmental expenses, that we believe are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines. Moreover, the proposed decision orders refunds relating to these issues where the underlying rates were previously deemed reasonable by the CPUC, which we believe to be contrary to California law. Based on our review of these CPUC proceedings, we estimate that our maximum exposure is approximately $220 million in reparation and refund payments and if the determinations made in the proposed decision were applied prospectively in two pending cases this could result in approximately $30 million in annual rate reductions.

The proposed decision is advisory in nature and can be rejected, accepted or modified by the CPUC. SFPP filed comments on May 3, 2010 outlining what it believes to be the errors in law and fact within the proposed decision, and on May 5, 2010, SFPP made oral arguments before the full CPUC. The matter remains pending before the CPUC, which may act at any time at its scheduled bimonthly meetings. Further procedural steps, including motions for rehearing and writ of review to California’s Court of Appeals, will be taken if warranted. We do not expect the final resolution of this matter to have an impact on our expected distributions to our limited partners for 2011.

Carbon Dioxide Litigation

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

Kinder Morgan CO2, Kinder Morgan Energy Partners, L.P. and Cortez Pipeline Company are among the defendants in a proceeding in the federal courts for the Southern District of Texas, Gerald O. Bailey et al. v. Shell Oil Company et al. (Civil Action Nos. 05-1029 and 05-1829 in the U.S. District Court for the Southern District of Texas—consolidated by Order dated July 18, 2005). The plaintiffs assert claims for the underpayment of royalties on carbon dioxide produced from the McElmo Dome unit, located in southwestern Colorado. The plaintiffs assert claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of contract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account. Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray & Co. also assert claims as private relators under the False Claims Act, claims on behalf of the State of Colorado and Montezuma County, Colorado, and claims for violation of federal and Colorado antitrust laws. The plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The defendants filed motions for summary judgment on all claims.

On April 22, 2008, the federal district court granted defendants’ motions for summary judgment and ruled that plaintiffs Bailey and Ptasynski take nothing on their claims, and that the claims of Gray be dismissed with prejudice. The court entered final judgment in favor of the defendants on April 30, 2008. The plaintiffs appealed to the United States Fifth Circuit Court of Appeals. On June 16, 2010, the Fifth Circuit Court of Appeals affirmed the trial court’s summary judgment decision. On October 18, 2010, the U.S. Supreme Court denied Gerald Bailey’s petition for writ of certiorari to the U.S. Supreme Court seeking further appellate review of the Fifth Circuit Court of Appeals’ decision.

CO2 Claims Arbitration

Kinder Morgan CO2 and Cortez Pipeline Company were among the named defendants in CO2 Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The arbitration arose from a dispute over a class action settlement agreement which became final on July 7, 2003 and disposed of five lawsuits formerly pending in the U.S. District Court, District of Colorado. The plaintiffs in such lawsuits primarily included overriding royalty interest owners, royalty interest owners, and small share working interest owners who alleged underpayment of royalties and other payments on carbon dioxide produced from the McElmo Dome unit.

The settlement imposed certain future obligations on the defendants in the underlying litigation. The plaintiffs in the arbitration alleged that, in calculating royalty and other payments, defendants used a transportation expense in excess of what is allowed by the settlement agreement, thereby causing alleged underpayments of approximately $12 million. The plaintiffs also alleged that Cortez Pipeline Company should have used certain funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.5 million. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. On June 21, 2007, the New Mexico federal district court entered final judgment confirming the August 7, 2006 arbitration decision.

On October 2, 2007, the plaintiffs initiated a second arbitration (CO2 Committee, Inc. v. Shell CO2 Company, Ltd., aka Kinder Morgan CO2 Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and an ExxonMobil entity. The second arbitration asserts claims similar to those asserted in the first arbitration. A second arbitration panel has convened and a final hearing on the parties’ claims and defenses is expected to occur in 2011.

178

MMS Notice of Noncompliance and Civil Penalty

On December 20, 2006, Kinder Morgan CO2 received from the MMS a “Notice of Noncompliance and Civil Penalty: Knowing or Willful Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO2 Company, L.P., case no. CP07-001.” This Notice, and the MMS’s position that Kinder Morgan CO2 has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO2 concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties.

The Notice of Noncompliance and Civil Penalty assessed a civil penalty of approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for each of 17 alleged violations) for Kinder Morgan CO2’s alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO2 produced at McElmo Dome, during the period from June 2005 through October 2006. The MMS stated that civil penalties would continue to accrue at the same rate until the alleged violations are corrected.

On January 3, 2007, Kinder Morgan CO2 appealed the Notice of Noncompliance and Civil Penalty to the Office of Hearings and Appeals of the Department of the Interior.

In July 2008, the parties reached a settlement in principle of the Notice of Noncompliance and Civil Penalty, subject to final approval by the MMS and the Department of the Interior. On September 8, 2010, the United States Department of the Interior, Bureau of Ocean Energy Management, Regulation, and Enforcement (formerly known as the MMS) approved the settlement, which is now final.

MMS Orders to Report and Pay

On March 20, 2007, Kinder Morgan CO2 received an Order to Report and Pay from the MMS. The MMS contends that Kinder Morgan CO2 over-reported transportation allowances and underpaid royalties in the amount of approximately $4.6 million for the period from January 1, 2005 through December 31, 2006 as a result of its use of the Cortez Pipeline tariff as the transportation allowance in calculating federal royalties. The MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO2 must use its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations.

Kinder Morgan CO2 submitted a notice of appeal in response to the Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 C.F.R. sec. 290.100, et seq.

In addition to the March 2007 Order to Report and Pay, the MMS issued a second Order to Report and Pay in August 2007, in which the MMS claims that Kinder Morgan CO2 over-reported transportation allowances and underpaid royalties (due to the use of the Cortez Pipeline tariff as the transportation allowance for purposes of federal royalties) in the amount of approximately $8.5 million for the period from April 2000 through December 2004. Kinder Morgan CO2 filed its notice of appeal and statement of reasons in response to the second Order in September 2007, challenging the Order and appealing it to the Director of the MMS.

In July 2008, the parties reached a settlement in principle of the March 2007 and August 2007 Orders to Report and Pay, subject to final approval by the MMS and the Department of the Interior. On September 8, 2010, the United States Department of the Interior, Bureau of Ocean Energy Management, Regulation, and Enforcement (formerly known as the MMS) approved the settlement, which is now final.

Colorado Severance Tax Assessment

On September 16, 2009, the Colorado Department of Revenue issued three Notices of Deficiency to Kinder Morgan CO2. The Notices of Deficiency assessed additional state severance tax against Kinder Morgan CO2 with respect to carbon dioxide produced from the McElmo Dome unit for tax years 2005, 2006, and 2007. The total amount of tax assessed was $5.7 million, plus interest of $1.0 million, plus penalties of $1.7 million. Kinder Morgan CO2 protested the Notices of Deficiency and paid the tax and interest under protest. Kinder Morgan CO2 is now awaiting the Colorado Department of Revenue’s response to the protest.

179

Montezuma County, Colorado Property Tax Assessment

In November of 2009, the County Treasurer of Montezuma County, Colorado, issued to Kinder Morgan CO2, as operator of the McElmo Dome unit, retroactive tax bills for tax year 2008, in the amount of $2 million. Of this amount, 37.2% is attributable to Kinder Morgan CO2’s interest. The retroactive tax bills were based on the assertion that a portion of the actual value of the carbon dioxide produced from the McElmo Dome unit was omitted from the 2008 tax roll due to an alleged over statement of transportation and other expenses used to calculate the net taxable value. Kinder Morgan CO2 paid the retroactive tax bills under protest and will file petitions for refunds of the taxes paid under protest and will vigorously contest Montezuma County’s position.

Other

In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO2’s payments on carbon dioxide produced from the McElmo Dome and Bravo Dome units are currently ongoing. These audits and inquiries involve federal agencies, the states of Colorado and New Mexico, and county taxing authorities in the state of Colorado.

Commercial Litigation Matters

Union Pacific Railroad Company Easements

SFPP and UPRR are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In February 2007, a trial began to determine the amount payable for easements on UPRR rights-of-way. The trial is ongoing and is expected to conclude by the end of the first quarter of 2011.

SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP appealed this decision, and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards in determining when relocations are necessary and in completing relocations. Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations.

Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the expense (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position and results of operations. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.

Severstal Sparrows Point Crane Collapse

On June 4, 2008, a bridge crane owned by Severstal Sparrows Point, LLC and located in Sparrows Point, Maryland collapsed while being operated by KMBT. According to our investigation, the collapse was caused by unexpected, sudden and extreme winds. On June 24, 2009, Severstal filed suit against KMBT in the United States District Court for the District of Maryland, cause no. WMN 09CV1668. Severstal alleges that KMBT was contractually obligated to replace the collapsed crane and that its employees were negligent in failing to properly secure the crane prior to the collapse. Severstal seeks unspecified damages for value of the crane and lost profits. KMBT denies each of Severstal’s allegations.

JR Nicholls Tug Incident

On February 10, 2010, the JR Nicholls, a tugboat operated by one of our subsidiaries, overturned and sank in the Houston Ship Channel. Five employees were on board and four were rescued, treated and released from a local hospital. The fifth employee died in the incident. The U.S. Coast Guard shut down a section of the ship channel for approximately 60 hours. Approximately 2,200 gallons of diesel fuel was released from the tugboat. Emergency response crews deployed booms and contained the product, which is substantially cleaned up. Salvage operations were commenced and the tugboat has been recovered. A full investigation of the incident is underway. Our subsidiary J.R. Nicholls LLC filed a limitations action entitled In the Matter of the Complaint of J.R. Nicholls LLC as Owner of the M/V J.R. NICHOLLS For Exoneration From or Limitation of Liability, CA No. 4:10-CV-00449, U.S. District Court, S.D. Tex. To date, three surviving crew members have filed claims in that action for personal injuries and emotional distress. On September 15, 2010, our subsidiary KM Ship Channel Services LLC, agreed to pay a civil penalty of $7,500 to the United States Coast Guard for the unintentional discharge of diesel fuel which occurred when the vessel sank.

180

The Premcor Refining Group, Inc. v. Kinder Morgan Energy Partners, L.P. and Kinder Morgan Petcoke, L.P.; Arbitration in Houston, Texas

On August 12, 2010, Premcor filed a demand for arbitration against us and our subsidiary Kinder Morgan Petcoke, L.P., collectively referred to as Kinder Morgan, asserting claims for breach of contract. Kinder Morgan performs certain petroleum coke handling operations at the Port Arthur, Texas refinery that is the subject of the claim. The arbitration is being administered by the American Arbitration Association in Dallas, Texas. Premcor alleges that Kinder Morgan breached its contract with Premcor by failing to name Premcor as an additional insured and failing to indemnify Premcor for claims brought against Premcor by PACC. PACC and Premcor are affiliated companies. PACC brought its claims against Premcor in a previous separate arbitration seeking to recover damages allegedly suffered by PACC when a pit wall of a coker unit collapsed at a refinery owned by Premcor. PACC obtained an arbitration award against Premcor in the amount of $50.3 million, plus post-judgment interest. Premcor is seeking to hold Kinder Morgan liable for the award. Premcor’s claim against Kinder Morgan is based in part upon Premcor’s allegation that Kinder Morgan is responsible to the extent of Kinder Morgan’s alleged proportionate fault in causing the pit wall collapse. Kinder Morgan denies and is vigorously defending against all claims asserted by Premcor. The final arbitration hearing is scheduled to begin on August 29, 2011.

Employee Matters

James Lugliani vs. Kinder Morgan G.P., Inc. et al. in the Superior Court of California, Orange County

James Lugliani, a former Kinder Morgan employee, filed suit in January 2010 against various Kinder Morgan affiliates. On behalf of himself and other similarly situated current and former employees, Mr. Lugliani claims that the Kinder Morgan defendants have violated the wage and hour provisions of the California Labor Code and Business & Professions Code by failing to provide meal and rest periods; failing to pay meal and rest period premiums; failing to pay all overtime wages due; failing to timely pay wages; failing to pay wages for vacation, holidays and other paid time off; and failing to keep proper payroll records. We intend to vigorously defend the case.

Pipeline Integrity and Releases

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

Pasadena Terminal Fire

On September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena, Texas liquids terminal facility. On January 8, 2010, a civil lawsuit was filed on behalf of the People of Texas and the TCEQ for alleged violations of the Texas Clean Air Act. The lawsuit was filed in the 53rd Judicial District Court, Travis County, Texas and is entitled State of Texas v. Kinder Morgan Liquids Terminals, case no. D1GV10000017. Specifically, the TCEQ alleges that KMLT had an unauthorized emission event relating to the pit 3 fire at the Pasadena terminal in September 2008. We have reached an agreement with the TCEQ to settle this matter for $40,000 plus $4,000 in attorneys’ fees to be paid to the state of Texas. The settlement was finalized and entered in court on December 20, 2010.

Charlotte, North Carolina

On January 17, 2010, our subsidiary Kinder Morgan Southeast Terminal LLC’s Charlotte #2 Terminal experienced an issue with a pollution control device known as the Vapor Recovery Unit, which led to a fire and release of gasoline from the facility to adjacent property and a small creek. There were no injuries. We are cooperating fully with state and federal agencies on the response and remediation.

181

Barstow, California

The United States Department of the Navy has alleged that historic releases of methyl tertiary-butyl ether, or MTBE, from Calnev’s Barstow terminal (i) have migrated underneath the Navy’s Marine Corps Logistics Base in Barstow; (ii) have impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by Calnev; and (iii) could affect the Barstow, California Marine Corps Logistic Base’s water supply system. Although Calnev believes that it has meritorious defenses to the Navy’s claims, it is working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for federal Comprehensive Environmental Response, Compensation and Liability Act (referred to as CERCLA) Removal Action to reimburse the Navy for $0.5 million in past response actions.

Westridge Release, Burnaby, British Columbia

On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within our Trans Mountain pipeline system near its Westridge terminal in Burnaby, British Columbia, resulting in a release of approximately 1,400 barrels of crude oil. The release impacted the surrounding neighborhood, several homes and nearby Burrard Inlet. No injuries were reported. To address the release, we initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the British Columbia Ministry of Environment, the National Energy Board (Canada), and the National Transportation Safety Board (Canada). Cleanup and environmental remediation is complete, and we have received a British Columbia Ministry of Environment Certificate of Compliance confirming complete remediation.

The National Transportation Safety Board released its investigation report on the incident on March 18, 2009. The report confirmed that an absence of pipeline location marking in advance of excavation and inadequate communication between the contractor and our subsidiary Kinder Morgan Canada Inc., the operator of the line, were the primary causes of the accident. No directives, penalties or actions of Kinder Morgan Canada Inc. were required as a result of the report.

Kinder Morgan Canada, Inc. commenced a lawsuit against the parties it believes were responsible for the third party strike, and a number of other parties have commenced related actions. The parties are currently involved in structured mediation.

On July 22, 2009, the British Columbia Ministry of Environment issued regulatory charges against the third-party contractor, the engineering consultant to the sewer line project, Kinder Morgan Canada Inc., and our subsidiary Trans Mountain L.P. The British Columbia Ministry of Environment claims that the parties charged caused the release of crude oil, and in doing so were in violation of various sections of the Environmental, Fisheries and Migratory Bird Act. A trial has been scheduled to commence in October 2011. We are of the view that the charges have been improperly laid against us, and we intend to vigorously defend against them.

Rockies Express Pipeline LLC Indiana Construction Incident

In April 2009, Randy Gardner, an employee of Sheehan Pipeline Construction Company (a third-party contractor to Rockies Express and referred to in this note as Sheehan Construction) was fatally injured during construction activities being conducted under the supervision and control of Sheehan Construction. The cause of the incident was investigated by Indiana OSHA, which issued a citation to Sheehan Construction. Rockies Express was not cited in connection with the incident.

In August 2010, the estate of Mr. Gardner filed a wrongful death action against Rockies Express and several other parties in the Superior Court of Marion County, Indiana, at case number 49D111008CT036870. The plaintiff alleges that the defendants were negligent in allegedly failing to provide a safe worksite, and seeks unspecified compensatory damages. Rockies Express denies that it was in any way negligent or otherwise responsible for this incident, and intends to assert contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers.

General

Although no assurance can be given, we believe that we have meritorious defenses to the actions set forth in this note and, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability.

182

Additionally, although it is not possible to predict the ultimate outcomes, we also believe, based on our experiences to date and the reserves we have established, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or distributions to limited partners. As of December 31, 2010 and 2009, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $169.8 million and $220.9 million, respectively. The reserve is primarily related to various claims from regulatory proceedings arising from our West Coast products pipeline transportation rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates. The overall change in the reserve from December 31, 2009 includes both a $172.0 million increase in expense in 2010 associated with various rate case liability adjustments that increased our overall rate case liability, and a $206.3 million payment in the second quarter of 2010 that reduced the liability. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

Environmental Matters

The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC; California Superior Court, County of Los Angeles, Case No. NC041463.

KMLT is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles. The lawsuit was stayed beginning in 2009 and remained stayed through the end of 2010. A hearing was held on December 13, 2010 to hear the City’s motion to remove the litigation stay. At the hearing, the judge denied the motion to lift the stay without prejudice. A full litigation stay is in effect until the next case management conference set for June 13, 2011. During the stay, the parties deemed responsible by the local regulatory agency have worked with that agency concerning the scope of the required cleanup and are now starting a sampling and testing program at the site. The local regulatory agency issued specific cleanup goals in early 2010, and two of those parties, including KMLT, have appealed those cleanup goals to the state agency.

Plaintiff’s Third Amended Complaint alleges that future environmental cleanup costs at the former terminal will exceed $10 million, and that the plaintiff’s past damages exceed $2 million. No trial date has yet been set.

Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC and ST Services, Inc.

On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The terminal is now owned by Plains Products, and it too is a party to the lawsuit.

The complaint seeks any and all damages related to remediating all environmental contamination at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit. The parties engaged in court ordered mediation in 2008 through 2009, which did not result in settlement. The trial judge has issued a Case Management Order and the parties are actively engaged in discovery.

On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil Corporation and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro terminal. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and KMLT filed third party complaints against Support Terminals/Plains seeking to bring Support Terminals/Plains into the case. Support Terminals/Plains filed motions to dismiss the third party complaints, which were denied. Support Terminals/Plains is now joined in the case, and it filed an Answer denying all claims. The court has consolidated the two cases. All private parties and the state participated in two mediation conferences in 2010.

In December 2010, KMLT and Plains Products entered into an agreement in principle with the New Jersey Department of Environmental Protection for settlement of the state’s alleged natural resource damages claim. Currently, a Consent Judgment is being finalized subject to public notice and comment and court approval. The tentative natural resource damage settlement includes a monetary award of $1.1 million and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. We anticipate a final Consent Judgment during second quarter 2011. The settlement with the state does not resolve the original complaint brought by Exxon Mobil. There is no trial date set.

183

Mission Valley Terminal Lawsuit

In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On September 26, 2007, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. The City disclosed in discovery that it is seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.

According to the Court’s most recent Case Management Order of January 6, 2011, the parties must complete all fact discovery by June 24, 2011 and all expert witness discovery by August 29, 2011. A mandatory settlement conference is set for July 6, 2011 and the trial is now set for March 13, 2012. We have been and will continue to aggressively defend this action. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. We continue to be in compliance with this agency order as we conduct an extensive remediation effort at the City’s stadium property site.

Kinder Morgan, EPA Section 114 Information Request

On January 8, 2010, Kinder Morgan Inc., on behalf of Natural Gas Pipeline Company of America LLC, Horizon Pipeline Company and Rockies Express Pipeline LLC, received a Clean Air Act Section 114 information request from the U.S. Environmental Protection Agency, Region V. This information request requires that the three affiliated companies provide the EPA with air permit and various other information related to their natural gas pipeline compressor station operations in Illinois, Indiana, and Ohio. The affiliated companies have responded to the request and believe the relevant natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.

Other Environmental

We are subject to environmental cleanup and enforcement actions from time to time. In particular, the CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these alleged violations will have a material adverse effect on our business.

We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.

In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. See “—Pipeline Integrity and Releases” above for additional information with respect to ruptures and leaks from our pipelines.

184

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur, and changing circumstances could cause these matters to have a material adverse impact. As of December 31, 2010, we have accrued an environmental reserve of $74.7 million, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations. In addition, as of December 31, 2010, we have recorded a receivable of $8.6 million for expected cost recoveries that have been deemed probable. As of December 31, 2009, our environmental reserve totaled $81.1 million and our estimated receivable for environmental cost recoveries totaled $4.3 million. Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.

Other

We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

17. Regulatory Matters

The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expanded the circumstances under which interstate petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2010, 2009 and 2008, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines.

Below is a brief description of our ongoing regulatory matters, including any material developments that occurred during 2010.

Natural Gas Pipeline Expansion Filings

Rockies Express Pipeline LLC Meeker to Cheyenne Expansion Project

Pursuant to certain rights exercised by EnCana Gas Marketing USA as a result of its foundation shipper status on the former Entrega Gas Pipeline LLC facilities (now part of the Rockies Express Pipeline), Rockies Express Pipeline LLC requested authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne Hub expansion project. The proposed expansion would add natural gas compression at its Big Hole compressor station located in Moffat County, Colorado, and its Arlington compressor station located in Carbon County, Wyoming. Furthermore, the additional compression would permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado.

By FERC order issued July 16, 2009, Rockies Express Pipeline LLC was granted authorization to construct and operate this project, and it commenced construction on August 4, 2009. The additional compression at the Big Hole compressor station was made available as of December 9, 2009, and the additional compression at the Arlington compressor station was made available as of October 5, 2010. The expansion is fully contracted. The total FERC authorized cost for the proposed project was approximately $78 million; however, total costs for the project were approximately $50.5 million.

Kinder Morgan Interstate Gas Transmission Pipeline - Huntsman 2009 Expansion Project

Our subsidiary Kinder Morgan Interstate Gas Transmission LLC (KMIGT) filed an application with the FERC for authorization to construct and operate certain storage facilities necessary to increase the storage capability of the existing Huntsman Storage Facility, located near Sidney, Nebraska. KMIGT also requested approval of new incremental rates for the project facilities under its currently effective Cheyenne Market Center Service Rate Schedule CMC-2. By FERC order issued September 30, 2009, KMIGT was granted authorization to construct and operate the project, and construction of the project commenced on October 12, 2009. KMIGT received FERC approval to commence service on the expanded storage project effective February 1, 2010, and KMIGT placed all remaining facilities into service on August 13, 2010. Total costs for the project were approximately $10.1 million, significantly under the original budget.

185

Kinder Morgan Interstate Gas Transmission Pipeline – Franklin to Hastings Expansion Project

KMIGT has filed a prior notice request to expand and replace certain mainline pipeline facilities to create up to 10,000 dekatherms per day of firm transportation capacity to serve an ethanol plant located near Aurora, Nebraska. The estimated cost of the proposed facilities is $18.6 million. On September 24, 2010 Seminole Energy Services, LLC filed a protest to the construction of this project, and the protest was subsequently denied by the FERC in an order issued October 15, 2010. KMIGT is proceeding with the construction of this project which is expected to be completed in early spring 2011.

Fayetteville Express Pipeline LLC – Docket No.CP09-433-000

In January 2011, construction was fully completed on the previously announced Fayetteville Express Pipeline project. The Fayetteville Express Pipeline is owned by Fayetteville Express Pipeline LLC, a 50/50 joint venture between us and Energy Transfer Partners, L.P. The Fayetteville Express Pipeline is a 187-mile, 42-inch diameter natural gas pipeline that begins in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnection with Trunkline Gas Company’s pipeline in Panola County, Mississippi. The pipeline will have an initial capacity of two billion cubic feet per day, and has currently secured binding commitments for approximately ten years totaling 1.85 billion cubic feet per day of capacity.

On December 17, 2009, the FERC approved the pipeline’s certificate application authorizing pipeline construction, and initial construction on the project began in January 2010. The pipeline began interim transportation service on October 12, 2010, and began firm contract transportation for all shippers on January 1, 2011. 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).

Products Pipelines and Natural Gas Pipelines Regulatory Proceedings

For information on our pipeline regulatory proceedings, see Note 16 “Litigation, Environmental and Other Contingencies—Federal Energy Regulatory Commission Proceedings” and “—California Public Utilities Commission Proceedings.”

18. Recent Accounting Pronouncements

Accounting Standards Updates

In December 2009, the FASB issued Accounting Standards Update No. 2009-16, “Accounting for Transfers of Financial Assets” and Accounting Standards Update No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.” ASU No. 2009-16 amended the Codification’s “Transfers and Servicing” Topic to include the provisions included within the FASB’s previous Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets—an amendment of FASB Statement No. 140,” issued June 12, 2009. ASU No. 2009-17 amended the Codification’s “Consolidations” Topic to include the provisions included within the FASB’s previous SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” also issued June 12, 2009. These two Updates changed the way entities must account for securitizations and special-purpose entities. ASU No. 2009-16 requires more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. ASU No. 2009-17 changes how a company determines whether an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. For us, both Updates were effective January 1, 2010; however, the adoption of these Updates did not have any impact on our consolidated financial statements.

186

In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Improving Disclosures about Fair Value Measurements.” This ASU requires both the gross presentation of activity within the Level 3 fair value measurement roll forward and the details of transfers in and out of Levels 1 and 2 fair value measurements. It also clarifies certain disclosure requirements on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. For us, this ASU was effective January 1, 2010 (except for the Level 3 roll forward which was effective for us January 1, 2011); however, because this ASU pertains to disclosure requirements only, the adoption of this ASU did not have a material impact on our consolidated financial statements. Furthermore, during each of the years ended December 31, 2010 and 2009, we made no transfers in and out of Level 1, Level 2, or Level 3 of the fair value hierarchy.

In July 2010, the FASB issued Accounting Standards Update No. 2010-20, “Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses.” ASU No. 2010-20 requires companies that hold financing receivables, which include loans, lease receivables, and the other long-term receivables to provide more information in their disclosures about the credit quality of their financing receivables and the credit reserves held against them. On December 31, 2010, we adopted all amendments that require disclosures as of the end of a reporting period, and on January 1, 2011, we adopted all amendments that require disclosures about activity that occurs during a reporting period (the remainder of this ASU). The adoption of this ASU did not have a material impact on our consolidated financial statements.

19. Quarterly Financial Data (Unaudited)

	Operating Revenues		Operating Income		Net Income		Limited Partners’ Net Income (Loss) per Unit
	(In millions, except per unit amounts)
2010
First Quarter(a)	$	2,129.6	$	287.9	$	227.4	$	(0.08	)
Second Quarter		1,961.5		443.6		365.1		0.88
Third Quarter		2,060.0		407.3		322.4		0.17
Fourth Quarter		1,926.6		466.3		412.2		0.42
2009
First Quarter	$	1,786.5	$	340.0	$	266.8	$	0.15
Second Quarter		1,645.3		372.0		328.6		0.33
Third Quarter		1,660.7		406.7		363.7		0.43
Fourth Quarter		1,910.9		396.4		324.7		0.26

____________

(a)	First quarter 2010 includes a $158.0 million increase in expense associated with rate case liability adjustments.

187

20. Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Operating Statistics

Operating statistics from our oil and gas producing activities for each of the years 2010, 2009 and 2008 are shown in the following table:

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

	Year Ended December 31,
	2010		2009		2008
Consolidated Companies(a)
Production costs per barrel of oil equivalent(b)(c)(d)	$	12.58	$	11.44	$	15.70
Crude oil production (MBbl/d)		35.5		37.4		36.2
SACROC crude oil production (MBbl/d)		24.3		25.1		23.3
Yates crude oil production (MBbl/d)		10.7		11.8		12.3

Natural gas liquids production (MBbl/d)(d)		5.8		5.4		4.8
Natural gas liquids production from gas plants(MBbl/d)(e)		4.2		4.0		3.5
Total natural gas liquids production(MBbl/d)		10.0		9.4		8.3
SACROC natural gas liquids production (MBbl/d)(d)		5.5		5.3		4.6
Yates natural gas liquids production (MBbl/d)(d)		0.2		0.1		0.2

Natural gas production (MMcf/d)(d)(f)		1.4		0.9		1.4
Natural gas production from gas plants(MMcf/d)(e)(f)		1.9		0.7		0.2
Total natural gas production(MMcf/d)(f)		3.3		1.6		1.6
Yates natural gas production (MMcf/d)(d)(f)		1.3		0.8		1.3

Average sales prices including hedge gains/losses:
Crude oil price per Bbl(g)	$	59.96	$	49.55	$	49.42
Natural gas liquids price per Bbl(g)	$	50.34	$	37.70	$	63.48
Natural gas price per Mcf(h)	$	4.08	$	3.45	$	7.73
Total natural gas liquids price per Bbl(e)	$	51.03	$	37.96	$	63.00
Total natural gas price per Mcf(e)	$	4.10	$	3.53	$	7.63
Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl(g)	$	76.93	$	59.03	$	97.70
Natural gas liquids price per Bbl(g)	$	50.34	$	37.70	$	63.48
Natural gas price per Mcf(h)	$	4.08	$	3.45	$	7.73

____________

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

188

The following three tables provide supplemental information on oil and gas producing activities, including (i) capitalized costs related to oil and gas producing activities; (ii) costs incurred for the acquisition of oil and gas producing properties and for exploration and development activities; and (iii) the results of operations from oil and gas producing activities.

Our capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing Activities

	As of December 31,
	2010			2009			2008
Consolidated Companies(a)
Wells and equipment, facilities and other	$	2,676.8		$	2,428.6		$	2,106.9
Leasehold		352.3			352.6			348.9
Total proved oil and gas properties		3,029.1			2,781.2			2,455.8
Unproved property(b)		88.3			10.2			-
Accumulated depreciation and depletion		(1,901.0	)		(1,501.1	)		(1,064.3	)
Net capitalized costs	$	1,216.4		$	1,290.3		$	1,391.5

____________

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries. Includes capitalized asset retirement costs and associated accumulated depreciation.
(b)	The unproved amounts consist of capitalized costs related to the Katz Strawn Unit, which is in the initial stages of the carbon dioxide floding operation.

For each of the years 2010, 2009 and 2008, our costs incurred for property acquisition, exploration and development were as follows (in millions):

Costs Incurred in Exploration, Property Acquisitions and Development

	Year Ended December 31,
	2010			2009			2008
Consolidated Companies(a)
Property acquisitions - proved oil and gas properties		$	-		$	5.3		$	-
Development			326.0			330.3			495.2

____________

(a)

Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries. During 2010, we spent $78.2 million on unproved properties development costs related to the Katz Strawn Unit, which is in the initial stages of the carbon dioxide flooding operation. No exploration costs were incurred for the periods reported.

Our results of operations from oil and gas producing activities for each of the years 2010, 2009 and 2008 are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing Activities

	Year Ended December 31,
	2010		2009		2008
Consolidated Companies(a)
Revenues(b)	$	903.2	$	767.0	$	785.5
Expenses:
Production costs(c)		229.5		188.8		308.4
Other operating expenses(d)		62.7		53.3		99.0
Depreciation, depletion and amortization expenses		406.3		441.4		342.2
Total expenses		698.5		683.5		749.6
Results of operations for oil and gas producing activities	$	204.7	$	83.5	$	35.9

____________

189

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Revenues include losses attributable to our hedging contracts of $219.9 million, $129.5 million and $693.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(c)	The decrease in operating expenses in 2009 compared to 2008 was primarily due to (i) lower prices charged by the industry’s material and service providers (for items such as outside services, maintenance, and well workover services), which impacted rig costs, other materials and services, and capital and exploratory costs; (ii) lower fuel and utility rates; and (iii) the successful renewal of lower priced service and supply contracts negotiated since the end of 2008.
(d)	Consists primarily of carbon dioxide expense.

Supplemental information is also provided for the following three items (i) estimated quantities of proved oil and gas reserves; (ii) the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and (iii) a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

The technical persons responsible for preparing the reserves estimates presented in this Note meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. They are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our oil and gas properties; and we do not employ them on a contingent basis. Our employee who is primarily responsible for overseeing Netherland, Sewell and Associate, Inc.’s preparation of the reserves estimates is a registered Professional Engineer in the states of Texas and Kansas with a Doctorate of Engineering from the University of Kansas. He is a member of the Society of Petroleum Engineers and has over 25 years of professional engineering experience.

We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change.

Furthermore, our management is responsible for establishing and maintaining adequate internal control over financial reporting, which includes the estimation of our oil and gas reserves. We maintain internal controls and guidance to ensure the reliability of our crude oil, natural gas liquids and natural gas reserves estimations, as follows:

▪

no employee’s compensation is tied to the amount of recorded reserves;

▪

we follow comprehensive SEC compliant internal policies to determine and report proved reserves, and our reserve estimates are made by experienced oil and gas reservoir engineers or under their direct supervision;

▪

we review our reported proved reserves at each year-end, and at each year-end, our CO2 business segment managers and our Vice President (President, CO2) reviews all significant reserves changes and all new proved developed and undeveloped reserves additions; and

▪

our CO2 business segment reports independently of our four remaining reportable business segments.

For more information on our controls and procedures, see Item 9A “Controls and Procedures—Management’s Report on Internal Control Over Financial Reporting” included in our Annual Report on Form 10-K for the year ended December 31, 2010.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, current prices and costs calculated as of the date the estimate is made. Beginning in 2009, pricing is applied based upon the twelve month unweighted arithmetic average of the first day of the month price for the year. For prior years, pricing was based on the price as of year end. Future development and production costs are determined based upon actual cost at year-end. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.

190

As of December 31, 2008, we had 53.4 million barrels of crude oil and 4.3 million barrels of natural gas liquids classified as proved developed reserves. Also as of year end 2008, we had 25.2 million barrels of crude oil and 2.6 million barrels of natural gas liquids classified as proved undeveloped reserves.

During 2009 production from the fields totaled 13.7 million barrels of oil and 2.0 million barrels of natural gas liquids. In addition, we incurred $330.3 million in capital costs which resulted in the development of 7.4 million barrels of oil and 0.4 million barrels of natural gas liquids and their transfer from the proved undeveloped category. These reclassifications reflect the transfer of 29.2% of crude oil and 13.7% of natural gas liquids from the proved undeveloped reserves reported as of December 31, 2008 to the proved developed classification of reserves reported as of December 31, 2009.

Also during 2009, previous estimates of proved undeveloped reserves were revised upwards by 15.9 million barrels of crude oil and 1.1 million barrels of natural gas liquids. These revisions were due primarily to utilizing a higher prescribed oil price basis for year end 2009 ($57.65 per barrel) than year end 2008 ($41.00 per barrel). The higher oil price basis resulted in 75 patterns being added to our SACROC carbon dioxide flood project; also, the SACROC carbon dioxide flood project life was extended from 2014 to 2018. These revisions to our previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category, as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 32.4% at year end 2008 to 42.6% at year end 2009.

After giving effect to production, revisions to previous estimates and minor purchases of reserves in place, during 2009 total proved reserves of crude oil increased by 2.2 million barrels and total proved reserves of natural gas liquids decreased by 0.9 million barrels. As of December 31, 2009, we had 47.0 million barrels of crude oil and 2.7 million barrels of natural gas liquids classified as proved developed reserves. Also as of year end 2009, we had 33.8 million barrels of crude oil and 3.2 million barrels of natural gas liquids classified as proved undeveloped reserves. Total proved reserves as of December 31, 2009 were 80.8 million barrels of oil and 5.9 million barrels of natural gas liquids.

During 2010, production from the fields totaled 13.0 million barrels of crude oil and 2.1 million barrels of natural gas liquids. In addition, we incurred $248.0 million in capital costs which resulted in the development of 10.0 million barrels of crude oil and 1.3 million barrels of natural gas liquids and their transfer from the proved undeveloped category to the proved developed category. These reclassifications reflect the transfer of 29.6% of crude oil and 39.9% of natural gas liquids from the proved undeveloped reserves reported as of December 31, 2009 to the proved developed classification of reserves reported as of December 31, 2010.

Also during 2010, previous estimates of proved developed reserves were revised upwards by 12.3 million barrels of crude oil and 0.4 million barrels of natural gas liquids, and proved undeveloped reserves were revised upward by 4.0 million barrels of crude oil and 0.7 million barrels of natural gas liquids. Almost 90 percent of the revisions were associated with our third party oil and gas consultants revising the methodology used to estimate reserves for our Yates Field Unit in order to take greater account of the reservoir mechanisms associated with carbon dioxide injection, for which there are now seven years of history. The revised methodology used to forecast the Yates Field Unit future performance utilizes a volume balance that is based on a correlation of historical production to observed oil saturations and reservoir volume factors during the life of the Yates Field Unit, with emphasis on the period from 1996 through 2010. A portion of these revisions were attributed to utilizing a higher prescribed oil price basis to calculate reserves ($75.96 per barrel for year end 2010 versus $57.65 per barrel for year end 2009).

These revisions to our previous estimates, as well as the transfer of proved undeveloped reservers to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves decreasing from 42.6% at year end 2009 to 33.9% at year end 2010. After giving effect to production and revisions to previous estimates during 2010, total proved reserves of crude oil increased by 3.3 million barrels and total proved reserves of natural gas liquids decreased by 1.1 million barrels.

As of December 31, 2010, we had 56.4 million barrels of crude oil and 2.2 million barrels of natural gas liquids classified as proved developed reserves. Also, as of year end 2010, we had 27.8 million barrels of crude oil and 2.6 million barrels of natural gas liquids classified as proved undeveloped reserves. Total proved reserves as of December 31, 2010, were 84.2 million barrels of crude oil and 4.9 million barrels of natural gas liquids. We currently expect that the proved undeveloped reserves we report as of December 31, 2010 will be developed within the next five years.

During 2010, we filed estimates of our oil and gas reserves for the year 2009 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this Note exceeds 5%.

191

The following Reserve Quantity Information table discloses estimates, as of December 31, 2010, of proved crude oil, natural gas liquids and natural gas reserves, prepared by Netherland, Sewell and Associates, Inc. (independent oil and gas consultants), of Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the state of Texas. This data has been prepared using current prices and costs, as discussed above, and the estimates of reserves and future revenues in this Note conform to the guidelines of the U.S. Securities and Exchange Commission (SEC).

Reserve Quantity Information

	Consolidated Companies(a)
	Crude Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)(b)
Proved developed and undeveloped reserves:
As of December 31, 2007		121,355			11,112			1,078
Revisions of previous estimates(c)		(29,536	)		(2,490	)		695
Production		(13,240	)		(1,762	)		(499	)
As of December 31, 2008		78,579			6,860			1,274
Revisions of previous estimates(d)		15,900			1,018			(293	)
Production		(13,688	)		(1,995	)		(298	)
Purchases of reserves in place		53			37			15
As of December 31, 2009		80,844			5,920			698
Revisions of previous estimates(e)		16,294			1,059			2,923
Production		(12,962	)		(2,116	)		(523	)
As of December 31, 2010		84,176			4,863			3,098

Proved developed reserves:
As of December 31, 2008	53,346	4,308	1,274
As of December 31, 2009	47,058	2,665	698
As of December 31, 2010	56,423	2,221	3,098

Proved undeveloped reserves:
As of December 31, 2008	25,233	2,552	-
As of December 31, 2009	33,786	3,255	-
As of December 31, 2010	27,753	2,642	-

____________

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees fahrenheit.
(c)	Predominantly due to lower product prices used to determine reserve volumes.
(d)	Predominantly due to higher product prices resulting in an expanded economic carbon dioxide project area.
(e)	Predominantly due to higher product prices used to determine reserve volumes and the change in methodology discussed above.

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with the “Extractive Activities—Oil and Gas” Topic of the Codification. The assumptions that underly the computation of the standardized measure of discounted cash flows, presented in the table below, may be summarized as follows:

▪

the standardized measure includes our estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions;

▪

for 2010 and 2009, pricing is applied based upon the 12 month unweighted arithmetic average of the first day of the month price for the year, and for 2008, was based upon the price as of the end of the year;

▪

future development and production costs are determined based upon actual cost at year-end;

192

▪

the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and

▪

a discount factor of 10% per year is applied annually to the future net cash flows.

Our standardized measure of discounted future net cash flows from proved reserves were as follows (in millions):

Standardized Measure of Discounted Future Net Cash Flows From

Proved Oil and Gas Reserves

	As of December 31,
	2010			2009			2008
Consolidated Companies(a)
Future cash inflows from production	$	6,665.8		$	4,898.0		$	3,498.0
Future production costs		(2,387.9	)		(1,951.5	)		(1,671.6	)
Future development costs(b)		(1,433.7	)		(1,179.7	)		(910.3	)
Undiscounted future net cash flows		2,844.2			1,766.8			916.1
10% annual discount		(946.6	)		(503.5	)		(257.7	)
Standardized measure of discounted future net cash flows	$	1,897.6		$	1,263.3		$	658.4

____________

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Includes abandonment costs.

The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in millions):

Changes in the Standardized Measure of Discounted Future Net Cash Flows From

Proved Oil and Gas Reserves

	As of December 31,
	2010			2009			2008
Consolidated Companies(a)
Present value as of January 1	$	1,263.3		$	658.4		$	4,078.4
Changes during the year:
Revenues less production and other costs(b)		(828.2	)		(652.7	)		(1,012.4	)
Net changes in prices, production and other costs(b)		890.0			915.7			(3,076.9	)
Development costs incurred		248.0			330.3			495.2
Net changes in future development costs		(296.6	)		(445.4	)		231.1
Purchases of reserves in place		-			-			-
Revisions of previous quantity estimates(c)		494.2			391.1			(417.1	)
Accretion of discount		126.9			65.9			392.9
Timing differences and other		-			-			(32.8	)
Net change for the year		634.3			604.9			(3,420.0	)
Present value as of December 31	$	1,897.6		$	1,263.3		$	658.4

____________

(a)	Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
(b)	Excludes the effect of losses attributable to our hedging contracts of $219.9 million, $129.5 million and $639.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.
(c)	2010 revisions were primarily due to higher product prices used to determine reserve volumes and the change in methodology discussed above. 2009 revisions were primarily due to higher product prices resulting in an expanded economic carbon dioxide project area. 2008 revisions were predominately due to lower product prices used to determine reserve volumes.

193

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	KINDER MORGAN ENERGY PARTNERS, L.P.
	Registrant (a Delaware Limited Partnership)

	By: KINDER MORGAN G.P., INC.,
	Its sole General Partner

	By: KINDER MORGAN MANAGEMENT, LLC, the Delegate of Kinder Morgan G.P., Inc.

	By: /s/ KIMBERLY A. DANG
	Kimberly A. Dang, Vice President and Chief Financial Officer (principal financial and accounting officer)

Date: February 22, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date

/s/ KIMBERLY A. DANG	Vice President and Chief Financial	February 22, 2011
Kimberly A. Dang	Officer of Kinder Morgan Management,
	LLC, Delegate of Kinder Morgan G.P., Inc. (principal financial officer and principal accounting officer)

/s/ RICHARD D. KINDER	Chairman of the Board and Chief	February 22, 2011
Richard D. Kinder	Executive Officer of Kinder Morgan
	Management, LLC, Delegate of Kinder Morgan G.P., Inc. (principal executive officer)

/s/ GARY L. HULTQUIST	Director of Kinder Morgan	February 22, 2011
Gary L. Hultquist	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc.

/s/ C. BERDON LAWRENCE	Director of Kinder Morgan	February 22, 2011
C. Berdon Lawrence	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc.

/s/ PERRY M. WAUGHTAL	Director of Kinder Morgan	February 22, 2011
Perry M. Waughtal	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc.

/s/ C. PARK SHAPER	Director and President of	February 22, 2011
C. Park Shaper	Kinder Morgan Management, LLC,
	Delegate of Kinder Morgan G.P., Inc.

194