UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-K

T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

or

£ 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 incorporation or organization)	(I.R.S. Employer 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 T    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 T

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 T   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 T   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.  T

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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 T   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 T

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, 2009 was approximately $9,217,003,530.  As of January 31, 2010, the registrant had 207,310,563 Common Units outstanding.

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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	10
	Narrative Description of Business	10
	Business Strategy	10
	Business Segments	10
	Products Pipelines	11
	Natural Gas Pipelines	15
	CO2	23
	Terminals	25
	Kinder Morgan Canada	29
	Major Customers	30
	Regulation	31
	Environmental Matters	34
	Other	36
	Financial Information about Geographic Areas	37
	Available Information	37
Item 1A.	Risk Factors	37
Item 1B.	Unresolved Staff Comments	48
Item 3.	Legal Proceedings	48
Item 4.	Submission of Matters to a Vote of Security Holders	48
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	49
Item 6.	Selected Financial Data	50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
	Critical Accounting Policies and Estimates	53
	Results of Operations	56
	Liquidity and Capital Resources	75
	Recent Accounting Pronouncements	84
	Information Regarding Forward-Looking Statements	84
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	85
	Energy Commodity Market Risk	86
	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	89
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
	Qualifications of Directors	92
	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	103
Item 13.	Certain Relationships and Related Transactions, and Director Independence	105
Item 14.	Principal Accounting Fees and Services	106
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	107
	Index to Financial Statements	112
Signatures		196

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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 $28 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 owned by Kinder Morgan, Inc.

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.  We pay our quarterly distributions from operations and interim capital transactions to our common and Class B unitholders in cash, and we pay our quarterly distributions to our sole i-unitholder in additional i-units rather than in cash.

Kinder Morgan, Inc., referred to as KMI in this report, is a Kansas corporation privately 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).  For a period, KMI was known as Knight Inc., the surviving legal entity from its May 30, 2007 going-private transaction.  On that date, KMI completed a merger whereby (i) generally each share of KMI common stock was converted into the right to receive $107.50 in cash without interest; (ii) KMI merged with a wholly-owned subsidiary of Knight Holdco LLC, a privately owned company in which Richard D. Kinder was a major investor; and (iii) KMI continued as the surviving legal entity and was subsequently renamed Knight Inc.  This transaction is referred to in this report as the going-private transaction.  On July 15, 2009, Knight Inc. changed its name back to Kinder Morgan, Inc.  Subsequently, Knight Holdco LLC was renamed Kinder Morgan Holdco LLC.

KMI indirectly owns all the common stock of our general partner; 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, 2009, KMI and its consolidated subsidiaries owned, through its general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management LLC (discussed following), an approximate 13.2% 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 2009 distribution level, KMI received approximately 51% of all quarterly “Available Cash” distributions (as defined in our partnership agreement) from us, with approximately 45% and 6% of all quarterly distributions from us attributable to KMI’s general partner and limited partner interests, respectively.

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Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company formed in February 2001.  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, 2009, KMR, through its sole ownership of our i-units, owned approximately 28.8% of all of our outstanding limited partner units.

Recent Developments

The following is a brief listing of significant developments since December 31, 2008.  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 June 1, 2009, we completed a phased horsepower expansion on our West Coast Products Pipelines’ 12-inch diameter, 175-mile Concord to Fresno, California refined petroleum products pipeline segment.  The expansion added approximately 10,000 barrels per day of capacity;

▪ On June 16, 2009, Plantation Pipe Line Company successfully completed the first U.S. transmarket commercial shipment of blended biodiesel (a 5% blend commonly referred to as B5) on a mainline segment of its pipeline.  During 2009, Plantation successfully delivered blended biodiesel to marketing terminals located in Georgia, North Carolina, and Virginia. Plantation is prepared to deliver biodiesel to other markets along its pipeline system in response to customers’ need for blending and transporting biodiesel to meet federal regulatory requirements;

▪ On September 22, 2009, we began commercial transportation of blended biodiesel (a 2% blend commonly referred to as B2) on our West Coast Products Pipelines’ 115-mile Oregon Pipeline that extends from Portland to Eugene, Oregon.  The first commercial batch of approximately 100,000 barrels of B2 was created using a newly installed blending system to inject B99 (a diesel blend that contains 99% biodiesel and 1% petroleum diesel) into ultra low sulfur diesel at our Willbridge refined products terminal located in Portland, Oregon;  subsequently, we have undertaken additional renewable fuels projects at several of our West Coast refined products terminal locations, including improvements to allow for the blending of biodiesel at both the truck-loading rack at our Willbridge terminal and the barge-loading facilities at our Linnton terminal, also located in Portland.  All of these biodiesel shipments help diesel fuel suppliers throughout Oregon meet a state biodiesel mandate that became effective on October 1, 2009;

▪ During 2009, we approved an approximately $15.8 million investment to install new infrastructure at our West Coast Products Pipelines’ California terminals to facilitate customer requirements to increase the ethanol blend rate to 10%, consistent with recent California environmental initiatives.  All of our California refined products terminals began blending ethanol at 10% effective January 11, 2010; and

▪ As of December 31, 2009, we completed modifications to our Central Florida Pipeline to more efficiently move gasoline and ultra-low sulfur diesel fuel within the terminal community at the Port of Tampa.  We modified existing inter-terminal pipelines to provide BP with access to the port’s deep-draft ship berths.  The modifications also provide a platform for third-party Port of Tampa terminals to tie-in to our Central Florida pipeline system.  Relatedly, in the fourth quarter of 2009, we placed into service two new storage tanks at our Central Florida’s Orlando terminal.  The additional tankage (half for ethanol and half for refined petroleum products) increased the facility’s total storage capacity by 200,000 barrels.

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Natural Gas Pipelines

▪ On June 21, 2009, we completed construction and fully placed into service our Kinder Morgan Louisiana Pipeline, a 133-mile, 42-inch diameter pipeline that 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 pipeline system interconnects with multiple third-party pipelines in Louisiana, and all of the pipeline capacity has been fully subscribed by Chevron and Total under 20-year firm transportation contracts.  The Kinder Morgan Louisiana Pipeline project cost approximately $1 billion to complete;

▪ On August 1, 2009, we completed construction and fully placed into service our 50%-owned Midcontinent Express Pipeline, a 507-mile natural gas pipeline system.  Energy Transfer Partners L.P. owns the remaining interest.  The pipeline’s Zone 1 segment extends from Bennington, Oklahoma to an interconnect with Columbia Gulf Transmission Company in Madison Parish, Louisiana.  It has a design capacity of approximately 1.5 billion cubic feet per day, and currently transports approximately 1.4 billion cubic feet per day.  The pipeline’s Zone 2 segment extends from the Columbia Gulf interconnect and terminates at an interconnection with the Transco Pipeline near Butler, Alabama.  It has a design capacity of approximately 1.2 billion cubic feet per day, and currently transports approximately 1.0 billion cubic feet per day.

The Midcontinent Express pipeline system connects the Barnett Shale, Bossier Sands and other natural gas producing regions in Texas, Oklahoma and Louisiana to markets in the eastern United States, and substantially all of the pipeline’s capacity is fully subscribed with long-term binding commitments from creditworthy shippers.  In an order issued September 17, 2009, the Federal Energy Regulatory Commission, referred to in this report as the FERC, approved Midcontinent Express’ (i) amendment to move one compressor station in Mississippi and modify the facilities at another station in Texas; and (ii) application to expand the capacity in Zone 1 by 0.3 billion cubic feet per day (this expansion is expected to be completed in December 2010).  Our current estimate of total construction costs on the entire project, including expansions, is approximately $2.3 billion;

▪ On June 29, 2009, we commenced interim transportation service for up to 1.6 billion cubic feet per day of natural gas on the first 444 miles of our then 51%-owned Rockies Express-East pipeline segment.  This segment extends from Audrain County, Missouri to the Lebanon Hub in Warren County, Ohio.  OnNovember 12, 2009, we completed and placed into service the remainder of Rockies Express-East, consisting of approximately 195-miles of 42-inch diameter pipe extending to a terminus near the town of Clarington in Monroe County, Ohio.

On November 14, 2009, Rockies Express-East experienced a pipeline girth weld failure downstream of its Chandlersville, Ohio compressor station (approximately 60 miles upstream from the system terminus at Clarington).  Rockies Express declared a force majeure on its contractual obligations to provide service east of the Chandlersville compressor station, in order to repair and inspect the affected segment.  Reservation charges under certain shipper service contracts were credited to shippers, in part, during this force majeure outage.

Following coordination with the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration, we developed a Return to Service Plan, the pipeline was repaired and the affected segment returned to reduced capacity on January 27, 2010.  The restoration of service at reduced capacity was sufficient to meet current contractual obligations and the reservation fees under shipper service contracts were billed at the level in effect prior to the force majeure event.  On February 6, 2010, the force majeure was lifted and the segment was returned to pre-failure capacity.  On February 17, 2010, the United States Department of Transportation Pipeline and Hazardous Materials Administration issued a Corrective Action Order that incorporated the Return of Service Plan. Rockies Express-East has completed implementation of the majority of the requirements of the Return of Service Plan and the Corrective Action Order.

The 639-mile, Rockies Express-East pipeline segment is the third and final phase the Rockies Express Pipeline.  It permits 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, Natural Gas Pipeline Company of America LLC (a 20% owned equity investee of KMI referred to in this report as NGPL), Midwestern Gas Transmission, Trunkline, Panhandle Eastern Pipe Line, ANR, Columbia Gas, Dominion Transmission, Tennessee Gas, Texas Eastern, and Texas Gas Transmission.  The local distribution companies include Ameren, Vectren, and Dominion East Ohio.  Now fully operational, the 1,679-mile Rockies Express Pipeline has the capacity to transport up to 1.8 billion cubic feet of natural gas per day.  Effective December 1, 2009, our ownership interest in the Rockies Express Pipeline was reduced to 50% and ConocoPhillips’ interest was increased to 25% (from 24%).  Sempra Pipelines and Storage owns the remaining 25% interest.

Binding firm commitments from creditworthy shippers have been secured for nearly all of the capacity on the Rockies Express Pipeline, including a compression expansion on the Rockies Express-Entrega segment.  The first leg of this expansion extends from Meeker, Colorado to Wamsutter, Wyoming, and began service in December 2009.  The second leg of the expansion will extend from Wamsutter to the Cheyenne Hub in Colorado and is expected to be completed in July 2010.  The Rockies Express Pipeline is one of the largest natural gas pipeline systems ever constructed in North America, and our current estimate of total construction costs on the entire project, including expansions, is approximately $6.8 billion;

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▪ On September 30, 2009, the FERC issued authority to our subsidiary Kinder Morgan Interstate Gas Transmission LLC, the right to construct and operate $14 million in capital improvements to increase the withdrawal capability of its Huntsman natural gas storage facility.  Incremental storage capacity arising from the expansion project is contracted under a firm service agreement for a five-year term.  The service for these new facilities commenced on February 1, 2010;

▪ Effective 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.  The acquired assets primarily consist of approximately 290 natural gas amine-treating and dew-point control plants and related equipment that 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 makes us the largest contract provider of natural gas treating services in the U.S. and complements and expands the existing natural gas treating operations currently being offered by our Texas intrastate natural gas pipeline group;

▪ On October 22, 2009, we announced that we had received the Continuing Excellence Award for our participation in the United States Environmental Protection Agency’s Natural Gas STAR program.  The Natural Gas STAR Program is a flexible, voluntary partnership that encourages oil and natural gas companies—both domestically and abroad—to adopt cost-effective technologies and practices that improve operational efficiency and reduce emissions of methane.

The Continuing Excellence Award recognizes a partner’s outstanding performance over multiple years in reducing methane emissions, identifying and implementing new emission-reducing technologies and practices, and supporting the overall objectives of the Natural Gas STAR program.  In 2008, we implemented several technologies and operational practices that resulted in methane emission reductions of 3,469,719 thousand cubic feet.  These reductions were achieved through the installation of new electric motor driven compressors and gas turbines, using compressors to pump down pipeline sections prior to maintenance activities, implementation of directed inspection and maintenance programs and other methane emission reduction practices;

▪ Effective November 1, 2009, we acquired a 40% ownership interest in Endeavor Gathering LLC, the natural gas gathering and compression business of GMX Resources Inc., for an aggregate consideration of $36.0 million.  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% interest in, Endeavor Gathering LLC.  The acquisition complements our existing natural gas gathering and transportation business located in the state of Texas;

▪ On November 13, 2009, we and Copano Energy, L.L.C. announced that we have entered into a letter of intent 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 will own 50% of the equity in the project, and Copano will own the remaining 50% interest.  As a first phase, the joint venture will construct an approximately 22-mile, 24-inch diameter natural gas gathering pipeline and enter into new commercial arrangements with both us and Copano.  The natural gas pipeline will originate in LaSalle County, Texas and will terminate in Duval County, Texas.  It will have an initial capacity of 350 million cubic feet per day and is expected to be completed mid-year 2010; and

▪ On December 17, 2009, the FERC approved and issued Fayetteville Express Pipeline LLC’s certificate application, authorizing construction of its previously announced Fayetteville Express Pipeline.  We own a 50% interest in Fayetteville Express Pipeline LLC, and Energy Transfer Partners L.P. owns the remaining interest.  As of February 2010, development continues on the construction of the Fayetteville Express Pipeline, a 187-mile, 42-inch diameter natural gas pipeline that will provide shippers in the Arkansas Fayetteville Shale area with takeaway natural gas capacity and further access to growing markets.  The pipeline will extend from Conway County, Arkansas to a terminus located in Panola County, Mississippi, and construction is expected to begin before the end of the first quarter of 2010.

The pipeline will have an initial capacity of two billion cubic feet per day, and has currently secured binding commitments for at least ten years totaling 1.85 billion cubic feet per day of capacity.  Pending necessary regulatory approvals, the pipeline is expected to be in service by late 2010 or early 2011.  Currently, we estimate that the Fayetteville Express Pipeline project will cost approximately $1.2 billion to complete.

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CO2

▪ In July 2009, we announced that we would invest approximately $180 million over the next several years to further expand our carbon dioxide operations in the eastern Permian Basin area of Texas.  The expansion will involve the installation of a 91-mile, 10-inch carbon dioxide distribution pipeline, and the development of a new carbon dioxide flood in the Katz field.  It is anticipated that the carbon dioxide pipeline will be placed in service in early 2011 and initial carbon dioxideinjections into the Katz field will commence shortly thereafter.

Terminals

▪ In the second quarter of 2009, we completed an approximately C$45.6 million expansion project at our Vancouver Wharves bulk marine terminal located in British Columbia, Canada.  We added 250,000 barrels of liquids petroleum storage capacity and expanded copper, zinc, and lead bulk-handling operations at the facility;

▪ Effective April 23, 2009, we acquired certain marine vessels from Megafleet Towing Co., Inc. for an aggregate consideration of $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 acquired assets primarily consist of nine marine vessels that provide towing and harbor boat services along the Gulf coast, the intracoastal waterway, and the Houston Ship Channel;

▪ In May 2009, we completed an approximately $12.8 million expansion at our Cora, Illinois coal terminal.  The expansion project increased terminal storage capacity by approximately 250,000 tons (to 1.25 million tons) and expanded maximum throughput at the terminal to approximately 13 million tons annually;

▪ On July 15, 2009, we announced that we had entered into an agreement with a major oil company and will invest approximately $60 million to construct one million barrels of new petroleum and ethanol storage tank capacity at our liquids terminal located in Carteret, New Jersey.  We expect to complete the project in the first quarter of 2011;

▪ In the fourth quarter of 2009, we brought approximately 450,000 barrels of new liquids storage capacity into service at our Galena Park and Pasadena, Texas liquids terminals, which are located on the Houston Ship Channel.  The incremental tank capacity is supported by multi-year customer agreements.  For the full year 2009, we added approximately 1.85 million barrels of combined liquids storage capacity at these two terminals; and

▪ Effective January 15, 2010, we acquired three unit train ethanol handling terminals from U.S. Development Group (USD) for an aggregate consideration of $197.4 million, consisting of $115.7 million in cash and $81.7 million in common units.  The three train terminals are located in Linden, New Jersey; Baltimore, Maryland; and Dallas, Texas.

As part of the transaction, we announced the formation of a joint venture with U.S. Development Group 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.  The joint agreement will combine USD’s expertise in designing, developing and operating ethanol terminals with our ethanol terminal assets and pipeline assets to create a nationwide distribution network of ethanol handling facilities connected by rail, marine, truck and pipeline, capable of meeting the growing U.S. demand for biofuels.  With the new terminal joint venture and other projects completed or underway (including projects in our Products Pipelines business segment), we expect to handle in excess of 250,000 barrels of ethanol per day in 2010; and

▪ On January 27, 2010, we announced that we had signed a definitive purchase and sale agreement to acquire four terminals from Slay Industries for approximately $98 million in cash.  The facilities 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 to develop.  All of the assets in Sauget have access to the Mississippi River and five rail carriers.

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Debt and Equity Offerings, Swap Agreements, and Debt Retirements

▪ On January 12, 2009, we terminated an existing fixed-to-variable interest rate swap agreement having a notional principal amount of $300 million.  We received proceeds of $144.4 million from the early termination of this swap agreement, and we used the proceeds to reduce the borrowings under our bank credit facility;

▪ On February 2, 2009, we paid $250 million to retire the principal amount of our 6.30% senior notes that matured on that date;

▪ In 2009, we issued a combined 22,942,447 common units, described following.  We used the net proceeds received from the issuance of these common units to reduce the borrowings under our bank credit facility:

On January 16, 2009, we entered into an equity distribution agreement with UBS Securities LLC as sales agent, and according to the provisions of this agreement, we issued 5,488,947 of our common units during 2009.  After commissions, we received net proceeds of $281.2 million from the issuance of these common units;

OnMarch 27, 2009, we completed a public offering of 5,666,000 of our common units at a price of $46.95 per unit, less commissions and underwriting expenses;

OnJuly 6, 2009, we completed a public offering of 6,612,500 of our common units at a price of $51.50 per unit, less commissions and underwriting expenses; and

OnDecember 4, 2009, we completed a public offering of 5,175,000 of our common units at a price of $57.15 per unit, less commissions and underwriting expenses; and

▪ In 2009, we completed two separate public offerings of senior notes, described following.  We used the net proceeds received from the issuance of these notes to reduce the borrowings under our bank credit facility:

On May 14, 2009, we issued 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 6.850% notes due February 15, 2020; and

On September 16, 2009, we issued 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.

2010 Outlook

▪ On November 23, 2009, we announced that we expect to declare cash distributions of $4.40 per unit for 2010, a 4.8% increase over our cash distributions of $4.20 per unit for 2009.  Our expected growth in distributions in 2010 assumes an average West Texas Intermediate (“WTI”) crude oil price of approximately $84 per barrel in 2010.

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 2010, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 segment’s cash flows by approximately $6 million (or 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 2009.  Our 2010 cash distribution expectations do not take into account any capital costs associated with financing any payment we may be required to make of reparations sought by shippers on our West Coast Products Pipelines’ interstate pipelines.  Any resolution of claims of shippers on our West Coast Products Pipelines’ interstate pipelines that requires us to pay reparations, absent other changes, could mean we may not generate sufficient cash from operations to cover our expected cash distributions. There are some items that could be adjusted—such as reductions in operating, general and administrative expenses and/or sustaining capital expenditures—to somewhat enhance cash from operations.  However, cumulative excess coverage may be reduced and/or our general partner may decide to forego part of its incentive distribution in order for us to meet our distribution forecast.  Cumulative excess coverage is cash from operations (as described under Item 7. “Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Partnership Distributions”) generated since our inception in excess of cash distributions paid.

Also on that date, we announced that for the year 2010, we anticipate that (i) our business segments will generate approximately $3.4 billion in earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments; (ii) we will distribute approximately $1.35 billon to our limited partners; and (iii) we will invest approximately $1.5 billion for our capital expansion program (including small acquisitions).

Our anticipated 2010 expansion investment will help drive earnings and cash flow growth in 2010 and beyond, and we estimate that approximately $400 million of the equity required for our 2010 investment program will be funded by cash retained as a function of KMR dividends.  In 2009, our capital expansion program was approximately $3.3 billion—including both sustaining and discretionary capital spending, equity contributions (net of distributions) to our equity investees, and acquisition cash expenditures.

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(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.

(c) Narrative Description of Business

Business Strategy

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

▪ focusing on stable, fee-based energy transportation and storage assets that are 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 approximately60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;

▪ Natural Gas Pipelines—which consists of approximately 15,000 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;

▪ CO2— which produces, markets and transports, through approximately 1,400 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates ten oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;

▪ Terminals—which consists of approximately 120 owned or operated liquids and bulk terminal facilities and more than 32 rail transloading and materials handling facilities located throughout the United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and

▪ Kinder Morgan Canada—which consists of approximately 800 miles of common carrier pipelines, originating at Edmonton, Alberta, for the transportation of crude oil and refined petroleum to the interior of British Columbia and to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington State, along with five associated product terminals.  It also includes a one-third interest in an approximately 1,700-mile integrated crude oil pipeline connecting Canadian and United States producers to refineries in the U.S. Rocky Mountain and Midwest regions, and a 25-mile aviation turbine fuel pipeline serving the Vancouver International Airport.

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Products Pipelines

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

West Coast Products Pipelines

Our West Coast Products Pipelines operations include our SFPP, L.P. operations (sometimes 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 SFPP, L.P. 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 2009, our SFPP mainline pipeline system transported approximately 1,078,800 barrels per day of refined products, with the product mix being approximately 61% gasoline, 22% diesel fuel, and 17% jet fuel.  In 2008, our SFPP pipeline system delivered approximately 1,122,600 barrels per day of refined petroleum products.

Our Calnev Pipeline consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from our facilities at Colton, California to Las Vegas, Nevada.  The pipeline serves the Mojave Desert through deliveries to a terminal at Barstow, California and two nearby major railroad yards.  It also serves Nellis Air Force Base, located in Las Vegas, and also includes approximately 55 miles of pipeline serving Edwards Air Force Base. In 2009, our Calnev pipeline system transported approximately 120,400 barrels per day of refined products, with the product mix being approximately 45% gasoline, 28% diesel fuel, and 27% jet fuel.  In 2008, our Calnev pipeline system delivered approximately 130,700 barrels per day of refined petroleum products.

OurWest Coast Products Pipelines operations include 15 truck-loading terminals (13 on SFPP, L.P. and two on Calnev) with an aggregate usable tankage capacity of approximately 14.8 million barrels.  The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.

Our West Coast Terminals are fee-based terminals located in the Seattle, Portland, San Francisco and Los Angeles areas along the west coast of the United States with a combined total capacity of approximately 8.5 million barrels of storage for both petroleum products and chemicals.

Markets.  Combined, our West Coast Products Pipelines operations’ pipelines transport approximately 1.2 million barrels per day of refined petroleum products, providing pipeline service to approximately 31 customer-owned terminals, 11 commercial airports and 15 military bases. Currently, our West Coast Products Pipelines operations’ pipelines serve approximately 74 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 volumes may be lower during the first and fourth quarters of each year.

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

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

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

Plantation Pipe Line Company

We own approximately 51% of Plantation Pipe Line Company, 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 its wholly-owned subsidiary, 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 49% ownership interest, and ExxonMobil is the largest shipper on the Plantation system both in terms of volumes and revenues.

In 2009, Plantation delivered approximately 487,000 barrels per day of refined petroleum products.  These delivered volumes were comprised of gasoline (63%), diesel/heating oil (22%) and jet fuel (15%).  In 2008, Plantation delivered approximately 480,000 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 2009, Plantation’s top seven shippers represented approximately 87% 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).

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 the northeastern United States.

Central Florida Pipeline

Our Central Florida pipeline system consists of (i) a 110-mile, 16-inch diameter pipeline that transports gasoline and ethanol and (ii) an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando.  In addition to being connected to our Tampa terminal, the pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, BP, and Marathon Petroleum.  The 10-inch diameter pipeline is connected to our Taft, Florida terminal (located near Orlando), has an 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 2009, the pipeline system transported approximately 107,100 barrels per day of refined products, with the product mix being approximately 69% gasoline and ethanol, 12% diesel fuel, and 19% jet fuel.  In 2008, our Central Florida pipeline system delivered approximately 106,700 barrels per day of refined petroleum products.

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

Markets. The 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 375,000 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.  Most of the jet fuel used at Orlando International Airport is moved through our Tampa terminal and the Central Florida pipeline system.  The market in Central Florida is seasonal 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 are utilizing tariff incentives to attract volumes to the pipeline that might otherwise enter the Orlando market area by truck from Tampa or by marine vessel into Cape Canaveral.  We believe it is unlikely that a new pipeline system comparable in size and scope to our Central Florida pipeline system will be constructed, due to the high cost of pipeline construction, tariff regulation and environmental and right-of-way permitting in Florida.  However, the possibility of such a pipeline or a smaller capacity pipeline being built is a continuing competitive factor.

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

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 2009 and 2008, the pipeline system transported approximately 29,300 and 30,800 barrels per day of natural gas liquids, respectively.

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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

Our Cypress pipeline is an interstate common carrier natural gas liquids pipeline originating at storage facilities in Mont Belvieu, Texas and extending 104 miles east to a connection with Westlake Chemical Corporation, a major petrochemical producer in the Lake Charles, Louisiana area.  Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for natural gas liquids gathering, transportation, fractionation and storage in the United States.  In 2009 and 2008, the pipeline system transported approximately 43,400 and 43,900 barrels per day of natural gas liquids, respectively.  On July 14, 2009, we received notice from Westlake Petrochemicals LLC, a wholly-owned subsidiary of Westlake Chemical Corporation, that it was exercising its option to purchase a 50% ownership interest in our Cypress Pipeline; however, we expect the transaction to close no earlier than the end of the first quarter of 2010.

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

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

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

Southeast Terminals

Our Southeast terminal operations consist of 24 high-quality, liquid petroleum products terminals located along the Plantation/Colonial pipeline corridor in the Southeastern United States.  The terminals are owned and operated by our subsidiary, Kinder Morgan Southeast Terminals LLC and its consolidated affiliate, Guilford County Terminal Company, LLC.  Combined, our Southeast terminals have a total storage capacity of approximately 8.2 million barrels.  In 2009 and 2008, these terminals transferred approximately 348,000 and 351,000 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.  During 2009, our Southeast terminal operations continued to expand their ethanol blending and storage services into several conventional gasoline markets.  The new ethanol blending facilities added in 2009 are located in Collins, Mississippi; Knoxville, Tennessee; Charlotte and Greensboro, North Carolina; and Roanoke, Virginia.  Longer term storage is available at many of the terminals.  Combined, the 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.

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.

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Transmix Operations

Our Transmix operations include the processing of petroleum pipeline transmix, a blend of dissimilar refined petroleum products that have become co-mingled in the pipeline transportation process.  During pipeline transportation, different products are transported through the pipelines abutting each other, and generate a volume of different mixed products called transmix.  At our transmix processing facilities, we process and separate pipeline transmix into pipeline-quality gasoline and light distillate products.  We process transmix at six separate processing facilities located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina.  Combined, our transmix facilities processed approximately 10.0 million and 10.4 million barrels of transmix in 2009 and 2008, 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 area and the New York Harbor are the target markets for our Illinois and Pennsylvania assets, respectively.  Our West Coast transmix processing operations support the markets served by our Pacific operations in Southern California.

Supply.  Transmix generated by Plantation, Colonial, Explorer, Sun, 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.

Competition.  Placid Refining is our main competitor in the Gulf Coast area.  There are various processors in the Mid-Continent area who compete with our transmix facilities, primarily ConocoPhillips, Gladieux Refining and Williams Energy Services.  Motiva Enterprises’s transmix facility located near Linden, New Jersey is the principal competition for New York Harbor transmix supply and for our Indianola facility.  A number of smaller organizations operate transmix processing facilities in the West and Southwest.  These operations compete for supply that we envision as the basis for growth in the west and southwest 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 15,000 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 Kinder Morgan Treating L.P.

Texas Intrastate Natural Gas Pipeline Group

Our Texas intrastate natural gas pipeline group, which operates primarily along the Texas Gulf Coast, consists of the following four natural gas pipeline systems (i) our Kinder Morgan Texas Pipeline; (ii) our Kinder Morgan Tejas Pipeline; (iii) our Mier-Monterrey Mexico Pipeline; and (iv) our Kinder Morgan North Texas Pipeline.

The two largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder Morgan Tejas Pipeline.  These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability.  The combined system includes approximately 6,000 miles of intrastate natural gas pipelines with a peak transport and sales capacity of approximately 5.2 billion cubic feet per day of natural gas and approximately 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.

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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, Kleburg County, Texas.  The pipeline has a capacity of approximately 300 million cubic feet of natural gas per day and is capable of importing this volume of Mexican gas into the United States or exporting this volume of gas to Mexico.

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

Our Kinder Morgan North Texas Pipeline consists of an 82-mile pipeline that transports natural gas from an interconnect with the facilities of 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 two existing storage caverns providing approximately 6.1 billion cubic feet of total capacity, consisting of 4.0 billion cubic feet of working capacity and 2.1 billion cubic feet of cushion gas.  We have entered into a long-term storage capacity and transportation agreement with NRG Energy, Inc. covering two billion cubic feet of natural gas working capacity that expires in March 2017.  In June 2006, we announced an expansion project that will significantly increase natural gas storage capacity at our North Dayton facility.  The project is now expected to cost between $100 million and $105 million and involves the development of a new underground storage cavern that will add an estimated 7.0 billion cubic feet of incremental working natural gas storage capacity.  The additional capacity is expected to be available in the third quarter of 2010.

We also own the West Clear Lake natural gas storage facility located in Harris County, Texas, and we lease both a salt dome storage facility 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 25.0 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 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 150 million cubic feet per day.  In addition to the aforementioned storage facilities, we contract for storage services from third parties, which we then sell to customers on our pipeline system.

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Additionally, effective November 1, 2009, we acquired a 40% equity ownership interest in Endeavor Gathering LLC, as 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 2009, deliveries through the existing interconnection near Arguellas fluctuated from zero to approximately 194 million cubic feet per day of natural gas.  Deliveries to Monterrey also ranged from zero to 309 million cubic feet per day.  We primarily provide transport service to these markets on a fee for service basis, including a significant demand component, which is paid regardless of actual throughput.  Revenues earned from our activities in Mexico are paid in U.S. dollar equivalent.

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

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

Kinder Morgan Treating L.P.

Our subsidiary, Kinder Morgan Treating, L.P., owns and operates (or leases to producers for operation) treating plants that remove impurities (carbon dioxide, hydrogen sulfide, and hydrocarbon liquids) 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 225 natural gas amine-treating plants and approximately 56 dew point control plants.

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 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.  Typically these plants use a Joules-Thompson expansion process to lower the temperature of the gas stream and collect the liquids before they enter the downstream pipeline.  As of December 31, 2009, we had approximately 200 treating and dew point control plants in operation.

Supply. We believe we have the largest natural gas treating fleet operation in the United States.  Natural gas from certain formations in the Texas Gulf Coast, as well as other locations, 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 formations in the Texas Gulf Coast, both of which are deep formations that are high in carbon dioxide.  We typically charge a fixed monthly rental fee plus, in those instances where we operate the equipment, a fixed monthly operating fee.

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Markets.  Many of the shale reservoirs being developed today have concentrations of carbon dioxide above the normal pipeline quality specifications of 2.0%.  The Haynesville Shale rock formation in northwest Louisiana and East Texas is experiencing robust development, and we believe that our treating business strategy is well suited to the producers in the Haynesville Shale.

Competition. Our natural gas treating operations face competition from manufacturers of new treating and 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.

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) our Kinder Morgan Interstate Gas Transmission Pipeline; (ii) our Trans Colorado Pipeline; and (iii) our 50% ownership interest in the Rockies Express Pipeline.

Kinder Morgan Interstate Gas Transmission LLC

Our subsidiary, Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, owns approximately 5,100 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska.  The KMIGT pipeline system is powered by 26 transmission and storage compressor stations having approximately 160,000 horsepower.  KMIGT also owns the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, which has approximately 11 billion cubic feet of firm capacity commitments and provides for withdrawal 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.

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

Markets.  Markets served by 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 seen a significant increase in demand from ethanol producers, and has expanded its system to meet the demands from the ethanol producing community.  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.

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Supply. As of December 31, 2009, approximately 13%, by volume, of KMIGT’s firm contracts expire within one year and 45% expire between one and five years.  Over 96% of the system’s total firm transport capacity is currently subscribed, with68% of KMIGT’s transport business in 2009 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 Bloomfield, New Mexico.  It has multiple points of interconnection with various interstate and intrastate pipelines, gathering systems, and local distribution companies.  The TransColorado pipeline system is powered by eight compressor stations having an aggregate of approximately 40,000 horsepower.

The TransColorado system has the ability to flow gas south or north.  It receives gas from one coal seam natural gas treating plant, located in the San Juan Basin of Colorado, and from pipeline, processing plant and gathering system interconnections within the Paradox and Piceance Basins of western Colorado.  Gas flowing south through the pipeline system flows into the El Paso, Transwestern and Questar Southern Trail pipeline systems, and gas moving north through the pipeline 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.  The 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 2009 and 2008, TransColorado transported an average of approximately 617 million and 675 million cubic feet per day of natural gas from these supply basins, respectively.

Supply. During 2009, 97% of TransColorado’s transport business was with processors or producers or their own marketing affiliates, and 3% was with marketing companies and various gas marketers.  Approximately 69% of TransColorado’s transport business in 2009 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 2010.  As of December 31, 2009, approximately 26%, by volume, of TransColorado’s firm transportation contracts expire within one year, and 23% expire between one and five years; however, TransColorado is actively pursuing contract extensions and/or replacement contracts to increase firm subscription levels beyond 2010.

Competition.  TransColorado competes with other transporters of natural gas in each of the natural gas supply basins it serves.  These competitors include both interstate and intrastate natural gas pipelines and natural gas gathering systems.  TransColorado’s shippers compete for market share with shippers drawing upon gas production facilities within the New Mexico portion of the San Juan Basin.  TransColorado has phased its past construction and expansion efforts to coincide with the ability of the interstate pipeline grid at Blanco, New Mexico and at the north end of its system to accommodate greater natural gas volumes.

Historically, the competition faced by TransColorado with respect to its natural gas transportation services has generally been based upon the price differential between the San Juan and Rocky Mountain Basins.  New pipelines servicing these producing basins and a reduction of rigs drilling in this area for gas have had the effect of reducing that price differential.

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Rockies Express Pipeline

We operate and currently 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 entire 1,679-mile system is powered by 18 compressor stations totaling approximately 412,000 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.  Now fully complete, the Rockies Express system has binding firm commitments secured for nearly all of the 1.8 billion cubic feet per day of pipeline capacity.  We account for our investment in Rockies Express under the equity method of accounting, and 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 Midcontinent area of the Unites States through various interconnects with other major interstate pipelines in Nebraska (Northern Natural Gas Pipeline and NGPL), Kansas (ANR Pipeline), and Missouri (Panhandle Eastern Pipeline), and through a connection with our subsidiary, KMIGT.

The Rockies Express system’s 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 and Vectren.

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

Central Interstate Natural Gas Pipeline Group

Our Central interstate natural gas pipeline group, which operates primarily in the mid-continent portion of the United States, consists of the following four natural gas pipeline systems (i) our Trailblazer Pipeline; (ii) our 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.

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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.  Trailblazer’s pipeline originates at an interconnection with Wyoming Interstate Company Ltd.’s pipeline system near Rockport, Colorado and runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where it interconnects with NGPL’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.

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, 2009, none of Trailblazer’s firm contracts, by volume, expire before one year and 53%, by volume, expire within one to five years.  Affiliated entities have contracted for less than 1% of the total firm transportation capacity.  All of the system’s firm transport capacity is currently subscribed.

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

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:

▪ 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 in Acadia Parish, Louisiana); and

▪ a 1-mile, 36-inch diameter pipeline with firm capacity of approximately 1.2 billion cubic feet per day that extends from the Sabine Pass terminal and connects to NGPL’s natural gas pipeline.

We commenced limited natural gas transportation service on the Kinder Morgan Louisiana pipeline system in April 2009, and construction was fully completed and transportation service on the system’s remaining portions began in full on June 21, 2009.

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, and we account for our investment under the equity method of accounting.  Energy Transfer Partners, L.P. owns the remaining 50% interest in Midcontinent Express Pipeline LLC.

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.  The Midcontinent Express transmission system commenced interim service for Zone 1 of its pipeline system on April 10, 2009, with deliveries to NGPL, and natural gas service to all Zone 1 delivery points occurred by May 21, 2009.  On August 1, 2009, Zone 2, the system’s remaining portion, was placed into service.  Now fully operational, it has the capability to transport up to 1.4 billion cubic feet per day of natural gas, and the pipeline capacity is fully subscribed with long-term binding commitments from creditworthy shippers.

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Fayetteville Express Pipeline LLC

Fayetteville Express Pipeline LLC is currently developing the Fayetteville Express natural gas pipeline system.  We own a 50% interest in Fayetteville Express Pipeline LLC, and we account for our investment under the equity method of accounting.  Energy Transfer Partners L.P. owns the remaining interest and will operate the Fayetteville Express pipeline system, which when completed, will consist of a 187-mile, 42-inch diameter pipeline originating in Conway County, Arkansas, continuing eastward through White County, Arkansas, and terminating at an interconnect with Trunkline Gas Company’s pipeline in Panola County, Mississippi.  The system will also interconnect 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, and will parallel existing pipeline or electric transmission right-of-ways where possible to minimize impact to the environment, communities and landowners.

The Fayetteville Express pipeline system will have an initial capacity of 2.0 billion cubic feet of natural gas per day.  Pending necessary regulatory approvals, the approximate$1.2 billion pipeline project is expected to be in service by early 2011.  Fayetteville Express Pipeline LLC has secured binding 10-year commitments totaling approximately 1.85 billion cubic feet per day.  On December 17, 2009, the FERC approved and issued the pipeline’s certificate application authorizing construction, and pending the FERC’s approval of Fayetteville Express’ implementation plan, construction of the pipeline is expected to begin before the end of the first quarter of 2010.  The pipeline is expected to be in service by late 2010 or early 2011.

Upstream

Our Natural Gas Pipelines’ upstream operations consist of our Casper and Douglas 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, which have the capacity to process up to 185 million cubic feet per day of natural gas depending on raw gas quality.

Markets.  Casper and Douglas are processing plants servicing gas streams flowing into 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 their Powder River natural gas liquids pipeline for either ultimate consumption at the Borger refinery or for further disposition to the natural gas liquids trading hubs located in Conway, Kansas and Mont Belvieu, Texas.

Competition. Other regional facilities in the Greater Powder River Basin include (i) the Hilight plant, which has a processing capacity of approximately 80 million cubic feet per day and is owned and operated by Anadarko; (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 Rawlins plant, which has a processing capacity of approximately 230 million cubic feet per day and is owned and operated by El Paso.  Casper and Douglas, however, are the only plants which provide straddle processing of natural gas flowing into the KMIGT pipeline system.

West Frenchie Draw Treater

In the first quarter of 2009, we placed into service a new carbon dioxide/sulfur treating facility in the West Frenchie Draw field of the Wind River Basin of Wyoming.  This is a 50 million cubic feet per day treating facility which 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 KMIGT.

Red Cedar Gathering Company

We own a 49% equity interest in the Red Cedar Gathering Company, a joint venture organized in August 1994 and referred to in this report as Red Cedar.  The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe.  Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado.  The Ignacio Blanco Field lies within the Colorado portion of the San Juan Basin, most of which is located within the exterior boundaries of the Southern Ute Indian Tribe Reservation.

Red Cedar gathers coal seam and conventional natural gas at wellheads and several central delivery points for treating, compression and delivery into any one of three major interstate natural gas pipeline systems and an intrastate pipeline.  Red Cedar’s gas gathering system currently consists of approximately 743 miles of gathering pipeline connecting more than 1,200 producing wells, 96,250 horsepower of compression at 23 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.

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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.

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.  We also hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas.

Oil Producing Activities

KMCO2 also 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 96% working interest in the Katz CB Long unit; (vi) a 100% working interest in the Katz SW River unit; (vii) a 100% working interest in the Katz East River unit; and (viii) 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 1.32 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 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 2009, the average purchased carbon dioxide injection rate at SACROC was 253 million cubic feet per day, down from an average of 259 million cubic feet per day in 2008.  The average oil production rate for 2009 was approximately 30,100 barrels of oil per day, up from an average of approximately 28,000 barrels of oil per day during 2008.  The average natural gas liquids production rate (net of the processing plant share) for 2009 was approximately 6,500 barrels per day, an increase from an average of approximately 5,500 barrels per day during 2008.

Our plan has been to increase the production rate and ultimate oil recovery from Yates by combining horizontal drilling with carbon dioxide injection to ensure a relatively steady production profile over the next several years.  We are implementing our plan and during 2009, the Yates unit produced approximately 26,500 barrels of oil per day, down from an average of approximately 27,600 barrels of oil per day during 2008.  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 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 218 barrels of oil per day during 2009, down from an average of 235 barrels of oil per day during 2008.  We are presently evaluating operating and subsurface technical data from the Claytonville unit to further assess redevelopment opportunities including carbon dioxide flood operations.

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We also operate and own working interests in the Katz CB Long unit, the Katz Southwest River unit and Katz East River unit.  The Katz field is located in the Permian Basin area of West Texas and during 2009, the field produced 380 barrels of oil per day, down from an average of 425 barrels of oil per day during 2008.  In July 2009, we announced that we would invest approximately $183 million over the next several years to further expand our operations in the eastern Permian Basin area of Texas. The expansion will involve the installation of a 91-mile, 10-inch carbon dioxide distribution pipeline, and the development of a new carbon dioxide flood in the Katz field.  It is anticipated that the carbon dioxide pipeline will be placed in service in early 2011 and initial carbon dioxideinjections into the Katz field will commence shortly thereafter.

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 gas produced from the SACROC unit and neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell units, all of which are located in the Permian Basin area of West Texas.  The Diamond M and the North Snyder plants contract with the Snyder plant to process gas.  Production of natural gas liquids at the Snyder gasoline plant during December 2009 was approximately 14,500 barrels per day, compared to 13,900 barrels per day in December 2008.

Carbon Dioxide Reserves

We own approximately 45% of, and operate, the McElmo Dome unit in Colorado, which contains more than ten 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, which contains more than one trillion cubic feet of recoverable carbon dioxide and produces approximately 300 million cubic feet per day, and an approximately 87% ownership interest in the Doe Canyon Deep unit in Colorado, which contains more than 1.5 trillion 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 Cortez pipeline currently transports over 1,200 million cubic feet of carbon dioxide per day, including approximately 99% of the carbon dioxide transported downstream on our Central Basin pipeline and our Centerline pipeline (discussed following).  The tariffs charged by Cortez Pipeline are not regulated.

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.

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

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

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

Markets. The principal market for transportation on our carbon dioxide pipelines is to customers, including ourselves, using carbon dioxide for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to 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 segment that runs from Wink to El Paso has a total capacity of 130,000 barrels of crude oil per day.  The pipeline allows us to better manage crude oil deliveries from our oil field interests in West Texas, and we have entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western’s 120,000 barrel per day refinery in El Paso.  The 20-inch pipeline segment transported approximately117,000 barrels of oil per day in 2009 and approximately118,000 barrels of oil per day in 2008.  The Kinder Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad Commission.

Terminals

Our Terminals segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel, ores and dry-bulk material services, including all transload, engineering, conveying and other in-plant services.  Combined, the segment is composed of approximately121 owned or operated liquids and bulk terminal facilities and more than 33 rail transloading and materials handling facilities located throughout the United States, Canada, and the Netherlands.

Liquids Terminals

Our liquids terminals operations primarily store refined petroleum products, petrochemicals, industrial chemicals and vegetable oil products in aboveground storage tanks and transfer products to and from pipelines, vessels, tank trucks, tank barges, and tank railcars.  Combined, our liquids terminals facilities possess liquids storage capacity of approximately 56.4 million barrels, and in 2009 and 2008, these terminals handled approximately 604 million barrels and 597 million barrels, respectively, of petroleum, chemicals and vegetable oil products.

Our major liquids terminal assets include the following:

▪ our 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 26.2 million barrels of capacity and is connected via pipeline to 14 refineries, four petrochemical plants and ten major outbound pipelines.  Combined, our Pasadena and Galena Park terminals brought an incremental 1.85 million barrels of liquids storage capacity online during 2009 (including incremental truck loading capacity) as refinery outputs along the Gulf Coast have continued to increase.  Since our acquisition of the terminal complex in January 2001, we have upgraded our pipeline manifold connection with the Colonial Pipeline system, added pipeline connections to new refineries and an additional cross-channel pipeline to increase the connectivity between the two terminals, and constructed an additional loading bay at our fully automated truck loading rack located at our Pasadena terminal.  In addition, the facilities have five ship docks and seven barge docks for inbound and outbound movement of products.  The terminals are served by the Union Pacific railroad;

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

The Carteret facility is located along the Arthur Kill River just south of New York City and has a capacity of approximately 7.8 million barrels of petroleum and petrochemical products.  Since our acquisition of the terminal in January 2001, we have added more than 1.5 million barrels of new storage capacity and completed the construction of a 16-inch diameter pipeline that connects to the Buckeye pipeline system, a major products pipeline serving the East Coast.  In the second quarter of 2009, we announced a major expansion to the facility, which will add over one million barrels of new liquids capacity for a large petroleum customer.  We expect the expansion to come on-line in the first quarter 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 and aggregates.  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 has a storage capacity of approximately 3.0 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 since our acquisition of the terminal in July 2005, we have constructed ship and barge berths at the facility that accommodate 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; and

▪ our Kinder Morgan North 40 terminal located near Edmonton, Alberta, Canada.  We constructed and placed into service our North 40 terminal, which 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 2.15 million barrels of crude oil and has access to more than 20 incoming pipelines and several major outbound systems, including a connection with our Trans Mountain pipeline system.  The entire capacity of this terminal is contracted under long-term contracts.

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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.  Combined, our dry-bulk and material transloading facilities handled approximately 78 million tons and 105 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2009 and 2008, respectively.  We own or operate approximately 95 dry-bulk terminals in the United States, Canada and the Netherlands.

Our major bulk terminal assets include the following:

▪ our Vancouver Wharves bulk marine terminal, located at the entrance to the Port of Vancouver, British Columbia, Canada.  We own certain bulk terminal buildings and equipment, and we operate the terminal under a 40-year 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 a shiploader.  The terminal can handle over 3.5 million tons of cargo annually.  In the second quarter of 2009, we completed a terminal expansion that brought on-line an additional 225,000 barrels of liquids capacity.  Vancouver Wharves has access to three major rail carriers connecting to shippers in western and central Canada and the U.S. Pacific Northwest.  Vancouver Wharves offers a variety of inbound, outbound and value-added services for mineral concentrates, wood products, agri-products and sulfur;

▪ our approximately 32 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 2009, we handled approximately 12.9 million tons of petroleum coke, as compared to approximately 14.8 million tons in 2008.  Petroleum coke is a by-product of the crude oil refining process and has characteristics similar to coal.  It is used in domestic utility and industrial steam generation facilities and by the steel industry in the manufacture of ferro alloys and carbon and graphite products.  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.  All of our petroleum coke assets are located in the state of Texas, and include facilities at the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship Channel.  These facilities also provide handling and storage services for a variety of other bulk materials.

In 2009, we also handled approximately 27.8 million tons of coal, as compared to approximately 34.3 million tons of coal handled in 2008.  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.

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Our Cora and Grand Rivers terminals handle low sulfur coal originating in Wyoming, Colorado, and Utah, as well as coal that originates in the mines of southern Illinois and western Kentucky.  However, since many shippers, particularly in the East, are using western coal or a mixture of western coal and other coals as a means of meeting environmental restrictions, we anticipate that growth in volume through the two terminals will be primarily due to increased use of western low sulfur coal originating in Wyoming, Colorado and Utah;

▪ our approximately 47 ferro alloys terminals located at strategic locations throughout the United States, which transload and handle steel, ferro chrome, ferro manganese, ferro silicon, silicon metal and many other alloys and ores.  Our value-added services include canning, drumming, bagging and filling boxes and supersacks, and our handling methods and integrity eliminates product degradation and assures accurate inventory control.  Combined, these facilities handled approximately 15.7 million tons and 30.8 million tons of ores/metals in 2009 and 2008, respectively.  The 49% decrease in year-to-year volumes was primarily due to the difficult economic environment during 2009, and 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.

In addition to steel handling activities at our Vancouver Wharves bulk marine terminal, we handle numerous types of steel and bulk commodities at two deepwater port facilities: our Chesapeake bulk terminal facility, located on Chesapeake Bay in Sparrows Point, Maryland; and our Berkley facility, located in Huger, South Carolina.  Our Chesapeake terminal offers stevedoring services, storage, and rail, ground, or water transportation for products such as coal, petroleum coke, iron and steel slag, and other mineral products.  It offers both warehouse storage and approximately 100 acres of open storage.  The facility is serviced by the Norfolk Southern and CSX railroads and offers storage services to and from vessels, barges, tank trucks or rail cars.  Our Berkley facility provides dedicated storage to Nucor Corporation (a large domestic steel company with significant operations in the Southeast region of the United States) for finished steel, scrap, hot briquetted iron, and direct reduced iron along the Cooper River.  The facility also provides scrap handling and processing services, and can unload barges, vessels and railcars.

Our Kinder Morgan Texas terminal is a 30-acre site, which provides 50,000 square feet of climate-controlled, covered storage, and provides another 100,000 square feet of leased covered storage located on the Houston Ship Channel.  The facility can handle coils, pipe, and other finished steel products.  The facility also has 55 rail spots and performs rail loading and unloading services.

Our river steel facilities include facilities on the Mississippi, Ohio, Tennessee, Missouri, and Arkansas rivers, and on other smaller inland waterways.  Our Hickman and Barfield terminals are located near Blytheville, Arkansas, and provide storage and handling services on the Mississippi river, primarily for Nucor.  Both facilities can service barge, truck, and perform rail loading and unloading.  Our Industry facility is located along the Ohio River in Industry, Pennsylvania, and it provides 435,000 square feet of covered warehouse space and 200,000 square feet of open storage.  This facility primarily handles ferro alloy products, and provides value-added ancillary services such as screening, processing, and packaging of alloy products.  Our Decatur, Alabama facility is located along the Tennessee River and provides dedicated storage to Nucor as well as scrap handling and charge bucket handling.

In September 2007, we acquired five steel handling facilities from Marine Terminals, Inc. (including those described above that are primarily dedicated to servicing Nucor’s steel plants), and as part of our asset purchase, we entered into a service contract with Nucor.  We estimate that approximately 95% of the projected revenues and profits of these five facilities will be generated from this contract with Nucor; and

▪ our Pier IX terminal located on a 30-acre storage site in Newport News, Virginia.  The terminal has the capacity to transload approximately 12 million tons of bulk products per year, and for coal, offers storage capacity of 1.4 million tons, 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.

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.

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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 2009 and 2008, our materials services operations handled approximately 227,000 and 348,000 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.

Trans Mountain Pipeline System

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

Trans Mountain’s pipeline is 715 miles in length. The capacity of the line at Edmonton ranges from 300,000 barrels per day when heavy crude represents 20% of the total throughput (which is a historically normal heavy crude percentage) to 400,000 barrels per day with no heavy crude.

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

In 2009, deliveries on Trans Mountain averaged 280,507 barrels per day.  This was an increase of 18% from average 2008 deliveries of 237,172 barrels per day.  Shipments of refined petroleum also represent a significant portion of Trans Mountain’s throughput.  In2009 and 2008, combined shipments of refined petroleum and iso-octane represented 20% of pipeline throughput.

The crude oil and refined petroleum transported through Trans Mountain’s pipeline system originates in Alberta and British Columbia. The refined and partially refined petroleum transported to Kamloops, British Columbia and Vancouver originates from oil refineries located in Edmonton.  Petroleum products delivered through Trans Mountain’s pipeline system are used in markets in British Columbia, Washington State and elsewhere.

Overall, Alberta crude oil supply has been increasing steadily over the past few years as a result of significant oil sands development, with projects led by firms including Royal Dutch Shell, Suncor Energy and Syncrude Canada. Notwithstanding current economic factors and some announced project delays, further development is expected to continue into the future with expansions to existing oil sands production facilities as well as with new projects.  In its moderate growth case, the Canadian Association of Petroleum Producers forecasts Western Canadian crude oil production to increase by over 1.4 million barrels per day by 2015.  While recently expanded pipeline capacity to the United States results in excess capacity currently, the long term increase in supply will require additional export capacity from Western Canada to both U.S. and offshore markets later this decade.  This long term supply growth and increasing global demand supports our view that the demand for transportation services provided by Trans Mountain’s pipeline will remain strong for the foreseeable future.

Competition. Trans Mountain’s pipeline to the West Coast of North America is one of several pipeline alternatives for Western Canadian petroleum production.  This pipeline, like all our petroleum pipelines, competes against other pipeline companies who could be in a position to offer different tolling structures.

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Express and Jet Fuel Pipeline Systems

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

The Express Pipeline is a 780-mile, 24-inch diameter pipeline that begins at the crude oil pipeline hub at Hardisty, Alberta and terminates at the Casper, Wyoming facilities of the Platte Pipeline.  At the Hardisty, Canada oil hub, the Express Pipeline receives a variety of light, medium and heavy crude oil produced in Western Canada, and makes deliveries to markets in Montana, Wyoming, Utah and Colorado.  The Express Pipeline has a design capacity of 280,000 barrels per day.  Receipts at Hardisty averaged 208,246 barrels per day in 2009, as compared to 196,160 barrels per day in 2008.

The Platte Pipeline is a 926-mile, 20-inch diameter pipeline that runs from the crude oil pipeline hub at Casper, Wyoming to refineries and interconnecting pipelines in the Wood River, Illinois area, and includes related pumping and storage facilities (including tanks). The Platte Pipeline transports crude oil shipped on the Express Pipeline and crude oil produced from the Rocky Mountain area of the U.S. to markets located in Kansas and Illinois, and to other interconnecting carriers in those areas.  The Platte Pipeline has a 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 137,810 barrels per day during 2009, as compared to 133,637 barrels per day during 2008.

The current Express pipeline system rate structure is a combination of committed rates and uncommitted rates. The committed rates apply to those shippers who have signed long-term (10 or 15 year) contracts with the Express pipeline system to transport crude oil on a ship-or-pay basis.  As of December 31, 2009, Express had total firm commitments of approximately 231,000 barrels per day, or 83% of its total capacity.  These contracts expire in 2012, 2014 and 2015 in amounts of 40%, 11% and 32% of total capacity, respectively.  The remaining contracts provide for committed tolls for transportation on the Express pipeline system, and can be increased each year by up to 2%.  The capacity in excess of 231,000 barrels per day is made available to shippers as uncommitted capacity.

We also own and operate the approximate 25-mile aviation turbine fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada.  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 the Port of 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 volume of 15,000 barrels.

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

Major Customers

Our total operating revenues are derived from a wide customer base.For each of the years ended December 31, 2009, 2008 and 2007, 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 2009, 2008 and 2007 accounted for 44.8%, 65.6% and 63.3%, respectively, of our total consolidated revenues.

As a result of our Texas intrastate group selling natural gas in the same price environment in which it is purchased, both our total consolidated revenues and our total consolidated purchases (cost of sales) increase considerably due to the inclusion of the cost of gas in both financial statement line items.  However, these higher revenues and higher purchased gas costs do not necessarily translate into increased margins, in comparison to those situations in which we charge a fee to transport gas owned by others.  To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales.  We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

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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 may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively.  Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

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

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

Common Carrier Pipeline Rate Regulation – Canadian Operations

The Canadian portion of our crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of Canada’s National Energy Board, referred to in this report as the NEB.  The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service.

Trans Mountain.  In the fourth quarter of 2006, our subsidiary Trans Mountain Pipeline L.P. completed negotiations with the Canadian Association of Petroleum Producers and principal shippers for a new incentive toll settlement for our Trans Mountain Pipeline to be effective for the period starting January 1, 2006 and ending December 31, 2010.  The 2006 toll settlement incorporates an incentive toll mechanism that is intended to provide Trans Mountain with the opportunity to earn a return on equity greater than that calculated using the formula established by the NEB.  In return for this opportunity, Trans Mountain has agreed to assume certain risks and provide cost certainty in certain areas.  Part of the incentive toll mechanism specifies that Trans Mountain is allowed to keep 75% of the net revenue generated by throughput in excess of 92.5% of the capacity of the pipeline.

The 2006 incentive toll settlement provides for base tolls which will remain in effect for the five-year period, unless recalculated or adjusted in certain specified circumstances.  The toll settlement also governs the financial arrangements for two expansion projects which were completed during 2007 and 2008.  Combined, the projects cost approximately C$765 million and added 75,000 barrels per day of incremental capacity to the system, increasing pipeline capacity to approximately 300,000 barrels per day.  The toll charged for the portion of Trans Mountain’s pipeline system located in the United States falls under the jurisdiction of the FERC.  See “—Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation – U.S. Operations” preceding.

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Express Pipeline System.

The Canadian segment of the Express Pipeline is regulated by the NEB as a Group 2 pipeline, which results in rates and terms of service being regulated on a complaint basis only.  Express committed rates are subject to a 2% inflation adjustment April 1 of each year.  The U.S. segment of the Express Pipeline and the Platte Pipeline are regulated by the FERC.  See “—Interstate Common Carrier Refined Petroleum 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 and storage services under the Natural Gas Act.  To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978.  Beginning in the mid-1980’s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace.  Among the most important of these changes were:

▪ the Energy Policy Act of 2005 (2005), which, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, directed the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and significantly increased the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder;

▪ Order No. 436 (1985) which required open-access, nondiscriminatory transportation of natural gas;

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

▪ Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies.

Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage).  Order No. 636 contains a number of procedures designed to increase competition in the interstate natural gas industry, including: (i) requiring the unbundling of sales services from other services; (ii) permitting holders of firm capacity on interstate natural gas pipelines to release all or a part of their capacity for resale by the pipeline; and (iii) providing for the issuance of blanket sales certificates to interstate pipelines for unbundled services.  Order No. 636 has been affirmed in all material respects upon judicial review, and our own FERC orders approving our unbundling plans are final and not subject to any pending judicial review; and

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▪ Order No. 717 (2008 and 2009) 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 as used in Order No. 497.

On November 25, 2003, the FERC issued Order No. 2004, adopting revised standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities.  In light of the changing structure of the energy industry, these standards of conduct govern relationships between regulated interstate natural gas pipelines and all of their energy affiliates.  These standards were designed to (i) eliminate the loophole in the previous regulations that did not cover an interstate natural gas pipeline’s relationship with energy affiliates that are not marketers; (ii) prevent interstate natural gas pipelines from giving an undue preference to any of their energy affiliates; and (iii) ensure that transmission is provided on a nondiscriminatory basis.  In addition, unlike the prior regulations, these requirements applied even if the energy affiliate was not a customer of its affiliated interstate pipeline.  However, on November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated FERC Order No. 2004 as applied to natural gas pipelines, and remanded these same orders back to the FERC.

On October 16, 2008, the FERC issued a Final Rule in Order No. 717.  According to the provisions of Order No. 717, a transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer.  The final rule also retains the long-standing no-conduit rule, which prohibits a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit.  Additionally, the final rule requires that a transmission provider provide annual training on the Standards of Conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information.  This rule became effective November 26, 2008.

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 certain 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.

California Public Utilities Commission Rate Regulation

The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the California Public Utilities Commission, referred to in this report as the CPUC, under a “depreciated book plant” methodology, which is based on an original cost measure of investment.  Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of our Pacific operations’ business.  Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC.  A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates could also arise with respect to our intrastate rates.  Certain of our Pacific operations’ pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 16 to our consolidated financial statements included elsewhere in this report.

Texas Railroad Commission Rate Regulation

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

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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, and 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.

The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication.  The Pipeline Safety Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as high consequence areas.  Testing consists of hydrostatic testing, internal magnetic flux or ultrasonic testing, or direct assessment of the piping.  In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained.  A similar integrity management rule exists for refined petroleum products pipelines.

In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards.  However, we cannot accurately estimate such increases in expenditures at this time.

State and Local Regulation

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

Environmental Matters

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

Environmental and human health and safety laws and regulations are subject to change.  The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health.  Also, 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 as the U.S. EPA, or similar state agency has identified us as one of the potentially responsible parties.  The involvement of other financially responsible companies at these multiparty sites could increase or mitigate our actual joint and several liability exposures.  Although no assurance can be given, we believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position or results of operations.  We have accrued an environmental reserve in the amount of $81.1 million as of December 31, 2009.  Our reserve estimates range in value from approximately $81.1 million to approximately $138.5 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.

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Hazardous and Non-Hazardous Waste

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

Superfund

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA in this report and commonly known as the Superfund law, and analogous state laws impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment.  These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site.

CERCLA authorizes the U.S. EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any.  Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate materials that may fall within the definition of a hazardous substance.  By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.

Clean Air Act

Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state statutes and regulations.  We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes.  The Clean Air Act regulations contain lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our pipelines, treating facilities, storage facilities and terminals.  Depending on the nature of those requirements and any additional requirements that may be imposed by state and local regulatory authorities, we may be required to incur certain capital and operating expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission-related issues.  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 laws impose restrictions and controls regarding the discharge of pollutants into state waters or waters of the United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities.  The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills.  Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release.

Climate Change

Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earth’s atmosphere.  Methane, a primary component of natural gas, and carbon dioxide, which is naturally occurring and also a byproduct of burning of natural gas, are examples of greenhouse gases.  The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases.  On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “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 is 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 separately announced on December 7, 2009, its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment. These findings by the U.S. EPA may allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In addition, on September 22, 2009, the U.S. EPA 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.

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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.

Some climatic models indicate that global warming is likely to result in sea level rise, 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.

Because natural gas emits less greenhouse gas emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or 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 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.

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

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, 2009, KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. had, in the aggregate, 7,931 full-time employees.  Approximately 890 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2010 and 2014.  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.

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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.  We generally do not own the land on which our pipelines are constructed.  Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time.  Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property.

In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the right-of-way grants.  In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained.  Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways.  In some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense.  Permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election.  Some such permits require annual or other periodic payments.  In a few minor cases, property for pipeline purposes was purchased in fee.  Our terminals, storage facilities, processing plants, regulator and compressor stations, 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.

(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

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

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

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

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

Regulators and shippers on our pipelines have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations.  Some shippers on our pipelines have filed complaints with the FERC and 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.  We may face challenges, similar to those described in Note 16 to our consolidated financial statements included elsewhere in this report, to the rates we receive on our pipelines in the future.  Any successful challenge could adversely and materially affect our future earnings and cash flows.

Rulemaking and oversight, as well as changes in regulations, by the 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, NEB and CPUC, and regulatory actions taken by these agencies have the potential to adversely affect our profitability.  Regulation extends to such matters as: (i) rates, 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, extension, disposition or abandonment of services or facilities; (vii) reporting and information posting requirements; (viii) the maintenance of accounts and records; and (ix) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

New laws or regulations or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to our assets could have a material adverse impact on our business, financial condition and results of operations.

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

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

Environmental, 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, including, for example, under CERCLA, the Resource Conservation and Recovery Act, the Clean Water Act and analogous state laws for the remediation of contaminated areas.  Private parties, including the owners of properties through which our pipelines pass may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage.  Our insurance may not cover all environmental risks and costs 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 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.

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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.

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 the burning of natural gas, are examples of greenhouse gases. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases. In addition, the U.S. EPA announced on December 7, 2009, its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment. These findings by the U.S.  EPA may allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In addition, 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 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 gas processing plants in our natural gas pipelines segment, 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. 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 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.

New regulations issued by the Department of Homeland Security could result in increased operating and capital costs for us.

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

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

We currently have several major expansion and new build projects planned or underway, including the Fayetteville Express Pipeline which is expected to cost $1.2 billion.  A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third party contractors, has resulted in, and may continue to result in, increased costs or delays in construction.  Cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows.

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

Part of our business strategy includes acquiring additional businesses, expanding existing assets, or constructing new facilities.  If we do not successfully integrate acquisitions, expansions, or newly constructed facilities, we may not realize anticipated operating advantages and cost savings.  The integration of companies that have previously operated separately involves a number of risks, including: (i) demands on management related to the increase in our size after an acquisition, an expansion, or a completed construction project; (ii) the diversion of our management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v)  potential adverse effects on operating results.

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

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

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

Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect operations.

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

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

The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative.  It is impossible to predict with certainty the production potential of a particular property or well.  Furthermore, a successful completion of a well does not ensure a profitable return on the investment.  A variety of geological, operational, 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.

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

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

A sharp decline in the price of natural gas, natural gas liquids, or oil prices would result in a commensurate reduction in our revenues, income and cash flows from the production of oil and natural gas and could have a material adverse effect on the carrying value of our proved reserves.  In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss.  In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts.  Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis.  These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas.  The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand.  These fluctuations necessarily impact the accuracy of assumptions used in our budgeting process.

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

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

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

We must either obtain the right from landowners or exercise the power of eminent domain in order to use most of the land on which our pipelines are constructed, and we are subject to the possibility of increased costs to retain necessary land use.

We obtain the right to construct and operate pipelines on other owners’ land for a period of time.  If we were to lose these rights or be required to relocate our pipelines, our business could be affected negatively.  In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

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Whether we have the power of eminent domain for our pipelines, other than interstate natural gas pipelines, varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas or carbon dioxide—and the laws of the particular state.  Our interstate natural gas pipelines have federal eminent domain authority.  In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court.  Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.

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

As of December 31, 2009, we had $10.6 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 because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions.  Each of these factors is to a large extent dependent on economic, financial, competitive and other factors beyond our control.

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

As of December 31, 2009, approximately $5.6 billion (53%) of our total $10.6 billion consolidated debt was subject to variable interest rates, either as short-term or long-term debt of variable rate credit facilities or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps.  Should interest rates increase significantly, the amount of cash required to service our debt would increase and our earnings could be adversely affected.  For information on our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

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

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

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

Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.  We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows.  Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities.  In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

Current levels of market volatility could impair our access to the credit and capital markets.

The capital markets have been experiencing extreme volatility since mid-year 2008.  Our plans for growth require regular access to the capital markets.  If current levels of market volatility continue or worsen, our access to capital markets could be disrupted making growth through acquisitions and development projects difficult or impractical to pursue until such time as markets stabilize.

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

Economic conditions worldwide have from time to time contributed to slowdowns in 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 may also be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the United States 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.

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Downturns in the credit markets can increase the cost of borrowing and can make financing difficult to obtain, each of which may have a material adverse effect on our results of operations and business.

In 2008 and 2009, events in the financial markets had an adverse impact on the credit markets and, as a result, the availability of credit has become more expensive and difficult to obtain.  Some lenders are imposing more stringent restrictions on the terms of credit, and there may be a general reduction in the amount of credit available in the markets in which we conduct business.  In addition, as a result of the current credit market conditions and the downgrade of our short-term credit ratings by Standard & Poor’s Rating Services, we are currently unable to access commercial paper borrowings and instead are meeting our short-term financing and liquidity needs through borrowings under our bank credit facility.   The negative impact of these events may have a material adverse effect on us resulting from, but not limited to, an inability to expand facilities or finance the acquisition of assets on favorable terms, if at all, increased financing costs or financing with increasingly restrictive covenants.

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

On May 30, 2007, KMI completed its going-private transaction.  In connection with the transaction, Standard & Poor’s Rating Services and Moody’s Investor Service, Inc. downgraded the ratings assigned to our senior unsecured debt to BBB and Baa2, respectively.  Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007.  Though steps have been taken which are intended to allow our senior unsecured indebtedness to continue to be rated investment grade, we can provide no assurance that that will be the case.

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

The rate of production from oil and natural gas properties declines as reserves are depleted.  Without successful development activities, the reserves and revenues of the oil producing assets within our CO2 business segment will decline.  We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future.  Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.

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

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

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

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

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

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

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

As a result of the operations of our Kinder Morgan Canada segment, a portion of our assets, liabilities, revenues and expenses are denominated in Canadian dollars.  We are a U.S. dollar reporting company.  Fluctuations in the exchange rate between United States and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our partners’ capital under applicable accounting rules.

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

The U.S. government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations.  These potential targets might include our pipeline systems or storage facilities.  Our operations could become subject to increased governmental scrutiny that would require increased security measures.  Recent federal legislation provides an insurance framework that should cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies.  Nonetheless, there is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future.  These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.

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

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

Risks Related to Our Common Units

The interests of 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).

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The limited partners may remove the general partner only if (i) the holders of at least 662/3% 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 662/3% 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.

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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 United States federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for United States federal income tax purposes or 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 units depends largely on our being treated as a partnership for United States federal income tax purposes.  In order for us to be treated as a partnership for United States federal income tax purposes, current law requires that 90% or more of our gross income for every taxable year consist of “qualifying income,” as defined in Section 7704 of the Internal Revenue Code.  We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for United States federal income tax purposes or otherwise subject us to taxation as an entity.  We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or the IRS, on this or any other matter affecting us.

If we were treated as a corporation for United States federal income tax purposes, we would pay United States federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income tax 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 unitholders, likely causing a substantial reduction in the value of our units.

Current law or our business may change so as to cause us to be treated as a corporation for United States federal income tax purposes or otherwise subject us to 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 total revenue that is apportioned to Texas.  This tax reduces, and the imposition of such a tax on us by any other state will reduce, 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 United Statesfederal income tax purposes, the minimum quarterly distribution and the target distribution levels will be adjusted to reflect the impact on us of that law.

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

The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our units, may be modified by administrative, legislative or judicial interpretation at any time.  For example, members of Congress are considering substantive changes to the existing United States federal income tax laws that affect certain publicly traded partnerships.  Any modification to the United States federal income tax laws or interpretations thereof could make it difficult or impossible to meet the requirements for us to be treated as a partnership for United States federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our units.  Moreover, any modification to the United States federal income tax laws and interpretations thereof may or may not be applied retroactively.  Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.  Any potential change in law or interpretation thereof could negatively impact the value of an investment in our units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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 unitholders.

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for United States 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 units and the price at which they trade.  In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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Our 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 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 United Statesfederal 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.  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 unitholder sells common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder's adjusted tax basis in those common units.  Because distributions in excess of a 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 units sold will, in effect, become taxable income allocated to that unitholder, which decreased the tax basis in that unitholder’s common unit, will, in effect, become taxable income to that unitholder if the unitholder sells such units at a price greater than that unitholder’s tax basis in those 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 unitholder's share of our nonrecourse liabilities, if a unitholder sells its units, such unitholder may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-United States 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-United States persons raises issues unique to them.  For example, virtually all of our income allocated to organizations exempt from United Statesfederal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.  Distributions to non-United States persons will be reduced by withholding taxes imposed at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.  Any tax-exempt entity or non-United States 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 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 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 unitholders.  The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner.  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 Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

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

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 United States federal income tax purposes.

We will be considered to have terminated for United States 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 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 unitholder's taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for United States 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 unitholder whose units are loaned to a "short seller" to cover a short sale may be considered as having disposed of those units.  If so, the unitholder would no longer be treated for United States federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a "short seller" to cover a short sale may be considered as having disposed of the loaned units, the unitholder may no longer be treated for United States 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 unitholder and any cash distributions received by the unitholder as to those 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, 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 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 United States 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 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 United States federal income taxes, our 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 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 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 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.

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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 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 defaults on its debt, in exercising their rights as lenders, KMI’s lenders could acquire control of our general partner or otherwise influence our general partner through control of KMI.

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. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of our unitholders during the fourth quarter of 2009.

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PART II

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

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

	Price Range
	High		Low		Cash Distributions		i-unit Distributions
2009
First Quarter	$	51.85	$	40.19	$	1.0500		0.025342
Second Quarter		53.11		46.00		1.0500		0.022146
Third Quarter		55.00		50.08		1.0500		0.021292
Fourth Quarter		61.29		53.02		1.0500		0.018430
2008
First Quarter	$	60.62	$	50.80	$	0.9600		0.017716
Second Quarter		60.89		53.81		0.9900		0.018124
Third Quarter		59.48		48.67		1.0200		0.021570
Fourth Quarter		56.00		35.59		1.0500		0.024580

Distribution information is for distributions declared with respect to that quarter.  The declared distributions were paid within 45 days after the end of the quarter.  We currently expect to declare cash distributions of at least $4.40 per unit for 2010; however, no assurance can be given that we will be able to achieve this level of distribution, and our expectation does not take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’ interstate pipelines.

As of January 31, 2010, there were approximately 314,000 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 2009 or sell any unregistered units in the fourth quarter of 2009.

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Item 6. Selected Financial Data

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

	Year Ended December 31,
	2009(f)		2008(f)		2007(f)			2006(g)		2005(h)
	(In millions, except per unit and ratio data)
Income and Cash Flow Data:
Revenues	$	7,003.4	$	11,740.3	$	9,217.7		$	9,048.7	$	9,745.9
Operating income	$	1,515.1	$	1,551.5	$	807.7		$	1,291.6	$	1,015.8
Earnings from equity investments	$	189.7	$	160.8	$	69.7		$	74.0	$	89.6
Income from continuing operations	$	1,283.8	$	1,317.2	$	423.4		$	1,005.2	$	819.7
Income (loss) from discontinued operations(a)	$	-	$	1.3	$	173.9		$	14.3	$	(0.2	)
Net income	$	1,283.8	$	1,318.5	$	597.3		$	1,019.5	$	819.5
Limited Partners’ interest in net income (loss)	$	331.7	$	499.0	$	(21.3	)	$	490.8	$	334.9
Basic Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations(b)	$	1.18	$	1.94	$	(0.82	)	$	2.12	$	1.58
Income from discontinued operations		-		-		0.73			0.07		-
Net income (loss) per unit	$	1.18	$	1.94	$	(0.09	)	$	2.19	$	1.58
Diluted Limited Partners’ net income (loss) per unit:
Income (loss) per unit from continuing operations(b)	$	1.18	$	1.94	$	(0.82	)	$	2.12	$	1.58
Income from discontinued operations		-		-		0.73			0.06		-
Net income (loss) per unit	$	1.18	$	1.94	$	(0.09	)	$	2.18	$	1.58
Per unit cash distribution declared(c)	$	4.20	$	4.02	$	3.48		$	3.26	$	3.13
Ratio of earnings to fixed charges(d)	$	3.82	$	3.77	$	2.13		$	3.64	$	3.76
Capital expenditures	$	1,323.8	$	2,533.0	$	1,691.6		$	1,182.1	$	863.1
Balance Sheet Data (at end of period):
Net property, plant and  equipment	$	14,153.8	$	13,241.4	$	11,591.3		$	10,106.1	$	8,864.6
Total assets	$	20,262.2	$	17,885.8	$	15,177.8		$	13,542.2	$	11,923.5
Long-term debt(e)	$	9,997.7		8,274.9		6,455.9			4,384.3		5,220.9

__________

(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 $332.5 million as of December 31, 2009, $951.3 million as of December 31, 2008, $152.2 million as of December 31, 2007, $42.6 million as of December 31, 2006 and $98.5 million as of December 31, 2005.

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(f) For each of the years 2009, 2008 and 2007, includes results of operations for net assets acquired since effective dates of acquisition.  2007 also includes four months of Trans Mountain’s results of operations from prior to the acquisition date.  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 net assets of Trans Mountain acquired on April 30, 2007 from KMI since January 1, 2006.  Also includes results of operations for the oil and gas properties acquired from  Journey Acquisition-I, L.P. and Journey 2000, L.P., the terminal assets and operations acquired from A&L Trucking, L.P. and U.S. Development Group, Transload Services, LLC, and Devco USA L.L.C. since effective dates of acquisition.  The April 5, 2006 acquisition of the Journey oil and gas properties were made effective March 1, 2006.  The assets and operations acquired from A&L Trucking and U.S. Development Group were acquired in three separate transactions in April 2006.  We acquired all of the membership interests in Transload Services, LLC effective November 20, 2006, and we acquired all of the membership interests in Devco USA L.L.C. effective December 1, 2006.  We also acquired a 66 2/3% ownership interest in Entrega Pipeline LLC effective February 23, 2006, however, our earnings were not materially impacted during 2006 because regulatory accounting provisions required capitalization of revenues and expenses until the second segment of the Entrega Pipeline was complete and in-service.

(h) Includes results of operations for the 64.5% interest in the Claytonville unit, the seven bulk terminal operations acquired from Trans-Global Solutions, Inc., the Kinder Morgan Staten Island terminal, the terminal facilities located in Hawesville, Kentucky and Blytheville, Arkansas, General Stevedores, L.P., the North Dayton natural gas storage facility, the Kinder Morgan Blackhawk terminal, the terminal repair shop acquired from Trans-Global Solutions, Inc., and the terminal assets acquired from Allied Terminals, Inc. since effective dates of acquisition.  We acquired the 64.5% interest in the Claytonville unit effective January 31, 2005.  We acquired the seven bulk terminal operations from Trans-Global Solutions, Inc. effective April 29, 2005.  The Kinder Morgan Staten Island terminal, the Hawesville, Kentucky terminal and the Blytheville, Arkansas terminal were each acquired separately in July 2005.  We acquired all of the partnership interests in General Stevedores, L.P. effective July 31, 2005.  We acquired the North Dayton natural gas storage facility effective August 1, 2005.  We acquired the Kinder Morgan Blackhawk terminal in August 2005 and the terminal repair shop in September 2005.  We acquired the terminal assets from Allied Terminals, Inc. effective November 4, 2005.

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 2009, 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 “Risk Factors” and “Information Regarding Forward-Looking Statements.”

General

Our business model is built to support two principal components:

▪ helping customers by providing energy, bulk commodity and liquids products transportation, storage and distribution; and

▪ creating long-term value for our unitholders.

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

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Our five reportable business segments are:

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

▪ Natural Gas Pipelines—the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems, 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; and (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 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.  The profitability of our products pipeline transportation business is generally driven by the utilization of our facilities in relation to their capacity, as well as the prices we receive for our services.  Transportation volume levels are primarily driven by the demand for the petroleum products being shipped or stored, and the prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index.  Because of the overall effect of utilization on our products pipeline transportation business, we seek to own refined products pipelines located in, or that transport to, stable or growing markets and population centers.

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

Our CO2 sales and transportation business, like our natural gas pipelines business, generally has take-or-pay contracts, although the contracts in our CO2 business typically have minimum volume requirements.  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 transport volumes under many of our contracts.  In the oil and gas producing activities within our CO2 business segment, we monitor the amount of capital we expend in relation to the amount of production that is added or the amount of declines in oil and gas production that are postponed.  In that regard, our production during any period and the reserves that we add during that period are important measures.  In addition, the revenues we receive from our crude oil, natural gas liquids and 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, published market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.

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

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

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

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 allocate 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.  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.

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

Legal Matters

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

As of December 31, 2009, our most significant ongoing litigation proceedings involved our West Coast Products Pipelines.  Tariffs charged by certain of these pipeline systems are subject to certain proceedings at the FERC involving shippers’ complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services.  Generally, the interstate rates on our product pipeline systems are “grandfathered” under the Energy Policy Act of 1992 unless “substantially changed circumstances” are found to exist.  To the extent “substantially changed circumstances” are found to exist, our West Coast Products Pipeline operations may be subject to substantial exposure under these FERC complaints and could, therefore, owe reparations and/or refunds to complainants as mandated by the FERC or the United States’ judicial system.  For more information on our FERC regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report.

Intangible Assets

Intangible assets are those assets which provide future economic benefit but have no physical substance.  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.  There have not been any significant changes in these estimates during 2009; however, during the second quarter of 2008, we changed the date of our annual goodwill impairment test date to May 31 of each year (from January 1).  We have determined that our goodwill was not impaired as of May 31, 2009.

In addition, the acquisition of our Trans Mountain pipeline system from KMI on April 30, 2007 (announced on April 18, 2007) caused KMI to consider the fair value of the Trans Mountain pipeline system and to determine whether goodwill related to these assets was impaired.  KMI used a discounted cash-flow analysis to compare the fair market value of the Trans Mountain reporting unit to its carrying value, and since the carrying amount exceeded the fair value, KMI determined that goodwill was impaired and recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007.  This impairment is also reflected in our accompanying consolidated statement of income for the year ended December 31, 2007 due to the accounting principles for transfers of assets between entities under common control, which required us to both transfer the assets and liabilities of the Trans Mountain pipeline system from KMI to us at their carrying value and to account for Trans Mountain as if the transfer had taken place on January 1, 2006.

For more information on our goodwill, see Note 2 and Note 7 to our consolidated financial statements included elsewhere in this report.  For more information on our acquisition of Trans Mountain, see Note 3 to our consolidated financial statements included elsewhere in this report.

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, lease value, and technology-based assets.  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 “Goodwill and Other Intangibles—Other Intangibles” to our consolidated financial statements included elsewhere in this report.

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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.

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Results of Operations

Consolidated

	Year Ended December 31,
	2009			2008			2007
	(In millions)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(b)	$	584.5		$	546.2		$	569.6
Natural Gas Pipelines(c)		789.6			760.6			600.2
CO2(d)		782.9			759.9			537.0
Terminals(e)		599.0			523.8			416.0
Kinder Morgan Canada(f)		154.5			141.2			(293.6	)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		2,910.5			2,731.7			1,829.2
Depreciation, depletion and amortization expense(g)		(850.8	)		(702.7	)		(547.0	)
Amortization of excess cost of equity investments		(5.8	)		(5.7	)		(5.8	)
General and administrative expenses(h)		(330.3	)		(297.9	)		(278.7	)
Unallocable interest expense, net of interest income(i)		(431.3	)		(397.6	)		(395.8	)
Unallocable income tax expense		(8.5	)		(9.3	)		(4.6	)
Net income		1,283.8			1,318.5			597.3
Net income attributable to noncontrolling interests(j)		(16.3	)		(13.7	)		(7.0	)
Net income attributable to Kinder Morgan Energy Partners, L.P.	$	1,267.5		$	1,304.8		$	590.3

____________

(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) 2009 amount includes (i) a $23.0 million increase in expense from the amounts previously reported in our 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries and is primarily noncash in 2009; (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.  2007 amount includes (i) a $152.8 million gain from the sale of our North System; (ii) a $136.8 million increase in expense associated with rate case and other legal liability adjustments; (iii) a $15.9 million increase in expense associated with environmental liability adjustments; (iv) a $15.0 million increase in expense for a litigation settlement reached with Contra Costa County, California; (v) a $3.2 million increase in expense from the settlement of certain litigation matters related to our West Coast refined products terminal operations; and (vi) a $1.8 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions.

(c) 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 from the amounts previously reported in our 2009 fourth quarter earnings release issued on January 20, 2010, 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) a combined $5.6 million increase in income resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas; (iii) a $0.5 million decrease in expense associated with environmental liability adjustments; (iv) a $5.0 million increase in expense related to hurricane clean-up and repair activities, and (v) a $0.3 million increase in expense associated with legal liability adjustments.  2007 amount includes an expense of $1.0 million, reflecting our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company, and a $0.4 million decrease in expense associated with environmental liability adjustments.

(d) 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.  2007 amount includes a $0.2 million increase in expense associated with environmental liability adjustments.

(e) 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 from the amounts previously reported in our 2009 fourth quarter earnings release issued on January 20, 2010, 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.  2007 amount includes (i) a $25.0 million increase in expense from the settlement of certain litigation matters related to our Cora coal terminal; (ii) a $2.0 million increase in expense associated with environmental liability adjustments; (iii) a $1.2 million increase in expense associated with legal liability adjustments; and (iv) an increase in income of $1.8 million from property casualty gains associated with the 2005 hurricane season.

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(f) 2009 amount includes a $14.9 million increase in expense primarily due to certain non-cash regulatory accounting adjustments to the carrying amount of the previously established deferred tax liability, and a $3.7 million decrease in expense due to a certain non-cash accounting change related to book tax accruals.  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 regulatory accounting adjustments.  2007 amount includes losses of $349.2 million for periods prior to our acquisition date of April 30, 2007 (including a $377.1 million goodwill impairment expense associated with a non-cash reduction in the carrying value of Trans Mountain’s goodwill), and a $1.3 million decrease in income from an oil loss allowance.

(g) 2007 amount includes Trans Mountain expenses of $6.3 million for periods prior to our acquisition date of April 30, 2007.

(h) Includes unallocated litigation and environmental expenses.  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.  2007 amount includes (i) a $26.2 million increase in non-cash expense, allocated to us from KMI, associated with closing the going-private transaction (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $5.5 million expense for Trans Mountain general and administrative expenses for periods prior to our acquisition date of April 30, 2007; (iii) a $2.1 million expense due to the adjustment of certain insurance related liabilities; (iv) a $1.7 million increase in expense associated with the 2005 hurricane season; (v) a $1.5 million expense for certain Trans Mountain acquisition costs; and (vi) a $0.8 million expense related to the cancellation of certain commercial insurance policies.

(i) 2009 amount includes a $1.6 million increase in imputed interest expense 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.  2007 amount includes a $2.4 million increase in imputed interest expense related to our January 1, 2007 Cochin Pipeline acquisition, and a $1.2 million expense for Trans Mountain interest expense for periods prior to our acquisition date of April 30, 2007.

(j) 2009, 2008 and 2007 amounts include decreases of $0.7 million, $0.4 million and $3.9 million, respectively, in net income attributable to our noncontrolling interests, related to the effect from all of the 2009, 2008 and 2007 items previously disclosed in these footnotes.

In 2009, net income attributable to our partners, which includes all of our limited partner unitholders and our general partner, totaled $1,267.5 million on revenues of $7,003.4 million.  This compares to net income attributable to our partners of $1,304.8 million on revenues of $11,740.3 million in 2008, and net income of $590.3 million on revenues of $9,217.7 million in 2007.  Our 2007 net income included the $377.1 million impairment expense associated with the non-cash reduction in the carrying value of Trans Mountain’s goodwill, discussed above in “Critical Accounting Policies and Estimates—Intangible Assets.”

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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 2009, our total segment earnings before depreciation, depletion and amortization increased by approximately 7% both before and after taking into effect the combined 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 in 2009 and decreased segment EBDA by $26.5 million in 2008).  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 and 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 the Rockies Express-East, Midcontinent Express and Kinder Morgan Louisiana natural gas pipelines; and (iv) a full year impact from the Rockies Express-West natural gas pipeline.

In 2008, total segment earnings before depreciation, depletion and amortization increased $902.5 million (49%) compared to 2007, and combined, the certain items described in the footnotes to the tables above accounted for $367.5 million of the overall increase (combining to decrease segment EBDA by $26.5 million in 2008 and to decrease segment EBDA by $394.0 million in 2007).  The remaining $535.0 million (24%) increase in total segment EBDA included higher earnings in 2008 from our CO2, Natural Gas Pipelines, Terminals and Kinder Morgan Canada business segments, and lower earnings from our Products Pipelines business segment.

During 2008, we benefitted from (i) higher revenues from crude oil and carbon dioxide sales; (ii) the start-up of the Rockies Express-West natural gas pipeline; (iii) improved margins from our Texas intrastate natural gas pipeline group; (iv) incremental earnings from expanded bulk and liquids terminal operations; and (v) a full year impact of Trans Mountain and its system expansions.  The year-to-year decrease in earnings from our Products Pipelines segment was primarily due to a continued slowing economy at the end of 2008 and to the negative impact of higher energy prices—primarily in the first three quarters of 2008—on demand for petroleum products, which negatively impacted our deliveries of gasoline, diesel and jet fuel in 2008 versus 2007.

Products Pipelines

	Year Ended December 31,
	2009			2008			2007
	(In millions, except operating statistics)
Revenues(a)	$	826.6		$	815.9		$	844.4
Operating expenses(b)		(269.5	)		(291.0	)		(451.8	)
Other income (expense)(c)		(0.6	)		(1.3	)		154.8
Earnings from equity investments(d)		29.0			24.4			32.5
Interest income and Other, net-income (expense)(e)		12.4			2.0			9.4
Income tax benefit (expense)(f)		(13.4	)		(3.8	)		(19.7	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	584.5		$	546.2		$	569.6
Gasoline (MMBbl)(g)		400.1			398.4			435.5
Diesel fuel (MMBbl)		143.2			157.9			164.1
Jet fuel (MMBbl)		111.4			117.3			125.1
Total refined product volumes (MMBbl)		654.7			673.6			724.7
Natural gas liquids (MMBbl)		26.5			27.3			30.4
Total delivery volumes (MMBbl)(h)		681.2			700.9			755.1

__________

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(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) 2009, 2008 and 2007 amounts include increases in expense of $11.5 million, $9.2 million and $15.9 million, respectively, associated with environmental liability adjustments.  2009 amount also includes (i) a $23.0 million increase in expense from the amounts previously reported in our 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries and is primarily noncash in 2009; and (ii) 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.  2007 amount also includes a $136.7 million increase in expense associated with rate case and other legal liability adjustments, a $15.0 million expense for a litigation settlement reached with Contra Costa County, California, and a $3.2 million increase in expense from the settlement of certain litigation matters related to our West Coast refined products terminal operations.

(c) 2009 amount includes a gain of $0.2 million from hurricane casualty indemnifications.  2008 and 2007 amounts include gains of $1.3 million and $152.8 million, respectively, from the 2007 sale of our North System.  2008 amount also includes a $2.2 million decrease in income resulting from certain property, plant and equipment write-offs.

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

(e) 2009, 2008 and 2007 amounts include a $1.7 million increase in income, a $3.6 million decrease in income and a $1.8 million increase in income, respectively, resulting from unrealized foreign currency gains and losses on long-term debt transactions.

(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) 2009, 2008 and 2007 volumes include ethanol volumes of 23.1 million barrels, 18.7 million barrels, and 11.8 million barrels, respectively.

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

Our Products Pipelines segment’s primary businesses include transporting refined petroleum products and natural gas liquids through pipelines and operating liquid petroleum products terminals and petroleum pipeline transmix processing facilities.  Combined, the certain items described in the footnotes to the table above accounted for decreases in earnings before depreciation, depletion and amortization expenses of $50.6 million in 2009, $25.3 million in 2008, and $16.3 million in 2007; accounting for decreases in earnings of $25.3 million in 2009 and $9.0 million in 2008, when compared to the respective prior year.  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 2009 and 2008, when compared to the respective prior year:

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	%

__________

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

	EBDA Increase/(Decrease)					Revenues Increase/(Decrease)
	(In millions, except percentages)
North System	$	(28.1	)	n/a		$	(41.1	)	n/a
Pacific operations		(9.8	)	(4	) %		(0.7	)	-
Plantation Pipeline		(2.4	)	(6	) %		1.8		4	%
Southeast Terminals		9.4		22	%		13.7		20	%
Cochin Pipeline System		6.6		15	%		(11.6	)	(15	) %
Central Florida Pipeline		5.8		16	%		6.0		13	%
West Coast Terminals		3.9		8	%		7.5		10	%
All others (including eliminations)		0.2		-			1.0		1	%
Total Products Pipelines	$	(14.4	)	(2	) %	$	(23.4	)	(3	) %

__________

Although ongoing weak economic conditions continued to dampen demand for refined petroleum products at many of our  assets in this segment, resulting in lower diesel and jet fuel volumes and relatively flat gasoline volumes versus 2008, earnings were positively impacted by higher ethanol and terminal revenues from our Pacific operations and our Central Florida Pipeline, improved warehousing margins at existing and expanded West Coast terminal facilities, and an overall reduction in combined segment operating expenses in 2009, primarily due to lower outside services and other discretionary expenses, and to lower fuel and power expenses, when compared to a year earlier.

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

▪ a $21.2 million (8%) increase in earnings from our Pacific operations—consisting of an $18.8 million decrease in combined operating expenses, a $4.2 million increase in total operating revenues, and a $1.8 million decrease in other operating and non-operating income items, relative to 2008.

The decrease in our Pacific operations’ operating expenses in 2009 versus 2008 was primarily due to the following: (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 year-over-year increase in operating revenues was driven by higher delivery revenues to U.S. military customers, due to military tender increases in 2009, annual 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, driven by higher revenues from our combined Carson/Los Angeles Harbor terminal system and by incremental returns from the completion of a number of capital expansion projects that modified and upgraded terminal infrastructure since the end of last year.  Revenues at our Carson/Los Angeles terminal complex increased $8.8 million in 2009 versus 2008, due mainly to both increased warehouse charges (escalated warehousing contract rates resulting from customer contract revisions made since the end of 2008) and to new customers (including incremental terminaling for U.S. defense fuel services).  Revenues from our remaining West Coast facilities increased $4.0 million in 2009 versus 2008, due mostly to additional throughput and storage services associated with renewable fuels (both ethanol and biodiesel), and partly to incremental revenues of $0.8 million from the terminals’ Portland, Oregon Airport pipeline, which was acquired on July 31, 2009;

▪ a $9.2 million (22%) increase in earnings from our Central Florida Pipeline—driven by incremental ethanol revenues and higher refined products delivery revenues, when compared to 2008.  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, and 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, 2008 and 2009;

▪ a $7.7 million (26%) increase in earnings from our transmix operations—mainly due to a combined $8.0 million increase in revenues in 2009, associated with certain true-ups related to transmix settlement gains;

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▪ a $3.8 million (10%) increase in earnings from our approximate 51% equity ownership in the Plantation Pipe Line Company.  Plantation’s net income increased as a result of higher pipeline transportation revenues (due to both higher volumes and average tariffs) and incremental other income in 2009 from insurance reimbursements related to the settlement of certain previous environmental matters.

The decrease in revenues associated with our investment in Plantation in 2009 compared to 2008 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, resulting in a minimal impact to our earnings.  Accordingly, the $24.9 million reduction in our fee revenues in 2009 was offset by a corresponding decrease in our operating expenses of $26.9 million; 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 in 2009 versus 2008.  The drop in fuel and power expenses was due primarily to an overall 8% decrease in refined products delivery volumes, chiefly due to lower diesel volumes.

The overall decreases in both segment earnings before depreciation, depletion and amortization expenses and segment revenues in 2008 compared to 2007 were primarily the result of the October 2007 divestiture of our North System pipeline system and our 50% ownership interest in the Heartland Pipeline Company (collectively referred to in this report as our North System) to ONEOK Partners, L.P.  Following purchase price adjustments, we received approximately $295.7 million in cash for the sale.  We accounted for our North System business as a discontinued operation pursuant to generally accepted accounting principles which require that our income statement be formatted to separate the divested business from our continuing operations; however, because the sale of our 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 North System’s operating results within our Products Pipelines business segment disclosures for all periods presented in this discussion and analysis.  This decision was based on the way our management organizes segments internally to make operating decisions and assess performance.

Our North System generated $28.1 million of earnings before depreciation, depletion and amortization expenses in 2007 prior to the effective sale date of October 5, 2007.  In addition, we recognized a $152.8 million gain on disposal of the North System in the fourth quarter of 2007, and we recorded incremental gain adjustments of $1.3 million in 2008.  The gains, unlike the earnings before depreciation, depletion and amortization expenses, are not reflected in the operating results above but are instead included within the certain items described in the footnotes to the table immediately following the heading “—Products Pipelines” above.  For more information regarding this divestiture, see Note 3 to our consolidated financial statements included elsewhere in this report.  For information on our reconciliation of segment information with our consolidated general-purpose financial statements, see Note 15 to our consolidated financial statements included elsewhere in this report.

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

▪ a $9.8 million (4%) decrease in earnings from our Pacific operations—primarily due to an increase in system-wide operating and maintenance expenses in 2008 versus 2007.  The increase primarily reflects lower product gains in 2008, due both to lower physical gains and to the impact of unfavorable changes in diesel fuel versus gasoline prices; lower capitalized overhead credits, due to lower capital spending in 2008; higher labor and payroll expenses, due to an increase in headcount; and incremental expenses associated with litigation and right-of-way liability adjustments.

Total revenues earned by our Pacific operations in 2008 were essentially flat compared to 2007, as higher pipeline delivery revenues were largely offset by lower fee-based terminal revenues.  The year-over-year increase in refined products delivery revenues resulted from both higher average tariff rates in 2008 and a more favorable delivery mix of higher-rate East Line volumes versus lower-rate West Line volumes;

▪ a $2.4 million (6%) decrease in earnings from our equity investment in Plantation Pipe Line Company—due mainly to lower overall net income earned by Plantation as a result of lower product transportation and pipeline service revenues.  In 2008, pipeline throughput volumes dropped 10% compared to the previous year.  The drop in delivery volumes was due to a combination of decreased demand due to lower product consumption, supply disruptions caused by hurricane related refinery outages, and a volume shift by customers to competing pipelines;

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▪ a combined $13.3 million (15%) increase in earnings from our Southeast and West Coast terminal operations—primarily related to higher margins on liquids inventory sales, increased earnings from incremental terminal throughput and storage activity at higher rates, and incremental returns from the completion of a number of capital expansion projects that modified and upgraded terminal infrastructure since the end of 2007, enabling us to provide additional terminal and ethanol related services to our customers;

▪ a $6.6 million (15%) increase in earnings from our Cochin pipeline system— driven largely by a year-end 2008 reduction in income tax expense, related to lower Canadian operating results in 2008 and to Canadian income tax liability adjustments.  The decrease in income tax expense more than offset a 15% drop in operating revenues that was primarily related to lower pipeline transportation revenues in 2008.  The decrease in delivery revenues was due both to a continued decrease in demand for propane in Eastern Canadian and Midwestern U.S. petrochemical and fuel markets since the end of 2007 and to Cochin’s ceasing of ethane transportation in July 2007; and

▪ a $5.8 million (16%) increase in earnings from our Central Florida Pipeline—chiefly due to higher revenues relative to 2007.  The increase in revenues was driven by incremental ethanol terminal revenues that began in April 2008, incremental ethanol pipeline transportation revenues that began in October 2008, and higher refined product delivery revenues, driven by an increase in the average tariff as a result of a mid-year 2008 tariff rate increase on product deliveries.

Natural Gas Pipelines

	Year Ended December 31,
	2009			2008			2007
	(In millions, except operating statistics)
Revenues	$	3,806.9		$	8,422.0		$	6,466.5
Operating expenses(a)		(3,193.0	)		(7,804.0	)		(5,882.9	)
Other income (expense)(b)		7.8			2.7			3.2
Earnings from equity investments(c)		141.8			113.4			19.2
Interest income and Other, net-income (expense)(d)		31.8			29.2			0.2
Income tax benefit (expense)		(5.7	)		(2.7	)		(6.0	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	789.6		$	760.6		$	600.2
Natural gas transport volumes (Trillion Btus)(e)		2,284.8			2,008.6			1,712.6
Natural gas sales volumes (Trillion Btus)(f)		794.5			866.9			865.5

__________

(a) 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.  2009 amount also includes a $0.1 million increase in expense from the amounts previously reported in our 2009 fourth quarter earnings release issued on January 20, 2010, 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.  2007 amount includes a $0.4 million decrease in expense associated with environmental liability adjustments.

(b) 2009 amount represents gains from hurricane casualty indemnifications.

(c) 2007 amount includes an expense of $1.0 million reflecting our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company.

(d) 2008 amount includes a $13.0 million gain from the sale of our 25% equity ownership interest in Thunder Creek Gas Services, LLC.

(e) Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC, 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.

Our Natural Gas Pipelines segment’s primary businesses involve marketing, transporting, storing, gathering, processing and treating natural gas through both intrastate and interstate pipeline systems and related facilities.  Combined, the certain items described in the footnotes to the table above accounted for increases in earnings before depreciation, depletion and amortization expenses of $2.1 million in 2009 and $13.8 million in 2008, and a decrease in earnings before depreciation, depletion and amortization of $0.6 million in 2007; accounting for an $11.7 million decrease in earnings before depreciation, depletion and amortization expenses in 2009, and a $14.4 million increase in earnings before depreciation, depletion and amortization in 2008, when compared to the respective prior year.  Following is information related to the increases and decreases in the segment’s (i) remaining changes in earnings before depreciation, depletion and amortization expenses; and (ii) operating revenues in both 2009 and 2008, when compared to the respective prior year:

62

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		14.1		n/a			-		-
Rockies Express Pipeline		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		1.7		2	%		(46.7	)	(25	) %
Intrasegment Eliminations		-		-			-		-
Total Natural Gas Pipelines	$	40.7		5	%	$	(4,615.1	)	(55	) %

__________

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

	EBDA Increase/(Decrease)					Revenues Increase/(Decrease)
	(In millions, except percentages)
Rockies Express Pipeline	$	97.0		769	%	$	-		-
Texas Intrastate Natural Gas Pipeline Group		37.7		11	%		1,924.9		32	%
Kinder Morgan Louisiana Pipeline		11.2		n/a			-		n/a
TransColorado Pipeline		11.1		26	%		12.5		24	%
Kinder Morgan Interstate Gas Transmission		5.4		5	%		(1.8	)	(1	) %
Casper and Douglas gas processing		(8.1	)	(38	) %		24.6		24	%
Trailblazer Pipeline		(5.6	)	(11	) %		(5.2	)	(9	) %
All others		(2.7	)	(8	) %		2.8		1,096	%
Intrasegment Eliminations		-		-			(2.3	)	(170	) %
Total Natural Gas Pipelines	$	146.0		24	%	$	1,955.5		30	%

__________

The overall increase in our Natural Gas Pipelines’ earnings before depreciation, depletion and amortization expenses in 2009 versus 2008 was driven by incremental contributions from our fully-owned Kinder Morgan Louisiana pipeline system, our 50% investment in the Midcontinent Express pipeline system, and our 50% investment in the Rockies Express pipeline system.  We account for our investments in Midcontinent Express and Rockies Express under the equity method of accounting.

Our Kinder Morgan Louisiana Pipeline commenced limited natural gas transportation service on the pipeline system in April 2009, and construction was fully completed and transportation service on the system’s remaining portions began in full on June 21, 2009.  The overall incremental earnings in 2009 compared to 2008 consisted of operating income (revenues less operating expenses) of $18.4 million and non-operating other income of $11.8 million, primarily due to higher non-cash allowances for capital funds used during construction.  Pursuant to FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance), we were allowed a reasonable return on the construction costs that we funded by equity contributions, similar to the allowance for capital costs funded by borrowings.

The incremental equity earnings from Midcontinent Express also relates to the start-up of natural gas transportation service in 2009.  The system commenced interim service for Zone 1 of its pipeline system on April 10, 2009, with deliveries to Natural Gas Pipeline Company of America LLC.  Natural gas service to all Zone 1 delivery points occurred by May 21, 2009, and on August 1, 2009, the system’s remaining portion (Zone 2) was placed into service.    Currently, the pipeline system can provide transportation service for up to 1.4 billion cubic feet per day of natural gas, and the pipeline capacity is fully subscribed with long-term binding commitments from creditworthy shippers.

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The increase in earnings from Rockies Express was primarily attributable to both the completion and start-up of the Rockies Express-East pipeline segment in 2009 and to the inclusion of a full year of operations from the Rockies Express-West pipeline segment.  The Rockies Express-East line is the third and final phase of the Rockies Express joint venture project.  It began initial pipeline service on June 29, 2009, and began full operations on November 12, 2009.  The Rockies Express-West line began initial pipeline service on January 12, 2008, and began full operations on May 20, 2008.

On November 14, 2009, a pipeline girth weld failure on the Rockies Express-East line resulted in approximately 60 miles of the pipeline being shutdown.  The pipeline was placed back into service at a reduced capacity on January 27, 2010, and at full capacity on February 6, 2010.  The negative impact on our equity earnings from Rockies Express 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 operational gas sales margins, higher firm transportation demand fees (resulting from both system expansions and incremental ethanol customers), and higher pipeline fuel recoveries (KMIGT’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and recovery of storage cushion gas volumes);

▪ incremental earnings of $9.4 million from our subsidiary Kinder Morgan Gas Treating, L.P., which acquired the natural gas treating business from Crosstex Energy, L.P. and Crosstex Energy, Inc. effective October 1, 2009.  The business consists of multiple natural gas treating plants, predominantly located in Texas and Louisiana, that are used to remove impurities and liquids from natural gas in order to meet pipeline quality specifications;

▪ a $3.5 million (6%) decrease in earnings from our TransColorado Pipeline—primarily due to a $2.6 million (4%) drop in natural gas transportation revenues and partly to increases in both pipeline remediation expenses and property tax expenses in 2009 compared to 2008.  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 to higher supply prices relative to sales prices in 2009.  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 in 2009; and (iii) higher system operational expenses, due primarily to higher pipeline integrity expenses relative to last year.  The overall decreases in earnings were partially offset by higher year-to-year natural gas storage margins which resulted from favorable proprietary and fee based storage activities and from the leasing of additional storage capacity to customers from completed capital expansion projects.

Our Texas intrastate natural gas pipeline group includes the operations of the following four natural gas pipeline systems: Kinder Morgan Tejas (including Kinder Morgan Border Pipeline), Kinder Morgan Texas Pipeline, Kinder Morgan North Texas Pipeline and our Mier-Monterrey Mexico Pipeline, and combined, the group accounted for 46% and 53%, respectively, of the segment’s earnings before depreciation, depletion and amortization expenses in 2009 and 2008, 89% and 95%, respectively, of the segment’s revenues in 2009 and 2008, and 95% and 97%, respectively, of the segment’s operating expenses in 2009 and 2008.

For each of the years 2009, 2008 and 2007, the overall changes in both segment revenues and segment operating expenses (which include natural gas costs of sales) primarily relate to the natural gas purchase and sale activities of our intrastate 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.  The 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 gas sales revenues are largely offset by corresponding increases and decreases in gas purchase costs.

With regard to natural gas sales activity, our intrastate group’s business strategy involves relying both on long and short-term natural gas sales and purchase agreements, and we use this flexibility to help optimize the margins we realize by capturing favorable differences due to changes in timing, location, prices and volumes.  To the extent possible, we balance the pricing and timing of our natural gas purchases to our natural gas sales, and our purchase and sales contracts are frequently settled in terms of an index price for both purchases and sales.  Generally, we attempt to lock-in an acceptable margin by capturing the difference between our average gas sales prices and our average gas purchase and cost of fuel prices.

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The most significant increases to segment earnings before depreciation, depletion and amortization expenses in 2008 compared to 2007 were incremental contributions from our investment in Rockies Express and from our Texas intrastate natural gas pipeline group.  The increase from Rockies Express was driven by the start-up of service on the Rockies Express-West line, discussed above, and the increase in earnings from our intrastate group was primarily due to higher margins on renewal and incremental sales contracts, higher natural gas transportation revenues, greater value from natural gas storage activities, and higher natural gas processing margins.

The earnings improvement from the intrastate group’s higher natural gas sales margins in 2008 reflected more favorable market conditions and year-over-year customer growth compared to the prior year.  The increases in earnings from natural gas transportation and fee-based storage activities were due primarily to higher volumes and rates and partly to incremental revenues due to a long-term contract with one of the group’s largest customers that became effective April 1, 2007.  The increase in gas processing margins in 2008 versus 2007 was largely due to more favorable price changes in natural gas liquids relative to the price of natural gas.

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

▪ incremental earnings of $11.2 million from our Kinder Morgan Louisiana Pipeline—reflecting other non-operating income realized in 2008 pursuant to FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance);

▪ an $11.1 million (26%) increase in earnings from our TransColorado Pipeline—reflecting natural gas transportation contract improvements, pipeline expansions completed since the end of 2007, and an increase in natural gas production in the Piceance and San Juan Basins of New Mexico and Colorado;

▪ a $5.4 million (5%) increase in earnings from our Kinder Morgan Interstate Gas Transmission system—driven by lower power expenses, due to decreased electricity use and lower negotiated rates in 2008, a higher gross margin due to both higher operational natural gas sales margins and additional transportation revenues, and lower tax expenses payable to the state of Texas;

▪ an $8.1 million (38%) decrease in earnings from our Casper Douglas gas processing operations—primarily attributable to higher natural gas purchase costs, due to increases in both prices and volumes, relative to 2007.  The higher cost of sales expense more than offset a year-to-year revenue increase resulting from both higher average prices on natural gas liquids sales and higher sales of excess natural gas; and

▪ a $5.6 million (11%) decrease in earnings from our Trailblazer Pipeline—mainly due to a 9% drop in revenues in 2008, relative to 2007, due mainly to lower revenues from both the sales of excess natural gas and interruptible natural gas transportation services.

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CO2

	Year Ended December 31,
	2009			2008			2007
	(In millions, except operating statistics)
Revenues(a)	$	1,035.7		$	1,133.0		$	824.1
Operating expenses(b)		(271.1	)		(391.8	)		(304.2	)
Earnings from equity investments		22.3			20.7			19.2
Other, net-income (expense)		-			1.9			-
Income tax benefit (expense)		(4.0	)		(3.9	)		(2.1	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	782.9		$	759.9		$	537.0
Carbon dioxide delivery volumes (Bcf)(c)		774.0			732.1			637.3
SACROC oil production (gross)(MBbl/d)(d)		30.1			28.0			27.6
SACROC oil production (net)(MBbl/d)(e)		25.1			23.3			23.0
Yates oil production (gross)(MBbl/d)(d)		26.5			27.6			27.0
Yates oil production (net)(MBbl/d)(e)		11.8			12.3			12.0
Natural gas liquids sales volumes (net)(MBbl/d)(e)		9.5			8.4			9.6
Realized weighted average oil price per Bbl(f)(g)	$	49.55		$	49.42		$	36.05
Realized weighted average natural gas liquids price per Bbl(g)(h)	$	37.96		$	63.00		$	52.91

__________

(a) 2009 amount includes a $13.5 million unrealized loss (from a decrease in revenues) on derivative contracts used to hedge forecasted crude oil sales.

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

(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes.

(d) Represents 100% of the production from the field.  We own an approximately 97% working interest in the SACROC unit and an approximately 50% working interest in the Yates unit.

(e) Net to 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.Combined, the certain items described in the footnotes to the table above accounted for decreases in earnings before depreciation, depletion and amortization expenses of $13.5 million in 2009, $0.3 million in 2008, and $0.2 million in 2007; accounting for decreases in earnings of $13.2 million in 2009 and $0.1 million in 2008, when compared to the respective prior year.  For each of the segment’s two primary businesses, following is information related to the remaining changes in (i) earnings before depreciation, depletion and amortization expenses; and (ii) operating revenues in both 2009 and 2008, when compared to the respective prior year:

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

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

__________

66

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

	EBDA Increase/(Decrease)				Revenues Increase/(Decrease)
	(In millions, except percentages)
Sales and Transportation Activities	$	123.5	70	%	$	147.3		79	%
Oil and Gas Producing Activities		99.5	28	%		198.5		29	%
Intrasegment Eliminations		-	-			(36.9	)	(77	) %
Total CO2	$	223.0	42	%	$	308.9		37	%

__________

The segment’s overall $36.2 million (5%) increase in earnings before depreciation, depletion and amortization expenses in 2009 compared to 2008 was due to a $120.6 million (26%) increase in earnings from its oil and gas producing activities, which include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants.  Generally, earnings from the segment’s oil and gas producing activities align closely with the revenues it earns from both crude oil and natural gas plant products sales, but the overall increase in earnings in 2009 consisted of (i) a $166.1 million (39%) increase from lower oil and gas related operating expenses; (ii) a $44.5 million (5%) decrease from lower revenues; and (iii) a $1.0 million (51%) decrease in other income items.

The overall decrease in combined operating expenses in 2009 consisted of a $103.6 million (29%) decrease in oil and gas related field operating and maintenance expenses (including all cost of sales and fuel and power expenses), and a $62.5 million (87%) decrease in taxes, other than income tax expenses.  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 by our CO2 segment since the end of 2008.  The overall decrease in other tax expenses, relative to 2008, was driven by a decrease in severance tax expenses, related both to the decrease in natural gas liquids and crude oil sales revenues (discussed following) and to a $30.3 million favorable adjustment to our accrued severance tax liabilities due to prior year overpayments.

The overall $44.5 million (5%) decline in oil and gas related revenues in 2009 versus 2008 was driven by a $61.2 million (32%) decrease in natural gas liquids sales revenues, but partly offset by a $22.9 million (3%) increase in crude oil sales revenues, due to a 3% increase in crude oil sales volumes.  The decrease in liquids sales revenues was due entirely to a 40% decrease in the realized weighted average price per barrel of liquids in 2009; however, the decrease in revenues caused by lower natural gas liquids realizations in 2009 was partly offset by higher revenues resulting from a 13% increase in natural gas liquids sales volumes in 2009, due in part to the negative impact on sales volumes in 2008 from Hurricane Ike.

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 have increased since the beginning of 2009.  Because prices of crude oil and natural gas liquids are subject to external factors over which we have no control, and because future price changes may be volatile, our CO2 business segment is exposed to price risk related to the price volatility of these commodities.  To some extent, however, we are able to mitigate this risk through a long-term hedging strategy that is intended to generate more stable realized prices by using derivative contracts as hedges to the exposure of fluctuating expected future cash flows produced by changes in commodity sales prices.  Nonetheless, decreases in the prices of crude oil and natural gas liquids will have a negative impact on the results of our CO2 segment, and we have exposure on all unhedged sales volumes, the majority of which are natural gas liquids volumes.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $59.02 per barrel in 2009, $97.70 per barrel in 2008 and $69.63 per barrel in 2007.

The $84.4 million (28%) decrease in the segment’s sales and transportation earnings for 2009 versus 2008 was due primarily to the $78.2 million (23%) drop in revenues, which included 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 from 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 last year, reducing revenues by $95.8 million.  The decrease in carbon dioxide sales revenues resulting from the unfavorable price change more than offset a $30.4 million increase in sales revenues resulting from higher sales volumes, which increased 13% in 2009, primarily due to carbon dioxide expansion projects completed since the end of 2008, and to a continued strong demand for carbon dioxide from tertiary oil recovery projects.  Although we purchase certain volumes of carbon dioxide on an intercompany basis for use, we do not recognize profits on carbon dioxide sales to ourselves.

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The overall 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 to lower crude oil transportation revenues from our Wink Pipeline.  Although its deliveries of carbon dioxide volumes increased 7% in 2009—and combined segment delivery volumes increased 6%—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 were indexed to lower oil prices in 2009, when compared to last year.  The decrease in delivery revenues from our Wink crude oil pipeline was primarily due to lower pipeline loss allowance revenues in 2009, resulting from lower market prices for crude oil relative to last year.

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

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

The increase in average carbon dioxide sales prices in 2008 versus 2007 was due both to continued customer demand for carbon dioxide for use in oil recovery projects throughout the Permian Basin area in 2008 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 2007.  The increases in carbon dioxide sales and delivery volumes were largely due to the January 17, 2008 start-up of the Doe Canyon carbon dioxide source field located in Dolores County, Colorado.  We hold an approximately 87% working interest in Doe Canyon and since mid-year 2006, we invested approximately $90 million to develop this source field.  In addition, investments were also made to drill additional carbon dioxide wells at the McElmo Dome unit, increase transportation capacity on the Cortez Pipeline, and extend the Cortez Pipeline to the new Doe Canyon Deep unit.

The year-over-year increase in earnings before depreciation, depletion and amortization from the segment’s oil and gas producing activities in 2008 was also driven by higher revenues and generally, our oil and gas related revenues are closely aligned with our realized price levels for crude oil and natural gas liquids products.  Revenues from crude oil sales and natural gas plant products sales increased $186.2 million (40%) and $7.0 million (4%), respectively, in 2008 compared to 2007, driven by increases of 37% and 19%, respectively, in the realized weighted average price per barrel.

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

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Terminals

	Year Ended December 31,
	2009			2008			2007
	(In millions, except operating statistics)
Revenues	$	1,109.0		$	1,173.6		$	963.7
Operating expenses(a)		(536.8	)		(631.8	)		(536.4	)
Other income (expense)(b)		27.6			(2.7	)		6.3
Earnings from equity investments		0.7			2.7			0.6
Other, net-income (expense)		3.7			1.7			1.0
Income tax benefit (expense)(c)		(5.2	)		(19.7	)		(19.2	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	$	599.0		$	523.8		$	416.0
Bulk transload tonnage (MMtons)(d)		78.0			103.0			96.2
Ethanol (MMBbl)		32.9			30.7			25.6
Liquids leaseable capacity (MMBbl)		56.4			54.2			47.5
Liquids utilization %		96.6			97.5			95.9

__________

(a) 2009, 2008 and 2007 amounts include a $0.9 million increase in expense, a $0.6 million decrease in expense and a $2.0 million increase in expense, respectively, associated with environmental liability adjustments.  2009 amount also includes a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal, a $0.3 million decrease in expense related to hurricane clean-up and repair activities, and a $0.7 million increase in expense from the amounts previously reported in our 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries.  2008 amount also includes a $5.3 million increase in expense related to hurricane clean-up and repair activities, a combined $2.8 million increase in expense from 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 a $1.9 million increase in expense related to fire damage and repair activities.  2007 amount also includes a $25.0 million increase in expense from the settlement of certain litigation matters related to our Cora coal terminal, and a $1.2 million increase in expense associated with legal liability adjustments.

(b) 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.  2007 amount includes gains of $1.8 million from hurricane casualty indemnifications associated with the 2005 hurricane season.

(c) 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 increased segment earnings before depreciation, depletion and amortization expenses by $22.9 million in 2009, and decreased earnings before depreciation, depletion and amortization by $15.1 million in 2008 and $26.4 million in 2007; accounting for a $38.0 million increase in earnings before depreciation, depletion and amortization expenses in 2009, and an $11.3 million increase in earnings before depreciation, depletion and amortization in 2008, when compared to the respective prior year.  The segment’s remaining $37.2 million (7%) increase in earnings before depreciation, depletion and amortization in 2009 compared to 2008, and its remaining $96.5 million (22%) increase in 2008 compared to 2007, were driven by a combination of internal asset growth and strategic business acquisitions.

We have made and continue to seek terminal acquisitions in order to gain access to new markets and to complement and/or enlarge our existing terminal operations and since the beginning of 2007, we have invested approximately $197.1 million in cash to acquire both terminal assets and equity interests in terminal operations.  Combined, these acquired operations contributed 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, and incremental earnings before depreciation, depletion and amortization of $30.4 million, revenues of $86.6 million, equity earnings of $1.7 million, and operating expenses of $57.9 million in 2008.

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All of the incremental 2009 and 2008 amounts listed above represent the earnings, revenues and expenses from acquired terminals’ operations during the additional months of ownership in 2009 and 2008, 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 for the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses; and (ii) operating revenues in both 2009 and 2008, when compared to the respective prior year.  The changes represent increases and decreases in terminal results at various locations for all bulk and liquids terminal operations owned during identical periods in both pairs of comparable years.  We group these 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, 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		(1.0	)	-			(25.7	)	(5	) %
Intrasegment Eliminations		-		-			0.8		79	%
Total Terminals	$	32.6		6	%	$	(80.7	)	(7	) %

__________

The increase in earnings before depreciation, depletion and amortization expenses from our Lower River (Louisiana) terminals was due mainly to both lower income tax expenses in 2009 compared to 2008, and to higher earnings realized from both our International Marine Terminals facility, a Louisiana partnership located in Port Sulphur, Louisiana and owned 66 2/3% by us, and our Geismar, Louisiana drumming facility, which began operations in the first quarter of 2009.  The drop in income tax expenses related to overall lower taxable income in many of our tax paying terminal subsidiaries, and the increase in earnings from IMT was largely due to lower year-over-year operating expenses in 2009, which more than offset corresponding drops in revenues resulting from less dockage, fleeting and barge services.  The terminal also recognized a $3.2 million property casualty gain (on a vessel dock that was damaged in March 2008) in the second quarter of 2009.

The increase in earnings from our Gulf Coast terminals reflects favorable results from our two large liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas.  The earnings increase was driven by higher liquids warehousing revenues, mainly due to new and incremental customer agreements (at higher rates) and to additional storage capacity, and also to additional ancillary terminal services.  Combined, our Pasadena and Galena Park terminals brought an incremental 1.85 million barrels of liquids tankage capacity online during 2009 (including incremental truck loading capacity).

For all terminals combined, total 2009 liquids throughput volumes were 1% higher than 2008, primarily due to both completed expansion projects and to 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, up 4% from a capacity of 54.2 million barrels at the end of 2008.  At the same time, our overall liquids utilization capacity rate (the ratio of our actual leased capacity to our estimated potential capacity) decreased by only 1% since the end of 2008.

The increase in earnings in 2009 from our West region terminals was driven by incremental contributions from our Kinder Morgan North 40 terminal, the crude oil tank farm we constructed near Edmonton, Alberta, Canada, and from our Vancouver Wharves bulk marine terminal, located on the north shore of Vancouver, British Columbia, Canada’s main harbor.  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 the Port Metro Vancouver.

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The increase in earnings from our Texas petroleum coke operations was chiefly due to 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 higher handling rates in 2009.  The higher volumes in 2009 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 decrease in earnings from these facilities was due primarily to decreased import/export activity, and to lower business activity at various owned and/or operated rail and terminal sites that are 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 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 relatedly, revenues from terminals owned in both years decreased by $80.7 million (7%).  However, while the overall volume and revenue declines in 2009 have generally been broad-based across all of our bulk terminals, the rate of decline has slowed—bulk tonnage decreased 28% in the first half of 2009 compared to the first half of 2008—and since the start of the year the segment has taken actions to manage costs and increase productivity.  For all terminals owned in both years, combined operating expenses decreased $97.9 million (16%) in 2009 versus 2008.  In addition to the effects from the declines in bulk tonnage volumes described above, the expense reductions were 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.

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

	EBDA Increase/(Decrease)				Revenues Increase/(Decrease)
	(In millions, except percentages)
Gulf Coast	$	27.8	25	%	$	33.8	21	%
Mid-Atlantic		20.3	50	%		34.9	34	%
Northeast		10.5	16	%		18.4	18	%
West		7.0	30	%		11.8	22	%
All others		0.5	-			8.8	2	%
Intrasegment Eliminations		-	-			15.6	100	%
Total Terminals	$	66.1	15	%	$	123.3	13	%

__________

The overall increase in earnings from our Gulf Coast terminal facilities in 2008 was primarily due to higher combined earnings from our Pasadena and Galena Park, Texas liquids facilities.  The increase was due mainly to higher liquids throughput volumes and increased liquids storage capacity as a result of terminal expansions completed since the end of 2007.

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

The increase in earnings in 2008 compared to 2007 from our Northeast terminals was largely due to higher earnings from our New York Harbor liquids terminals, which include our Perth Amboy, New Jersey terminal; our Carteret, New Jersey terminal; and our Staten Island, New York terminal.  The year-over-year increase in earnings from these terminals was driven by a combined 21% increase in liquids throughput volumes (resulting both from incremental business driven by strong demand for imported fuel and from tank expansions completed since the end of 2007), higher transfer and storage rates, and incremental revenues from ancillary terminal services.

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The overall increase in earnings from our West region terminals in 2008 versus 2007 was driven by higher earnings in 2008 from our Vancouver Wharves bulk marine terminal, due largely to higher terminal revenues from liquids throughput and handling services, and from incremental earnings from the start-up of our Kinder Morgan North 40 terminal.

Kinder Morgan Canada

	Year Ended December 31,
	2009			2008			2007
	(In millions, except operating statistics)
Revenues	$	226.1		$	196.7		$	160.8
Operating expenses		(72.5	)		(67.9	)		(65.9	)
Other expense(a)		-			-			(377.1	)
Earnings from equity investments		(4.1	)		(0.4	)		-
Interest income and Other, net-income (expense)(b)		23.9			(6.2	)		8.0
Income tax benefit (expense)(c)		(18.9	)		19.0			(19.4	)
Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(d)	$	154.5		$	141.2		$	(293.6	)
Transport volumes (MMBbl)(e)		102.5			86.7			94.4

__________

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

(b) 2008 amount includes a $19.3 million decrease in expense associated with favorable changes in Canadian income tax rates, and a $12.3 million decrease in other non-operating income, due to certain non-cash Trans Mountain regulatory accounting adjustments.

(c) 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 change related to book tax accruals made by the Express pipeline system.  2008 amount includes a $6.6 million increase in expense due to certain non-cash Trans Mountain regulatory accounting adjustments.

(d) 2007 amount includes losses of $349.2 million for periods prior to our acquisition date of April 30, 2007, and a $1.3 million decrease in income from an oil loss allowance.

(e) Represents Trans Mountain pipeline system volumes.

Our Kinder Morgan Canada business segment includes the operations of the Trans Mountain, Express, and Jet Fuel pipeline systems.  We acquired our Trans Mountain pipeline system from KMI effective April 30, 2007, and we acquired both our one-third equity ownership interest in the approximate 1,700-mile Express crude oil pipeline system and our full ownership of the approximate 25-mile Jet Fuel pipeline system from KMI effective August 28, 2008.

The certain items related to our Kinder Morgan Canada business segment and described in the footnotes to the table above accounted for a decrease in earnings before depreciation, depletion and amortization expenses of $11.6 million in 2009, when compared with 2008.  The remaining $24.9 million (18%) increase in segment earnings before depreciation, depletion and amortization consisted of (i) higher earnings of $18.1 million (13%) from Trans Mountain; (ii) incremental earnings of $10.1 million from the combined Express and Jet Fuel pipeline operations during the periods we owned the assets in 2009 only (January through August); and (iii) lower earnings of $3.3 million from the combined Express and Jet Fuel pipeline operations during the period (September through December) we owned the assets in both years.

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

The overall $3.3 million decrease in earnings from our Express and Jet Fuel operations for the same comparable periods in 2009 and 2008 was driven by a $3.4 million decrease in equity earnings from our 33 1/3% ownership interest in the Express pipeline system in 2009.  The decrease was 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.

When comparing the segment’s operating results for 2008 with 2007, the certain items described in the footnotes to the table above accounted for an increase in earnings before depreciation, depletion and amortization of $350.9 million.  The remaining $83.9 million (147%) increase in segment earnings before depreciation, depletion and amortization in 2008 versus 2007 consisted of higher earnings of $38.1 million (67%) from the Trans Mountain pipeline assets we owned in the same periods in both years (May through December), and incremental earnings of $45.8 million from periods we owned assets in 2008 only (Trans Mountain for the period January through April, and Express and Jet Fuel for the period September through December).

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The increase in earnings from Trans Mountain during the same periods in both 2008 and 2007 was driven primarily by higher operating revenues, due largely to the completion of the Trans Mountain Pipeline Anchor Loop expansion project.  The Anchor Loop project boosted pipeline capacity from 260,000 to 300,000 barrels per day and resulted in higher period-to-period average toll rates.  The higher tariffs became effective in June 2008, and more than offset an 8% decline in mainline throughput volumes in 2008, which resulted primarily from lower demand for water-borne exports out of Vancouver, British Columbia.

Other

	Year Ended December 31,
	2009			2008			2007
	(In millions-income (expense)
General and administrative expenses(a)	$	(330.3	)	$	(297.9	)	$	(278.7	)
Unallocable interest expense, net of interest income(b)	$	(431.3	)	$	(397.6	)	$	(395.8	)
Unallocable income tax expense	$	(8.5	)	$	(9.3	)	$	(4.6	)
Net income attributable to noncontrolling interests(c)	$	(16.3	)	$	(13.7	)	$	(7.0	)

__________

(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.  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.  2007 amount includes (i) a $26.2 million increase in expense, allocated to us from KMI, associated with closing the going-private transaction (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $5.5 million expense related to Trans Mountain expenses for periods prior to our acquisition date of April 30, 2007; (iii) a $2.1 million expense due to the adjustment of certain insurance related liabilities; (iv) a $1.7 million increase in expense associated with the 2005 hurricane season; (v) a $1.5 million expense for certain Trans Mountain acquisition costs; and (vi) a $0.8 million expense related to the cancellation of certain commercial insurance policies.

(b) 2009 amount includes a $1.6 million increase in imputed interest expense 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.  2007 amount includes a $2.4 million increase in expense related to imputed interest on our Cochin Pipeline acquisition, and a $1.2 million expense for Trans Mountain expenses for periods prior to our acquisition date of April 30, 2007.

(c) 2009, 2008 and 2007 amounts include decreases of $0.7 million, $0.4 million and $3.9 million, respectively, in net income attributable to our noncontrolling interests, related to the effect from all of the 2009, 2008 and 2007 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.  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.

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Combined, the certain items described in the footnotes to the table above increased our general and administrative expenses $6.6 million in 2009, $5.0 million in 2008, and $37.8 million in 2007, and after taking into effect these certain items, our general and administrative expenses increased $30.8 million (11%) and $52.0 million (22%), respectively, in 2009 and 2008, when compared to the respective prior year.  The overall increase in general and administrative expenses in 2009 versus 2008 included a combined $15.8 million increase due to higher employee benefits and payroll tax expenses in 2009, and a $10.7 million increase due to a drop in capitalized overhead expenses (other than benefits and payroll taxes), relative to 2008.  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 year-over-year labor force.  The increase due to lower capitalized expenses was due in part to lower overall spending on capital projects in 2009 versus 2008, and to fewer overhead expenses meeting the criteria for capitalization.

The overall increase in general and administrative expenses in 2008 versus 2007 was driven by a $19.0 million increase in employee benefits and payroll tax expenses and a $16.5 million increase from incremental expenses and higher corporate overhead associated with the Trans Mountain, Express (one-third interest) and Jet Fuel pipeline systems we acquired from KMI since the beginning of 2007.  The increases in benefits and payroll taxes were primarily due to our larger asset base in 2008, including increases associated with the acquired bulk and liquids terminal operations that are described above in “—Terminals”).

After taking into effect the certain items described in footnote (b) to the table above, our unallocable interest expense, net of interest income and capitalized interest, increased $27.2 million (7%) in 2009 compared to 2008, and increased $10.3 million (3%) 2008 compared to 2007.  For both comparable periods, the increase in interest expense was attributable to higher average borrowings, and partly offset by lower effective interest rates.

Our average debt balances increased 23% in 2009 and 22% in 2008, when compared to the respective prior years.  The increases in average borrowings were largely due to the capital expenditures, joint venture contributions, and external business acquisitions we have made since the beginning of 2007.  Generally, we initially fund both our discretionary capital spending (including payments for asset expansion and improvement projects, including additional pipeline construction costs) and our acquisition outlays from borrowings under our long-term revolving bank credit facility.  From time to time, we issue senior notes and equity in order to refinance our credit facility borrowings.  For more information on our capital expansion and acquisition expenditures, see “—Liquidity and Capital Resources—Investing Activities.”

The overall year-over-year increases in interest expense in both 2009 and 2008 were partially offset by decreases in expense resulting from lower average interest rates in both years, when compared to the respective prior years, due primarily to a general drop in variable interest rates since the beginning of 2007, including decreases in the variable interest rate we paid on the borrowings made under our revolving bank credit facility.  The weighted average interest rate on all of our borrowings decreased 16% in 2009 compared to 2008, and decreased 15% in 2008 compared to 2007.  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 period-to-period decreases in our interest expense.

As of December 31, 2009, approximately 53% of our $10,592.4 million consolidated debt balance (excluding the value of interest rate swap agreements) was subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps.  As of December 31, 2008, approximately 34% of our $8,563.6 million consolidated debt balance (excluding the value of interest rate swap agreements) was subject to variable interest rates.  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 initiated January 1, 2007 and imposed on the amount of our total revenue that is apportioned to the state of Texas.  Both the decrease in expense, in 2009, and the increase in expense, in 2008, was due to higher margin tax expense accruals in 2008, relative to both 2009 and 2007.

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, increased in both 2009 and 2008, when compared to the respective prior years.  The increases in income attributable to our noncontrolling interests were due to our higher overall net income in each succeeding year.

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Liquidity and Capital Resources

General

As of December 31, 2009, we believe our balance sheet and liquidity position remained strong.  We had $146.6 million of cash and cash equivalents on hand and we had approximately $1.2 billion of borrowing capacity available under our $1.85 billion senior unsecured revolving bank credit facility (discussed below in “—Short-term Liquidity”).  We have consistently generated strong cash flows from operations—generating $2.1 billion and $2.2 billion in cash from operations for each of the years ended December 31, 2009 and 2008, respectively, and we demonstrated continued access to the equity market by raising $1.2 billion in cash from the public offering of additional common units in 2009.

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 (resulting from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings, 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.”

As described under Items 1 and 2 “Business and Properties—Environmental Matters—Climate Change,” passage of any climate control legislation or other regulatory initiatives that regulate or restrict emissions of greenhouse gases 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.

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, Baa2 and BBB, respectively, at Standard & Poor’s Rating Services, Moody’s Investor Services Inc. and Fitch Inc.  As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market.  We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations, and we are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors.

On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code.  Lehman Brothers Commercial Bank was a lending institution that provided $63.3 million of the commitments under our $1.85 billion senior unsecured revolving bank credit facility.  During the first quarter of 2009, we amended our facility to remove Lehman Brothers Commercial Bank as a lender, thus reducing the facility by $63.3 million (see Note 8  to our consolidated financial statements included elsewhere in this report).  The commitments of the other banks remain unchanged, and the facility is not defaulted.

On October 13, 2008, Standard & Poor’s Rating Services revised its outlook on our long-term credit rating to negative from stable (but affirmed our long-term credit rating at BBB), due to our previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project.  At the same time, Standard & Poor’s lowered our short-term credit rating to A-3 from A-2.  As a result of this revision to our short-term credit rating and the current commercial paper market conditions, we are unable to access commercial paper borrowings.  On May 6, 2009, Moody’s Investors Service downgraded our commercial paper rating to Prime-3 from Prime-2 and assigned a negative outlook to our long-term credit rating.  The downgrade and negative outlook were primarily related to the increases, since the beginning of 2009, in our outstanding debt balance.  However, we continue to maintain an investment grade credit rating, and all of our long-term credit ratings remain unchanged since December 31, 2008.  Furthermore, we expect that our financing and our short-term liquidity needs will continue to be met through borrowings made under our bank credit facility.  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.

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

Short-term Liquidity

Our principal sources of short-term liquidity are our (i) $1.85 billion senior unsecured revolving bank credit facility that matures August 18, 2010; and (ii) cash from operations (discussed below in “—Operating Activities”).  Borrowings under our bank credit facility can be used for general partnership purposes and as a backup for our commercial paper program.  The facility can be amended to allow for borrowings of up to $2.04 billion (after reductions for the lending commitments made by Lehman Brothers Commercial Bank, which were canceled in connection with the Lehman Brothers bankruptcy and discussed above in “—Credit Ratings and Capital Market Liquidity”).  We plan to negotiate a renewal of our credit facility before its maturity date.

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 million in principal amount of 7.50% senior notes that mature on November 1, 2010.  As discussed above in “—Credit Ratings and Capital Market Liquidity,” there were no borrowings under our commercial paper program.

As of December 31, 2008, our outstanding short-term debt was $288.7 million, primarily consisting of a $250 million principal amount of 6.30% senior notes that matured and was paid on February 1, 2009.  We had no outstanding borrowings under our credit facility or our commercial paper program as of December 31, 2008.

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; (ii) our outstanding borrowings under our credit facility; and (iii) the lending commitments made by Lehman Brothers Commercial Bank, the remaining available borrowing capacity under our bank credit facility was $1,203.8 million as of December 31, 2009.  This remaining borrowing capacity allows us to manage our day-to-day cash requirements and any anticipated obligations and currently, we believe our liquidity to be adequate.

Working capital—current assets minus current liabilities—can also be used to measure how much in liquid assets a company has available to build its business, and we had working capital deficits of $772.9 million as of December 31, 2009 and $537.7 million as of December 31, 2008.  The unfavorable change from year-end 2008 was primarily due to our incremental $300 million bank credit facility borrowings as of December 31, 2009.  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 to satisfy current liabilities and maturing obligations when they come due.

We employ a centralized cash management program for our U.S.-based bank acounts 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.

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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 to our common unitholders, Class B unitholders and general partner) through issuing long-term notes or additional common units, or by utilizing the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.  Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares to institutional investors).

From time to time we issue long-term debt securities, often referred to as our senior notes.  All of our senior notes issued to date, other than those issued under our long-term revolving credit facility or those issued by our subsidiaries and operating partnerships, generally have the same terms except for interest rates, maturity dates and prepayment premiums.  All of our outstanding 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.

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 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.

As of December 31, 2009 and December 31, 2008, the total liability balance due on the various series of our senior notes was $10,125.3 million and $8,381.5 million, respectively, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $167.1 million and $182.1 million, respectively.For more information on our debt securities and credit facility, and on our 2009 and 2008 debt related transactions, including our issuances and payments of senior notes, see Note 8 to our consolidated financial statements included elsewhere in this report.  For information on our 2009 and 2008 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.

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.

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Capital Expenditures

Our sustaining capital expenditures for the year ended December 31, 2009 were $172.2 million (including approximately $0.2 million for our proportionate share of Rockies Express’ sustaining capital expenditures).  For the year ended December 31, 2008, our sustaining capital expenditures totaled $180.6 million (including approximately $0.1 million for our proportionate share of Rockies Express’ sustaining capital expenditures).  Our forecasted expenditures for 2010 for sustaining capital expenditures are approximately $207.3 million (including $0.1 million for our proportionate shares of Rockies Express and Midcontinent Express).  Generally, we fund our sustaining capital expenditures with our cash flows from operations.  In addition to utilizing cash generated from their own operations, Rockies Express and Midcontinent Express can each fund their own cash requirements for capital expenditures through borrowings under their own credit facility, issuing their own long-term notes, or with proceeds from contributions received from their equity owners.

All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary.  The discretionary capital expenditures reflected in our consolidated statement of cash flows for the years ended December 31, 2009 and 2008, were $1,151.8 million and $2,352.5 million, respectively.  The year-to-year decrease in discretionary capital expenditures in 2009 versus 2008 was mainly due to higher capital expenditures made during 2008 on our major natural gas pipeline projects and on our Trans Mountain crude oil and refined petroleum products pipeline system.  We forecast $824.8 million for discretionary capital expenditures in our 2010 budget.

In addition to our discretionary capital expenditures, we contributed a combined $2,040.8 million in 2009 to the Rockies Express, Midcontinent Express and Fayetteville Express natural gas pipeline projects (all three reported as investments on our balance sheet and accounted for under the equity method of accounting), primarily to fund our proportionate share of both construction and/or pre-construction costs, and the repayment of senior notes by Rockies Express in August 2009.  Generally, we fund our discretionary capital expenditures and our investment contributions through borrowings under our bank credit facility.  To the extent this source of funding is not sufficient, we generally fund additional amounts through the issuance of long-term notes or common units for cash.  During 2009, we used sales of common units and the issuance of senior notes to refinance portions of our short-term borrowings under our bank credit facility.

Capital Requirements for Recent Transactions

For the years ended December 31, 2009 and 2008, our net cash outlays for the acquisition of assets and investments totaled$328.9 million in 2009 versus $16.8 million in 2008 (including the $23.4 million cash contribution we received in April 2008 from KMI as a result of a certain true-up provision in our Trans Mountain acquisition agreement).  All of our 2009 and 2008 asset acquisitions and divestitures 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.  As of December 31, 2009, our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, are summarized below (dollars in millions):

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Entity	Investment Type	Our Ownership Interest			Remaining Interest(s) Ownership	Total Entity Assets(a)		Total Entity Debt			Our Contingent Share of Entity Debt(b)
Rockies Express Pipeline LLC(c)	Limited Liability		50	%	ConocoPhillips and Sempra Energy	$	6,606.2	$	2,970.8	(d)	$	836.4
Fayetteville Express Pipeline LLC(e)	Limited Liability		50	%	Energy Transfer Partners, L.P.	$	406.1	$	355.0		$	177.5
Cortez Pipeline Company	General Partner		50	%	(f)	$	76.1	$	152.8		$	76.4	(g)
Midcontinent Express Pipeline LLC(h)	Limited Liability		50	%	Energy Transfer Partners, L.P.	$	2,227.1	$	828.3	(i)	$	14.8	(j)
Nassau County, Florida Ocean Highway and Port Authority(k)	N/A		N/A		Nassau County, Florida Ocean Highway and Port Authority		N/A		N/A		$	19.8

_________

(a) Principally property, plant and equipment.

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

(c) Rockies Express Pipeline LLC is a limited liability company and the surviving legal entity from its December 30, 2009 merger with its parent entity West2East Pipeline LLC.  As of December 31, 2009, the remaining limited liability member interests in Rockies Express Pipeline LLC are owned by ConocoPhillips (25%) and Sempra Energy (25%).  We owned a 51% ownership interest in Rockies Express Pipeline LLC from June 30, 2006 until December 1, 2009.

(d) Amount includes an aggregate carrying value of $1,298.1 million in fixed rate senior notes issued by Rockies Express Pipeline LLC in a private offering in June 2008.  All payments of principal and interest in respect of these senior notes are the sole obligation of Rockies Express.  Noteholders have no recourse against us or the other member owners of Rockies Express Pipeline LLC for any failure by Rockies Express to perform or comply with its obligations pursuant to the notes or the indenture.

(e) Fayetteville Express Pipeline LLC is a limited liability company and the owner of the Fayetteville Express Pipeline.

(f) 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.

(g) We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt.  As of December 31, 2009, Shell Oil Company shares our several guaranty obligations jointly and severally for $42.9 million of Cortez’s debt balance; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty.  Accordingly, as of December 31, 2009 we have a letter of credit in the amount of $21.4 million issued by JP Morgan Chase, in order to secure our indemnification obligations to Shell for 50% of the Cortez debt balance of $42.9 million.

Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency.  The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation.  The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement.

(h) Midcontinent Express Pipeline LLC is a limited liability company and the owner of the Midcontinent Express Pipeline.  In January 2008, in conjunction with the signing of additional binding pipeline transportation commitments, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement which provided MarkWest a one-time right to purchase a 10% ownership interest in Midcontinent Express Pipeline LLC after the pipeline was fully constructed and placed into service.  In September 2009, MarkWest declined to exercise this option.

(i) Amount includes an aggregate carrying value of $798.8 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.

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(j) In addition to our contingent share of entity debt, there is a letter of credit outstanding to support the construction of the Midcontinent Express Pipeline.  As of December 31, 2009, this letter of credit, issued by the Royal Bank of Scotland plc, had a face amount of $33.3 million.  Our contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).

(k) Arose from our Vopak terminal acquisition in July 2001.  Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida.  During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida.  A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals LLC, the operator of the port facilities.  In July 2002, we acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement.  In December 2002, we issued a $28 million letter of credit under our credit facilities and the former letter of credit guarantee was terminated.  As of December 31, 2009, the face amount of this letter of credit outstanding under our credit facility was $19.8 million.  Principal payments on the bonds are made on the first of December each year and reductions are made to the letter of credit.

For additional information with regard to our contingent debt obligations, see Note 12 to our consolidated financial statements included elsewhere in this report.

We account for our investments in Rockies Express Pipeline LLC, Fayetteville Express Pipeline LLC, Cortez Pipeline Company, and Midcontinent Express Pipeline LLC under the equity method of accounting.  For the year ended December 31, 2009, our share of earnings, based on our ownership percentage and before amortization of excess investment cost, if any, was $98.5 million from Rockies Express Pipeline LLC, $3.6 million from Fayetteville Express Pipeline LLC, $22.3 million from Cortez Pipeline Company, and $14.7 million from Midcontinent Express Pipeline LLC.  Additional information regarding the nature and business purpose of these 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	$	10,617.1	$	594.7	$	2,189.1	$	1,008.8	$	6,824.5
Interest payments(a)		9,259.0		668.7		1,180.9		1,050.8		6,358.6
Lease obligations(b)		162.5		37.7		55.7		30.4		38.7
Pension and postretirement welfare plans(c)		65.0		5.3		11.4		12.2		36.1
Other obligations(d)		11.5		6.5		-		5.0		-
Total	$	20,115.1	$	1,312.9	$	3,437.1	$	2,107.2	$	13,257.9
Other commercial commitments:
Standby letters of credit(e)	$	368.6	$	343.2	$	25.4	$	-	$	-
Capital expenditures(f)	$	260.4	$	260.4	$	-	$	-	$	-

____________

(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, 2009.

(d) For the Less than 1 year column only, represents payments due under carbon dioxide take-or-pay contracts and, for the 3-5 Years column only, represents payments due pursuant to our purchase and sale agreement with Megafleet Towing Co., Inc. for the acquisition of certain marine vessels effective April 23, 2009.

(e) The $368.6 million in letters of credit outstanding as of December 31, 2009 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) a combined $55.0 million in two letters of credit supporting our hedging of energy commodity price risks; (iv) our $30.3 million guarantee under letters of credit totaling $45.5 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a $25.4 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (vi) a $24.1 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (vii) a $21.4 million letter of credit supporting our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; (viii) a $19.8 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; (ix) a $5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois Development Revenue Bonds; and (x) a combined $17.0 million in eight letters of credit supporting environmental and other obligations of us and our subsidiaries.

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(f) Represents commitments for the purchase of plant, property and equipment as of December 31, 2009.

Operating Activities

Net cash provided by operating activities was $2,117.1 million in 2009, versus $2,235.9 million in 2008.  The overall year-to-year decrease of $118.8 million (5%) in cash flows from operations primarily consisted of:

▪ a $259.2 million decrease in cash inflows relative to net changes in working capital items, primarily driven by timing differences that resulted in lower net cash inflows 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), and by higher payments in 2009 for the settlement of certain refined product imbalance liabilities owed to U.S. military customers of our Products Pipelines business segment;

▪ a $49.9 million decrease in cash from settlements related to the early termination of interest rate swap agreements.  In January 2009, we terminated a fixed-to-variable interest rate swap agreement having a notional principal amount of $300 million and a maturity date of March 15, 2031, and we received $144.4 million for the termination of this swap agreement.  In 2008, we terminated two fixed-to-variable interest rate swap agreements having a combined notional principal amount of $700 million, and we received an aggregate amount of $194.3 million for the terminations of these swap agreements;

▪ a $113.5 million increase in cash from overall higher net income—after adjusting for depreciation, depletion and amortization expenses.  The year-to-year increase in income before depreciation, depletion and amortization from our five reportable business segments in 2009 compared to 2008 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes);

▪ a $48.6 million increase in cash inflows related to year-to-year changes in both non-current assets and liabilities and other non-cash expenses, primarily driven by a $23.8 million noncash expense associated with adjustments to long-term receivables for environmental cost recoveries recognized in the fourth quarter of 2009; and

▪ a $47.2 million increase in cash received from equity investments (distributions less earnings from equity investments) in 2009—chiefly due to incremental distributions received from Rockies Express Pipeline LLC.  The additional distributions were mainly due to the incremental earnings attributable to both the Rockies Express-East natural gas pipeline segment, which began initial pipeline service in June 2009, and the Rockies Express-West segment, which began full operations in May 2008.

Investing Activities

Net cash used in investing activities was $3,454.0 million for the year ended December 31, 2009, compared to $2,825.4 million in the prior year.  The $628.6 million (22%) overall increase in cash utilized in investing activities was primarily attributable to the following:

▪ a $1,662.2 million increase in cash used due to higher net contributions to equity investments (contributions, net of distributions in excess of cumulative earnings) in 2009—primarily driven by incremental contributions to Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Pipeline LLC to partially fund their respective Rockies Express, Midcontinent Express, and Fayetteville Express Pipeline construction and/or pre-construction costs, and the repayment of senior notes by Rockies Express in August 2009.  Combined, we contributed $2,040.8 million in 2009 to partially fund our proportionate share of these three pipeline projects, and in 2008, we contributed a combined $342.5 million.

On November 13, 2009, Fayetteville Express Pipeline LLC entered into and then made borrowings under a new $1.1 billion two and one-half year, unsecured revolving credit facility due May 11, 2012.  Fayetteville Express then made distributions to its two member owners (Energy Transfer Partners, L.P. and us) to reimburse them for prior contributions made to fund its pre-construction costs for the Fayetteville Express Pipeline, and we received returns of capital totaling $112.0 million.  Prior to the establishment of its credit facility, Fayetteville Express funded its pipeline construction costs with contributions from its member owners.

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Similarly, in February 2008, Midcontinent Express Pipeline LLC entered into and then made borrowings under a new $1.4 billion three-year, unsecured revolving credit facility due February 28, 2011.  Midcontinent then made distributions in excess of cumulative earnings to its two member owners to reimburse them for prior contributions made to fund its pipeline construction costs.  Our proportionate share of these distributions was $89.1 million;

▪ a $312.1 million increase in cash used for the acquisition of assets and investments, when compared to 2008.  The increase was driven by the $265.3 million we paid to acquire the natural gas treating business from Crosstex Energy L.P. and Crosstex Energy, Inc. effective October 1, 2009, and the $36.0 million we paid to acquire a 40% membership interest in Endeavor Gathering LLC effective November 1, 2009;

▪ an $89.5 million increase in cash used primarily due to the return of margin deposits in 2008, which was posted in a prior period.  We deposit margin money with our counterparties in order to maintain certain energy commodity hedging positions, and our margin deposits are associated largely with our utilization of derivative contracts to hedge (offset) against the volatility of energy commodity price risks.  These margin deposits must be posted and maintained daily, and provide financial security to ensure performance on our hedging contracts;

▪ a $1,209.2 million decrease in cash used for capital expenditures—largely due to the higher investment undertaken in 2008 to construct our Kinder Morgan Louisiana Pipeline and to expand our Trans Mountain crude oil and refined petroleum products pipeline system; and

▪ a $219.2 million decrease in cash used due to our receipt, in 2009, of the full repayment of a $109.6 million loan we made in December 2008 to a single customer of our Texas intrastate natural gas pipeline group.

Financing Activities

Net cash provided by financing activities totaled $1,415.0 million in 2009.  In 2008, our financing activities provided net cash of $601.3 million.  The $813.7 million (135%) overall increase in cash inflows provided by financing activities in 2009 versus 2008 was mainly due to:

▪ a $594.7 million increase in cash from higher partnership equity issuances.  The increase relates to the combined $1,155.6 million we received, after commissions and underwriting expenses, from the sales of additional common units in 2009, versus the combined $560.9 million we received, after commissions and underwriting expenses, from sales of common units in 2008.  We used the proceeds from each of our 2009 unit issuances to reduce the borrowings under our bank credit facility.  We used the proceeds from our 2008 common unit sales to reduce the borrowings under our commercial paper program.  All of our 2009 and 2008 equity issuances are discussed further in Note 10 to our consolidated financial statements included elsewhere in this report;

▪ a $532.1 million increase in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs.  The year-to-year increase was primarily due to (i) a $589.1 million increase in cash due to net commercial paper repayments in 2008; (ii) a $300.0 million increase in cash from incremental net borrowings under our bank credit facility in 2009; and (iii) a $349.5 million decrease in cash due to lower net issuances and repayments of senior notes in 2009, when compared to 2008.

The increases and decreases in cash inflows from our commercial paper and credit facility borrowings were related in part to our short-term credit rating downgrade discussed above in “—Credit Ratings and Capital Market Liquidity,” and in part to the year-to-year changes in our working capital items.  The decrease in cash inflows from changes in senior notes outstanding reflects the $1,730.7 million we received after issuing and repaying senior notes in 2009, versus the combined $2,080.2 million we received from three public offerings of senior notes in 2008.  We used the proceeds from each of our 2009 offerings to reduce the borrowings under our revolving bank credit facility.  We used the proceeds from our first two 2008 offerings to reduce the borrowings under our commercial paper program, and we used the proceeds from our third 2008 debt offering (in December) to reduce the borrowings under our revolving bank credit facility.  All of our 2009 and 2008 debt offerings and repayments are discussed fully in Note 8 to our consolidated financial statements included elsewhere in this report;

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▪ a $283.2 million decrease in cash due to higher partnership distributions paid in 2009, when compared to distributions paid in 2008.  Distributions to all partners, consisting of our common and Class B unitholders, our general partner and noncontrolling interests, totaled $1,771.9 million in 2009, compared to $1,488.7 million last year.  The increase in distributions to all partners was due to an increase in the per unit cash distributions paid, an increase in the number of units outstanding, and an increase in our general partner incentive distributions.  The increase in our general partner incentive distributions resulted from both increased cash distributions per unit and an increase in the number of common units and i-units outstanding; and

▪ a $31.8 million decrease in cash from net changes in cash book overdrafts—resulting from timing differences on checks issued but not yet presented for payment.

Partnership Distributions

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

Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for 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.  For 2009, 2008 and 2007, we distributed approximately 101%, 92%, and 99%, respectively, of the total of cash receipts less cash disbursements (calculations assume that KMR unitholders received cash instead of additional i-units).  The difference between these numbers and 100% of distributable cash flow reflects net changes in reserves.

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

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.  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 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.  We retain this cash and use it in our business.  To date, all our cash distributions 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.

Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed.  Our general partner’s incentive distribution that we declared for 2009 and 2008 was $932.3 million and $800.8 million, respectively, while the incentive distribution paid to our general partner during 2009 and 2008 was $906.5 million and $754.6 million, respectively.  The difference between declared and paid distributions is due to the fact that our distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year.

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On February 12, 2010, we paid a quarterly distribution of $1.05 per unit for the fourth quarter of 2009.  This distribution matched the $1.05 distribution per unit we paid for the fourth quarter of 2008.  We paid this distribution in cash to our common unitholders and to our Class B unitholders.  KMR, our sole i-unitholder, received additional i-units based on the $1.05 cash distribution per common unit.  We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions; however, no assurance can be given that future distributions will continue at such levels.

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 levels of cash from operations would be adjusted downward proportionately by multiplying each distribution 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.  For example, assuming the unrecovered initial common unit price is $5.75 per common unit and if cash from the first interim capital transaction of $2.375 per unit was distributed to owners of common units, then the amount of the first three distribution levels would each be reduced to 50% of its then current level.  The unrecovered initial common unit price generally is the amount by which the initial common unit price exceeds the aggregate distribution of cash from interim capital transactions per common unit.

When the initial common unit price is fully recovered, then each of the first three distribution levels will have been reduced to zero. 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.

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 or the California Public Utilities Commission;

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

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

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

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

▪ 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 and the Alberta, Canada 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;

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

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

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

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

▪ capital and credit markets conditions, inflation and interest rates;

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

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

▪ our ability to achieve cost savings and revenue growth;

▪ foreign exchange fluctuations;

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

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

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

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

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

▪ the timing and success of our business development efforts; and

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

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

See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements.  When considering forward-looking statements, one should keep in mind the risk factors described in 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.

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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 Rating Services):

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

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 in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net income.  Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs.

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

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The accumulated components of other comprehensive income are reported separately as accumulated other comprehensive income or loss in the stockholders’ equity section of the balance sheet. For us, the amounts included in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets primarily include (i) the effective portion of the gains and losses on cash flow hedging derivatives (which are primarily related to the derivative contracts associated with our hedging of anticipated future cash flows from the sales and purchases of natural gas, natural gas liquids and crude oil) and (ii) foreign currency translation adjustments (which result from translating all of our foreign denominated assets and liabilities at current exchange rates, while equity is translated by using historical or weighted-average exchange rates).

The total “Accumulated other comprehensive loss” balance included within the Partners’ Capital section of our accompanying balance sheets as of December 31, 2009 included both a cumulative debit amount (unrealized loss) associated with cash flow hedging derivatives of $418.9 million and a cumulative credit amount (unrealized gain) associated with foreign currency translation of $32.4 million. The total “Accumulated other comprehensive loss” included within the Partners’ Capital section of our accompanying balance sheets as of December 31, 2008 included a cumulative debit amount (unrealized loss) associated with cash flow hedging derivatives of $64.6 million and a cumulative debit amount (unrealized loss) of $217.3 million from foreign currency translation adjustments.

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

We measure the risk of price changes in the natural gas, natural gas liquids and crude oil markets utilizing a value-at-risk model. Value-at-risk is a statistical measure 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. The value-at-risk computations utilize a confidence level of 97.7% for the resultant price movement and a holding period of one day is chosen for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the value-at-risk number presented.

For each of the years ended December 31, 2009 and 2008, our value-at-risk reached a high of $10.4 million and $1.8 million, respectively, and a low of $2.6 million and $0.7 million, respectively. Value-at-risk as of December 31, 2009 was $10.1 million, and averaged $7.6 million for 2009. Value-at-risk as of December 31, 2008 was $0.7 million, and averaged $1.5 million for 2008. The increase in value-at-risk during 2009 largely results from our increased use of options to hedge crude oil production.

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 these 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 portfolio of derivative contracts is offset largely by changes in the value of the underlying physical transactions. For more information on our 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.

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As of December 31, 2009 and 2008, the carrying values of our fixed rate debt were approximately $10,198.4 million and $8,469.5 million, respectively.  These amounts compare to, as of December 31, 2009 and 2008, fair values of $10,871.7 million and $7,536.4 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 2009 and 2008, would result in changes of approximately $448.3 million and $284.2 million, respectively, in the fair values of these instruments.

The carrying value and fair value of our variable rate debt, including associated accrued interest and excluding the value of interest rate swap agreements (discussed below), was $394.2 million as of December 31, 2009 and $94.5 million as of December 31, 2008.  A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 46 basis points in 2009), when applied to our outstanding balance of variable rate debt as of December 31, 2009 and 2008, including adjustments for notional swap amounts, would result in changes of approximately $25.6 million and $15.8 million, respectively, in our 2009 and 2008 annual pre-tax earnings.

As of December 31, 2009 and 2008, we were a party to interest rate swap agreements with notional principal amounts of $5.2 billion and $2.8 billion, respectively.  An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount.  Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment.  The principal amount is notional because there is no need to exchange actual amounts of principal.

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

As of both December 31, 2009 and 2008, 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, 2009 and 2008, our cash and investment portfolio included approximately $13.2 million and $13.2 million, respectively, in fixed-income debt securities.  Because our investment in debt securities was made and will be maintained in the future to directly offset the interest rate risk on a like amount of long-term debt, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio.  Also, since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.

See Note 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 swap agreements, see Note 13.

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 112.

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

None.

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Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2009, 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, 2009.

The effectiveness of our internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their attestation report which appears herein.

Certain businesses we acquired during 2009 were excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2009.  The excluded businesses consisted of the following:

▪ the marine vessels we acquired from Megafleet Towing Co., Inc. effective April 23, 2009;

▪ the natural gas treating business we acquired from Crosstex Energy, L.P. and Crosstex Energy, Inc. effective October 1, 2009; and

▪ the 40% equity ownership interest in Endeavor Gathering LLC we acquired effective November 1, 2009.

These businesses, in the aggregate, constituted0.34% of our total revenues for 2009 and1.64% of our total assets as of December 31, 2009.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Directors and Executive Officers of our General Partner and its Delegate

Set forth below is certain information concerning the directors and executive officers of our general partner and KMR, the delegate of our general partner.  All directors of our general partner are elected annually by, and may be removed by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of KMR are elected annually by, and may be removed by, our general partner as the sole holder of KMR’s voting shares.  Kinder Morgan (Delaware), Inc. is a wholly-owned subsidiary of KMI.  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	65	Director, Chairman and Chief Executive Officer
C. Park Shaper	41	Director and President
Steven J. Kean	48	Executive Vice President and Chief Operating Officer
Gary L. Hultquist	66	Director
C. Berdon Lawrence	67	Director
Perry M. Waughtal	74	Director
Kimberly A. Dang	40	Vice President and Chief Financial Officer
Jeffrey R. Armstrong	41	Vice President (President, Terminals)
Thomas A. Bannigan	56	Vice President (President, Products Pipelines)
Richard T. Bradley	54	Vice President (President, CO2)
David D. Kinder	35	Vice President, Corporate Development and Treasurer
Joseph Listengart	41	Vice President, General Counsel and Secretary
Thomas A. Martin	48	Vice President (President, Natural Gas Pipelines)
James E. Street	53	Vice President, Human Resources and Administration

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

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

Steven J. Kean is Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and KMI.  Mr. Kean was elected Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and KMI 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 KMI from May 2005 to January 2006.  He served as President, Texas Intrastate Pipeline Group from June 2002 until May 2005.  He served as Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002.  He has also served as Chief Operating Officer, and as a member of the Board of Managers, of Kinder Morgan Holdco LLC since May 2007.  Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State University in May 1982.

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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, a FINRA-registered broker-dealer and investment bank, specializing in technology, mergers and acquisitions.

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.

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.

Kimberly A. Dang is Vice President and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and KMI.  Mrs. Dang was elected Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and KMI in May 2005.  She served as Treasurer of KMR, Kinder Morgan G.P., Inc. and KMI from January 2004 to May 2005.  She was elected Vice President, Investor Relations of KMR, Kinder Morgan G.P., Inc. and KMI 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 KMI.  She has also served as Chief Financial Officer of Kinder Morgan Holdco LLC since May 2007.  Mrs. Dang received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University and a Bachelor of Business Administration degree in accounting from Texas A&M University.

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

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

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

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

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

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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 April2003 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. and KMI.  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 KMI in August 1999.  Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.

Qualifications of Directors

Mr. Kinder's experience as the Chief Executive Officer of KMR since its formation in 2001 and of our general partner since 1997, combined with his significant equity ownership of Kinder Morgan Holdco LLC, which indirectly owns all the common equity of our general partner, uniquely qualify him to serve as the Chairman and a Director of KMR and our general partner.

Mr. Shaper's experience as President of KMR and of our general partner since 2005, together with his experience as an executive officer of various Kinder Morgan entities since 2000, provide him intimate knowledge of our operations, finances and strategy.

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.

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.

Mr. Waughtal served for 30 years as Vice Chairman of development and operations and as Chief Financial Officer of Hines Interests Limited Partnership, a privately owned, international real estate firm, and for the last 15 years has been Chairman of Songy Partners Limited, providing him with strategic planning, management, finance and accounting experience.

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.

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

Section 16(a) Beneficial Ownership Reporting Compliance

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

Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2009.

Item 11. Executive Compensation.

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

Compensation Discussion and Analysis

Program Objectives

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

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

Currently, our executive compensation program is principally comprised of the following two elements: (i) base cash salary; and (ii) possible annual cash bonus (reflected in the Summary Compensation Table below as Non-Equity Incentive Plan Compensation).  In addition, we believe that the compensation of our (i) principal executive officer; (ii) principal financial officer; and (iii) three most highly compensated executive officers (other than our principal executive officer and principal financial officer) serving at fiscal year end 2009 and named below (collectively referred to in this Item 11 as our named executive officers), should be directly and materially tied to the financial performance of KMI 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 2009, 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 KMI; and (ii) a cash distribution per common unit target by us.

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We pay our executive officers a base salary not to exceed $300,000.  We believe the base salaries paid to our executive officers continue to be below the industry average for similarly positioned executives, based upon independent salary surveys in which we participate, and we periodically compare our executive compensation components with market information.  The purpose of this comparison is to ensure that our total compensation package operates effectively, remains both reasonable and competitive with the energy industry, and is generally comparable to the compensation offered by companies of similar size and scope as us.  We also keep abreast of current trends, developments, and emerging issues in executive compensation, and if appropriate, will obtain advice and assistance from outside legal, compensation or other advisors.

We have endeavored to design our executive compensation program and practices with appropriate consideration of all tax, accounting, legal and regulatory requirements.  Section 162(m) of the Internal Revenue Code limits the deductibility of certain compensation for our executive officers to $1.0 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 are paid under KMI’s Annual Incentive Plan as a result of reaching designated financial targets established by Mr. 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 we and private companies, such as KMI, are not subject to section 162(m), we and KMI have chosen to generally operate as if this code section does apply to us and KMI as a measure of appropriate governance.

For each of the years ended December 31, 2009, 2008 and 2007, no restricted stock or options to purchase shares of KMI, units of us or shares of KMR were granted to any of our named executive officers; however, as a result of its May 2007 going-private transaction, KMI became a wholly-owned subsidiary of Kinder Morgan Holdco LLC, and in connection with the going-private transaction, Kinder Morgan Holdco LLC awarded members of KMI’s management Class A-1 and Class B units of Kinder Morgan Holdco LLC.  While not awarded by us, KMR’s compensation committee was aware of the units awarded by Kinder Morgan Holdco LLC and took these awards into account as components of the total compensation received by our executive officers in 2007.

In accordance with generally accepted accounting principles, Kinder Morgan Holdco LLC is required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units.  As a subsidiary of Kinder Morgan Holdco LLC, we are, under accounting rules, allocated a portion of this compensation expense, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units.  The Class A-1 and Class B units awarded to members of our management may be viewed as a replacement of restricted stock as a component of long-term executive compensation.  For more information concerning the Kinder Morgan Holdco LLC units, see “Elements of Compensation—Other Compensation—Kinder Morgan Holdco LLC Units” below.

Behaviors Designed to Reward

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

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

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At his request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, receives $1 of base salary per year and no other compensation from KMI.  Additionally, Mr. Kinder has requested that he receive no annual bonus or other compensation from us (other than the unit awards by Kinder Morgan Holdco LLC he received in 2007).  Mr. Kinder does not have any deferred compensation, supplemental retirement or any other special benefit, compensation or perquisite arrangement with us.  Each year, Mr. Kinder reimburses us for his portion of health care premiums and parking expenses.  Mr. Kinder was awarded Class B units by and in Kinder Morgan Holdco LLC in connection with KMI’s going-private transaction, and while we are, under accounting rules, allocated compensation expense attributable to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.

Elements of Compensation

As outlined above, our executive compensation program currently is principally composed of two elements: (i) a base cash salary; and (ii) a possible annual cash bonus.  Mr. Richard D. Kinder and our compensation committee review and approve annually the financial goals and objectives of both KMI and us that are relevant to the compensation of our named executive officers.

Information is solicited from relevant members of senior management regarding the performance of our named executive officers, and determinations and recommendations are made at the regularly scheduled first quarter board and compensation committee meetings.  If any of KMI’s executive officers is also an executive officer of our general partner or KMR, the compensation determination or recommendation (i) may be with respect to the aggregate compensation to be received by such officer from KMI, 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 KMI, KMR or our general partner, as the case may be, in which case such compensation will be allocated among KMI, on the one hand, and KMR and our general partner, on the other.

Base Salary

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

Possible Annual Cash Bonus (Non-Equity Cash Incentive)

Our possible annual cash bonuses are provided for under KMI’s Annual Incentive Plan, which became effective January 18, 2005.  The Annual Incentive Plan ends after the 2009 bonus year; however, for the 2010 bonus year, KMI’s and KMR’s Boards of Directors have approved a new Annual Incentive Plan that mirrors the current plan.  The overall purpose of the KMI Annual Incentive Plan is to increase our executive officers’ and our employees’ personal stake in the continued success of KMI and us by providing to them additional incentives through the possible payment of annual cash bonuses.  Under the plan, annual cash bonuses are budgeted for at the beginning of each year and may be paid to our executive officers and other employees depending on whether KMI and its subsidiaries (including us) meet certain performance objectives.  Assuming the performance objectives are met, the budgeted pool of bonus dollars is further assessed and potentially decreased or increased based on KMI and its subsidiaries’ (including us) overall performance in a variety of areas, including safety and environmental goals and regulatory compliance.

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

Whether KMI and its subsidiaries (including us) have met their overall performance objectives, as well as how they have performed with respect to a variety of areas such as safety and environmental goals and regulatory compliance, negatively or positively, impacts the bonuses of our named executive officers.  Individual performance also impacts their bonuses.  Our named executive officers have different areas of responsibility that require different skill sets.  Consequently, many of the skills and aspects of performance taken into account in determining the bonus awards for the respective named executive officers differ based on their areas of responsibility.  However, some skills, such as working within a budget, are applicable for all of the executive officers.  While no formula is used in assessing individual performance, the process of assessing the performance of each of the named executive officers is consistent, with each such officer being assessed relative to the officer’s performance of his or her job in preceding years as well as with respect to specific matters assigned to the officer over the course of the year.  Individual performance, as described above, as well as safety and environmental goals and regulatory compliance were taken into account with respect to the 2009 awards.

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

The plan consists of two components: the executive plan component and the non-executive plan component.  Our Chairman and Chief Executive Officer and all employees who report directly to the Chairman are eligible for the executive plan component; however, as stated elsewhere in this “Compensation Discussion and Analysis”, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, has elected to not participate under the plan.  As of December 31, 2009, excluding Mr. Richard D. Kinder, eleven of our current 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.

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

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

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

▪ KMI’s free cash flow or the free cash flow of one of its subsidiaries or business units;

▪ KMI’s net income or the net income of one of its subsidiaries or business units;

▪ KMI’s revenues or the revenues of one of its subsidiaries or business units;

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

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

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

▪ KMI’s capital expenditures or the capital expenditures of one of its subsidiaries or business units;

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

▪ KMI’s debt-equity ratios and key profitability ratios, or the debt-equity ratios and key profitability ratios of one of its subsidiaries or business units; or

▪ KMP’s distribution per unit.

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Two financial performance objectives were set for 2009 under both the executive plan component and the non-executive plan component.  The 2009 financial performance objectives were (i) $4.20 in cash distributions per common unit by us; (ii) $646 million of free cash flow by KMI, which are distributions received from KMP (including value received in the form of KMR units) and NGPL less cash taxes, cash interest, and general and administrative expenses; and (iii) improving our environmental, health, and safety performance objectives by beating industry average incident rates and improving our incident rates compared to our previous three year averages.  Our targets were the same as our previously disclosed 2009 budget expectations.  At the end of 2009 the extent to which the financial performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by KMR’s compensation committee was determined.

The 2009 bonuses for our executive officers were overwhelmingly based on whether the established financial performance objectives were met.  Other factors, such as individual over performance or under performance, were considered.  With respect to using these other factors in assessing performance, KMR’s compensation committee did not find it practicable to, and did not, use a “score card”, or quantify or assign relative weight to the specific criteria considered.  The amount of a downward or upward adjustment, subject to the maximum bonus opportunity that was established at the beginning of the year, was not subject to a formula.  Specific aspects of an individual’s performance were not identified in advance.  Rather, the adjustment was based on KMR’s compensation committee’s judgment, giving consideration to the totality of the record presented, including the individual’s performance, and the magnitude of any positive or negative factors.

The table below sets forth the bonus opportunities that could have been payable by KMI and us collectively to our executive officers for 100% achievement of the performance objectives established for 2009. The amount of the portion of the bonus actually paid by us to any executive officer under the plan may be reduced from the amount of any bonus opportunity open to such executive officer. Because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established each year for eligible executive officers chosen to participate for that year, it is not possible to accurately predict any amounts that will actually be paid under the executive plan portion of the plan over the life of the plan. The compensation committee set bonus opportunities under the plan for 2009 for the executive officers at dollar amounts in excess of that which were expected to actually be paid under the plan. The actual payout amounts under the Non-Equity Incentive Plan Awards made for 2009 (paid in 2010) are set forth in the Summary Compensation Table in the column entitled “Non-Equity Incentive Plan Compensation.”

KMI Annual Incentive Plan

Bonus Opportunities for 2009

Name and Principal Position	Dollar Value
Richard D. Kinder, Chairman and Chief Executive Officer	$	-	(a)
Kimberly A. Dang, Vice President and Chief Financial Officer		1,000,000	(b)
Steven J. Kean, Executive Vice President and Chief Operating Officer		1,500,000	(c)
Joseph Listengart, Vice President, General Counsel and Secretary		1,000,000	(b)
C. Park Shaper, Director and President		1,500,000	(c)

_____________

(a) Declined to participate.

(b) Under the plan, for 2009, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $500,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $1,500,000 in bonus opportunities would have been available.  The KMR compensation committee may, in its sole discretion, reduce the award payable by us to any participant for any reason.

(c) Under the plan, for 2009, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $750,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $2,000,000 in bonus opportunities would have been available.  The KMR compensation committee may, in its sole discretion, reduce the award payable by us to any participant for any reason.

KMI may amend the plan from time to time without shareholder approval except as required to satisfy the Internal Revenue Code or any applicable securities exchange rules.  The plan ended with the 2009 bonus, which was paid in February 2010.

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Other Compensation

KMI Savings Plan.  The KMI Savings Plan is a defined contribution 401(k) plan.  The plan permits all full-time employees of KMI and KMGP Services Company, Inc., including our 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 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.

KMI Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and KMI, including our named executive officers, are also eligible to participate in a Cash Balance Retirement Plan.  For more information on this plan, see Note 9 “Employee Benefits—Cash Balance Retirement Plan” to our consolidated financial statements included elsewhere in this report.  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, 2009, under the provisions of the Cash Balance Retirement Plan.  With respect to our named executive officers, the benefits were computed using the same assumptions used for financial statement purposes, assuming current remuneration levels without any salary projection, and assuming participation until normal retirement at age sixty-five.  These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.

Pension Benefits
Name	Plan Name	Current Credited Yrs of Service	Present Value of Accumulated Benefit(a)		Contributions During 2009(b)
Richard D. Kinder	Cash Balance	9	$	-	$	-
Kimberly A. Dang	Cash Balance	8		43,936		4,243
Steven J. Kean	Cash Balance	8		55,162		4,683
Joseph Listengart	Cash Balance	9		65,349		5,082
C. Park Shaper	Cash Balance	9		65,349		5,082

__________

(a) The present values in the Pension Benefits table are based on certain assumptions, including a 6.0% 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.

(b) Contributions were made from January 1, 2009 through April 12, 2009.  The plan suspended contributions for the remainder of 2009; however, individual accounts were credited with interest for the entire twelve month period.

Other Potential Post-Employment Benefits.  On October 7, 1999, Mr. Richard D. Kinder entered into an employment agreement with KMI 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 KMI’s long term viability.  Mr. Kinder continues to accept an annual salary of $1, and he receives no other compensation from us.  Mr. Kinder was awarded Class B units by and in Kinder Morgan Holdco LLC in connection with KMI’s going-private transaction, and while we, as a subsidiary of Kinder Morgan Holdco LLC, are allocated compensation expense attributable to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.

KMI believes that Mr. Kinder’s employment agreement contains provisions that are beneficial to KMI and its subsidiaries and accordingly, Mr. Kinder’s employment agreement is extended annually at the request of KMI and KMR’s Board of Directors.  For example, with limited exceptions, Mr. Kinder is prevented from competing in any manner with KMI or any of its subsidiaries, while he is employed by KMI and for 12 months following the termination of his employment with KMI.  The agreement contains provisions that address termination with and without cause, termination as a result of change in duties or disability, and death.  At his current compensation level, the maximum amount that would be paid to Mr. Kinder or his estate in the event of his termination is three times $750,000, or $2.25 million.  This payment would be made if Mr. Kinder were terminated by KMI without cause or if Mr. Kinder terminated his employment with KMI as a result of a change in duties (as defined in the employment agreement).  There are no employment agreements or change-in-control arrangements with any of our other executive officers.

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

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

The Class A-1 units were awarded by Kinder Morgan Holdco LLC to members of KMI’s management (other than Mr. Richard D. Kinder) who reinvested their equity interests in Kinder Morgan Holdco LLC in connection with the going-private transaction in consideration of their services to or for the benefit of Kinder Morgan Holdco LLC.  Class A-1 units entitle a holder thereof to receive distributions from Kinder Morgan Holdco LLC in an amount equal to distributions paid on Class A units (other than distributions on the Class A units that represent a return of the capital contributed in respect of such Class A units), but only after the Class A units have received aggregate distributions in an amount equal to the amount of capital contributed in respect of the Class A units.

Summary Compensation Table

The following table shows compensation paid or otherwise awarded to (i) our principal executive officer; (ii) our principal financial officer; and (iii) our three most highly compensated executive officers (other than our principal executive officer and principal financial officer) serving at fiscal year end 2009 (collectively referred to as our named executive officers) for services rendered to us, our subsidiaries or our affiliates, including KMI and Kinder Morgan Holdco LLC (collectively referred to as the KMI affiliated entities), during fiscal years 2009, 2008 and 2007.

The amounts in the columns below, except the column entitled “Unit Awards by Kinder Morgan Holdco LLC”, represent the total compensation paid or awarded to our 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.  The amounts in the column entitled “Unit Awards by Kinder Morgan Holdco LLC” consist of the portion of the grant date fair value of the Kinder Morgan Holdco LLC Class A-1 and Class B units received by our named executive officers that was allocated to us for financial reporting purposes.  As a subsidiary of Kinder Morgan Holdco LLC, we are allocated a portion of the compensation expense recognized by Kinder Morgan Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units and none of our named executive officers has received any payments in respect of such units.

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						(a)		(b)		(c)		(d)
Name and Principal Position	Year	Salary		Bonus		Non-Equity Incentive Plan Compensation		Change in Pension Value		All Other Compensation		Unit Awards by Kinder Morgan Holdco LLC		Total
Richard D. Kinder	2009	$	1	$	-	$	-	$	-	$	-	$	-	$	1
Director, Chairman and	2008		1		-		-		-		-		-		1
Chief Executive Officer	2007		1		-		-		-		-		9,200,000		9,200,001
Kimberly A. Dang	2009		257,692		-		550,000		4,243		3,115		-		815,050
Vice President and	2008		223,077		-		440,000		8,285		11,863		-		683,225
Chief Financial Officer	2007		200,000		-		400,000		7,294		32,253		672,409		1,311,956
Steven J. Kean	2009		257,692		-		1,250,000		4,683		4,251		-		1,516,626
Executive Vice President	2008		223,077		-		1,150,000		8,755		13,007		-		1,394,839
and	2007		200,000		-		1,100,000		7,767		147,130		2,708,095		4,162,992
Chief Operating Officer
Joseph Listengart	2009		257,692		-		925,000		5,082		2,866		-		1,190,640
Vice President, General	2008		223,077		-		900,000		9,188		11,629		-		1,143,894
Counsel and Secretary	2007		200,000		-		1,000,000		8,194		102,253		1,706,963		3,017,410
C. Park Shaper	2009		257,692		-		1,300,000		5,082		3,971		-		1,566,745
Director and President	2008		223,077		-		1,200,000		9,188		12,769		-		1,445,034
	2007		200,000		-		1,200,000		8,194		155,953		4,296,125		5,860,272

_______________

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

(b) Represents the 2009, 2008 and 2007, as applicable, change in the actuarial present value of accumulated defined pension benefit (including unvested benefits) according to the provisions of KMI’s Cash Balance Retirement Plan.

(c) Amounts include value of contributions to the KMI Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000, taxable parking subsidy and, for 2007 only, dividends paid on unvested restricted stock awards.  Amounts in 2009, 2008 and 2007 representing the value of contributions to the KMI Savings Plan are $2,308, $11,154 and $10,000, respectively.  For 2009, Mrs. Dang also has $226 in imputed income from a company provided cell phone.  Amounts in 2007 representing the value of dividends paid on unvested restricted stock awards are as follows: for Mrs. Dang $21,875; for Mr. Kean $136,500; for Mr. Listengart $91,875; and for Mr. Shaper $144,375.

(d) Such amounts represent the grant date fair value of the Class A-1 and Class B units of Kinder Morgan Holdco LLC received by the named executive officers (a portion of which is allocated to us for financial reporting purposes).  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.  See “—Elements of Compensation—Other Compensation—Kinder Morgan Holdco LLC Units” above for further discussion of these units.

Grants of Plan-Based Awards

The following supplemental compensation table shows compensation details on the value of all non-guaranteed and non-discretionary incentive awards granted during 2009 to our named executive officers.  The table includes awards made during or for 2009.  The information in the table under the caption “Estimated Future Payments Under Non-Equity Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the KMI Annual Incentive Plan for performance in 2009.  Amounts actually paid under that plan for 2009 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 2009.

	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		2,000,000
Joseph Listengart		500,000		1,000,000		1,500,000
C. Park Shaper		750,000		1,500,000		2,000,000

___________

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

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Outstanding Equity Awards at Fiscal Year-End

The only unvested equity awards outstanding at the end of fiscal 2009 were the Class B units of Kinder Morgan Holdco LLC awarded in 2007 by Kinder Morgan Holdco LLC to our named executive officers.  As a subsidiary of Kinder Morgan Holdco LLC, we are allocated a portion of the compensation expense recognized by Kinder Morgan Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units.

	Stock Awards
Name	Type of Units	Number of units that have not vested		Market value of units of stock that have not vested(a)
Richard D. Kinder	Class B units		791,405,452		N/A
Kimberly A. Dang	Class B units		49,462,841		N/A
Steven J. Kean	Class B units		158,281,090		N/A
Joseph Listengart	Class B units		79,140,545		N/A
C. Park Shaper	Class B units		217,636,499		N/A

__________

(a) Because the Class B units are equity interests of Kinder Morgan Holdco LLC, a private limited liability company, the market value of such interests is 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.  See “Elements of Compensation—Other Compensation—Kinder Morgan Holdco LLC Units” above for further discussion of these units.

Risks Associated with Compensation Practices

KMGP Services Company, Inc., KMI 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.

Director Compensation

Compensation Committee Interlocks and Insider Participation.

The compensation committee of KMR functions as our compensation committee.  KMR’s compensation committee is comprised of Mr. Gary L. Hultquist, Mr. C. Berdon Lawrence (since January 21, 2009), and Mr. Perry M. Waughtal.  KMR’s compensation committee makes compensation decisions regarding the executive officers of our general partner and its delegate, KMR.  Mr. Richard D. Kinder, Mr. James E. Street, and Messrs. Shaper and Kean, who are executive officers of KMR, participate in the deliberations of the KMR compensation committee concerning executive officer compensation.  None of the members of KMR’s compensation committee is or has been one of our officers or employees, and none of our executive officers served during 2009 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

Beginning in 2005, awards under our Common Unit Compensation Plan for Non-Employee Directors have served 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 KMI (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.

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The following table discloses the compensation earned by each of KMR’s three non-employee directors for board service during fiscal year 2009.  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		864		159,136		6,720		166,720
Perry M. Waughtal		160,000		-		243,925		403,925

__________

(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 multiplied by the closing price on date of election.  For Mr. Lawrence, 3,200 units elected on January 28, 2009 multiplied by the closing price of $49.73.

(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, 2008 ($45.75) to December 31, 2009 ($60.98).  Also, in 2009, Mr. Edward O. Gaylord’s estate exercised his remaining 17,500 unit appreciation rights at an aggregate fair value of $53.75 per unit and received a cash amount of $179,275.  Mr. Gaylord served as a KMR director until his death on September 28, 2008, and the realized value of his unit appreciation rights earned for the year 2009 was $117,400.

Compensation Committee Report

Throughout fiscal 2009, the compensation committee of KMR’s board of directors was comprised of two directors (Mr. Gary L. Hultquist and Mr. Perry M. Waughtal), and effective January 28, 2009, a third director (Mr. C. Berdon Lawrence), 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 2009 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 2009.

KMR Compensation Committee:

Gary L. Hultquist

C. Berdon Lawrence

Perry M. Waughtal

102

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

The following tables set forth information as of January 31, 2010, regarding (i) the beneficial ownership of (a) our common and Class B units, (b) KMR shares and (c) Kinder Morgan Holdco LLC units by all directors of our general partner and KMR, its delegate, by each of the named executive officers identified in Item 11 “Executive Compensation” and by all directors and executive officers as a group; and (ii) the beneficial ownership of our common and Class B units and KMR shares by all persons known by our general partner to own beneficially at least 5% of such units or shares.  Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002.

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		*			-		-			144,464		*
C. Park Shaper		4,000		*			-		-			30,652		*
Gary L. Hultquist		5,000		*			-		-			-		-
C. Berdon Lawrence(f)		5,650		*			-		-			-		-
Perry M. Waughtal		46,918		*			-		-			54,531		*
Steven J. Kean		1,780		*			-		-			2,118		*
Joseph Listengart		5,498		*			-		-			1,414		*
Kimberly A. Dang		121		*			-		-			519		*
Directors and Executive Officers as a group (14 persons)(g)		398,225		*			-		-			258,120		*
Kinder Morgan, Inc.(h)		16,370,428		7.90	%		5,313,400		100.00	%		12,204,691		14.27	%
Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne(i)		-		-			-		-			6,087,460		7.12	%
Janus Capital Management LLC(j)		-		-			-		-			7,381,111		8.63	%

____________

*  Less than 1%.

(a) Except as noted otherwise, each beneficial owner has sole voting power and sole investment power over the units and shares listed.  On January 18, 2005, KMR’s board of directors initiated a rule requiring each director to own a minimum of 10,000 common units, KMR shares, or a combination thereof by the sixth anniversary of the later to occur of (i) January 18, 2005 or (ii) the election date of the director to KMR’s board.

(b) As of January 31, 2010, we had 207,310,563 common units issued and outstanding.

(c) As of January 31, 2010, we had 5,313,400 Class B units issued and outstanding.

(d) Represent the limited liability company shares of KMR.  As of January 31, 2010, there were 85,538,263 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 1,000 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 7,879 common units and 1,000 KMR shares owned by an executive’s spouse and 786 KMR shares held by one of our executives for his children.  The respective executives disclaim any beneficial ownership in 7,879 common units and 1,786 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 10, 2010 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 6,084,098 shares, sole disposition power over 0 shares and shared disposition power over 6,084,098 shares.  Mr. Kayne reports that in regard to KMR shares, he had sole voting power over 3,362 shares, shared voting power over 6,084,098 shares, sole disposition power over 3,362 shares and shared disposition power over 6,084,098 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 16, 2010 by Janus Capital Management LLC.  Janus Capital Management reported that in regard to KMR shares, it has sole voting power over 7,322,993 shares, shared voting power over 58,118 shares, sole disposition power over 7,322,993 shares and shared disposition power over 58,118 shares.  Janus Capital Management LLC’s address is 151 Detroit Street, Denver, Colorado, 80206.

____________

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Amount and Nature of Beneficial Ownership(a)

Name	Kinder Morgan Holdco LLC Class A Units		% of Class A Units(b)			Kinder Morgan Holdco LLC Class A-1 Units		% of Class A-1 Units(c)			Kinder Morgan Holdco LLC Class B Units		% of Class B Units(d)
Richard D. Kinder(e)		2,424,000,000		30.6	%		–		–			791,405,452		40.0	%
C. Park Shaper(f)		13,598,785		*			7,799,775		28.3	%		217,636,499		11.0	%
Gary L. Hultquist		–		–			–		–			–		–
C. Berdon Lawrence		–		–			–		–			–		–
Perry M. Waughtal		–		–			–		–			–		–
Steven J. Kean		6,684,149		*			3,833,788		13.9	%		158,281,090		8.0	%
Joseph Listengart		6,059,449		*			3,475,483		12.6	%		79,140,545		4.0	%
Kimberly A. Dang(g)		750,032		*			430,191		1.6	%		49,462,841		2.5	%
Directors and Executive Officers as a group (14 persons)		2,460,763,539		31.1	%		21,086,247		76.5	%		1,626,338,205		82.2	%

____________

*  Less than 1%.

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

(b) As of January 31, 2010, Kinder Morgan Holdco LLC had 7,914,367,913 Class A Units issued and outstanding.

(c) As of January 31, 2010, Kinder Morgan Holdco LLC had 27,225,694 Class A-1 Units issued and outstanding and 345,042 phantom Class A-1 Units issued and outstanding.  The phantom Class A-1 Units were issued to Canadian management employees.

(d) As of January 31, 2010, Kinder Morgan Holdco LLC had 1,933,997,073 Class B Units issued and outstanding and 44,516,557 phantom Class B Units issued and outstanding.  The phantom Class B Units were issued to Canadian management employees.

(e) Includes 522,372 Class A units owned by Mr. Kinder's wife.  Mr. Kinder disclaims any and all beneficial or pecuniary interest in the Class A units held by his wife.  Also includes 263,801,817 Class B Units that Mr. Kinder transferred to a limited partnership.  Mr. Kinder may be deemed to be the beneficial owner of these transferred Class B Units, because Mr. Kinder controls the voting and disposition power of these Class B Units, but he disclaims ninety-nine percent of any beneficial and pecuniary interest in them.

(f) Includes 217,636,499 Class B Units that Mr. Shaper transferred to a limited partnership.  Mr. Shaper may be deemed to be the beneficial owner of these transferred Class B Units because he controls the voting and disposition power of these Class B Units, but he disclaims approximately twenty-two percent of any beneficial and pecuniary interest in them.

(g) Includes 49,462,841 Class B Units that Mrs. Dang transferred to a limited partnership.  Mrs. Dang may be deemed to be the beneficial owner of these transferred Class B Units because she has voting and disposition power of these Class B Units, but she disclaims ten percent of any beneficial and pecuniary interest in them.

Equity Compensation Plan Information

The following table sets forth information regarding ourequity compensation plans as of December 31, 2009.  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		74,682
Total		74,682

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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”).  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.

Director Independence

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

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

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

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

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

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

105

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

The board has affirmatively determined that Messrs. Hultquist, Lawrence and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the New York Stock Exchange rules.  Each of them meets the standards above and has no other relationship with us.  In conjunction with all regular quarterly and certain special board meetings, these three non-management directors also meet in executive session without members of management.  In January 2010, Mr. Waughtal was elected for a one year term to serve as lead director to develop the agendas for and preside at these executive sessions of independent directors.

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

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, 2009 and 2008 (in dollars):

	Year Ended December 31,
	2009		2008
Audit fees(a)	$	2,421,145	$	2,409,571
Tax fees(b)		2,303,427		2,144,808
Total	$	4,724,572	$	4,554,379

__________

(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 2009 and 2008, amounts include fees of $2,231,537 and $2,113,318, respectively, billed for professional services rendered for tax processing and preparation of Forms K-1 for our unitholders.  Amounts also include fees of $71,890 and $31,490, respectively, billed for professional services rendered for Internal Revenue Service assistance and for general state, local and foreign tax compliance and consulting services.

All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and were pre-approved by the audit committee of KMR and our general partner.  Pursuant to the charter of the audit committee of KMR, the delegate of our general partner, the committee’s primary purposes include the following: (i) to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; (ii) to pre-approve all audit and non-audit services, including tax services, to be provided, consistent with all applicable laws, to us by our external auditors; and (iii) to establish the fees and other compensation to be paid to our external auditors.  The audit committee has reviewed the external auditors’ fees for audit and non audit services for fiscal year 2009.  The audit committee has also considered whether such non audit services are compatible with maintaining the external auditors’ independence and has concluded that they are compatible at this time.

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

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PART IV

Item 15. Exhibits and Financial Statement Schedules

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

See “Index to Financial Statements” set forth on page 112.

(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 — Form of 7.50% Notes due November 1, 2010 (contained in the Indenture filed as Exhibit 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2001).

*4.5 — 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).

*4.6 — 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).

*4.7 — 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).

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*4.8 — 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).

*4.9 — Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).

*4.10 — 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).

*4.11 — 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).

*4.12 — 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).

*4.13 — 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”)).

*4.14 — 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).

*4.15 — 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)).

*4.16 — 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”)).

*4.17 — 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).

*4.18 — 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).

*4.19 — 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)).

*4.20 — 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. 1-11234)).

*4.21 — 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)).

108

*4.22 — Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% 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)).

*4.23 — Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2006 filed March 1, 2007).

*4.24 — 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 ofKinder 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).

*4.25 — 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 5.85% 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).

*4.26 — 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 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).

*4.27 — Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 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).

*4.28 — 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 5.625% 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).

*4.29 — 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).

4.30 — Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601.  Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.

*10.1 — Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234)).

109

*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)).

*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 — Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K, filed on August 11, 2005 (File No. 1-11234)).

*10.8 — First Amendment, dated October 28, 2005, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Form 10-Q for the quarter ended September 30, 2006).

*10.9 — Second Amendment, dated April 13, 2006, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P.’s Form 10-Q for the quarter ended September 30, 2006).

*10.10 — Third Amendment, dated October 6, 2006, to Five-Year Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.3 to Kinder Morgan Energy Partners, L.P.’s Form 10-Q for the quarter ended September 30, 2006).

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.

110

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.

99.1 — Estimates of the net reserves and future net revenues, as of December 31, 2009, 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, 2009, 2008 and 2007; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 and 2007; (iii) our Consolidated Balance Sheets as of December 31, 2009 and December 31, 2008; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007; (v) our Consolidated Statements of Partners’ Capital for the years ended December 31, 2009, 2008 and 2007; and (vi) the notes to our Consolidated Financial Statements, tagged as blocks of text.

__________

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

111

INDEX TO FINANCIAL STATEMENTS

	Page Number
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm	113
Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007	115
Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 and 2007	116
Consolidated Balance Sheets as of December 31, 2009 and 2008	117
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007	118
Consolidated Statements of Partners’ Capital for the years ended December 31, 2009, 2008 and 2007	120
Notes to Consolidated Financial Statements	122

112

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. (the “Partnership”) and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009 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 (not presented herein) appearing in Item 9A of the Partnership's 2009 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.

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

· The marine vessels acquired from Megafleet Towing Co., Inc, effective April 23, 2009;

· The natural gas treating business acquired from Crosstex Energy, L.P. and Crosstex Energy, Inc., effective October 1, 2009; and

· The 40% equity ownership interest in Endeavor Gathering LLC, acquired effective November 1, 2009

113

(the “Acquired Businesses”) from its assessment of internal control over financial reporting as of December 31, 2009 because each of these businesses were acquired by the Partnership in purchase business combinations during 2009.  We have also excluded the Acquired Businesses from our audit of internal control over financial reporting.  These Acquired Businesses' total assets and total revenues, in the aggregate, represent 1.64% and 0.34%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2009.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, Texas

February 19, 2010

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2009			2008			2007
Revenues	(In millions except per unit amounts)
Natural gas sales	$	3,137.2		$	7,705.2		$	5,834.7
Services		2,739.1			2,770.3			2,449.2
Product sales and other		1,127.1			1,264.8			933.8
Total Revenues		7,003.4			11,740.3			9,217.7
Operating Costs, Expenses and Other
Gas purchases and other costs of sales		3,068.8			7,716.1			5,809.8
Operations and maintenance		1,136.2			1,282.8			1,262.1
Depreciation, depletion and amortization		850.8			702.7			540.0
General and administrative		330.3			297.9			278.7
Taxes, other than income taxes		137.0			186.7			153.8
Goodwill impairment expense		-			-			377.1
Other expense (income)		(34.8	)		2.6			(11.5	)
Total Operating Costs, Expenses and Other		5,488.3			10,188.8			8,410.0
Operating Income		1,515.1			1,551.5			807.7
Other Income (Expense)
Earnings from equity investments		189.7			160.8			69.7
Amortization of excess cost of equity investments		(5.8	)		(5.7	)		(5.8	)
Interest, net		(409.0	)		(388.2	)		(391.4	)
Other, net		49.5			19.2			14.2
Total Other Income (Expense)		(175.6	)		(213.9	)		(313.3	)
Income from Continuing Operations Before Income Taxes		1,339.5			1,337.6			494.4
Income Taxes		(55.7	)		(20.4	)		(71.0	)
Income from Continuing Operations		1,283.8			1,317.2			423.4
Discontinued Operations (Note 3):
Income from operations of North System		-			-			21.1
Gain on disposal of North System		-			1.3			152.8
Income from Discontinued Operations		-			1.3			173.9
Net Income		1,283.8			1,318.5			597.3
Net Income Attributable to Noncontrolling Interests		(16.3	)		(13.7	)		(7.0	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	1,267.5		$	1,304.8		$	590.3
Calculation of Limited Partners’ Interest in Net Income (Loss) Attributable to Kinder Morgan Energy Partners, L.P.:
Income from Continuing Operations	$	1,267.5		$	1,303.5		$	416.4
Less: General Partner’s interest		(935.8	)		(805.8	)		(609.9	)
Limited Partners’ interest		331.7			497.7			(193.5	)
Add: Limited Partners’ interest in discontinued operations		-			1.3			172.2
Limited Partners’ Interest in Net Income (Loss)	$	331.7		$	499.0		$	(21.3	)
Limited Partners’ Net Income (loss) per Unit:
Income (loss) from continuing operations	$	1.18		$	1.94		$	(0.82	)
Income from discontinued operations		-			-			0.73
Net Income (Loss)	$	1.18		$	1.94		$	(0.09	)
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) Per Unit		281.5			257.2			236.9
Per Unit Cash Distribution Declared	$	4.20		$	4.02		$	3.48

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2009			2008			2007
	(In millions)
Net Income	$	1,283.8		$	1,318.5		$	597.3
Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes		(458.2	)		658.0			(984.1	)
Reclassification of change in fair value of derivatives to net income		100.3			670.5			437.6
Foreign currency translation adjustments		252.2			(333.2	)		133.7
Minimum pension liability adjustments, other postretirement benefit plan transition obligations, pension and other postretirement benefit plan actuarial gains/losses, and reclassification of pension and other postretirement benefit plan actuarial gains/losses, prior service costs/credits and transition obligations to net income, net of tax		(2.5	)		3.7			(3.6	)
Total Other Comprehensive Income (Loss)		(108.2	)		999.0			(416.4	)
Comprehensive Income		1,175.6			2,317.5			180.9
Comprehensive Income Attributable to Noncontrolling Interests		(15.2	)		(23.8	)		(2.6	)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.	$	1,160.4		$	2,293.7		$	178.3

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009			2008
	(Dollars in millions)
ASSETS
Current assets
Cash and cash equivalents	$	146.6		$	62.5
Restricted deposits		15.2			-
Accounts, notes and interest receivable, net		902.1			987.9
Inventories		71.9			44.2
Gas in underground storage		43.5			-
Fair value of derivative contracts		20.8			115.3
Other current assets		44.6			34.5
Total current assets		1,244.7			1,244.4
Property, plant and equipment, net		14,153.8			13,241.4
Investments		2,845.2			954.3
Notes receivable		190.6			178.1
Goodwill		1,149.2			1,058.9
Other intangibles, net		218.7			205.8
Fair value of derivative contracts		279.8			796.0
Deferred charges and other assets		180.2			206.9
Total Assets	$	20,262.2		$	17,885.8
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	594.7		$	288.7
Cash book overdrafts		34.8			42.8
Accounts payable		614.8			855.6
Accrued interest		222.4			172.3
Accrued taxes		57.8			51.9
Deferred revenues		76.0			41.1
Fair value of derivative contracts		272.0			129.5
Accrued other current liabilities		145.1			200.2
Total current liabilities		2,017.6			1,782.1
Long-term liabilities and deferred credits
Long-term debt
Outstanding		9,997.7			8,274.9
Value of interest rate swaps		332.5			951.3
Total Long-term debt		10,330.2			9,226.2
Deferred income taxes		216.8			178.0
Fair value of derivative contracts		460.1			92.2
Other long-term liabilities and deferred credits		513.4			491.0
Total long-term liabilities and deferred credits		11,520.5			9,987.4
Total Liabilities		13,538.1			11,769.5
Commitments and contingencies (Notes 8, 12 and 16)
Partners’ Capital
Common units (206,020,826 and 182,969,427 units issued and outstanding as of December 31, 2009 and 2008, respectively)		4,057.9			3,458.9
Class B units (5,313,400 and 5,313,400 units issued and outstanding as of December 31, 2009 and 2008, respectively)		78.6			94.0
i-units (85,538,263 and 77,997,906 units issued and outstanding as of December 31, 2009 and 2008, respectively)		2,681.7			2,577.1
General partner		221.1			203.3
Accumulated other comprehensive loss		(394.8	)		(287.7	)
Total Kinder Morgan Energy Partners, L.P. partners’ capital		6,644.5			6,045.6
Noncontrolling interests		79.6			70.7
Total Partners’ Capital		6,724.1			6,116.3
Total Liabilities and Partners’ Capital	$	20,262.2		$	17,885.8

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009			2008			2007
	(In millions)
Cash Flows From Operating Activities
Net Income	$	1,283.8		$	1,318.5		$	597.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		850.8			702.7			547.0
Amortization of excess cost of equity investments		5.8			5.7			5.8
Impairment of goodwill		-			-			377.1
Income from the allowance for equity funds used during construction		(22.7	)		(10.6	)		-
Income from the sale or casualty of property, plant and equipment and other net assets		(34.8	)		(11.7	)		(164.3	)
Earnings from equity investments		(189.7	)		(160.8	)		(71.5	)
Distributions from equity investments		234.5			158.4			104.1
Proceeds from termination of interest rate swap agreements		144.4			194.3			15.0
Changes in components of working capital:
Accounts receivable		54.5			105.4			92.6
Inventories		(20.0	)		(7.3	)		(6.9	)
Other current assets		(75.9	)		(9.1	)		3.9
Accounts payable		(184.6	)		(100.6	)		(79.7	)
Accrued interest		50.2			41.1			47.3
Accrued taxes		5.3			(22.3	)		40.7
Accrued liabilities		(24.1	)		57.4			(9.5	)
Rate reparations, refunds and other litigation reserve adjustments		2.5			(13.7	)		140.0
Other, net		37.1			(11.5	)		102.9
Net Cash Provided by Operating Activities		2,117.1			2,235.9			1,741.8
Cash Flows From Investing Activities
Acquisitions of assets and equity investments		(328.9	)		(40.2	)		(164.2	)
Repayment (Payment) for Trans Mountain Pipeline		-			23.4			(549.1	)
Repayments (Loans) from customers		109.6			(109.6	)		-
Capital expenditures		(1,323.8	)		(2,533.0	)		(1,691.6	)
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs		47.4			47.8			310.6
(Investments in) Net proceeds from margin deposits		(18.5	)		71.0			(70.2	)
Contributions to investments		(2,051.8	)		(366.7	)		(276.1	)
Distributions from equity investments in excess of cumulative earnings		112.0			89.1			-
Other		-			(7.2	)		12.1
Net Cash Used in Investing Activities		(3,454.0	)		(2,825.4	)		(2,428.5	)
Cash Flows From Financing Activities
Issuance of debt		6,891.9			9,028.6			7,686.1
Payment of debt		(4,857.1	)		(7,525.0	)		(6,409.3	)
Repayments from related party		3.7			1.8			4.4
Debt issue costs		(13.7	)		(12.7	)		(13.8	)
(Decrease) Increase in cash book overdrafts		(8.0	)		23.8			(27.2	)
Proceeds from issuance of common units		1,155.6			560.9			342.9
Proceeds from issuance of i-units		-			-			297.9
Contributions from noncontrolling interests		15.4			9.3			8.9
Distributions to partners and noncontrolling interests:
Common units		(809.2	)		(684.5	)		(552.6	)
Class B units		(22.3	)		(20.7	)		(18.0	)
General Partner		(918.4	)		(764.7	)		(567.7	)
Noncontrolling interests		(22.0	)		(18.8	)		(16.0	)
Other, net		(0.9	)		3.3			0.1
Net Cash Provided by Financing Activities		1,415.0			601.3			735.7
Effect of Exchange Rate Changes on Cash and Cash Equivalents		6.0			(8.2	)		3.2
Increase in Cash and Cash Equivalents		84.1			3.6			52.2
Cash and Cash Equivalents, Beginning of Period		62.5			58.9			6.7
Cash and Cash Equivalents, End of Period	$	146.6		$	62.5		$	58.9

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS   (continued)

	Year Ended December 31,
	2009		2008		2007
	(In millions)
Noncash Investing and Financing Activities
Assets acquired by the issuance of units	$	5.0	$	-	$	15.0
Related party assets acquired by the issuance of units	$	-	$	116.0	$	-
Assets acquired by the assumption or incurrence of liabilities	$	7.7	$	4.8	$	19.7
Related party asset settlements with KMI	$	-	$	-	$	276.2
Related party liability settlements with KMI	$	-	$	-	$	556.6
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	400.3	$	373.3	$	336.0
Cash paid during the period for income taxes	$	3.4	$	35.7	$	6.2

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	2009					2008					2007
	Units		Amount			Units		Amount			Units		Amount
	(Dollars in millions)
Common Units:
Beginning Balance		182,969,427	$	3,458.9			170,220,396	$	3,048.4			162,816,303	$	3,414.9
Net income (loss)		-		229.0			-		343.4			-		(20.4	)
Units issued as consideration pursuant to common unit compensation plan for non-employee directors		3,200		0.2			4,338		0.3			7,280		0.4
Units issued as consideration in the acquisition of assets		105,752		5.0			2,014,693		116.0			266,813		15.0
Units issued for cash		22,942,447		1,154.8			10,730,000		560.3			7,130,000		342.5
Adjustments to capital resulting from related party acquisitions		-		15.5			-		69.1			-		(166.8	)
Distributions		-		(809.2	)		-		(684.5	)		-		(552.6	)
Other Adjustments		-		3.7			-		5.9			-		15.4
Ending Balance		206,020,826		4,057.9			182,969,427		3,458.9			170,220,396		3,048.4
Class B Units:
Beginning Balance		5,313,400		94.0			5,313,400		102.0			5,313,400		126.1
Net income (loss)		-		6.3			-		10.4			-		(0.6	)
Adjustments to capital resulting from related party acquisitions		-		0.5			-		2.1			-		(6.0	)
Distributions		-		(22.3	)		-		(20.7	)		-		(18.0	)
Other Adjustments		-		0.1			-		0.2			-		0.5
Ending Balance		5,313,400		78.6			5,313,400		94.0			5,313,400		102.0
i-Units:
Beginning Balance		77,997,906		2,577.1			72,432,482		2,400.8			62,301,676		2,154.2
Net income (loss)		-		96.4			-		145.2			-		(0.3	)
Units issued for cash		-		-			-		-			5,700,000		297.6
Adjustments to capital resulting from related party acquisitions		-		6.6			-		28.6			-		(57.4	)
Distributions		7,540,357		-			5,565,424		-			4,430,806		-
Other Adjustments		-		1.6			-		2.5			-		6.7
Ending Balance		85,538,263		2,681.7			77,997,906		2,577.1			72,432,482		2,400.8
General Partner:
Beginning Balance		-		203.3			-		161.1			-		119.2
Net income		-		935.8			-		805.8			-		611.6
Adjustments to capital resulting from related party acquisitions		-		0.3			-		1.0			-		(2.2	)
Distributions		-		(918.4	)		-		(764.7	)		-		(567.7	)
Other Adjustments		-		0.1			-		0.1			-		0.2
Ending Balance		-		221.1			-		203.3			-		161.1
Accumulated other comprehensive income (loss):
Beginning Balance		-		(287.7	)		-		(1,276.6	)		-		(866.1	)
Change in fair value of derivatives utilized for hedging purposes		-		(453.6	)		-		651.4			-		(974.2	)
Reclassification of change in fair value of derivatives to net income		-		99.3			-		663.7			-		433.2
Foreign currency translation adjustments		-		249.7			-		(329.8	)		-		132.5
Adjustments to pension and other postretirement benefit plan liabilities		-		(2.5	)		-		3.6			-		(3.5	)
Adj. to initially reflect funded status – pension and other postretirement benefit accounting changes		-		-			-		-			-		1.5
Ending Balance		-		(394.8	)		-		(287.7	)		-		(1,276.6	)
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital		296,872,489	$	6,644.5			266,280,733	$	6,045.6			247,966,278	$	4,435.7

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL   (continued)

	2009					2008					2007
	Units		Amount			Units		Amount			Units		Amount
	(Dollars in millions)
Noncontrolling interests:
Beginning Balance		-	$	70.7			-	$	54.2			-	$	60.2
Net income (loss)		-		16.3			-		13.7			-		7.0
Adjustments to capital resulting from related party acquisitions		-		0.3			-		2.2			-		(2.4	)
Contributions		-		15.4			-		9.2			-		9.6
Distributions		-		(22.0	)		-		(18.8	)		-		(16.0	)
Change in fair value of derivatives utilized for hedging purposes		-		(4.6	)		-		6.6			-		(9.9	)
Reclassification of change in fair value of derivatives to net income		-		1.0			-		6.8			-		4.4
Foreign currency translation adjustments		-		2.5			-		(3.4	)		-		1.2
Adjustments to pension and other postretirement  benefit plan liabilities		-		-			-		0.1			-		(0.1	)
Other Adjustments		-		-			-		0.1			-		0.2
Ending Balance		-		79.6			-		70.7			-		54.2
Total Partners’ Capital		296,872,489	$	6,724.1			266,280,733	$	6,116.3			247,966,278	$	4,489.9

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

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

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 an interest in an integrated oil transportation network that connects Canadian and United States producers to refineries in the U.S. Rocky Mountain and Midwest regions.

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

Kinder Morgan, Inc., referred to as KMI in this report, is owned by investors led by Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. (our general partner), and Kinder Morgan Management, LLC (our general partner’s delegate discussed following).  For a period, KMI was known as Knight Inc., the surviving legal entity from its May 30, 2007 merger.  On that date, KMI completed a merger whereby (i) generally each share of KMI common stock was converted into the right to receive $107.50 in cash without interest; (ii) KMI merged with a wholly-owned subsidiary of Knight Holdco LLC, a privately owned company in which Richard D. Kinder is a major investor; and (iii) KMI continued as the surviving legal entity and was subsequently renamed Knight Inc.  This transaction is referred to in this report as the going-private transaction.  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.

KMI is privately owned and indirectly owns all of the common stock of our general partner.  On July 27, 2007, our general partner issued and sold 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057.  The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us, or two of our subsidiaries: SFPP, L.P. and Calnev Pipe Line LLC.  As of December 31, 2009, KMI and its consolidated subsidiaries owned, through its general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management LLC (discussed following), an approximate 13.2% interest in us.

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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, our general partner delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner.

Under the delegation of control agreement, KMR manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries.  Furthermore, in accordance with its limited liability company agreement, KMR’s activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries.  As of December 31, 2009, KMR owned approximately 28.8% 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.

Cash Equivalents

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

123

Accounts Receivable

The amounts reported as “Accounts, notes and interest receivable, net” on our accompanying balance sheets as of December 31, 2009 and December 31, 2008 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, 2009, 2008 and 2007 (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, 2009	$	6.1	$	0.5	$	-	$	(1.2	)	$	5.4
Year ended December 31, 2008	$	7.0	$	0.6	$	-	$	(1.5	)	$	6.1
Year ended December 31, 2007	$	6.8	$	0.4	$	-	$	(0.2	)	$	7.0

__________

(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 $10.9 million as of December 31, 2009 and $10.8 million as of December 31, 2008.

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 the lower of cost or market.

As of December 31, 2009, the value of natural gas in our underground storage facilities under the weighted-average cost method was $43.5 million, and we reported this amount separately as “Gas in underground storage” in our accompanying consolidated balance sheet.  As of December 31, 2008, we owed certain customers a total of $1.0 million for the value of natural gas inventory stored in our underground storage facilities, and we reported this amount within “Accounts payable” in our accompanying consolidated balance sheet.

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, 2009 and 2008, our gas imbalance receivables—including both trade and related party receivables—totaled $14.0 million and $14.1 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets.  As of December 31, 2009 and 2008, our gas imbalance payables—including both trade and related party payables—totaled $7.4 million and $12.4 million, respectively, and we included these amounts within “Accrued other current liabilities” on our accompanying consolidated balance sheets.

124

Property, Plant and Equipment

Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost.  We expense costs for maintenance and repairs in the period incurred.  The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition, 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 compute depreciation using the straight-line method based on estimated economic lives.  Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics.  The rates range from 1.6% to 12.5%, excluding certain short-lived assets such as vehicles.  Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.  Uncertainties that impact these estimates included changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area.  When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable.  However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense.  Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

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

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

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

As discussed in “—Inventories” above, we 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.

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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 2009, 2008 and 2007 was $32.9 million, $48.6 million and $31.4 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, 2009, 2008 and 2007, we also capitalized approximately $22.7 million, $10.6 million and $6.1 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.”

Equity Method of Accounting

We account for investments greater than 20% in affiliates, which we do not control, by the equity method of accounting.  Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income, and decreased by our proportionate share of the investee’s net losses and by dividends 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 $1,149.2 million as of December 31, 2009 and $1,058.9 million as of December 31, 2008.  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.

On January 1, 2002, we selected a goodwill impairment measurement date of January 1 of each year, and we determined that our goodwill was not impaired as of January 1, 2008.  In the second quarter of 2008, we changed the date of our annual goodwill impairment test date to May 31 of each year.  The change was made following our management’s decision to match our impairment testing date to the impairment testing date of KMI—following the completion of its going-private transaction on May 30, 2007, KMI established as its goodwill impairment measurement date May 31 of each year.  This change to the date of our annual goodwill impairment test constituted a change in the method of applying an accounting principle; however, we believe that this change in accounting principle was preferable because our test would then be performed at the same time as KMI, which indirectly owns all the common stock of our general partner.

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We are required to report a change in accounting principle through retrospective application of the new accounting principle to all periods, unless it is impracticable to do so.  However, our change to a new testing date, when applied to prior periods, does not yield different financial statement results.  Furthermore, there were no impairment charges resulting from the May 31, 2008 or May 31, 2009 impairment testing, and no event indicating an impairment has occurred subsequent to May 31, 2009.

Our consolidated income statement for the year ended December 31, 2007 includes a goodwill impairment expense of $377.1 million, due to the inclusion of KMI’s first quarter 2007 impairment of goodwill that resulted from a determination of the fair values of Trans Mountain pipeline assets prior to our acquisition of these assets from KMI 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.  KMI determined that goodwill was impaired and recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007.  This impairment is also reflected in our consolidated results of operations (reported separately as “Goodwill impairment expense” in our accompanying consolidated statement of income for the year ended December 31, 2007) due to the accounting principles for transfers of assets between entities under common control, which require us to include all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006 (the date of common control).  For more information on our Trans Mountain acquisition, see Note 3; 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, with periodic price adjustments.  In some cases, we sell natural gas under short-term agreements at prevailing market prices.  In all cases, we recognize natural gas sales revenues when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured.  The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies.  We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and generally, our natural gas marketing revenues are recorded gross, not net of cost of gas sold.

In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell for our own account, 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 “park and loan service” to assist customers in managing short-term gas surpluses or deficits.  Revenues are recognized based on the terms negotiated under these contracts.

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

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

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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.  On January 1, 2009, we adopted certain provisions concerning the accounting and reporting for noncontrolling interests included within the “Consolidation” Topic of the Codification.  Specifically, these provisions establish accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent to be clearly identified, labeled, and presented in the consolidated balance sheet within equity, but separate from the parent’s equity; and (ii) the equity amount of consolidated net income attributable to the parent and to the noncontrolling interests to be clearly identified and presented on the face of the consolidated income statement.

The adopted provisions apply prospectively, with the exception of the presentation and disclosure requirements, which must be applied retrospectively for all periods presented.  Accordingly, our consolidated net income and comprehensive income are now determined without deducting amounts attributable to our noncontrolling interests, but our earnings-per-unit information continues to be calculated on the basis of the net income attributable to our limited partners.  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 “Total Partners’ Capital.”

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As of December 31, 2009, 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.

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 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 income/(loss) within “Partners’ Capital” in our consolidated balance sheets.

Comprehensive Income

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 income/(loss) within “Partners’ Capital” in our consolidated balance sheets.  The following table summarizes changes in the amount of our “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets for each of the two years ended December 31, 2008 and 2009 (in millions):

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	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, 2007	$	(1,379.7	)	$	112.5		$	(9.4	)	$	(1,276.6	)
Change for period		1,315.1			(329.8	)		3.6			988.9
December 31, 2008		(64.6	)		(217.3	)		(5.8	)		(287.7	)
Change for period		(354.3	)		249.7			(2.5	)		(107.1	)
December 31, 2009	$	(418.9	)	$	32.4		$	(8.3	)	$	(394.8	)

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.

Among other things, this Topic contains (i) master limited partnership subsections that provide guidance for how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights; and (ii) provisions which clarify that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities.  As participating securities, these instruments should be included in the calculation of basic earnings per share. We adopted the subsections and provisions described above on January 1, 2009; however, the adoption did not have any impact on our consolidated financial statements.

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, 2009 and December 31, 2008 are not material to our consolidated balance sheets.

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Subsequent Events

We are required to disclose the date through which we evaluate subsequent events and the basis for that date.  For this annual report, we evaluated subsequent events—events or transactions that occurred after December 31, 2009 but before our accompanying consolidated financial statements were issued—through February 19, 2010, the date our management reviewed our accompanying consolidated financial statements.  We issued the financial statements on the same day.

3.  Acquisitions and Divestitures

Acquisitions from Unrelated Entities

The provisions of the Codification’s Topic 805, “Business Combinations,” are to be effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  Accordingly, we adopted the provisions of Topic 805 on January 1, 2009. Topic 805 requires that the acquisition method of accounting be used for all business combinations, and an acquirer be identified for each business combination.

Significant provisions of Topic 805 concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.  This Topic also amends the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination.  It requires that acquired contingencies in a business combination be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the allocation period.  Otherwise, companies would typically account for the acquired contingencies in accordance with the provisions of the “Contingencies” Topic of the Codification.  The adoption of Topic 805 did not have a material impact on our consolidated financial statements.

During 2009, 2008 and 2007, 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.

			Allocation of Purchase Price
			(in millions)
Ref.	Date	Acquisition	Purchase Price		Current Assets		Property Plant & Equipment		Deferred Charges & Other		Goodwill
(1)	1/07	Interest in Cochin Pipeline	$	47.8	$	-	$	47.8	$	-	$	-
(2)	5/07	Vancouver Wharves Marine Terminal.		59.5		6.1		53.4		-		-
(3)	9/07	Marine Terminals, Inc. Assets.		102.1		0.2		60.8		22.5		18.6
(4)	8/08	Wilmington, North Carolina Liquids Terminal		12.7		-		5.9		-		6.8
(5)	12/08	Phoenix, Arizona Products Terminal		27.5		-		27.5		-		-
(6)	4/09	Megafleet Towing Co., Inc. Assets		21.7		-		7.1		4.0		10.6
(7)	10/09	Crosstex Energy, L.P. Natural Gas Treating Business		270.7		15.0		181.7		25.4		48.6
(8)	11/09	Endeavor Gathering LLC		36.0		-		-		36.0		-

(1) Interest in Cochin Pipeline

Effective January 1, 2007, we acquired the remaining approximate 50.2% interest in the Cochin pipeline system that we did not already own for an aggregate consideration of approximately $47.8 million, consisting of $5.5 million in cash and a note payable having a fair value of $42.3 million.  As part of the transaction, the seller also agreed to reimburse us for certain pipeline integrity management costs over a five-year period in an aggregate amount not to exceed $50 million.  Upon closing, we became the operator of the pipeline.  The Cochin Pipeline is a multi-product liquids pipeline consisting of approximately 1,900 miles of pipe operating between Fort Saskatchewan, Alberta, and Windsor, Ontario, Canada.  Its operations are included as part of our Products Pipelines business segment.

(2) Vancouver Wharves Terminal

On May 30, 2007, we purchased the Vancouver Wharves bulk marine terminal from British Columbia Railway Company, a crown corporation owned by the Province of British Columbia, for an aggregate consideration of $59.5 million, consisting of $38.8 million in cash and $20.7 million in assumed liabilities.  The acquisition both expanded and complemented our existing West region terminal operations, and all of the acquired assets are included in our Terminals business segment.  In the first half of 2008, we made our final purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities.  Our adjustments increased “Property, Plant and Equipment, net” by $2.7 million, reduced working capital balances by $1.6 million, and increased long-term liabilities by $1.1 million.

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(3) Marine Terminals, Inc. Assets

Effective September 1, 2007, we acquired certain bulk terminals assets from Marine Terminals, Inc. for an aggregate consideration of $102.1 million, consisting of $100.8 million in cash and assumed liabilities of $1.3 million.  The acquired assets and operations are primarily involved in the handling and storage of steel and alloys.  The acquisition both expanded and complemented our existing ferro alloy terminal operations and provides customers further access to our growing national network of marine and rail terminals.  All of the acquired assets are included in our Terminals business segment.  In the first nine months of 2008, we paid an additional $0.5 million for purchase price settlements, and we made purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities.  Our 2008 adjustments primarily reflected changes in the allocation of the purchase cost to intangible assets acquired.

The $22.5 million allocation to “Deferred charges and other assets” included a $20.1 million amount representing the fair value of a service contract entered into with Nucor Corporation, a large domestic steel company with significant operations in the Southeast region of the United States.  For valuation purposes, the service contract was determined to have a useful life of 20 years, and pursuant to the contract’s provisions, the acquired terminal facilities will continue to provide Nucor with handling, processing, harboring and warehousing services.

The $18.6 million allocation to “Goodwill,” which is expected to be deductible for tax purposes, was based on the fact that this acquisition both expanded and complemented our existing ferro alloy terminal operations and will provide Nucor and other customers further access to our growing national network of marine and rail terminals.  We believe the acquired value of the assets, including all contributing intangible assets, exceeded the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.

(4) 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.

In the fourth quarter of 2008, we allocated our purchase price to reflect final fair value of acquired assets and final expected value of assumed liabilities.  A total of $6.8 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.  We believe this acquisition resulted in the recognition of goodwill primarily because of certain advantageous factors (including the synergies provided by increasing our liquids storage capacity in the Southeast region of the U.S.) that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.

(5) 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.

(6) 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, and there has been no change in the fair value during the post-acquisition period ended December 31, 2009.

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The acquired assets primarily consist of nine marine vessels that provide towing and harbor boat services along the Gulf coast, the intracoastal waterway, and the Houston Ship Channel.  The acquisition complements and expands our existing Gulf Coast and Texas petroleum coke terminal operations, and all of the acquired assets are included in our Terminals business segment.  We allocated $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).

(7) 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 consist of approximately 290 natural gas amine-treating and 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 made us the largest provider of contract-provided treating plants in the U.S. and complemented and expanded the existing natural gas treating operations offered by our Texas intrastate natural gas pipeline group.  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.

(8) 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.

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, 2008 as if they had occurred as of January 1, 2008 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.

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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 method of accounting for such net asset transfers is similar to the pooling-of-interests method of accounting.  Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination (that is, no recognition is made for a purchase premium or discount representing any difference between the consideration paid and the book value of the net assets acquired).  In addition, (i) all acquired equity accounts are also carried forward intact initially, and subsequently adjusted due to differences between (a) the consideration paid for the acquired net assets; and (b) the book value (carrying value) of the acquired net assets; (ii) all financial statements presented as of the date of common control must be combined; and (iii) all financial statements and financial information presented for prior periods should be restated to furnish comparative information.  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 for these net assets are 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 transaction was approved by the independent directors of both KMI and KMR following the receipt by such directors of separate fairness opinions from different investment banks.  We paid $549 million of the purchase price on April 30, 2007, and we paid the remaining $0.1 million in July 2007.  We reported this $549.1 million payment separately as a cash outflow item from investing activities in our accompanying consolidated statement of cash flows.

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 cash contribution as an adjustment to equity—primarily as an increase in “Partners’ Capital” in our accompanying consolidated balance sheet.  We also included this $23.4 million receipt as a cash inflow item from investing activities in our accompanying consolidated statement of cash flows.

The Trans Mountain pipeline system transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington.  Because its operations are managed separately, involve different products and marketing strategies, and produce discrete financial information that is separately evaluated internally by our management, we identified our Trans Mountain pipeline system as a separate reportable business segment prior to the third quarter of 2008.  Following the acquisition of our interests in the Express and Jet Fuel pipeline systems on August 28, 2008, discussed following, we combined the operations of our Trans Mountain, Express and Jet Fuel pipeline systems to represent our Kinder Morgan Canada business segment.

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 existing Canadian pipeline system (Trans Mountain), and all of the acquired assets (including an acquired cash balance of $7.4 million) are included in our Kinder Morgan Canada business segment.

We 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.”

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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.

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 whereby the financial results and the gains on disposal of the North System have been reclassified to discontinued operations in our accompanying consolidated statements of income.  We reported the gains separately as “Gain on disposal of North System” within the discontinued operations section of our accompanying consolidated statements of income for the years ended December 31, 2008 and 2007.  Prior to the sale, all of the assets were included in our Products Pipelines business segment.

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

	Year Ended December 31,
	2008		2007
Operating revenues	$	-	$	41.1
Operating expenses		-		(14.8	)
Depreciation and amortization		-		(7.0	)
Earnings from equity investments		-		1.8
Amortization of excess cost of equity investments		-		-
Other, net – income (expense)		-		-
Income from operations		-		21.1
Gain on disposal		1.3		152.8
Total earnings from discontinued operations	$	1.3	$	173.9

Additionally, in our accompanying consolidated statement of cash flows, we elected not to present separately the North System’s operating and investing cash flows as discontinued operations, and, because the sale of the North System does not change the structure of our internal organization in a manner that causes a change to our reportable business segments, we have included the North System’s financial results within our Products Pipelines business segment disclosures for all periods presented in this report.

Thunder Creek Gas Services, LLC

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

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Cypress Pipeline

On July 14, 2009 we received notice from Westlake Petrochemicals LLC, a wholly-owned subsidiary of Westlake Chemical Corporation, that it was exercising an option it held to purchase a 50% ownership interest in our Cypress Pipeline.  We expect the transaction to close no earlier than the end of the first quarter of 2010.  As of December 31, 2009, the net assets of our Cypress Pipeline totaled approximately $21.3 million.  The sale of 50% of our Cypress Pipeline will not have a material impact on our business, financial position, results of operations or our cash flows.

Acquisitions Subsequent to December 31, 2009

USD Terminal Acquisition

On January 15, 2010, we acquired three ethanol handling train terminals from U.S Development Group for an aggregate consideration of $197.4 million, consisting of $115.7 million in cash and $81.7 million in common units.  The three train terminals are located in Linden, New Jersey; Baltimore, Maryland; and Dallas, Texas.  As part of the transaction, we announced the formation of a venture with U.S. Development Group 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.  The acquisition complemented and expanded the ethanol and rail terminal operations we previously owned, and all of the acquired assets are included in our Terminals business segment.  In the first quarter of 2010, we expect to make final purchase price adjustments for acquired working capital items and measure the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date.

Slay Industries Terminal Acquisition

On January 27, 2010, we announced that we had signed a definitive purchase and sale agreement to acquire four terminals from Slay Industries for approximately $98 million in cash.  The facilities 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 credit worthy 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 to develop.  All of the assets in Sauget have access to the Mississippi River and 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.  In the first quarter of 2010, we expect to make final purchase price adjustments for acquired working capital items and measure the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date.

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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,
	2009			2008			2007
Taxes current expense:
Federal	$	2.7		$	24.4		$	12.7
State		6.7			8.5			8.2
Foreign		(1.0	)		(4.5	)		31.5
Total		8.4			28.4			52.4
Taxes deferred expense:
Federal		7.3			6.0			11.8
State		9.4			1.5			6.2
Foreign		30.6			(15.5	)		0.6
Total		47.3			(8.0	)		18.6
Total tax provision	$	55.7		$	20.4		$	71.0
Effective tax rate		4.2	%		1.5	%		14.4	%

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

	Year Ended December 31,
	2009			2008			2007
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	%		2.8	%
Income tax expense attributable to corporate equity earnings		0.8	%		0.6	%		2.3	%
Income tax expense attributable to foreign corporate earnings		2.2	%		(1.2	) %		6.6	%
State taxes		1.2	%		0.5	%		2.7	%
Effective tax rate		4.2	%		1.5	%		14.4	%

Our deferred tax assets and liabilities as of December 31, 2009 and 2008 result from the following (in millions):

	Year Ended December 31,
	2009		2008
Deferred tax assets:
Book accruals	$	16.6	$	3.2
Net Operating Loss/Alternative minimum tax credits		11.4		1.4
Other		1.3		1.8
Total deferred tax assets		29.3		6.4
Deferred tax liabilities:
Property, plant and equipment		239.3		161.3
Other		6.8		23.1
Total deferred tax liabilities		246.1		184.4
Net deferred tax liabilities	$	216.8	$	178.0

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.

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A reconciliation of our beginning and ending gross unrecognized tax benefits for each of the years ended December 31, 2009 and 2008 is as follows (in millions):

	Year Ended December 31,
	2009			2008
Balance at beginning of period	$	14.9		$	6.3
Additions based on current year tax positions		-			0.4
Additions based on prior year tax positions		8.5			9.6
Reductions based on settlements with taxing authority		-			(0.1	)
Reductions due to lapse in statute of limitations		(0.1	)		(1.3	)
Balance at end of period	$	23.3		$	14.9

Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense.  During the years ended December 31, 2009 and 2008, we recognized approximately $1.1 million and $0.5 million, respectively, in interest expense, and during the year ended December 31, 2007, we recognized interest income of approximately $0.4 million.

As of December 31, 2009 (i) we had $2.3 million of accrued interest and no accrued penalties; (ii) we believe it is reasonably possible that our $23.3 million liability for unrecognized tax benefits will increase by approximately $7.1 million during the next twelve months; and (iii) we believe the full amount of $23.3 million of unrecognized tax benefits, if recognized, would favorably affect our effective income tax rate in future periods.  As of December 31, 2008, we had $1.2 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 2009.

5.  Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2009 and 2008, our property, plant and equipment consisted of the following (in millions):

	Year Ended December 31,
	2009			2008
Natural gas, liquids, crude oil and carbon dioxide pipelines	$	6,883.3		$	5,752.4
Natural gas, liquids, carbon dioxide, and terminals station equipment.		8,131.9			6,991.1
Natural gas, liquids (including linefill), and transmix processing		220.3			210.3
Other		1,113.0			964.1
Accumulated depreciation and depletion		(3,365.6	)		(2,554.0	)
		12,982.9			11,363.9
Land and land right-of-way		596.6			549.0
Construction work in process		574.3			1,328.5
Property, Plant and Equipment, net	$	14,153.8		$	13,241.4

Depreciation and depletion expense charged against property, plant and equipment consisted of $829.6 million in 2009, $684.2 million in 2008 and $529.3 million in 2007.

Asset Retirement Obligations

As of December 31, 2009 and December 31, 2008, we have recognized asset retirement obligations in the aggregate amount of $100.9 million and $76.5 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, 2009 and December 31, 2008 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.

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A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the years ended December 31, 2009 and 2008 is as follows (in millions):

	Year Ended December 31,
	2009			2008
Balance at beginning of period	$	76.5		$	52.2
Liabilities incurred/revised		26.0			26.2
Liabilities settled		(6.2	)		(5.4	)
Accretion expense		4.6			3.5
Balance at end of period	$	100.9		$	76.5

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 $2,845.2 million as “Investments” in our accompanying consolidated balance sheet as of December 31, 2009.  As of December 31, 2008, our investments totaled $954.3 million.  As of both dates, our investment amounts included bond investments totaling $13.2 million.  These bond investments consisted of certain tax exempt, fixed-income development revenue bonds acquired in the fourth quarter of 2008.  Because we have both the ability and the intent to hold these debt securities to maturity, we account for these investments at historical cost.  Our bond investments are further discussed in Note 8 “Debt—Subsidiary Debt—Gulf Opportunity Zone Bonds.”

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

	Year Ended December 31,
	2009		2008
Rockies Express Pipeline LLC	$	1,693.4	$	501.1
Midcontinent Express Pipeline LLC		662.3		-
Plantation Pipe Line Company		197.3		196.6
Red Cedar Gathering Company		145.8		138.9
Express pipeline system		68.0		64.9
Endeavor Gathering LLC		36.2		-
Cortez Pipeline Company		11.2		13.6
All others		17.8		26.0
Total equity investments	$	2,832.0	$	941.1

The increase in the carrying amount of our equity investments since December 31, 2008 was primarily driven by equity capital contributions of $2,051.8 million in 2009, paid primarily to Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Pipeline LLC to partially fund their respective Rockies Express, Midcontinent Express, and Fayetteville Express Pipeline construction and/or pre-construction costs, and the repayment of senior notes by Rockies Express in August 2009.  For information pertaining to guarantees or indemnifications we have made with respect to our equity investees, see Note 12 “Commitments and Contingent Liabilities—Contingent Debt.”

As shown in the table above, our significant equity investments as of December 31, 2009 consisted of the following:

▪ Rockies Express Pipeline LLC—we operate and own a 50% ownership interest in Rockies Express Pipeline LLC, the surviving legal entity from its December 30, 2009 merger with its parent entity, West2East Pipeline LLC.  Rockies Express Pipeline LLC is the sole owner of the Rockies Express natural gas pipeline system, which 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 Sempra Energy and ConocoPhillips.

Effective December 1, 2009, our ownership interest in West2East 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 2009 and 2008, we made capital contributions of $1,273.1 million and $306.0 million, respectively, to Rockies Express Pipeline LLC (West2East Pipeline LLC before the merger) to partially fund both the construction costs for the Rockies Express pipeline system and the repayment of senior notes (which matured in August 2009).  In 2009 and 2008, we also received, from Rockies Express Pipeline LLC, cash distributions of $148.8 million and $82.9 million, respectively;

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▪ Midcontinent Express Pipeline LLC—we operate and own a 50% ownership interest in Midcontinent Express Pipeline LLC, which we formed in May 2006.  It is the sole owner of the Midcontinent Express natural gas pipeline system and Energy Transfer Partners, L.P. owns the remaining 50% ownership interest.  In 2007, we began making cash contributions for our share of the construction costs for the Midcontinent Express pipeline system, and in 2009 and 2008, we made capital contributions of $664.5 million and $27.5 million, respectively, to Midcontinent Express Pipeline LLC to partially fund its pipeline construction costs.  We received cash distributions of $16.2 million and $1.9 million in 2009 and 2008, respectively; however, as of December 31, 2008, we had no net investment in Midcontinent Express Pipeline LLC because in 2008, it established and made borrowings under its own revolving bank credit facility in order to fund its pipeline construction costs and to make distributions to its member owners to fully reimburse them for prior contributions.  Accordingly, we received an $89.1 million return of capital from Midcontinent Express in the first quarter of 2008.

Additionally, in January 2008, in conjunction with the signing of additional binding transportation commitments, Midcontinent Express Pipeline LLC entered into an option agreement with a subsidiary of MarkWest Energy Partners, L.P. providing it a one-time right to purchase a 10% ownership interest in the Midcontinent Express pipeline system.  In September 2009, MarkWest declined to exercise this option;

▪ Red Cedar Gathering Company—we acquired a 49% ownership interest in the Red Cedar Gathering Company from KMI on December 31, 1999.  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;

▪ 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;

▪ 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—(8) Endeavor Gathering LLC”); 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.  We acquired our ownership interest in Cortez Pipeline Company from affiliates of Shell in April 2000.  A subsidiary of Exxon Mobil Corporation owns a 37% ownership interest and Cortez Vickers Pipeline Company owns the remaining 13% ownership interest.

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.”

We also own a 50% ownership interest in Fayetteville Express Pipeline LLC, which we formed in August 2008.  Fayetteville Express Pipeline LLC is the sole owner of the Fayetteville Express natural gas pipeline joint venture project that is currently being developed.  Energy Transfer Partners, L.P. owns the remaining 50% ownership interest in Fayetteville Express Pipeline LLC and will operate the Fayetteville Express pipeline system.  In 2009 and 2008, we made capital contributions of $103.2 million and $9.0 million, respectively, to Fayetteville Express Pipeline LLC to partially fund certain pre-construction pipeline costs.  As of December 31, 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 costs and to make distributions to its member owners to reimburse them for prior contributions.  Accordingly, we received cash distributions of $115.6 million from Fayetteville Express Pipeline LLC in 2009.

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

	Year Ended December 31,
	2009			2008			2007
Rockies Express Pipeline LLC	$	98.5		$	84.9		$	(12.4	)
Plantation Pipe Line Company		26.8			22.3			29.4
Red Cedar Gathering Company		24.9			26.7			28.0
Cortez Pipeline Company		22.3			20.8			19.2
Midcontinent Express Pipeline LLC		14.7			0.5			1.4
Endeavor Gathering LLC		0.1			-			-
Express pipeline system		(4.1	)		(0.5	)		-
Thunder Creek Gas Services, LLC		-			1.3			2.2
All others		6.5			4.8			1.9
Total	$	189.7		$	160.8		$	69.7
Amortization of excess costs	$	(5.8	)	$	(5.7	)	$	(5.8	)

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	2009		2008		2007
Revenues	$	1,216.6	$	1,015.0	$	473.0
Costs and expenses		832.6		681.6		355.1
Earnings before extraordinary items and cumulative effect of a change in accounting principle		384.0		333.4		117.9
Net income	$	384.0	$	333.4	$	117.9

	December 31,
Balance Sheet	2009		2008
Current assets	$	294.3	$	221.7
Non-current assets		9,895.9		6,797.5
Current liabilities		2,162.6		3,690.1
Non-current liabilities		2,905.9		2,015.3
Partners’/Owners’ equity		5,121.7		1,313.8

On January 1, 2009, we adopted certain provisions included within the “Investments—Equity Method and Joint Ventures” Topic of the Codification.  These provisions clarify certain accounting and impairment considerations involving equity method investments.  The adoption of these provisions did not have any impact on our consolidated financial statements.

Also, on June 30, 2009, we adopted certain provisions included within the “Investments—Debt and Equity Securities” Topic of the Codification.  These adopted provisions provide additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities.  The provisions change (i) the method for determining whether an other-than-temporary impairment exists for debt securities; and (ii) the amount of an impairment charge to be recorded in earnings.  The adoption of these provisions did not have a material impact on our consolidated financial statements. For more information on certain of our equity investments, see Note 17.

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.

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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, 2009 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, 2009 and 2008 are summarized as follows (in millions):

	Products Pipelines		Natural Gas Pipelines		CO2		Terminals		Kinder Morgan Canada			Total
Balance as of December 31, 2007
Goodwill.	$	263.2	$	288.4	$	46.1	$	229.1	$	628.1		$	1,454.9
Accumulated impairment losses.		-		-		-		-		(377.1	)		(377.1	)
		263.2		288.4		46.1		229.1		251.0			1,077.8
Acquisitions and purchase price adjs.		-		-		-		28.5		-			28.5
Disposals.		-		-		-		-		-			-
Impairments		-		-		-		-		-			-
Currency translation adjustments		-		-		-		-		(47.4	)		(47.4	)
Balance as of December 31, 2008
Goodwill.		263.2		288.4		46.1		257.6		580.7			1,436.0
Accumulated impairment losses.		-		-		-		-		(377.1	)		(377.1	)
		263.2		288.4		46.1		257.6		203.6			1,058.9
Acquisitions and purchase price adjs.		-		48.6		-		9.3		-			57.9
Disposals.		-		-		-		-		-			-
Impairments		-		-		-		-		-			-
Currency translation adjustments		-		-		-		-		32.4			32.4
Balance as of December 31, 2009
Goodwill.		263.2		337.0		46.1		266.9		613.1			1,526.3
Accumulated impairment losses.		-		-		-		-		(377.1	)		(377.1	)
	$	263.2	$	337.0	$	46.1	$	266.9	$	236.0		$	1,149.2

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, the price we paid to acquire our share of the net assets of such equity investees differed from the underlying book value of such net assets.  This differential consists of two pieces.  First, an amount related to the difference between the investee’s recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (referred to as equity method goodwill) we paid to acquire the investment.  We include both amounts within “Investments” on our accompanying consolidated balance sheets.

The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at the date of acquisition totaled $163.2 million and $169.0 million as of December 31, 2009 and 2008, 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, 2009, this excess investment cost is being amortized over a weighted average life of approximately 28.9 years.

The second differential, representing total unamortized excess cost over underlying fair value of net assets acquired (equity method goodwill) was $138.2 million as of both December 31, 2009 and December 31, 2008.  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, 2009, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted.

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Other Intangibles

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, technology-based assets, and lease value.  These intangible assets have definite lives, are being amortized on a straight-line basis over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.  Following is information related to our intangible assets subject to amortization (in millions):

	December 31,
	2009			2008
Customer relationships, contracts and agreements
Gross carrying amount	$	273.0		$	246.0
Accumulated amortization		(67.1	)		(51.1	)
Net carrying amount		205.9			194.9
Technology-based assets, lease value and other
Gross carrying amount		15.7			13.3
Accumulated amortization		(2.9	)		(2.4	)
Net carrying amount		12.8			10.9
Total Other intangibles, net	$	218.7		$	205.8

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.

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 the years ended December 31, 2009, 2008 and 2007, the amortization expense on our intangibles totaled $16.5 million, $14.7 million and $14.3 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 (2010 – 2014) is approximately $20.9 million, $18.8 million, $17.2 million, $16.3 million and $15.4 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, 2009, the weighted average amortization period for our intangible assets was approximately 15.6 years.

8.  Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments or as of the earliest put date available to the holders of the applicable debt.  We defer costs associated with debt issuance over the applicable term or to the first put date, in the case of debt with a put feature. These costs are amortized as interest expense in our consolidated statements of income. The weighted average interest rate on all of our borrowings was approximately4.57% during 2009 and 5.44% during 2008.

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Short-Term Debt

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 due November 1, 2010; (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) an $8.9 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); (v) a $6.8 million portion of 5.23% senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes); 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).

Our outstanding short-term debt as of December 31, 2008 was $288.7 million, consisting of (i) $250 million in principal amount of 6.30% senior notes due February 1, 2009; (ii) the $23.7 million in principal amount of tax-exempt bonds due from our subsidiary Kinder Morgan Operating L.P. “B”; (iii) an $8.5 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; and (iv) a $6.5 million portion of the 5.23% senior notes due from our subsidiary Kinder Morgan Texas Pipeline, L.P.

Credit Facility

Our $1.85 billion unsecured revolving bank credit facility is with a syndicate of financial institutions, and Wachovia Bank, National Association is the administrative agent.  The credit facility permits us to obtain bids for fixed rate loans from members of the lending syndicate, and the facility can be amended to allow for borrowings of up to $2.0 billion.  Interest on our credit facility accrues at our option at a floating rate equal to either (i) the administrative agent’s base rate (but not less than the Federal Funds Rate, plus 0.5%); or (ii) LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.  Borrowings under our credit facility can be used for general partnership purposes and as a backup for our commercial paper program.

The outstanding balance under our credit facility was $300 million as of December 31, 2009, and the average interest rate on these borrowings was 0.59%.  As of December 31, 2008, there were no borrowings under the credit facility.  The credit facility matures August 18, 2010 and currently, we plan to negotiate a renewal of the credit facility before its maturity date.

During the first quarter of 2009, following Lehman Brothers Holdings Inc.’s filing for bankruptcy protection in September 2008, we amended the credit facility to remove Lehman Brothers Commercial Bank as a lender, thus reducing the borrowing capacity under the facility by $63.3 million.  The commitments of the other banks remain unchanged, and the facility is not defaulted.

Additionally, as of December 31, 2009, the amount available for borrowing under our credit facility was reduced byan aggregate amount of $282.8 million, consisting ofthe following letters of credit: (i) a $100 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined $89.4 million in three letters of credit that support tax-exempt bonds; (iii) a combined $55.0 million in two letters of credit that support our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil; (iv) a $21.4 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (v) a combined $17.0 million in other letters of credit supporting other obligations of us and our subsidiaries.

Our credit facility included the following restrictive covenants as of December 31, 2009:

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

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

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

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

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▪ 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 investment rating.  None of our debt is subject to payment acceleration as a result of any change to our credit ratings.

Commercial Paper Program

On October 13, 2008, Standard & Poor’s Rating Services lowered our short-term credit rating to A-3 from A-2.  Additionally, on May 6, 2009, Moody’s Investor Services, Inc. downgraded our commercial paper rating to Prime-3 from Prime-2.  As a result of these revisions and current commercial paper market conditions, we are currently unable to access commercial paper borrowings, and as of both December 31, 2009 and December 31, 2008, we had no commercial paper borrowings.  However, we expect that our financing and liquidity needs will continue to be met through borrowings made under our bank credit facility described above.

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Long-Term Debt

Our outstanding long-term debt, excluding the value of interest rate swaps, as of December 31, 2009 and 2008 was $9,997.7 million and $8,274.9 million, respectively.  The balances consisted of the following (in millions):

	December 31,
	2009			2008
Kinder Morgan Energy Partners, L.P. borrowings:
6.30% senior notes due February 1, 2009	$	-		$	250.0
7.50% senior notes due November 1, 2010		250.0			250.0
6.75% senior notes due March 15, 2011		700.0			700.0
7.125% senior notes due March 15, 2012		450.0			450.0
5.85% senior notes due September 15, 2012		500.0			500.0
5.00% senior notes due December 15, 2013		500.0			500.0
5.125% senior notes due November 15, 2014		500.0			500.0
5.625% senior notes due February 15, 2015		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			-
5.80% senior notes due March 1, 2021		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			-
Commercial paper borrowings		-			-
Bank credit facility borrowings		300.0			-
Subsidiary borrowings:
Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010		5.3			5.3
Kinder Morgan Louisiana Pipeline LLC-6.0% LA Development Revenue note due Jan. 1, 2011		5.0			5.0
Kinder Morgan Operating L.P. “A”-5.40% BP note, due March 31, 2012		14.9			19.4
Kinder Morgan Canada Company-5.40% BP note, due March 31, 2012		13.2			17.2
Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014		30.5			37.0
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		(24.7	)		(18.5	)
Current portion of long-term debt		(594.7	)		(288.7	)
Total long-term debt	$	9,997.7		$	8,274.9

____________

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

Senior Notes

As of December 31, 2009 and 2008, our total liability balance due on the various series of our senior notes was $10,125.3 million and $8,381.5 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.

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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.

During 2008, we completed three separate public offerings of senior notes.  With regard to thethree offerings, we received proceeds, net of underwriting discounts and commissions, as follows (i) $894.1 million from a February 12, 2008 public offering of a total of $900 million in principal amount of senior notes, consisting of $600 million of 5.95% notes due February 15, 2018, and $300 million of 6.95% notes due January 15, 2038 (these notes constitute a further issuance of the $550 million aggregate principal amount of 6.95% notes we issued on June 21, 2007 and form a single series with those notes); (ii) $687.7 million from a June 6, 2008 public offering of a total of $700 million in principal amount of senior notes, consisting of $375 million of 5.95% notes due February 15, 2018 (these notes constitute a further issuance of the $600 million aggregate principal amount of 5.95% notes we issued on February 12, 2008 and form a single series with those notes), and $325 million of 6.95% notes due January 15, 2038 (these notes constitute a further issuance of the combined $850 million aggregate principal amount of 6.95% notes we issued on June 21, 2007 and February 12, 2008, and form a single series with those notes); and (iii) $498.4 million from a December 19, 2008 public offering of $500 million in principal amount of 9.00% senior notes due February 1, 2019.

We used the proceeds from the first two 2008 debt offerings to reduce the borrowings under our commercial paper program.  We used the proceeds from our December 2008 debt offering and 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.

Central Florida Pipeline LLC Debt

On July 23, 2008, Central Florida Pipeline LLC paid the final $5.0 million outstanding principal amount of its 7.84% senior notes that matured on that date, and following its repayment, Central Florida Pipeline LLC had no outstanding debt.

Arrow Terminals L.P.

Our subsidiary Arrow Terminals L.P. is an obligor on a $5.3 million principal amount of Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority.  The bonds have a maturity date of January 1, 2010, and interest on these bonds is paid and computed quarterly at the Bond Market Association Municipal Swap Index.  The bonds are collateralized by a first mortgage on assets of Arrow’s Chicago operations and a third mortgage on assets of Arrow’s Pennsylvania operations.  As of December 31, 2009, the interest rate was 0.365%.  The bonds are also backed by a $5.4 million letter of credit issued by JP Morgan Chase that backs-up the $5.3 million principal amount of the bonds and $0.1 million of interest on the bonds for up to 45 days computed at 12% per annum on the principal amount thereof.  On January 4, 2010, Arrow Terminals L.P. paid the $5.3 million outstanding principal amount of the bonds that matured on that date, and following its repayment, Arrow Terminals L.P. had no outstanding debt.

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Kinder Morgan Operating L.P. “A” Debt

Effective January 1, 2007, we acquired the remaining approximately 50.2% interest in the Cochin pipeline system that we did not already own.  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.  The final payment is due March 31, 2012.  As of December 31, 2008, the net present value (representing the outstanding balance on our balance sheet) of the note was $36.6 million.  We paid the second installment on March 31, 2009, and 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 with a fixed annual stated interest rate as of August 1, 2005, of 8.85%.  We assumed this debt on August 1, 2005 when we acquired a natural gas storage facility located in Liberty County, Texas from a third party, and 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.  As of December 31, 2009, Kinder Morgan Texas Pipeline L.P.’s outstanding balance under the senior notes was $30.5 million.  Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million and at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid.

Kinder Morgan Liquids Terminals LLC Debt

Kinder Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority.  These bonds have a maturity date of January 15, 2018.  Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period.  As of December 31, 2009, the interest rate was 0.19%.  We have an outstanding letter of credit issued by Citibank in the amount of $25.4 million that backs-up the $25.0 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 46 days computed at 12% on a per annum basis on the principal thereof.

Kinder Morgan Operating L.P. “B” Debt

As of December 31, 2008, our subsidiary Kinder Morgan Operating L.P. “B” was the obligor of a principal amount of $23.7 million of tax-exempt bonds due April 1, 2024.  The bonds were issued by the Jackson-Union Counties Regional Port District, a political subdivision embracing the territories of Jackson County and Union County in the state of Illinois.  These variable rate demand bonds bear interest at a weekly floating market rate and are backed-up by a letter of credit issued by Wachovia.

The bond indenture also contains certain standby purchase agreement provisions which allow investors to put (sell) back their bonds at par plus accrued interest.  In the fourth quarter of 2008, certain investors elected to sell back their bonds and we paid a total principal and interest amount of $5.2 million according to the letter of credit reimbursement provisions; however, the bonds were subsequently resold and as of December 31, 2008, we were fully reimbursed for our prior payments.  As of December 31, 2009, the interest rate on these bonds was 0.21%.  Our outstanding letter of credit issued by Wachovia 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 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, 2009, the interest rate on these bonds was 3.25%.

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 Wachovia Bank, National Association.  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.

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Gulf Opportunity Zone Bonds

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

The Mississippi revenue bonds mature on September 1, 2022, and both principal and interest is due in full at maturity.  We hold an option to redeem in full (and settle the note payable to MBFC) the principal amount of bonds held by us without penalty after one year.  The Louisiana revenue bonds have a maturity date of January 1, 2011 and provide for semi-annual interest payments each July 1 and January 1.

Maturities of Debt

The scheduled maturities of our outstanding debt, excluding the value of interest rate swaps, as of December 31, 2009, are summarized as follows (in millions):

Year	Commitment
2010	$	594.7
2011		721.4
2012		1,466.7
2013		506.8
2014		500.5
Thereafter		6,802.3
Total	$	10,592.4

9.  Employee Benefits

Pension and Postretirement Benefit Plans

In connection with our acquisition of the Trans Mountain pipeline system in 2007 (see Note 3), 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 2009, 2008 and 2007 were approximately $2.9 million, $3.5 million and $3.2 million, respectively, recognized ratably over each year.

As of December 31, 2009, we estimate our overall net periodic pension and postretirement benefit costs for these plans for the year 2010 will be approximately $3.6 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 $4.8 million to these benefit plans in 2010.

Additionally, in connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk Terminals, Inc. in 1998, we acquired certain liabilities for pension and postretirement benefits.  We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals.  We also provide the same benefits to former salaried employees of SFPP.  Additionally, we will continue to fund these costs for those employees currently in the plan during their retirement years.  SFPP’s postretirement benefit plan is frozen and no additional participants may join the plan.  The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement Plan.  The benefits under this plan are based primarily upon years of service and final average pensionable earnings; however, benefit accruals were frozen as of December 31, 1998.

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Our net periodic benefit cost for the SFPP postretirement benefit plan was acredit ofless than$0.1 million in 2009, acredit ofless than$0.1 million in 2008, and a credit of $0.2 million in 2007.  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, 2009, we estimate our overall net periodic postretirement benefit cost for the SFPP postretirement benefit plan for the year 2010 will 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 2010.

As of December 31, 2009 and 2008, the recorded value of our pension and postretirement benefit obligations for these plans was a combined $37.4 million and $33.4 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.  

Multiemployer Plans

As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of employees who are union members.  We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts.  Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs.  Amounts charged to expense for these plans were approximately $8.4 million for the year ended December 31, 2009, $7.8 million for the year ended December 31, 2008, and $6.7 million for the year ended December 31, 2007.

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.  In addition to a contribution equal to 4% of base compensation per year for most plan participants, our general partner may make special discretionary contributions.  Certain employees’ contributions are based on collective bargaining agreements.  The contributions are made each pay period on behalf of each eligible employee.  Participants may direct the investment of their contributions and all employer contributions, including discretionary contributions, into a variety of investments.  Plan assets are held and distributed pursuant to a trust agreement.  The total amount charged to expense for the Kinder Morgan Savings Plan was $12.1 million during 2009, $13.3 million during 2008, and $11.7 million during 2007.

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.

In July 2008, Mr. Richard D. Kinder and KMR’s compensation committee approved a special contribution through July 2009 of an additional 1% of base pay into the Savings Plan for each eligible employee.  Each eligible employee received an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2008 and continuing through the last pay period of July 2009.  The additional 1% contribution did not change or otherwise impact the annual 4% contribution that eligible employees also received during that time.  The additional contribution may be converted to any other Savings Plan investment fund at any time and it vested according to the same vesting schedule described in the preceding paragraph.

Since this additional 1% company contribution was discretionary, Mr. Kinder’s and the KMR compensation committee’s approvals will be required for each additional contribution.  Beginning with the first pay period of August 2009 and continuing through the last pay period of December 2009, we did not make any additional discretionary contributions to individual accounts for 2009, and we will not make any additional discretionary contributions to individual accounts for 2009 during the first six months of 2010.

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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, we credit each participating employee’s personal retirement account an amount equal to 3% of eligible compensation every pay period.  Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year.  Employees become fully vested in the plan after three years, and they may take a lump sum distribution upon termination of employment or retirement.

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.  Effective January 1, 2010, all contribution credits on behalf of participating employees resumed.

10.  Partners’ Capital

Limited Partner Units

As of December 31, 2009 and 2008, our partners’ capital included the following limited partner units:

	December 31,
	2009		2008
Common units		206,020,826		182,969,427
Class B units		5,313,400		5,313,400
i-units		85,538,263		77,997,906
Total limited partner units		296,872,489		266,280,733

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% ownership interest in us, excluding its incentive distribution rights.

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.  As of December 31, 2008, our common unit total consisted of 166,598,999 units held by third parties, 14,646,428 units held by 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, 2009 and December 31, 2008, 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 unit.  If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns.

Based on the preceding, KMR received a distribution of 1,783,310 i-units on November 13, 2009.  These additional i-units distributed were based on the $1.05 per unit distributed to our common unitholders on that date.  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.

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For more information on our i-unit distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions.”

Equity Issuances

2009 Issuances

On January 16, 2009, we entered into an equity distribution agreement with UBS Securities LLC, referred to in this report as 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 2009, we issued 5,488,947 of our common units pursuant to this agreement.  After commissions of $4.0 million, we received net proceeds from the issuance of these common units of approximately $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.

2008 Issuances

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

In March 2008, we issued, in a public offering, 5,750,000 of our common units at a price of $57.70 per unit, less commissions and underwriting expenses.  After commissions and underwriting expenses, we received net proceeds of $324.2 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

In connection with our August 28, 2008 acquisition of KMI’s 33 1/3% ownership interest in the Express pipeline system and KMI’s full ownership of the Jet Fuel pipeline system, we issued 2,014,693 of our common units to KMI.  The units were issued August 28, 2008, and as agreed between KMI and us, were valued at $116.0 million.  For more information on this acquisition, see Note 3 “Acquisitions and Divestitures—Acquisitions from KMI—Express and Jet Fuel Pipeline Systems.”

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On December 22, 2008, we issued, in a public offering, 3,900,000 of our common units at a price of $46.75 per unit, less commissions and underwriting expenses.  After commissions and underwriting expenses, we received net proceeds of $176.6 million for the issuance of these common units, and we used the proceeds to reduce the borrowings under our bank credit facility.

Income Allocation and Declared Distributions

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

Incentive distributions allocated to our general partner are determined by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement.  For the years ended December 31, 2009, 2008 and 2007, we declared distributions of $4.20, $4.02 and $3.48 per unit, respectively.  Under the terms of our partnership agreement, our total distributions to unitholders for 2009, 2008 and 2007 required incentive distributions to our general partner in the amount of $932.3 million, $800.8 million and $611.9 million, respectively.  The increased incentive distributions paid for 2009 over 2008, and 2008 over 2007 reflect the increases in amounts distributed per unit as well as the issuance of additional units.  Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.

Fourth Quarter 2009 Incentive Distribution

On January 20, 2010, we declared a cash distribution of $1.05 per unit for the quarterly period ended December 31, 2009.  This distribution was paid on February 12, 2010, to unitholders of record as of January 29, 2010.  Our common unitholders and Class B unitholders received cash.  KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $1.05 distribution per common unit.  The number of i-units distributed was 1,576,470.  For each outstanding i-unit that KMR held, a fraction of an i-unit (0.018430) was issued.  The fraction was determined by dividing:

▪ $1.05, the cash amount distributed per common unit

by

▪ $56.972, the average of KMR’s limited liability shares’ closing market prices from January 12-26, 2010, 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 12, 2010 distribution included an incentive distribution to our general partner in the amount of $242.3 million.  Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2009 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.

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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 Kinder Morgan Holdco LLC (KMI’s parent) 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.  As a subsidiary of KMI and Kinder Morgan Holdco LLC, 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 2009, 2008 and 2007, we recognized non-cash compensation expense of $5.7 million, $5.6 million and $26.2 million, respectively, due to certain going-private transaction expenses allocated to us from KMI and Kinder Morgan Holdco LLC.  For more information on KMI’s May 2007 going-private transaction, see Note 1.

Partnership Interests and Distributions

Kinder Morgan G.P., Inc.

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

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

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

In addition, as of December 31, 2009, our general partner owned 1,724,000 common units, representing approximately 0.58% of our outstanding limited partner units.

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

Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for 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 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.  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 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.  We retain this cash and use it in our business.  To date, all our cash distributions have been treated as distributions of cash from operations.

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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.

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 levels of cash from operations would be adjusted downward proportionately by multiplying each distribution 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.  For example, assuming the unrecovered initial common unit price is $5.75 per common unit and if cash from the first interim capital transaction of $2.375 per unit was distributed to owners of common units, then the amount of the first three distribution levels would each be reduced to 50% of its then current level.  The unrecovered initial common unit price generally is the amount by which the initial common unit price exceeds the aggregate distribution of cash from interim capital transactions per common unit.

When the initial common unit price is fully recovered, then each of the first three distribution levels will have been reduced to zero. 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.

For more information on incentive distributions paid to our general partner, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions.”

Kinder Morgan, Inc.

KMI remains the sole indirect stockholder of our general partner.  Also, as of December 31, 2009, 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 12,204,694 KMR shares, representing an indirect ownership interest of 12,204,694 i-units.  Together, these units represented approximately 11.4% of our outstanding limited partner units.  Including both its general and limited partner interests in us, at the 2009 distribution level, KMI received approximately 51% of all quarterly distributions from us, of which approximately 45% was attributable to its general partner interest and the remaining 6% was attributable to its limited partner interest.  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, 2009, KMR, our general partner’s delegate, remained the sole owner of our 85,538,263 i-units.

Asset Acquisitions and Sales

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

From time to time in the ordinary course of business, we buy and sell pipeline and related services from 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.

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Operations

Natural Gas Pipelines and Products Pipelines Business Segments

On February 15, 2008, KMI sold an 80% ownership interest in NGPL PipeCo LLC, which owns Natural Gas Pipeline Company of America LLC and certain affiliates (collectively referred to in this report as NGPL) to Myria Acquisition Inc. for approximately $5.9 billion.  Myria is comprised of a consortium of investors, including Prime Infrastructure, a Canadian pension fund and a Netherlands pension fund.  KMI accounts for its remaining 20% ownership interest in NGPL under the equity method of accounting and, pursuant to the provisions of a 15-year operating agreement, continues to operate NGPL’s assets.

KMI (or its subsidiaries) operates and maintains for us the assets comprising our Natural Gas Pipelines business segment.  KMI operates Trailblazer Pipeline Company LLC’s assets under a long-term contract pursuant to which Trailblazer Pipeline Company LLC incurs the costs and expenses related to KMI’s operating and maintaining the assets.  Trailblazer Pipeline Company LLC 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 Cypress Pipeline (and our North System until its sale in October 2007, described in Note 3 “Acquisitions and Divestitures—Divestitures—North System Natural Gas Liquids Pipeline System – Discontinued Operations,”) which is part of our Products Pipelines business segment, are operated under other agreements between KMI and us.  Pursuant to the applicable underlying agreements, we pay KMI either a fixed amount or actual costs incurred as reimbursement for the corporate general and administrative expenses incurred in connection with the operation of these assets.  The combined amounts paid to KMI for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company LLC, were $46.5 million of actual costs incurred for 2009 (and no fixed costs); $45.0 million of actual costs incurred for 2008 (and no fixed costs); and $1.0 million of fixed costs and $48.1 million of actual costs incurred for 2007.

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 believe the fixed amounts that were agreed upon at the time the contracts were entered into were reasonable estimates of the corporate general and administrative expenses to be incurred by KMI in performing such services.  We also reimburse KMI for operating and maintenance costs and capital expenditures incurred with respect to our assets.

In addition, we purchase natural gas transportation and storage services from NGPL.  For each of the years 2009, 2008 and 2007, these expenses totaled $8.8 million, $8.1 million and $6.8 million, respectively, and we included these expense amounts within the caption “Gas purchases and other costs of sales” in our accompanying consolidated statements of income.

CO2 Business Segment

KMI or its subsidiaries also operate and maintain for us the power plant we constructed at the SACROC oil field unit, located in the Permian Basin area of West Texas.  The power plant provides nearly half of SACROC’s current electricity needs.  Kinder Morgan Power Company, a subsidiary of KMI, operates and maintains the power plant under a five-year contract expiring in June 2010.  Pursuant to the contract, KMI incurs the costs and expenses related to operating and maintaining the power plant for the production of electrical energy at the SACROC field.  Such costs include supervisory personnel and qualified operating and maintenance personnel in sufficient numbers to accomplish the services provided in accordance with good engineering, operating and maintenance practices.  Our subsidiary Kinder Morgan Production Company fully reimburses KMI’s expenses, including all agreed-upon labor costs.

In addition, Kinder Morgan Production Company is responsible for processing and directly paying invoices for fuels utilized by the plant.  Other materials, including but not limited to lubrication oil, hydraulic oils, chemicals, ammonia and any catalyst are purchased by KMI and invoiced monthly as provided by the contract, if not paid directly by Kinder Morgan Production Company.  The amounts paid to KMI in 2009, 2008 and 2007 for operating and maintaining the power plant were $5.4 million, $3.1 million and $3.1 million, respectively.  Furthermore, we believe the amounts paid to KMI for the services they provide each year fairly reflect the value of the services performed.

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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 $18,878 and $430,835 in 2009 and 2008, respectively, and Kirby made payments, in 2008, to our subsidiaries totaling $144,300.

Risk Management

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

Our commodity-related risk management activities are monitored by our risk management committee, which is a separately designated standing committee whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business.  Our risk management committee is charged with the review and enforcement of our management’s risk management policy.  The committee is comprised of 17 executive-level employees of 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.

In addition, as a result of KMI’s going-private transaction, a number of individuals and entities became significant investors in KMI.  By virtue of the size of their ownership interest in KMI, two of those investors became “related parties” to us (as that term is defined in authoritative accounting literature): (i) American International Group, Inc., referred to in this report as AIG, and certain of its affiliates; and (ii) Goldman Sachs Capital Partners and certain of its affiliates.

We and/or our affiliates enter into transactions with certain AIG affiliates in the ordinary course of their conducting insurance and insurance-related activities, although no individual transaction is, and all such transactions collectively are not, material to our consolidated financial statements.  We also conduct commodity risk management activities in the ordinary course of implementing our risk management strategies in which the counterparty to certain of our derivative transactions is an affiliate of Goldman Sachs.  In conjunction with these activities, we are a party (through one of our subsidiaries engaged in the production of crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs which requires us to provide certain periodic information, but does not require the posting of margin.  As a result of changes in the market value of our derivative positions, we have created both amounts receivable from and payable to Goldman Sachs affiliates.

The following table summarizes the fair values of our energy commodity derivative contracts that are (i) associated with commodity price risk management activities with related parties; and (ii) included within “Fair value of derivative contracts” on our accompanying consolidated balance sheets as of December 31, 2009 and December 31, 2008 (in millions):

	December 31,
	2009			2008
Derivatives-asset/(liability)
Current assets	$	4.3		$	60.4
Noncurrent assets		18.4			20.1
Current liabilities		(96.8	)		(13.2	)
Noncurrent liabilities		(190.8	)		(24.1	)

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 the related party general and administrative expenses.  For each of the years 2009, 2008 and 2007, these expenses totaled $8.4 million, $7.6 million and $3.6 million, respectively.

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Notes Receivable

Plantation Pipe Line Company

We have a seven-year note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, our 51.17%-owned equity investee.  The outstanding note receivable balance was $84.8 million as of December 31, 2009, and $88.5 million as of December 31, 2008.  Of these amounts, $2.6 million and $3.7 million were included within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheets as of December 31, 2009 and December 31, 2008, respectively, and the remainder was included within “Notes receivable” at each reporting date.

Express US Holdings LP

In conjunction with the acquisition of our 33 1/3% equity ownership interest in the Express pipeline system from KMI on August 28, 2008 (discussed in Note 3), 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.  As of our acquisition date, the value of this unsecured debenture was equal to KMI’s carrying value of $107.0 million.  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, 2009 and December 31, 2008, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $108.1 million and $93.3 million, respectively, and we included these amounts within “Notes receivable” on our accompanying consolidated balance sheets.

Kinder Morgan, Inc.

Prior to our acquisition of Trans Mountain on April 30, 2007, KMI and certain of its affiliates advanced cash to Trans Mountain.  The advances were primarily used by Trans Mountain for capital expansion projects.  KMI and its affiliates also funded Trans Mountain’s cash book overdrafts (outstanding checks) as of April 30, 2007.  Combined, the funding for these items totaled $67.5 million, and we reported this amount within the caption “Changes in components of working capital:  Accounts receivable” in the operating section of our accompanying consolidated statement of cash flows.

Other Receivables and Payables

As of December 31, 2009 and December 31, 2008, our related party receivables (other than note receivables discussed above in “—Notes Receivable”) totaled $13.8 million and $5.3 million, respectively.  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, primarily due from NGPL and included within “Other current assets.”  The December 31, 2008 related party receivable amount was included entirely within “Accounts, notes and interest receivable, net” and primarily consisted of interest accrued on our long-term note receivable from Plantation and accounts receivable due from the Express pipeline system.

As of December 31, 2009 and December 31, 2008, our related party payables totaled $13.4 million and $26.8 million, respectively.  The December 31, 2009 amount primarily consisted of amounts owed to KMI and we included this amount within “Accounts payable” on our accompanying balance sheet.  The December 31, 2008 amount consisted of (i) $24.6 million included within “Accounts payable” and primarily related to amounts we owed to KMI; and (ii) $2.2 million of natural gas imbalance payables included within “Accrued other current liabilities” and owed mainly to NGPL.

Other

Generally, KMR makes all decisions relating to the management and control of our business.  Our general partner owns all of KMR’s voting securities and is its sole managing member.  KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner.  Certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us.  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 themselves.  In general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders.

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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 amount of capital leases included within “Property, Plant and Equipment, net” in our accompanying consolidated balance sheets as of December 31, 2009 and December 31, 2008 are not material to our consolidated balance sheets.  Including probable elections to exercise renewal options, the remaining terms on our operating leases range from one to 59 years.  Future commitments related to these leases as of December 31, 2009 are as follows (in millions):

Year	Commitment
2010	$	37.7
2011		32.2
2012		23.5
2013		16.8
2014		13.6
Thereafter		38.7
Total minimum payments	$	162.5

We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $0.4 million.  Total lease and rental expenses were $55.6 million for 2009, $61.7 million for 2008 and $49.2 million for 2007.

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.

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In 2007, Mr. Hultquist exercised 7,500 unit appreciation rights at an aggregate fair value of $53.00 per unit, and he received a cash amount of $116,250.  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 received a cash amount of $179,275.  As of December 31, 2009, 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 2007 and 2008 were made effective January 17, 2007 and January 16, 2008, respectively.  The elections for 2009 were made effective January 21, 2009 by Messrs. Hultquist and Waughtal, and January 28, 2009 by Mr. Lawrence.  The elections under this plan for 2010 were made effective January 20, 2010.

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

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

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

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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) will be 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) will be paid in cash as described above.  No other compensation will be paid to the non-employee directors during 2010.

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.  The following is a description of our contingent debt agreements as of December 31, 2009.

Cortez Pipeline Company Debt

Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. – 50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and Cortez Vickers Pipeline Company – 13% partner) are required, on a several, proportional percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency.  Furthermore, due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company.

As of December 31, 2008, the debt facilities of Cortez Capital Corporation consisted of (i) $53.6 million of Series D notes due May 15, 2013; (ii) a $125 million short-term commercial paper program; and (iii) a $125 million committed revolving bank credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program).

On December 11, 2009, Cortez Capital Corporation performed the following:

▪ issued $100 million in principal amount of three-year, variable rate Series E notes that mature in full on December 11, 2012.  Interest on the Series E notes is paid quarterly and based on an interest rate of LIBOR plus a spread.  The net proceeds from the sale of the notes were used to repay borrowings under its bank credit facility;

▪ amended its bank credit facility to allow for borrowings up to $40.0 million due December 11, 2012; and

▪ terminated its commercial paper program.

As of December 31, 2009, in addition to the $100 million of outstanding Series E notes, Cortez Capital Corporation had $42.9 million of outstanding Series D notes and $9.9 million of outstanding borrowings under its credit facility.  Accordingly, as of December 31, 2009, our contingent share of Cortez’s debt was $76.4 million (50% of total guaranteed borrowings).

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With respect to Cortez’s Series D notes, the average interest rate on the notes is 7.14%, and the outstanding $42.9 million principal amount of the notes is due in four equal annual installments of approximately $10.7 million beginning May 2010.  Shell Oil Company shares our several guaranty obligations jointly and severally; however, we are obligated to indemnify Shell for liabilities it incurs in connection with such guaranty.  As of December 31, 2009, JP Morgan Chase has issued a letter of credit on our behalf in the amount of $21.4 million to secure our indemnification obligations to Shell for 50% of the $42.9 million in principal amount of Series D notes outstanding as of that date.

Nassau County, Florida Ocean Highway and Port Authority Debt

We have posted a letter of credit as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority.  The bonds were issued for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida.  Our subsidiary, Nassau Terminals LLC is the operator of the marine port facilities.  The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020.  Principal payments on the bonds are made on the first of December each year and corresponding reductions are made to the letter of credit.  As of December 31, 2009, this letter of credit had a face amount of $19.8 million.

In addition, in October 2008, pursuant to the standby purchase agreement provisions contained in the bond indenture—which require the sellers of those guarantees to buy the debt back—certain investors elected to put (sell) back their bonds at par plus accrued interest.  A total principal and interest amount of $11.8 million was tendered and drawn against our letter of credit and accordingly, we paid this amount pursuant to the letter of credit reimbursement provisions.  This payment reduced the face amount of our letter of credit from $22.5 million to $10.7 million.  In December 2008, the bonds that were put back were re-sold, and we were fully reimbursed for our prior letter of credit payments.

Rockies Express Pipeline LLC Debt

Pursuant to certain guaranty agreements, all three member owners of Rockies Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Rockies Express Pipeline LLC, borrowings under Rockies Express’$2.0 billion five-year, unsecured revolving credit facility (due April 28, 2011) and Rockies Express’ $2.0 billion commercial paper program.  Rockies Express Pipeline LLC is an equity method investee of ours, and the three member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline LLC – 50%, a subsidiary of Sempra Energy – 25%, and a subsidiary of ConocoPhillips – 25%.

Prior to completing construction of its Rockies Express interstate natural gas pipeline system in November 2009, borrowings under the Rockies Express’ commercial paper program and/or its credit facility were primarily used to finance pipeline construction costs and to pay related expenses.  Subsequent borrowings can be used for general corporate purposes.  The credit facility, which can be amended to allow for borrowings of up to $2.5 billion, supports borrowings under the commercial paper program, and borrowings under the commercial paper program reduce the borrowings allowed under the credit facility.  Lehman Brothers Commercial Bank was a lending bank with a $41 million commitment under Rockies Express Pipeline LLC’s $2.0 billion credit facility, and during the first quarter of 2009, Rockies Express amended its facility to remove Lehman Brothers Commercial Bank as a lender, thus reducing the borrowing capacity under the facility by $41.0 million.  However, the commitments of the other banks remain unchanged, and the facility is not defaulted.

In October 2008, Standard & Poor’s Rating Services lowered Rockies Express’ short-term credit rating to A-3 from A-2, and effective November 20, 2009, Rockies Express terminated its commercial paper program.  Rockies Express expects that its financing and liquidity needs will continue to be met through both borrowings made under its long-term bank credit facility and contributions by its equity investors.  As of December 31, 2009, Rockies Express had outstanding borrowings of $1,672.7 million under its credit facility. Accordingly, as of December 31, 2009, our contingent share of Rockies Express’ debt was $836.4 million (50% of total guaranteed borrowings).

On August 20, 2009, Rockies Express paid $600 million to retire the principal amount of its floating rate senior notes that matured on that date.  It obtained the necessary funds to repay these senior notes from contributions received from its equity investors, including $306.0 million received from us (51% of total principal repayments, corresponding to our percentage ownership at that time).

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Additionally, on June 24, 2008, Rockies Express completed a private offering of an aggregate of $1.3 billion in principal amount of fixed rate senior notes.  Rockies Express received net proceeds of approximately $1.29 billion from this offering, after deducting the initial purchasers’ discount and estimated offering expenses, and virtually all of the net proceeds from the sale of the notes were used to repay short-term commercial paper borrowings.  All payments of principal and interest in respect of these senior notes are the sole obligation of Rockies Express.  Noteholders will have no recourse against us, Sempra Energy or ConocoPhillips, or against any of our or their respective officers, directors, employees, shareholders, members, managers, unitholders or affiliates for any failure by Rockies Express to perform or comply with its obligations pursuant to the notes or the indenture.

Midcontinent Express Pipeline LLC Debt

Pursuant to certain guaranty agreements, each of the two member owners of Midcontinent Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Midcontinent Express, borrowings under its $255.4 million three-year, unsecured revolving credit facility due February 28, 2011.  The facility is with a syndicate of financial institutions with The Royal Bank of Scotland plc as the administrative agent.  Midcontinent Express is an equity method investee of ours, and the two member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan Operating L.P. “A” – 50%, and Energy Transfer Partners, L.P. – 50%.

Borrowings under the credit facility can be used for general corporate purposes, and in the fourth quarter of 2009, Midcontinent Express amended and reduced the borrowing capacity of its credit facility from $1.4 billion to $255.4 million after completing permanent long-term financing (discussed below) and removing Lehman Brothers Commercial Bank as a lender under the facility.  As of December 31, 2009, Midcontinent Express had outstanding borrowings of $29.5 million under its bank credit facility.  Accordingly, as of December 31, 2009, our contingent share of Midcontinent Express’ debt was $14.8 million (50% of total borrowings).  Furthermore, the credit facility can be used for the issuance of letters of credit to support the operation of the Midcontinent Express pipeline system, and as of December 31, 2009, a letter of credit having a face amount of $33.3 million was issued under the credit facility.  Accordingly, as of December 31, 2009, our contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).

On September 16, 2009, Midcontinent Express completed a private offering of an aggregate of $800 million in principal amount of fixed rate senior notes.  Midcontinent Express received net proceeds of $793.9 million from this offering, after deducting the initial purchasers’ discount and estimated offering expenses, and the net proceeds from the sale of the notes were used to repay borrowings under its revolving credit facility.  All payments of principal and interest in respect of the notes are the sole obligation of Midcontinent Express.  Noteholders will have no recourse against us, Energy Transfer Partners, or against any of our or their respective officers, directors, employees, members, managers, unitholders or affiliates for any failure by Midcontinent Express to perform or comply with its obligations pursuant to the notes or the indenture.

Fayetteville Express Pipeline LLC Debt

Pursuant to certain guaranty agreements, each of the two member owners of Fayetteville Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Fayetteville Express, borrowings under its $1.1 billion two and one-half year, unsecured revolving credit facility, entered into on November 13, 2009 and due May 11, 2012.  The facility is with a syndicate of financial institutions with The Royal Bank of Scotland plc as the administrative agent.  Borrowings under the credit facility will be used to finance the construction of the Fayetteville Express natural gas pipeline system and to pay related expenses.  Fayetteville Express is an equity method investee of ours, and the two member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan Operating L.P. “A” – 50%, and Energy Transfer Partners, L.P. – 50%.

As of December 31, 2009, Fayetteville Express had outstanding borrowings of $355.0 million under its bank credit facility.  Accordingly, as of December 31, 2009, our contingent share of Fayetteville Express’ debt was $177.5 million (50% of total borrowings).

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.

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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 unfavorable price volatility related to (i) pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas purchases; and (iii) natural gas system use and storage.  The unfavorable 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 2009, we recognized a net loss of $13.5 million related to crude oil hedges, which resulted from hedge ineffectiveness and amounts excluded from effectiveness testing.  Reflecting the portion of changes in the value of derivative contracts that were not effective in offsetting underlying changes in expected cash flows (the ineffective portion of hedges), we recognized losses of $2.4 million and $0.1 million during 2008 and 2007, respectively.

Furthermore, during the years 2009, 2008 and 2007, we reclassified losses of $99.3 million, $663.7 million and $433.2 million, respectively, of “Accumulated other comprehensive loss” included in our Partners’ Capital into earnings.  With the exception of an approximate $0.1 million loss reclassified in the first quarter of 2007, none of the reclassification of “Accumulated other comprehensive loss” into earnings during 2009, 2008 or 2007 resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred).  The proceeds or payments resulting from the settlement of cash flow hedges are reflected in the operating section of our statement of cash flows as changes to net income and working capital.

The “Accumulated other comprehensive loss” balance included in our Partners’ Capital was $394.8 million as of December 31, 2009, and $287.7 million as of December 31, 2008.  These totals included “Accumulated other comprehensive loss” amounts associated with energy commodity price risk management activities of $418.2 million as of December 31, 2009 and $63.2 million as of December 31, 2008.  Approximately $238.1 million of the total amount associated with energy commodity price risk management activities and included in our Partners’ Capital as of December 31, 2009 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, 2009, 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 2014.

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As of December 31, 2009, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

	Notional quantity
Derivatives designated as hedging contracts
Crude oil	25.6 million barrels
Natural gas(a)	44.3 billion cubic feet
Derivatives not designated as hedging contracts
Natural gas(a)	0.1 billion cubic feet

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(a) Notional quantities are shown net.

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.  This will result in non-cash gains or losses being reported in our operating results.

Effective at the beginning of the second quarter of 2008, we determined that the derivative contracts of our Casper and Douglas natural gas processing operations that previously had been designated as cash flow hedges for accounting purposes no longer met the hedge effectiveness assessment as required by generally accepted accounting principles.  Consequently, we discontinued hedge accounting treatment for these relationships (primarily crude oil hedges of heavy natural gas liquids sales) effective March 31, 2008.  Since the forecasted sales of natural gas liquids volumes (the hedged item) were still expected to occur, all of the accumulated losses through March 31, 2008 on the related derivative contracts remained in accumulated other comprehensive income, and were not reclassified into earnings until the physical transactions occurred.  Any changes in the value of these derivative contracts subsequent to March 31, 2008 were no longer deferred in other comprehensive income, but rather impacted current period income.  The last of these derivative contracts expired in December 2009.

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, 2008, we were a party to interest rate swap agreements with a total notional principal amount of $2.8 billion.  During 2009, we terminated an existing fixed-to-variable interest rate swap agreement having a notional principal amount of $300 million and a maturity date of March 15, 2031, and entered into sixteen separate fixed-to-variable swap agreements having a combined notional principal amount of $2.95 billion.  We received proceeds of $144.4 million from the early termination of the $300 million swap agreement.  In addition, an existing fixed-to-variable rate swap agreement having a notional principal amount of $250 million matured on February 1, 2009.  This swap agreement corresponded with the maturity of our $250 million in principal amount of 6.30% senior notes that also matured on that date (discussed in Note 8).

Therefore, as of December 31, 2009, we had a combined notional principal amount of$5.2 billion of fixed-to-variable interest rate swap agreements effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread.  All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2009, 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 throughJanuary 15, 2038.

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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, 2009 and 2008 (in millions):

Fair Value of Derivative Contracts

	Asset derivatives						Liability derivatives
	December 31, 2009			December 31, 2008			December 31, 2009				December 31, 2008
	Balance sheet location	Fair value		Balance sheet Location	Fair value		Balance Sheet Location	Fair value			Balance sheet location	Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current	$	19.1	Current	$	113.5	Current	$	(270.8	)	Current	$	(129.4	)
	Non-current		57.3	Non-current		48.9	Non-current		(241.5	)	Non-current		(92.2	)
Subtotal			76.4			162.4			(512.3	)			(221.6	)
Interest rate swap agreements	Non-current		222.5	Non-current		747.1	Non-current		(218.6	)	Non-current		-
Total			298.9			909.5			(730.9	)			(221.6	)
Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current		1.7	Current		1.8	Current		(1.2	)	Current		(0.1	)
Total derivatives		$	300.6		$	911.3		$	(732.1	)		$	(221.7	)

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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, 2009 and December 31, 2008, this unamortized premium totaled $328.6 million and $204.2 million, respectively.

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, 2009 and 2008 (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,
		2009			2008				2009		2008
Interest rate swap agreements	Interest, net – income/(expense)	$	(598.7	)	$	609.1	Fixed rate debt	Interest, net – income/(expense)	$	598.7	$	(609.1	)
Total		$	(598.7	)	$	609.1	Total		$	598.7	$	(609.1	)

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(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.

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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,
	2009			2008			2009			2008				2009			2008
Energy commodity derivative contracts	$	(458.2	)	$	658.0	Revenues-natural gas sales	$	14.9		$	2.5		Revenues	$	(13.5	)	$	-
						Revenues-product sales and other		(139.2	)		(638.8	)
						Gas purchases and other costs of sales		24.0			(34.2	)	Gas purchases and other costs of sales		-			(2.4	)
Total	$	(458.2	)	$	658.0	Total	$	(100.3	)	$	(670.5	)	Total	$	(13.5	)	$	(2.4	)

____________

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,
		2009			2008
Energy commodity derivative contracts	Gas purchases and other costs of sales	$	(4.2	)	$	5.6
Total		$	(4.2	)	$	5.6

The above disclosures regarding our derivative contracts and hedging activities are made pursuant to provisions included within the Codification’s “Derivatives and Hedging” Topic.  These provisions provide for enhanced disclosure requirements that include, among other things, (i) a tabular summary of the fair value of derivative contracts and their gains and losses; (ii) disclosure of derivative features that are credit-risk–related to provide more information regarding an entity’s liquidity; and (iii) cross-referencing within footnotes to make it easier for financial statement users to locate important information about derivative contracts.  We adopted these provisions on January 1, 2009, and the adoption of these disclosure provisions did not have a material impact on our consolidated financial statements.

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 a 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.

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The maximum potential exposure to credit losses on our derivative contracts as of December 31, 2009 was (in millions):

	Asset position
Interest rate swap agreements	$	222.5
Energy commodity derivative contracts		78.1
Gross exposure		300.6
Netting agreement impact		(74.7	)
Net exposure	$	225.9

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, 2009 and December 31, 2008, we had outstanding letters of credit totaling $55.0 million and $40.0 million, respectively, 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, 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.  As of December 31, 2008, our counterparties associated with our energy commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $3.1 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet.

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, 2009, 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	$	58.1	$	128.3
Two notches to below BBB-/Baa3 (below investment grade)	$	76.9	$	205.2

__________

(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 one notch downgrade to BBB-/Baa3 by one agency would not trigger the entire $58.1 million incremental obligation.

(b) Includes current posting at current rating.

14.  Fair Value Measurements

Our fair value measurements and disclosures are made in accordance with the “Fair Value Measurements and Disclosures” Topic of the Codification.  This Topic establishes a single definition of fair value in generally accepted accounting principles and prescribes disclosures about fair value measurements.

We adopted the provisions of this Topic for our financial assets and financial liabilities effective January 1, 2008, and the adoption did not have a material impact on our balance sheet, statement of income, or statement of cash flows since we already applied its basic concepts in measuring fair values.  With regard to our non-financial assets and non-financial liabilities, we adopted the provisions of this Topic effective January 1, 2009.  This includes applying the provisions to (i) nonfinancial assets and liabilities initially measured at fair value in business combinations; (ii) reporting units or nonfinancial assets and liabilities measured at fair value in conjunction with goodwill impairment testing; (iii) other nonfinancial assets measured at fair value in conjunction with impairment assessments; and (iv) asset retirement obligations initially measured at fair value.  The adoption for non-financial assets and liabilities did not have a material impact on our balance sheet, statement of income, or statement of cash flows since we already applied its basic concepts in measuring fair values.

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.

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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).

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, 2009 and December 31, 2008, based on the three levels established by the Codification and does not include cash margin deposits, which are reported as “Restricted deposits” in our accompanying consolidated balance sheets (in millions):

	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, 2009
Energy commodity derivative contracts(a)	$	78.1	$	-	$	14.4	$	63.7
Interest rate swap agreements		222.5		-		222.5		-
As of December 31, 2008
Energy commodity derivative contracts(b)	$	164.2	$	0.1	$	108.9	$	55.2
Interest rate swap agreements		747.1		-		747.1		-

____________

	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, 2009
Energy commodity derivative contracts(c)	$	(513.5	)	$	-	$	(462.8	)	$	(50.7	)
Interest rate swap agreements		(218.6	)		-		(218.6	)		-
As of December 31, 2008
Energy commodity derivative contracts(d)	$	(221.7	)	$	-	$	(210.6	)	$	(11.1	)
Interest rate swap agreements		-			-		-			-

__________

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

(b) Level 1 consists primarily of NYMEX natural gas futures.  Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX.  Level 3 consists primarily of West Texas Intermediate options and West Texas Sour hedges.

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

(d) Level 2 consists primarily of OTC West Texas Intermediate hedges.  Level 3 consists primarily of natural gas basis swaps, natural gas options and West Texas Intermediate options.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the years ended December 31, 2009 and 2008 (in millions):

Significant unobservable inputs (Level 3)

	Year Ended December 31,
	2009			2008
Derivatives-net asset (liability)
Beginning of period	$	44.1		$	(100.3	)
Realized and unrealized net losses		(48.4	)		69.6
Purchases and settlements		17.3			74.8
Transfers in (out) of Level 3		-			-
End of period	$	13.0		$	44.1
Change in unrealized net losses relating to contracts still held at end of period	$	(42.1	)	$	88.8

In addition, on both October 10, 2008 and June 30, 2009, we adopted separate provisions included within the “Fair Value Measurements and Disclosures” Topic of the Codification.  The provisions adopted in October 2008 provide guidance clarifying how fair value measurements should be applied when valuing securities in markets that are not active, and reaffirm the notion of fair value as an exit price as of the measurement date.  Among other things, the guidance also states that significant judgment is required in valuing financial assets.  The adoption of these provisions was effective immediately; however, the adoption did not have any impact on our consolidated financial statements.

The provisions adopted on June 30, 2009 provide guidelines for making fair value measurements more consistent with the overall principles presented in the “Fair Value Measurements and Disclosures” Topic.  They provide additional guidance to highlight and expand on the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for a financial asset.  The adoption of these provisions did not have a material impact on our consolidated financial statements.

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, 2009 and December 31, 2008 (both short-term and long-term, but excluding the value of interest rate swaps), is disclosed below (in millions):

	December 31, 2009				December 31, 2008
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Total Debt	$	10,592.4	$	11,265.7	$	8,563.6	$	7,627.3

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;

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▪ 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.

We evaluate performance principally based on each segments’ earnings before depreciation, depletion and amortization, which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income and income tax expense, and net income attributable to noncontrolling interests.  Our reportable segments are strategic business units that offer different products and services.  Each segment is managed separately because each segment involves different products and marketing strategies.  We identified our Trans Mountain pipeline system as a separate reportable business segment prior to the third quarter of 2008.  Following the acquisition of our interests in the Express and Jet Fuel pipeline systems on August 28, 2008, discussed in Note 3, we combined the operations of our Trans Mountain, Express and Jet Fuel pipeline systems to represent the “Kinder Morgan Canada” segment.

Our Products Pipelines segment derives its revenues primarily from the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids.  Our Natural Gas Pipelines segment derives its revenues primarily from the sale, transport, processing, treating, storage and gathering of natural gas.  Our CO2 segment derives its revenues primarily from the production and sale of crude oil from fields in the Permian Basin of West Texas and from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields.  Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals.  Our Kinder Morgan Canada business segment derives its revenues primarily from the transportation of crude oil and refined products.

As discussed in Note 3, due to the October 2007 sale of our North System, an approximately 1,600-mile interstate common carrier pipeline system whose operating results were included as part of our Products Pipelines business segment, we accounted for the North System business as a discontinued operation.  Consistent with the management approach of identifying and reporting discrete financial information on operating segments, we have included the North System’s financial results within our Products Pipelines business segment disclosures for all periods presented in this report.  We have reconciled the total of our reportable segment’s financial results to our consolidated financial results by separately identifying, in the following pages where applicable, the North System amounts as discontinued operations.

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Financial information by segment follows (in millions):

	Year Ended December 31,
	2009			2008			2007
Revenues
Products Pipelines
Revenues from external customers	$	826.6		$	815.9		$	844.4
Intersegment revenues		-			-			-
Natural Gas Pipelines
Revenues from external customers		3,806.9			8,422.0			6,466.5
Intersegment revenues		-			-			-
CO2
Revenues from external customers		1,035.7			1,133.0			824.1
Intersegment revenues		-			-			-
Terminals
Revenues from external customers		1,108.1			1,172.7			963.0
Intersegment revenues		0.9			0.9			0.7
Kinder Morgan Canada
Revenues from external customers		226.1			196.7			160.8
Intersegment revenues		-			-			-
Total segment revenues		7,004.3			11,741.2			9,259.5
Less: Total intersegment revenues		(0.9	)		(0.9	)		(0.7	)
		7,003.4			11,740.3			9,258.8
Less: Discontinued operations		-			-			(41.1	)
Total consolidated revenues	$	7,003.4		$	11,740.3		$	9,217.7

Operating expenses(a)
Products Pipelines	$	269.5		$	291.0		$	451.8
Natural Gas Pipelines		3,193.0			7,804.0			5,882.9
CO2		271.1			391.8			304.2
Terminals		536.8			631.8			536.4
Kinder Morgan Canada		72.5			67.9			65.9
Total segment operating expenses		4,342.9			9,186.5			7,241.2
Less: Total intersegment operating expenses		(0.9	)		(0.9	)		(0.7	)
		4,342.0			9,185.6			7,240.5
Less: Discontinued operations		-			-			(14.8	)
Total consolidated operating expenses	$	4,342.0		$	9,185.6		$	7,225.7

Other expense (income)
Products Pipelines	$	0.6		$	1.3		$	(154.8	)
Natural Gas Pipelines		(7.8	)		(2.7	)		(3.2	)
CO2		-			-			-
Terminals		(27.6	)		2.7			(6.3	)
Kinder Morgan Canada(b)		-			-			377.1
Total segment Other expense (income)		(34.8	)		1.3			212.8
Less: Discontinued operations		-			1.3			152.8
Total consolidated Other expense (income)	$	(34.8	)		2.6		$	365.6

Depreciation, depletion and amortization
Products Pipelines	$	94.1	$	89.4	$	89.2
Natural Gas Pipelines		93.4		68.5		64.8
CO2		487.9		385.8		282.2
Terminals		136.9		122.6		89.3
Kinder Morgan Canada		38.5		36.4		21.5
Total segment depreciation, depletion and amortization		850.8		702.7		547.0
Less: Discontinued operations		-		-		(7.0	)
Total consol. depreciation, depletion and amortization	$	850.8		702.7	$	540.0

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Earnings from equity investments
Products Pipelines	$	29.0		$	24.4		$	32.5
Natural Gas Pipelines		141.8			113.4			19.2
CO2		22.3			20.7			19.2
Terminals		0.7			2.7			0.6
Kinder Morgan Canada		(4.1	)		(0.4	)		-
Total segment earnings from equity investments.		189.7			160.8			71.5
Less: Discontinued operations		-			-			(1.8	)
Total consolidated equity earnings.	$	189.7			160.8		$	69.7

Amortization of excess cost of equity investments
Products Pipelines	$	3.4	$	3.3	$	3.4
Natural Gas Pipelines		0.4		0.4		0.4
CO2		2.0		2.0		2.0
Terminals		-		-		-
Kinder Morgan Canada		-		-		-
Total segment amortization of excess cost of investments.		5.8		5.7		5.8
Less: Discontinued operations		-		-		-
Total consol. amortization of excess cost of investments	$	5.8		5.7	$	5.8

Interest income
Products Pipelines	$	4.1	$	4.3	$	4.4
Natural Gas Pipelines		6.2		1.2		-
CO2		-		-		-
Terminals		-		-		-
Kinder Morgan Canada		12.0		3.9		-
Total segment interest income		22.3		9.4		4.4
Unallocated interest income		0.2		0.6		1.3
Total consolidated interest income	$	22.5		10.0	$	5.7

Other, net-income (expense)
Products Pipelines	$	8.3	$	(2.3	)	$	5.0
Natural Gas Pipelines		25.6		28.0			0.2
CO2		-		1.9			-
Terminals		3.7		1.7			1.0
Kinder Morgan Canada		11.9		(10.1	)		8.0
Total segment other, net-income (expense)		49.5		19.2			14.2
Less: Discontinued operations		-		-			-
Total consolidated other, net-income (expense)	$	49.5		19.2		$	14.2

Income tax benefit (expense)
Products Pipelines	$	(13.4	)	$	(3.8	)	$	(19.7	)
Natural Gas Pipelines		(5.7	)		(2.7	)		(6.0	)
CO2		(4.0	)		(3.9	)		(2.1	)
Terminals		(5.2	)		(19.7	)		(19.2	)
Kinder Morgan Canada		(18.9	)		19.0			(19.4	)
Total segment income tax benefit (expense)		(47.2	)		(11.1	)		(66.4	)
Unallocated income tax benefit (expense)		(8.5	)		(9.3	)		(4.6	)
Total consolidated income tax benefit (expense)	$	(55.7	)		(20.4	)	$	(71.0	)

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Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(c)
Products Pipelines	$	584.5		$	546.2		$	569.6
Natural Gas Pipelines		789.6			760.6			600.2
CO2		782.9			759.9			537.0
Terminals		599.0			523.8			416.0
Kinder Morgan Canada		154.5			141.2			(293.6	)
Total segment earnings before DD&A		2,910.5			2,731.7			1,829.2
Total segment depreciation, depletion and amortization		(850.8	)		(702.7	)		(547.0	)
Total segment amortization of excess cost of invests.		(5.8	)		(5.7	)		(5.8	)
General and administrative expenses		(330.3	)		(297.9	)		(278.7	)
Unallocable interest expense, net of interest income		(431.3	)		(397.6	)		(395.8	)
Unallocable income tax expense		(8.5	)		(9.3	)		(4.6	)
Total consolidated net income	$	1,283.8			1,318.5		$	597.3

Capital expenditures(d)
Products Pipelines	$	199.8	$	221.7	$	259.4
Natural Gas Pipelines		372.0		946.5		264.0
CO2		341.8		542.6		382.5
Terminals		378.2		454.1		480.0
Kinder Morgan Canada		32.0		368.1		305.7
Total consolidated capital expenditures	$	1,323.8		2,533.0	$	1,691.6

Investments at December 31	2009		2008		2007
Products Pipelines	$	203.7	$	202.6	$	202.3
Natural Gas Pipelines		2,542.9		654.0		427.5
CO2		11.2		13.6		14.2
Terminals		18.7		18.6		10.6
Kinder Morgan Canada		68.7		65.5		0.8
Total consolidated investments	$	2,845.2		954.3	$	655.4

Assets at December 31
Products Pipelines	$	4,299.0	$	4,183.0	$	4,045.0
Natural Gas Pipelines		7,772.7		5,535.9		4,347.3
CO2		2,224.5		2,339.9		2,004.5
Terminals		3,636.6		3,347.6		3,036.4
Kinder Morgan Canada		1,797.7		1,583.9		1,440.8
Total segment assets		19,730.5		16,990.3		14,874.0
Corporate assets(e)		531.7		895.5		303.8
Total consolidated assets	$	20,262.2		17,885.8	$	15,177.8

____________

(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) 2007 amount represents an expense of $377.1 million attributable to a goodwill impairment charge recognized by KMI, as discussed in Note 2 “Summary of Significant Accounting Policies—Goodwill.”

(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 Rockies Express’ sustaining capital expenditures, totaled $172.2 million in 2009, $180.6 million in 2008 and $152.6 million in 2007.  These listed amounts do not include sustaining capital expenditures for the Trans Mountain Pipeline (part of Kinder Morgan Canada) for periods prior to our acquisition date of April 30, 2007.  Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.

(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.

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We do not attribute interest and debt expense to any of our reportable business segments.  For each of the years ended December 31, 2009, 2008 and 2007, we reported total consolidated interest expense of $431.5 million, $398.2 million and $397.1 million, respectively.

Our total operating revenues are derived from a wide customer base.For each of the three years ended December 31, 2009, 2008 and 2007, no revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues.

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

	Year Ended December 31,
	2009		2008		2007
Revenues from external customers
United States	$	6,680.5	$	11,452.0	$	8,986.3
Canada		301.9		267.0		211.9
Mexico and other(a)		21.0		21.3		19.5
Total consolidated revenues from external customers.	$	7,003.4	$	11,740.3	$	9,217.7

Long-lived assets at December 31(b)	2009		2008		2007
United States	$	15,556.6	$	13,563.2	$	11,054.3
Canada		1,813.6		1,547.6		1,420.0
Mexico and other(a)		89.1		87.8		89.5
Total consolidated long-lived assets	$	17,459.3	$	15,198.6	$	12,563.8

__________

(a) Includes operations in Mexico and the Netherlands.

(b) Long-lived assets exclude (i) goodwill; (ii) other intangibles, net; and (iii) long-term note receivables from related parties.

16.  Litigation, Environmental and Other Contingencies

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during 2009.  This note also contains a description of any material legal proceeding initiated during 2009 in which we are involved.

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; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; ExxonMobil Oil Corporation as ExxonMobil; Tosco Corporation as Tosco; Ultramar Diamond Shamrock Corporation/Ultramar Inc. as Ultramar; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; America West Airlines, Inc., Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the 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 United States Department of Transportation Pipeline and Hazardous Materials Safety Administration as the PHMSA; the North Carolina Department of Environment and Natural Resources as the NCDENR; the Florida Department of Environmental Protection as the Florida DEP; our subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; 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

▪ FERC Docket Nos. OR92-8, et al (West and East Line Rates)—Complainants: Chevron, Navajo, ARCO, BP, Western Refining, ExxonMobil, Tosco, and Texaco—Defendant: SFPP—Status:  Appeals pending at the D.C. Circuit;

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▪ FERC Docket No. OR92-8-025 (Watson Drain-Dry Charge)—Complainants:  BP; ExxonMobil; Chevron; ConocoPhillips; and Ultramar—Defendant: SFPP—Status:  Appeal denied by the D.C. Circuit;

▪ FERC Docket Nos. OR96-2, et al (All SFPP Rates)—Complainants: All Shippers except Chevron—Defendant: SFPP—Status:  Compliance filings pending with FERC;

▪ FERC Docket No. OR02-4 (All SFPP Rates)—Complainant: Chevron—Defendant: SFPP; Status:  Appeal of complaint dismissal pending at the D.C. Circuit;

▪ FERC Docket Nos. OR03-5, OR04-3, OR05-4 & OR05-5 (West, East, North, and Oregon Line Rates)—Complainants: BP, ExxonMobil, ConocoPhillips, the Airlines—Defendant: SFPP—Status:  Exceptions to initial decision pending at FERC;

▪ FERC Docket Nos. OR07-1 & OR07-2 (North and West Line Rates)—Complainant: Tesoro—Defendant: SFPP—Status:  Held in abeyance;

▪ FERC Docket Nos. OR07-3 & OR07-6 (not consolidated) (2005-2006 Index Rate Increases)—Complainants: BP, Chevron, ConocoPhillips, ExxonMobil, Tesoro, and Valero Marketing—Defendant: SFPP—Status:  Appeal of dismissal by FERC pending at the D.C. Circuit;

▪ FERC Docket No. OR07-4 (All SFPP Rates)—Complainants: BP, Chevron, and ExxonMobil—Defendant: SFPP—Status:  Held in abeyance;

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

▪ FERC Docket No. OR07-20 (2007 Index Rate Increases)—Complainant: BP—Defendant: SFPP—Status:  Appeal of dismissal by FERC pending at the D.C. Circuit;

▪ FERC Docket No. OR08-13 (Most SFPP Rates)—Complainants: BP and ExxonMobil—Defendant: SFPP—Status:  Held in abeyance;

▪ FERC Docket No. IS05-230 (North Line Rates)—Protestants: Shippers—Defendant: SFPP—Status:  Exceptions to initial decision pending at FERC;

▪ FERC Docket No. IS08-390 (West Line Rates)— Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the Airlines—Defendant: SFPP—Status:  Exceptions to initial decision pending at FERC;

▪ FERC Docket No. IS09-375 (2009 Index Rate Increases)—Protestants: BP, ExxonMobil, Chevron, Tesoro, ConocoPhillips, Western, Navajo, Valero Marketing, and Southwest—Defendant: SFPP—Status:  Requests for rehearing of FERC dismissal pending before FERC;

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

▪ FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero, Chevron, Western Refining, and Southwest Airlines—Defendant: SFPP—Status:  Pre-hearing stage;

▪ FERC Docket Nos. OR08-15/OR09-8 (consolidated) (2008 Index Increases)—Complainants:  BP/Chevron—Defendant:  SFPP—Status:  Complaints partially dismissed and remainder set for hearing; hearing held in abeyance pending settlement discussions;

▪ FERC Docket Nos. OR09-18/OR09-21 (not consolidated) (2008 and 2009 Index Increases)—Complainants: BP (for 2009)/Tesoro (for 2008 and 2009)—Defendant: SFPP—Status:  BP appeal of FERC dismissal pending at the D.C. Circuit;

▪ FERC Docket Nos. OR09-11/OR09-14 (not consolidated) (2007 and 2008 Page 700 Audit Request)—Complainants: BP/Tesoro—Defendant: Calnev—Status:  BP appeal of FERC dismissal pending at the D.C. Circuit;

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▪ FERC Docket Nos. OR09-12/OR09-16 (not consolidated) (2007 and 2008 Page 700 Audit Request)—Complainants: BP/Tesoro—Defendant: SFPP—Status:  BP appeal of FERC dismissal pending at the D.C. Circuit;

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

▪ FERC Docket Nos. OR09-17/OR09-22 (Most SFPP Rates) (not consolidated)—Complainants: Tesoro/BP—Defendant: SFPP—Status:  BP appeal of FERC dismissal pending at the D.C. Circuit; and

▪ FERC Docket Nos. OR09-19/OR09-23 (not consolidated) (2009 Index Increases)—Complainants: Tesoro/BP—Defendant: Calnev—Status:  BP appeal of FERC dismissal pending at the D.C. Circuit.

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

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

During 2009, SFPP made settlement payments to various shippers totaling approximately $15.5 million in connection with OR07-8, OR07-11, and IS08-28 and related dockets.  The IS08-28 settlement (East Line rates) was approved by FERC in March 2009, and SFPP implemented reduced settlement rates effective May 1, 2009, along with refunds and settlement payments.  Due to reduced East Line volumes, SFPP terminated the IS08-28 settlement pursuant to its terms and filed for increased East Line rates (IS09-437), which were accepted and became effective January 1, 2010, subject to refund and investigation.

Based on our review of these FERC proceedings and the information available to us, we estimate that as of December 31, 2009, shippers are seeking approximately$350 million in reparation and refund payments and approximately $35 to $40 million in additional annual rate reductions.  We assume that, with respect to our SFPP litigation reserves, any reparations and accrued interest thereon will be paid no earlier than the end of the first quarter of 2010.

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.  As of the filing of this report, it is unknown when a decision from the CPUC regarding either of the two groups of consolidated matters will be issued.  Based on our review of these CPUC proceedings, we estimate that shippers are seeking approximately $100 million in reparation and refund payments and approximately $35 million in annual rate reductions.

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 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.

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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.  Defendants filed a motion seeking sanctions against plaintiffs Bailey and Ptasynski and their attorney.  The plaintiffs appealed the final judgment to the United States Fifth Circuit Court of Appeals.  The parties concluded their briefing to the Fifth Circuit Court of Appeals in February 2009, and the appeal remains pending.

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.  On June 3, 2008, the plaintiffs filed a request with the American Arbitration Association seeking administration of the arbitration.  In October 2008, the New Mexico federal district court entered an order declaring that the panel in the first arbitration should decide whether the claims in the second arbitration are barred by res judicata (an adjudicated issue that cannot be relitigated).  The plaintiffs filed a motion for reconsideration of that order, which was denied by the New Mexico federal district court in January 2009.  Plaintiffs appealed to the Tenth Circuit Court of Appeals.  On December 21, 2009, the Tenth Circuit Court of Appeals reversed the District Court and ruled that a new arbitration panel should be convened to decide the claims and defenses asserted by the parties.

MMS Notice of Noncompliance and Civil Penalty

On December 20, 2006, Kinder Morgan CO2 received a “Notice of Noncompliance and Civil Penalty:  Knowing or Willful Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO2 Company, L.P., Case No. CP07-001” from the U.S. Department of the Interior, Minerals Management Service, referred to in this note as the MMS.  This Notice, and the MMS’s position that Kinder Morgan CO2 has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO2 concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties.

The Notice of Noncompliance and Civil Penalty assesses a civil penalty of approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for each of 17 alleged violations) for Kinder Morgan CO2’s alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO2 produced at McElmo Dome, during the period from June 2005 through October 2006.  The MMS stated that civil penalties will continue to accrue at the same rate until the alleged violations are corrected.

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 February 2007, Kinder Morgan CO2 filed a motion seeking to stay the accrual of civil penalties during the appeal, which was denied.

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In July 2008, the parties reached a settlement of the Notice of Noncompliance and Civil Penalty, subject to final approval by the MMS and the Department of the Interior.  On January 28, 2010, a representative of the MMS notified Kinder Morgan CO2 that the Department of the Interior will not approve the settlement on its existing terms.

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 has over-reported transportation allowances and underpaid royalties in the amount of approximately $4.6 million for the period from January 1, 2005 through December 31, 2006 as a result of its use of the Cortez Pipeline tariff as the transportation allowance in calculating federal royalties. The MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO2 must use its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations.  The MMS set a due date of April 13, 2007 for Kinder Morgan CO2’s payment of the $4.6 million in claimed additional royalties, with possible late payment charges and civil penalties for failure to pay the assessed amount.

Kinder Morgan CO2 has not paid the $4.6 million, and on April 19, 2007, it submitted a notice of appeal and statement of reasons in response to the Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 C.F.R. sec. 290.100, et seq.

In addition to the March 2007 Order to Report and Pay, the MMS issued a second Order to Report and Pay in August 2007, in which the MMS claims that Kinder Morgan CO2 has over-reported transportation allowances and underpaid royalties (due to the use of the Cortez Pipeline tariff as the transportation allowance for purposes of federal royalties) in the amount of 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 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 January 28, 2010, a representative of the MMS notified Kinder Morgan CO2 that the Department of the Interior will not approve the settlement on its existing terms.

J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New Mexico)

This case involved a purported class action against Kinder Morgan CO2 alleging that it failed to pay the full royalty and overriding royalty, collectively referred to as the royalty interests, on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome unit, located in northeastern New Mexico, during the period beginning January 1, 2000

The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome unit.

On September 10, 2009, the parties signed a settlement agreement providing for (i) a payment of $3.2 million to the class; (ii) a new royalty methodology pursuant to which future royalties will be based on a price formula that is tied in part to published crude oil prices; and (iii) a dismissal with prejudice of all claims.  On October 22, 2009, the trial court entered final judgment approving the settlement.  The time period for appeal of the judgment has expired and is final for all purposes.  Accordingly, the case is concluded.

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.

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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 second quarter of 2010, with a decision from the judge expected by the end of 2010.

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.

United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).

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

In May 2005, a Special Master appointed in this litigation found that because there was a prior public disclosure of the allegations and that Grynberg was not an original source, the Court lacked subject matter jurisdiction.  As a result, the Special Master recommended that the Court dismiss all of the KMP defendants.  In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the KMP defendants on jurisdictional grounds.  Grynberg appealed this Order to the Tenth Circuit Court of Appeals.  Briefing was completed and oral argument was held on September 25, 2008.  A decision by the Tenth Circuit Court of Appeals affirming the dismissal of the KMP defendants was issued on March 17, 2009.  Grynberg’s petition for rehearing was denied on May 4, 2009 and the Tenth Circuit issued its Mandate on May 18, 2009.  On October 5, 2009 the United States Supreme Court denied Grynberg’s Petition for Writ of Certiorari, ending his appeal.

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Prior to the dismissal order on jurisdictional grounds, the KMP defendants filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his Complaint without evidentiary support and for an improper purpose.  On January 8, 2007, after the dismissal order, the KMP defendants also filed a Motion for Attorney Fees under the False Claim Act.  A decision is still pending on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees.

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. 

Leukemia Cluster Litigation

Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) (“Jernee”).

Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326  (Second Judicial District Court, State of Nevada, County of Washoe) (“Sands”).

On May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against us and several KMP related entities and individuals, and additional unrelated defendants.  Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing harmful substances and emissions and gases to damage the environment and health of human beings.  Plaintiffs claim that Adam Jernee’s death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins.  Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages.

On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against the same defendants and alleged the same claims as in the Jernee case with respect to Stephanie Suzanne Sands.  The Jernee case has been consolidated for pretrial purposes with the Sands case.

In July 2009, plaintiffs in both the Sands and Jernee cases agreed to dismiss all claims against the KMP related defendants with prejudice in exchange for the KMP defendants’ agreement that they would not seek to recover their defense costs against the plaintiffs.  The KMP defendants filed a Motion for Approval of Good Faith Settlement which was granted by the court on August 27, 2009, effectively concluding these cases with respect to all KMP related entities and individuals.

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.  Because the case was only recently filed and served, the Kinder Morgan defendants have not yet filed an answer.  The defendants will file their answer in February 2010 and intend to vigorously defend the case.

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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.

Midcontinent Express Pipeline LLC Construction Incident

On July 15, 2009, a Midcontinent Express Pipeline LLC contractor and subcontractor were conducting a nitrogen pressure test onfacilities at a Midcontinent Express Pipeline delivery meter station that was under constructionin Smith County, Mississippi.  An unexpected release occurred during testing, resulting in one fatality and injuries to four other employees of the contractor or subcontractor.  The United States Occupational Safety and Health Administration completed their investigation.  Neither Midcontinent Express Pipeline LLC nor we were cited for any violations by OSHA.

Pasadena Terminal Fire

On September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena, Texas liquids terminal facility.  One of our employees was injured and subsequently died.  In addition, the pit 3 manifold was severely damaged.  On July 13, 2009, a civil lawsuit was filed by and on behalf of the family of the deceased employee entitled Brandy Williams et. al. v. KMGP Services Company, Inc. in the 133rd District Court of Harris County, Texas, case no. 2009-44321.  On December 28, 2009, the case was settled via an Agreed Judgment entered by the court, and the matter is now concluded.

State of Texas v. Kinder Morgan Liquids Terminals, Case # D1GV10000017, 53rd Judicial District Court, Travis County, Travis, Texas.

This case was filed on January 8, 2010 and brought on behalf of the People of Texas and the Texas Commission of Environmental Quality (TCEQ) for alleged violations of the Texas Clean Air Act. Specifically, TCEQ alleges that KMLT had an unauthorized emission event relating to the pit 3 fire at the Pasadena Terminal. We are currently in discussions with TCEQ legal representatives and the Texas Attorney General’s office regarding resolution of this matter. We do not expect any fines and penalties related to this matter to be material.

Rockies Express Pipeline LLC Wyoming Construction Incident

On November 11, 2006, a bulldozer operated by an employee of Associated Pipeline Contractors, Inc., a third-party contractor to Rockies Express, struck an existing subsurface natural gas pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline Group.  The pipeline was ruptured, resulting in an explosion and fire.  The incident occurred in a rural area approximately nine miles southwest of Cheyenne, Wyoming.  The incident resulted in one fatality (the operator of the bulldozer) and there were no other reported injuries.  The cause of the incident was investigated by the PHMSA.  In March 2008, the PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order, or NOPV, to El Paso Corporation in which it concluded that El Paso failed to comply with federal law and its internal policies and procedures regarding protection of its pipeline, resulting in this incident. PHMSA issued a Final Order to El Paso on November 23, 2009.

PHMSA has not issued any NOPV’s to Rockies Express, and we do not expect that it will do so.  Immediately following the incident, Rockies Express and El Paso Pipeline Group reached an agreement on a set of additional enhanced safety protocols designed to prevent the reoccurrence of such an incident.

In September 2007, the family of the deceased bulldozer operator filed a wrongful death action against us, Rockies Express and several other parties in the District Court of Harris County, Texas, 189th Judicial District, at case number 2007-57916.  The plaintiffs seek unspecified compensatory and exemplary damages plus interest, attorney’s fees and costs of suit.  We have asserted contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers.  On March 25, 2008, we entered into a settlement agreement with one of the plaintiffs, the decedent’s daughter, resolving any and all of her claims against us, Rockies Express and its contractors.  In January 2010, we entered into a settlement agreement with each of the remaining plaintiffs, effectively concluding this matter.  We were indemnified for the full amount of both settlements by one of Rockies Express’ contractors.

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Charlotte, North Carolina

On January 17, 2010, our subsidiary Kinder Morgan Southeast Terminal LLCs’ 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.

Barstow, California

The United States Department of Navy has alleged that historic releases of methyl tertiary-butyl ether, or MTBE, from Calnev Pipe Line Company’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 certain meritorious defenses to the Navy’s claims, it is working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for 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 Terminal, Burnaby, British Columbia

On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within our Trans Mountain pipeline system near its Westridge terminal in Burnaby, 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 (U.S.).  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.

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 charges claim 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 Acts.  We are of the view that the charges have been improperly laid against us, and we intend to vigorously defend against them.

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.

Additionally, although it is not possible to predict the ultimate outcomes, we also believe, based on our experiences to date, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or cash flows.  As of December 31, 2009 and December 31, 2008, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $220.9 million and $234.8 million, respectively.  The reserve is primarily related to various claims from lawsuits 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.  We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

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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.

Our subsidiary, Kinder Morgan Liquids Terminals LLC, 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 for the first half of 2009 in order to allow the parties to work with the regulatory agency concerning the scope of the required cleanup. The regulatory agency has not yet made any final decisions concerning cleanup of the former terminal, although the agency is expected to issue final cleanup orders in 2010.

The lawsuit stay has now been lifted, and two new defendants have been added to the lawsuit by the plaintiff in a Third Amended Complaint.  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, later owned by Support Terminals.  The terminal is now owned by Pacific Atlantic Terminals, LLC, and it too is a party to the lawsuit.

The complaint seeks any and all damages related to remediating all environmental contamination at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit.  The parties are currently involved in mandatory mediation and met in June and October 2008.  No progress was made at any of the mediations.  The mediation judge has referred the case back to the litigation court room.

On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil Corporation and our subsidiary Kinder Morgan Liquids Terminals LLC, formerly known as GATX Terminals Corporation.  The complaint was filed in Gloucester County, New Jersey.  Both ExxonMobil and Kinder Morgan Liquids Terminals LLC filed third party complaints against Support Terminals seeking to bring Support Terminals into the case.  Support Terminals filed motions to dismiss the third party complaints, which were denied.  Support Terminals is now joined in the case and it filed an Answer denying all claims. The court has consolidated the two cases.

The plaintiffs seek the costs and damages that the plaintiffs allegedly have incurred or will incur as a result of the discharge of pollutants and hazardous substances at the Paulsboro, New Jersey facility.  The costs and damages that the plaintiffs seek include cleanup costs and damages to natural resources.  In addition, the plaintiffs seek an order compelling the defendants to perform or fund the assessment and restoration of those natural resource damages that are the result of the defendants’ actions.  Plaintiffs have filed a report asserting that the cost of natural resource restoration is $81 million.  Defendants vigorously dispute that estimate.  In addition, we believe that any damages, including restoration damages, would be the responsibility of the other co-defendants under applicable law and indemnity agreements between the parties.

Mission Valley Terminal Lawsuit

In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the city’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility.  The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL.  On September 26, 2007, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB.  On October 3, 2007, we filed a Motion to Dismiss all counts of the Complaint.  The court denied in part and granted in part the Motion to Dismiss and gave the City leave to amend their complaint.  The City submitted its Amended Complaint and we filed an Answer.  The parties have commenced with discovery.  This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board.

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Kinder Morgan Port Manatee Terminal LLC, Palmetto, Florida

On June 18, 2009, our subsidiary Kinder Morgan Port Manatee Terminal LLC, referred to in this note as KM PMT, received a Revised Warning Letter from the Florida DEP, advising us of possible regulatory and air permit violations regarding operations at our Port Manatee, Florida terminal.  We previously conducted a voluntary internal audit at this facility in March 2008 and identified various environmental compliance and permitting issues primarily related to air quality compliance.  We self-reported our findings from this audit in a self-disclosure letter to the Florida DEP in March 2008.  Following the submittal of our self-disclosure letter, the agency conducted numerous inspections of the air pollution control devices at the terminal and issued this Revised Warning Letter.  In addition, KM PMT received a subpoena from the U.S. Department of Justice for production of documents related to the service and operation of the air pollution control devices at the terminal.

In February 2010, KM PMT entered into a plea agreement with the U.S. Attorney’s office for the Middle District of Florida to resolve the air permit violations at our Port Manatee terminal that occurred between 2001 and 2008.  During this period of time, former local terminal management failed to disclose and address the operational condition of control equipment at the facility, as required by the Clean Air Act.  To resolve the matter, KM PMT has entered into a plea agreement concerning criminal violations of the Clean Air Act and has agreed to pay a fine of $750,000 and a community service payment of $250,000 to the National Fish & Wildlife Foundation.  In addition, in order to resolve the matter with the Florida DEP, KM PMT has entered into a civil Consent Order with the Florida DEP under which it has agreed to implement an Environmental Compliance Plan and to pay $336,000 in civil penalties and costs.  We have fully cooperated with the government’s investigation, and have taken appropriate measures at the terminal, including replacing and repairing control equipment, adding new equipment, terminating certain employees, and retraining current employees on proper environmental procedures.

Kinder Morgan, EPA Section 114 Information Request

On January 8, 2010, we received a Clean Air Act Section 114 information request from the U.S. Environmental Protection Agency, Region V.  This information request requires that we provide the EPA with air permit and various other information related to its natural gas pipeline compressor station operations in Illinois, Indiana, and Ohio.  We believe our natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations and are preparing a response to this EPA information request.

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.  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 air, water and waste violations issued by various governmental authorities related to compliance with environmental regulations.  As we receive notices of non-compliance, we negotiate and settle these matters.  We do not believe that these 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 issued by various regulatory authorities related to compliance with environmental regulations associated with our assets.  We have established a reserve to address the costs associated with the cleanup.

In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites.  Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable.  In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide.  See “—Pipeline Integrity and Releases” above for additional information with respect to ruptures and leaks from our pipelines.

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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, 2009, we have accrued an environmental reserve of$81.1 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, 2009, we have recorded a receivable of $4.3 million for expected cost recoveries that have been deemed probable.  As of December 31, 2008, our environmental reserve totaled $78.9 million and our estimated receivable for environmental cost recoveries totaled $20.7 million, respectively.  Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.

Other

We are a defendant in various lawsuits arising from the day-to-day operations of our businesses.  Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

17.  Regulatory Matters

The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the FERC, under the Interstate Commerce Act.  The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory.  Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index.  FERC Order No. 561-A, affirming and clarifying Order No. 561, expanded the circumstances under which interstate petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995.  For each of the years ended December 31, 2009, 2008 and 2007, 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 2009.  This note also contains a description of any material regulatory matters initiated during 2009 in which we are involved.

Natural Gas Pipeline Expansion Filings

Rockies Express Pipeline-East Project

OnNovember 12, 2009, we completed and placed into service the remainder of the Rockies Express-East natural gas pipeline segment, consisting of approximately 195-miles of 42-inch diameter pipe extending to a terminus near the town of Clarington in Monroe County, Ohio.  Rockies Express-East is the third and final phase of the Rockies Express Pipeline.  On June 29, 2009, we commenced interim transportation service for up to 1.6 billion cubic feet per day of natural gas on the first 444 miles of the Rockies Express-East pipeline segment, which extends from Audrain County, Missouri to the Lebanon Hub in Warren County, Ohio.

Now fully operational, the 1,679-mile Rockies Express Pipeline has the capacity to transport up to 1.8 billion cubic feet of natural gas per day and can make deliveries to pipeline interconnects owned by Northern Natural Gas Company, NGPL, ANR, Panhandle Eastern Pipeline Company, our subsidiary Kinder Morgan Interstate Gas Transmission LLC (referred to as KMIGT and discussed further below), Missouri Gas Pipeline, Midwestern Gas Transmission, Trunkline, Columbia Gas, Dominion Transmission, Tennessee Gas, Texas Eastern, and Texas Gas Transmission.  It also connects with the following local distribution companies: Ameren, Vectren, and Dominion East Ohio.

We own 50% of Rockies Express Pipeline LLC, the sole owner of the Rockies Express Pipeline, and virtually all of the pipeline system’s natural gas transportation capacity has been contracted under long-term firm commitments from creditworthy shippers.  Market conditions for consumables, labor and construction equipment, along with certain provisions in the final regulatory orders resulted in increased costs and impacted certain projected completion dates for the Rockies Express Pipeline, and including expansions, our current estimate of total Rockies Express Pipeline project construction costs is approximately $6.8 billion.

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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 Rockies Express Pipeline expansion project.  The proposed expansion will 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.  Upon completion, the additional compression will permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado.

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 expansion is fully contracted.  The additional compression at Big Hole compressor station was made available as of December 9, 2009 and the additional compression at the Arlington compressor station  is expected to be operational in the second quarter of 2010.  The total FERC authorized cost for the proposed project is approximately $78 million; however, Rockies Express Pipeline LLC is currently projecting that the final actual cost will be approximately $25 million less.

Kinder Morgan Interstate Gas Transmission Pipeline - Huntsman 2009 Expansion Project

KMIGT has 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.  When fully constructed, the proposed facilities will create incremental firm storage capacity for up to one million dekatherms of natural gas, with an associated injection capability of approximately 6,400 dekatherms per day and an associated deliverability of approximately 10,400 dekatherms per day.  As a result of an open season, KMIGT and one shipper executed a firm precedent agreement for 100% of the capacity to be created by the project facilities for a five-year term.  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 has received FERC approval to commence the expanded storage service effective February 1, 2010.

Kinder Morgan Louisiana Pipeline LLC (KMLP) – Docket No. CP06-449-000

On April 16, 2009, our subsidiary Kinder Morgan Louisiana Pipeline LLC received authorization from the FERC to begin service on Leg 2 of the approximately 133-mile, 42-inch diameter Kinder Morgan Louisiana Pipeline.  Natural gas transportation service on Leg 2 commenced April 18, 2009, and on June 21, 2009, Kinder Morgan Louisiana Pipeline LLC completed pipeline construction and placed the remaining portion of the pipeline system into service.  The Kinder Morgan Louisiana Pipeline project cost approximately $1 billion to complete and 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, to various delivery points in Louisiana.  The pipeline interconnects with multiple third-party pipelines and all of the capacity on the pipeline system has been fully subscribed by Chevron and Total under 20-year firm transportation contracts.  Total’s contract became effective on June 21, 2009, and Chevron’s contract became effective on October 1, 2009.

Midcontinent Express Pipeline LLC – Docket Nos. CP08-6-000 and CP09-56-000

On April 10, 2009, Midcontinent Express Pipeline LLC placed Zone 1 of the Midcontinent Express natural gas pipeline system into interim service.  Zone 1 extends from Bennington, Oklahoma to the interconnect with Columbia Gulf Transmission Company in Madison Parish, Louisiana.  It has a design capacity of approximately 1.5 billion cubic feet per day.  On August 1, 2009, construction of the pipeline was completed, and Zone 2 was placed into service.  Zone 2 extends from the Columbia Gulf interconnect to the terminus of the system in Choctaw County, Alabama.  It has a design capacity of approximately 1.2 billion cubic feet per day.  In an order issued September 17, 2009, the FERC approved Midcontinent Express’ (i) amendment to move one compressor station in Mississippi and modify the facilities at another station in Texas (both stations were among the facilities certificated in the July 2008 Order authorizing the system’s construction); and (ii) application to expand the capacity in Zone 1 by 0.3 billion cubic feet per day (this expansion is expected to be completed in December 2010).

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The Midcontinent Express Pipeline is owned by Midcontinent Express Pipeline LLC, a 50/50 joint venture between us and Energy Transfer Partners, L.P.  The pipeline originates near Bennington, Oklahoma and extends from southeast Oklahoma, across northeast Texas, northern Louisiana and central Mississippi, and terminates at an interconnection with the Transco Pipeline near Butler, Alabama.  The approximate 500-mile natural gas pipeline system connects the Barnett Shale, Bossier Sands and other natural gas producing regions to markets in the eastern United States, and substantially all of the pipeline’s capacity is fully subscribed with long-term binding commitments from creditworthy shippers.  The entire Midcontinent Express project cost approximately $2.3 billion to complete.

Fayetteville Express Pipeline LLC – Docket No.CP09-433-000

Pipeline system development work continues on the previously announced Fayetteville Express Pipeline project.  The Fayetteville Express Pipeline is owned by Fayetteville Express Pipeline LLC, another 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 will begin in Conway County, Arkansas, continue eastward through White County, Arkansas, and will terminate 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 at least ten years totaling 1.85 billion cubic feet per day of capacity.

On June 15, 2009, Fayetteville Express filed its certificate application with the FERC.  On October 15, 2009, the FERC issued its Environmental Assessment finding that, subject to compliance with certain conditions, the environmental impact of the Fayetteville Express Pipeline could be adequately mitigated.  On December 17, 2009, the FERC approved and issued the pipeline’s certificate application authorizing construction.  Pending the FERC’s approval of Fayetteville Express’ implementation plan, construction of the pipeline is expected to begin before the end of the first quarter of 2010, and the pipeline is expected to be in service by late 2010 or early 2011.  Our estimate of the total costs of this pipeline project is approximately $1.2 billion (consistent with our January 20, 2010 fourth quarter earnings press release).

18.  Recent Accounting Pronouncements

SEC’s Final Rule on Oil and Gas Disclosure Requirements

On December 31, 2008, the Securities and Exchange Commission, referred to in this report as the SEC, issued Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” which revises the disclosures required by oil and gas companies.  The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities.  The provisions of this final rule are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009.  We have fully adopted the provisions required pursuant to the SEC’s final rule; however, we are not able to disclose the impact of these new SEC guidelines due to the impracticability of the effort that would be required to prepare reserve reports under both the old and new rules.  For further disclosures on our oil and gas producing activities, see Note 20.

Accounting Standards Updates

In August 2009, the FASB issued Accounting Standards Update No. 2009-05, “Measuring Liabilities at Fair Value.”  This Accounting Standards Update, or ASU, amends the “Fair Value Measurements and Disclosures” Topic of the Codification to provide further guidance on how to measure the fair value of a liability.  ASU No. 2009-05 is effective for the first reporting period beginning after issuance (September 30, 2009 for us), and the adoption of this ASU did not have a material impact on our consolidated financial statements.

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 change 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 when 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.

188

In January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas—Oil and Gas Reserve Estimation and Disclosures.”  This ASU amends the “Extractive Industries—Oil and Gas” Topic of the Codification to align the oil and gas reserve estimation and disclosure requirements in this Topic with the SEC’s Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” discussed above.  The amendments are effective for annual reporting periods ending on or after December 31, 2009, and the adoption of these provisions on December 31, 2009 did not have a material impact on our consolidated financial statements.

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 Level 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 is effective for us January 1, 2011); however, because this ASU pertains to disclosure requirements only, the adoption of this ASU will not have a material impact on our consolidated financial statements.

19.  Quarterly Financial Data (Unaudited)

	Operating Revenues		Operating Income		Income from Continuing Operations		Income from Discontinued Operations		Net Income
	(In millions)
2009
First Quarter	$	1,786.5	$	340.0	$	266.8	$	-	$	266.8
Second Quarter		1,645.3		372.0		328.6		-		328.6
Third Quarter		1,660.7		406.7		363.7		-		363.7
Fourth Quarter		1,910.9		396.4		324.7		-		324.7
2008
First Quarter	$	2,720.3	$	419.4	$	350.2	$	0.5	$	350.7
Second Quarter		3,495.7		406.2		365.5		0.8		366.3
Third Quarter		3,232.8		407.9		332.9		-		332.9
Fourth Quarter		2,291.5		318.0		268.6		-		268.6

	Limited Partners’ Interest in:
	Income from Continuing Operations		Income from Discontinued Operations		Net Income
Limited Partners’ income per unit:
2009
First Quarter		0.15		-		0.15
Second Quarter		0.33		-		0.33
Third Quarter		0.43		-		0.43
Fourth Quarter		0.26		-		0.26
2008
First Quarter		0.63		-		0.63
Second Quarter		0.64		0.01		0.65
Third Quarter		0.48		-		0.48
Fourth Quarter		0.19		-		0.19

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20.  Supplemental Information on Oil and Gas Producing Activities (Unaudited)

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, 2009.  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		2,290		1,423		983		759		4		4
Natural Gas		5		2		31		15		-		-
Total Wells		2,295		1,425		1,014		774		4		4

__________

(a) Includes active wells and wells temporarily shut-in.  As of December 31, 2009, 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, 2009.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 three years ended December 31, 2009, 2008 and 2007:

	Year Ended December 31,
	2009		2008		2007
Productive
Development		42		47		31
Exploratory		-		-		-
Dry
Development		-		-		-
Exploratory		-		-		-
Total Wells		42		47		31

__________

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, 2009:

	Gross		Net
Developed Acres		72,435		67,748
Undeveloped Acres		9,715		9,056
Total		82,150		76,804

190

Operating Statistics

Operating statistics from our oil and gas producing activities for each of the years 2009, 2008 and 2007 are shown in the following table:

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

	Year Ended December 31,
	2009		2008		2007
Consolidated Companies(a)
Production costs per barrel of oil equivalent(b)(c)(d)	$	11.44	$	15.70	$	12.84
Crude oil production (MBbl/d)		37.4		36.2		35.6
SACROC crude oil production (MBbl/d)		25.1		23.3		23.0
Yates crude oil production (MBbl/d)		11.8		12.3		12.0
Natural gas liquids production (MBbl/d)(d)		5.4		4.8		5.5
Natural gas liquids production from gas plants(MBbl/d)(e)		4.0		3.5		4.1
Total natural gas liquids production(MBbl/d)		9.5		8.3		9.6
SACROC natural gas liquids production (MBbl/d)(d)		5.3		4.6		5.2
Yates natural gas liquids production (MBbl/d)(d)		0.1		0.2		0.2
Natural gas production (MMcf/d)(d)(f)		0.9		1.4		0.8
Natural gas production from gas plants(MMcf/d)(e)(f)		0.7		0.2		0.3
Total natural gas production(MMcf/d)(f)		1.6		1.6		1.1
Yates natural gas production (MMcf/d)(d)(f)		0.8		1.3		0.7
Average sales prices including hedge gains/losses:
Crude oil price per Bbl(g)	$	49.55	$	49.42	$	36.05
Natural gas liquids price per Bbl(g)	$	37.70	$	63.48	$	52.22
Natural gas price per Mcf(h)	$	3.45	$	7.73	$	6.08
Total natural gas liquids price per Bbl(e)	$	37.96	$	63.00	$	52.91
Total natural gas price per Mcf(e)	$	3.53	$	7.63	$	5.89
Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl(g)	$	59.03	$	97.70	$	69.63
Natural gas liquids price per Bbl(g)	$	37.70	$	63.48	$	52.22
Natural gas price per Mcf(h)	$	3.45	$	7.73	$	6.08

__________

(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.

The remaining supplementary information on oil and gas producing activities is presented as required by the disclosure rules prescribed by the SEC.  The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities; exploration and development activities; and the results of operations from oil and gas producing activities.

191

Supplemental information is also provided for the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

Our capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing Activities

	As of December 31,
	2009			2008			2007
Consolidated Companies(a)
Wells and equipment, facilities and other	$	2,438.8		$	2,106.9		$	1,612.5
Leasehold		352.6			348.9			348.1
Total proved oil and gas properties		2,791.4			2,455.8			1,960.6
Accumulated depreciation and depletion		(1,501.1	)		(1,064.3	)		(725.5	)
Net capitalized costs	$	1,290.3		$	1,391.5		$	1,235.1

__________

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.  Includes capitalized asset retirement costs and associated accumulated depreciation.  There are no capitalized costs associated with unproved oil and gas properties for the periods reported.

Our costs incurred for property acquisition, exploration and development were as follows (in millions):

Costs Incurred in Exploration, Property Acquisitions and Development

	Year Ended December 31,
	2009		2008		2007
Consolidated Companies(a)
Property Acquisition
Proved oil and gas properties	$	5.3	$	-	$	-
Development		330.3		495.2		244.4

__________

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.  There are no costs incurred associated with unproved oil and gas properties for the periods reported.  All capital expenditures were made to develop our proved oil and gas properties and no exploration costs were incurred for the periods reported.

Our results of operations from oil and gas producing activities for each of the years 2009, 2008 and 2007 are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing Activities

	Year Ended December 31,
	2009		2008		2007
Consolidated Companies(a)
Revenues(b)	$	767.0	$	785.5	$	589.7
Expenses:
Production costs(c)		188.8		308.4		243.9
Other operating expenses(d)		53.3		99.0		56.9
Depreciation, depletion and amortization expenses		441.4		342.2		258.5
Total expenses		683.5		749.6		559.3
Results of operations for oil and gas producing activities	$	83.5	$	35.9	$	30.4

__________

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.

(b) Revenues include losses attributable to our hedging contracts of $129.5 million, $693.3 million $434.2 million for the years ended December 31, 2009, 2008 and 2007, 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.

192

The table below represents estimates, as of December 31, 2009, 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.  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.  This data has been prepared using current prices and costs, as discussed in subsequent paragraphs of this document, and the estimates of reserves and future revenues in this report conform to the guidelines of the SEC.

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, 2009.

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 with 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.

During 2009, our continued investments in wells and oil field infrastructure resulted in the reclassification of 7.4 million barrels of crude oil and 0.4 million barrels of natural gasoline liquids from proved undeveloped to the proved developed classification of  reserves.  These reclassifications reflect the transfer of 29.2% of crude oil and 13.7% of natural gasoline 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.  We currently expect that the proved undeveloped reserves we report as of December 31, 2009 will be developed within the next five years.

During 2009, we filed estimates of our oil and gas reserves for the year 2008 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23.  The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest.  The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this report exceeds 5%.

193

Reserve Quantity Information

	Consolidated Companies(a)
	Crude Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)(b)
Proved developed and undeveloped reserves:
As of December 31, 2006		123,978			10,333			291
Revisions of previous estimates(c)		10,361			2,784			1,077
Production		(12,984	)		(2,005	)		(290	)
As of December 31, 2007		121,355			11,112			1,078
Revisions of previous estimates(d)		(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(e)		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

Proved developed reserves:
As of December 31, 2006	69,073	5,877	291
As of December 31, 2007	70,868	5,517	1,078
As of December 31, 2008	53,346	4,308	1,274
As of December 31, 2009	47,058	2,665	698

Proved undeveloped reserves:
As of December 31, 2006	54,905	4,456	-
As of December 31, 2007	50,487	5,595	-
As of December 31, 2008	25,233	2,552	-
As of December 31, 2009	33,786	3,255	-

__________

(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) Associated with an expansion of the carbon dioxide flood project area of the SACROC unit.

(d) Predominantly due to lower product prices used to determine reserve volumes.

(e) Predominantly due to higher product prices resulting in an expanded economic carbon dioxide project area.

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 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 prior years 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;

▪ 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.

194

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,
	2009			2008			2007
Consolidated Companies(a)
Future cash inflows from production	$	4,898.0		$	3,498.0		$	12,099.5
Future production costs		(1,951.5	)		(1,671.6	)		(3,536.2	)
Future development costs(b)		(1,179.7	)		(910.3	)		(1,919.2	)
Undiscounted future net cash flows		1,766.8			916.1			6,644.1
10% annual discount		(503.5	)		(257.7	)		(2,565.7	)
Standardized measure of discounted future net cash flows	$	1,263.3		$	658.4		$	4,078.4

__________

(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,
	2009			2008			2007
Consolidated Companies(a)
Present value as of January 1	$	658.4		$	4,078.4		$	2,207.8
Changes during the year:
Revenues less production and other costs(b)		(652.7	)		(1,012.4	)		(722.1	)
Net changes in prices, production and other costs(b)		915.7			(3,076.9	)		2,153.2
Development costs incurred		330.3			495.2			244.5
Net changes in future development costs		(445.4	)		231.1			(547.8	)
Purchases of reserves in place		-			-			-
Revisions of previous quantity estimates(c)		391.1			(417.1	)		510.8
Accretion of discount		65.9			392.9			198.1
Timing differences and other		-			(32.8	)		33.9
Net change for the year		604.9			(3,420.0	)		1,870.6
Present value as of December 31	$	1,263.3		$	658.4		$	4,078.4

__________

(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 $129.5 million, $639.3 million and $434.2 million for the years ended December 31, 2009, 2008 and 2007, respectively.

(c) 2009 revisions are primarily due to higher product prices resulting in an expanded economic carbon dioxide project area. 2008 revisions are predominately due to lower product prices used to determine reserve volumes.  2007 revisions are associated with an expansion of the carbon dioxide flood project area for the SACROC unit.

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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 19, 2010

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 19, 2010
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 19, 2010
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 19, 2010
Gary L. Hultquist	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc.
/s/ C. BERDON LAWRENCE	Director of Kinder Morgan	February 19, 2010
C. Berdon Lawrence	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc.
/s/ PERRY M. WAUGHTAL	Director of Kinder Morgan	February 19, 2010
Perry M. Waughtal	Management, LLC, Delegate of
	Kinder Morgan G.P., Inc.
/s/ C. PARK SHAPER	Director and President of	February 19, 2010
C. Park Shaper	Kinder Morgan Management, LLC,
	Delegate of Kinder Morgan G.P., Inc.

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