Kinder Morgan, Inc. (KMI, NYSE)
Industry: Oil & Gas Midstream
Annual report, fiscal year 2009


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

Form 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 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: 1-06446



Kinder Morgan, Inc.

(Exact name of registrant as specified in its charter)

Kansas
(State or other jurisdiction of incorporation or organization)

48-0290000
(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:

None

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

None

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

Indicate by checkmark 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 [X] No [ ]

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 [ ] No [X]

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 [ ] 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. [X]



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

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

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

The number of shares outstanding of the registrant’s common stock, $0.01 par value, as of January 29, 2010 was 100 shares.



## KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS

PART I
Items 1. and 2. Business and Properties
(a) General Development of Business
Organizational Structure
Recent Developments
(b) Financial Information about Segments
(c) Narrative Description of Business
Business Strategy
Business Segments
Products Pipelines-KMP
Natural Gas Pipelines-KMP
CO₂-KMP
Terminals-KMP
Kinder Morgan Canada-KMP
NGPL PipeCo LLC
Power
Major Customers
Regulation
Environmental Matters
Other
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
General
Critical Accounting Policies and Estimates
New Basis of Accounting
Results of Operations
Income Taxes—Continuing Operations
Income Taxes—Realization of Deferred Tax Assets
Liquidity and Capital Resources
Cash Flows
Investment in Kinder Morgan Energy Partners
Noncontrolling Interests Distributions to Kinder Morgan Energy Partners'
Common Unit Holders
Recent Accounting Pronouncements
Information Regarding Forward-looking Statements
Quantitative and Qualitative Disclosures About Market Risk
Energy Commodity Market Risk
Interest Rate Risk
Foreign Currency Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure



Item 9A. Controls and Procedures 90
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures 90
Management's Report on Internal Control over Financial Reporting 90
Changes in Internal Control over Financial Reporting 91
Item 9B. Other Information 91

PART III

Item 10. Directors, Executive Officers and Corporate Governance 92
Directors and Executive Officers 92
Compensation Committee Interlocks and Insider Participation 94
Corporate Governance 94
Item 11. Executive Compensation 94
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 105

PART IV

Item 15. Exhibits, Financial Statement Schedules 106
Index to Financial Statements 109

Signatures 199

Note: Individual financial statements of the parent company are omitted pursuant to the provisions of Accounting Series Release No. 302.



## PART I

## Items 1 and 2. Business and Properties.

Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries, including Kinder Morgan Energy Partners, L.P. All dollars are United States dollars, except where stated otherwise. Canadian dollars are designated as C$. Unless otherwise indicated, all volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute and at 60 degrees Fahrenheit and, in most instances, are rounded to the nearest major multiple. In this report, the term “MMcf” means million cubic feet, the term “Bcf” means billion cubic feet, the term “MBbl/d” means million barrels per day, the term “Bbl” means barrels, the term “bpd” means barrels per day and the terms “Dth” (dekathems) and “MMBtu” mean million British Thermal Units (“Btu’s”). Natural gas liquids consist of ethane, propane, butane, iso-butane and natural gasoline.

You should read the following in conjunction with the accompanying audited Consolidated Financial Statements and related Notes. We have prepared the Consolidated Financial Statements under the rules and regulations of the United States Securities and Exchange Commission.

## (a) General Development of Business

## Organizational Structure

Kinder Morgan, Inc. (formerly Knight Inc.) is a large private pipeline transportation and storage company based in North America and incorporated in Kansas on May 18, 1927. We operate or own an interest in approximately 37,000 miles of pipelines and approximately 180 terminals. 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 “CO \( _{2} \) ,” for enhanced oil recovery projects in North America. We have both regulated and nonregulated operations. The address of our principal executive offices is 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.

Kinder Morgan Management, LLC, referred to in this report as “Kinder Morgan Management” is a publicly traded Delaware limited liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., of which we indirectly own all of the outstanding common equity, owns all of Kinder Morgan Management’s voting shares. Kinder Morgan Management, pursuant to a delegation of control agreement, has been delegated, to the fullest extent permitted under Delaware law, all of Kinder Morgan G.P., Inc.’s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. (“Kinder Morgan Energy Partners”), subject to Kinder Morgan G.P., Inc.’s right to approve certain transactions. Kinder Morgan Management also owns all of the i-units of Kinder Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy Partners’ limited partner interests that have been, and will be, issued only to Kinder Morgan Management. We have certain rights and obligations with respect to these securities.

Kinder Morgan Energy Partners is a publicly traded pipeline limited partnership whose limited partnership units are traded on the New York Stock Exchange under the ticker symbol “KMP.” Kinder Morgan Management’s shares (other than the voting shares held by Kinder Morgan G.P., Inc.) are traded on the New York Stock Exchange under the ticker symbol “KMR.”

The equity interests in Kinder Morgan Energy Partners and Kinder Morgan Management (which are both consolidated in our financial statements) owned by the public are reflected within “noncontrolling interests” on the accompanying Consolidated Balance Sheets. The earnings recorded by Kinder Morgan Energy Partners and Kinder Morgan Management that are attributed to their units and shares, respectively, held by the public are reported as “noncontrolling interests” in the accompanying Consolidated Statements of Operations.

On May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of Kinder Morgan Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal entity and subsequently renamed Knight Inc. On July 15, 2009, the Company’s name was changed back to Kinder Morgan, Inc. Kinder Morgan Holdco LLC is a private company owned by Richard D. Kinder, our Chairman and Chief Executive Officer; our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez Sarofim and Michael C. Morgan; other members of our senior management, most of whom are also senior officers of Kinder Morgan G.P., Inc. and Kinder Morgan Management and affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar Capital, (iii) The Carlyle Group and (iv) Riverstone Holdings LLC. This transaction is referred to in this report as “the Going Private transaction.” As a result of the Going Private transaction, we are now privately owned, our stock is no longer traded on the New York Stock Exchange and we have adopted a new basis of accounting for our assets and liabilities.

Additional information concerning the business of, and our investment in and obligations to, Kinder Morgan Energy Partners and Kinder Morgan Management is contained in Notes 2 and 10 of the accompanying Notes to Consolidated



Financial Statements and in Kinder Morgan Energy Partners' and Kinder Morgan Management's Annual Reports on Form 10-K for the year ended December 31, 2009.

## 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–KMP

On June 1, 2009, Kinder Morgan Energy Partners completed a phased horsepower expansion on its 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 United States (“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, Kinder Morgan Energy Partners began commercial transportation of blended biodiesel (a 2% blend commonly referred to as B2) on its 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 the Willbridge refined products terminal located in Portland, Oregon.

Subsequently, Kinder Morgan Energy Partners has undertaken additional renewable fuels projects at several of its West Coast refined products terminal locations, including improvements to allow for the blending of biodiesel at both the truck-loading rack at its Willbridge terminal and the barge-loading facilities at its 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, Kinder Morgan Energy Partners approved an approximately $15.8 million investment to install new infrastructure at its 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 Kinder Morgan Energy Partners' California refined products terminals began blending ethanol at 10% effective January 11, 2010; and

- As of December 31, 2009, Kinder Morgan Energy Partners completed modifications to its Central Florida Pipeline to more efficiently move gasoline and ultra-low sulfur diesel fuel within the terminal community at the Port of Tampa. Kinder Morgan Energy Partners modified its 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 the Central Florida pipeline system. Relatedly, in the fourth quarter of 2009, Kinder Morgan Energy Partners placed into service two new storage tanks at its 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.

## Natural Gas Pipelines–KMP

- On June 21, 2009, Kinder Morgan Energy Partners completed construction and fully placed into service its 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, Kinder Morgan Energy Partners completed construction and fully placed into service its 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 \( ^{(i)} \)  (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). The current estimate of total construction costs on the entire project, including expansions, is approximately 2.3 billion;

On June 29, 2009, Kinder Morgan Energy Partners commenced interim transportation service for up to 1.6 billion cubic feet per day of natural gas on the first 444 miles of its then 51%-owned Rockies Express-East pipeline segment. This segment extends from Audrain County, Missouri to the Lebanon Hub in Warren County, Ohio. On November 12, 2009, Kinder Morgan Energy Partners 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 Clarlington 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 Clarlington). 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, Kinder Morgan Energy Partners 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 Safety Administration issued a Corrective Action Order that incorporates the Return to Service Plan. Rockies Express-East has completed implementation of the majority of the requirements of the Return to Service Plan and the Corrective Action Order.

The 639-mile, Rockies Express-East pipeline segment is the third and final phase of 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 Kinder Morgan, Inc. and 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, Kinder Morgan Energy Partners' 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 the current estimate of total construction costs on the entire project, including expansions, is approximately $6.8 billion;

On September 30, 2009, the FERC issued authority to Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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 its Texas intrastate natural gas pipeline group;

On October 22, 2009, Kinder Morgan Energy Partners announced that it had received the Continuing Excellence Award for its 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, Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' existing natural gas gathering and transportation business located in the state of Texas;

- On November 13, 2009, Kinder Morgan Energy Partners and Copano Energy, L.L.C. announced that they 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. Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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 in the third quarter of 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. Kinder Morgan Energy Partners 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, it is estimated that the Fayetteville Express Pipeline project will cost approximately $1.2 billion to complete.

## CO_{2}-KMP

- In July 2009, Kinder Morgan Energy Partners announced that it would invest approximately $180 million over the next several years to further expand its 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 dioxide injections into the Katz field will commence shortly thereafter.

## Terminals–KMP

- In the second quarter of 2009, Kinder Morgan Energy Partners completed an approximately C$45.6 million expansion project at its Vancouver Wharves bulk marine terminal located in British Columbia, Canada. The project 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, Kinder Morgan Energy Partners acquired certain marine vessels from Megafleet Towing Co., Inc. for an aggregate consideration of $21.7 million. Kinder Morgan Energy Partners' 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 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, Kinder Morgan Energy Partners completed an approximately $12.8 million expansion at its 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, Kinder Morgan Energy Partners announced that it 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 its liquids terminal located in Carteret, New Jersey. The project is expected to be completed in the first quarter of 2011;

- In the fourth quarter of 2009, Kinder Morgan Energy Partners brought approximately 450,000 barrels of new liquids storage capacity into service at its 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, approximately 1.85 million barrels of combined liquids storage capacity at these two terminals was added; and

- Effective January 15, 2010, Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners announced the formation of a joint venture with USD to optimize and coordinate customer access to the three acquired terminals, other ethanol terminal assets already owned and operated by Kinder Morgan Energy Partners, 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 Kinder Morgan Energy Partners' 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 the Products Pipelines–KMP business segment) Kinder Morgan Energy Partners expects to handle in excess of 250,000 barrels of ethanol per day in 2010; and

- On March 5, 2010, Kinder Morgan Energy Partners acquired 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, Kinder Morgan Energy Partners 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.

Kinder Morgan Energy Partners' Debt and Equity Offerings, Swap Agreements and Debt Retirements

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

• On February 1, 2009, Kinder Morgan Energy Partners paid $250 million to retire the principal amount of 6.30% senior notes that matured on that date;

- In 2009, Kinder Morgan Energy Partners issued a combined 22,942,447 common units, described following. The net proceeds received from the issuance of these common units were used to reduce the borrowings under its bank credit facility:



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

On March 27, 2009, Kinder Morgan Energy Partners completed a public offering of 5,666,000 of its common units at a price of $46.95 per unit, less commissions and underwriting expenses;

On July 6, 2009, Kinder Morgan Energy Partners completed a public offering of 6,612,500 of its common units at a price of $51.50 per unit, less commissions and underwriting expenses; and

On December 4, 2009, Kinder Morgan Energy Partners completed a public offering of 5,175,000 of its common units at a price of $57.15 per unit, less commissions and underwriting expenses; and

- In 2009, Kinder Morgan Energy Partners completed two separate public offerings of senior notes, described following. The net proceeds received from the issuance of these notes were used to reduce the borrowings under its bank credit facility:

On May 14, 2009, Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners announced that it expects to declare cash distributions of $4.40 per unit for 2010, a 4.8% increase over its cash distributions of $4.20 per unit for 2009. Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners' assets is fee based and is not sensitive to commodity prices, theCO \( _{2} \) -KMP business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. Kinder Morgan Energy Partners hedges the majority of its crude oil production, but does have exposure to unhedged volumes, the majority of which are natural gas liquids volumes. For 2010, Kinder Morgan Energy Partners expects that every $1 change in the average WTI crude oil price per barrel will impact its CO \( _{2} \) -KMP segment's cash flows by approximately $6 million (or less than 0.2% of its combined business segments' anticipated earnings before depreciation, depletion and amortization expenses). This sensitivity to the average WTI price is very similar to what was experienced in 2009. Kinder Morgan Energy Partners' 2010 cash distribution expectations do not take into account any capital costs associated with financing any payment it may be required to make of reparations sought by shippers on its West Coast Products Pipelines' interstate pipelines. Any resolution of claims of shippers on Kinder Morgan Energy Partners West Coast Products Pipelines' interstate pipelines that requires it to pay reparations, absent other changes, could mean it may not generate sufficient cash from operations to cover its 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 we, as indirect owner of Kinder Morgan Energy Partners' general partner, may decide to forego part of our incentive distribution in order for Kinder Morgan Energy Partners to meet its 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—Noncontrolling Interests Distributions to Kinder Morgan Energy Partners' Common Unit Holders") generated since the inception in excess of cash distributions paid.

Also on that date, Kinder Morgan Energy Partners announced that for the year 2010, Kinder Morgan Energy Partners anticipates that (i) its 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) it will distribute approximately $1.35 billion to its limited partners and (iii) it will invest approximately $1.5 billion for its capital expansion program (including small acquisitions).

Kinder Morgan Energy Partners anticipates 2010 expansion investment will help drive earnings and cash flow growth in 2010 and beyond, and estimates that approximately $400 million of the equity required for its 2010 investment program will be funded by cash retained as a function of Kinder Morgan Management dividends. In 2009, Kinder



Morgan Energy Partners' capital expansion program was approximately $3.3 billion—including both sustaining and discretionary capital spending, equity contributions (net of distributions) to its equity investees, and acquisition cash expenditures.

## (b) Financial Information About Segments

For financial information on our seven reportable business segments, see Note 15 of the accompanying Notes to Consolidated Financial Statements.

## (c) Narrative Description of Business

## Business Strategy

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

- focusing on stable, fee-based energy transportation and storage assets that are 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 stockholder.

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 (primarily through Kinder Morgan Energy Partners) regularly consider and enter into discussions regarding potential acquisitions 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 seven reportable business segments, the first five of which are also business segments of Kinder Morgan Energy Partners. These segments are as follows:

- Products Pipelines–KMP—which consists of approximately 8,400 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;

- Natural Gas Pipelines–KMP—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;

-  \( CO_{2} \) —KMP—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–KMP—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;

- Kinder Morgan Canada–KMP—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;



- NGPL PipeCo LLC—consists of our 20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system, which we operate. Prior to February 15, 2008, we owned 100% of NGPL; and

• Power—consists of two natural gas-fired electric generation facilities.

## Products Pipeline–KMP

The Products Pipelines–KMP segment consists of Kinder Morgan Energy Partners’ refined petroleum products and natural gas liquids pipelines and associated terminals, Southeast terminals and transmix processing facilities.

## West Coast Products Pipelines

West Coast Products Pipelines operations include SFPP, L.P. operations (sometimes referred to in this report as Pacific operations), Calnev Pipeline operations and 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.

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, the 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, the SFPP pipeline system delivered approximately 1,122,600 barrels per day of refined petroleum products.

The Calnev Pipeline consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from Kinder Morgan Energy Partners' 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, the 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, the Calnev pipeline system delivered approximately 130,700 barrels per day of refined petroleum products.

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

The 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, the 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, the 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 transported, 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.

Supply. The majority of refined products supplied to the 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 the West Coast Products Pipelines operations' pipeline system are proprietary pipelines owned and operated by major oil companies in the area where the pipeline system delivers products and also refineries with terminals that have trucking arrangements within its market areas. Kinder Morgan Energy Partners believes 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 the 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. The West Coast Products Pipelines terminal operations compete with terminals owned by its 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. Kinder Morgan Energy Partners' cannot predict with any certainty whether the use of short haul trucking will decrease or increase in the future.

## Plantation Pipe Line Company

Kinder Morgan Energy Partners owns 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. Kinder Morgan Energy Partners operates 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

The 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 Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners' 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, the Central Florida pipeline system delivered approximately 106,700 barrels per day of refined petroleum products.

Kinder Morgan Energy Partners also owns and operates 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. Kinder Morgan Energy Partners distributes 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 Kinder Morgan Energy Partners' 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 the Central Florida pipeline system, the most significant competitors are trucking firms and marine transportation firms. Trucking transportation is more competitive in serving markets close to the marine terminals on the east and west coasts of Florida. Kinder Morgan Energy Partners is 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. Kinder Morgan Energy Partners believes it is unlikely that a new pipeline system comparable in size and scope to the 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 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

The 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.

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, L.P. 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

The Cypress pipeline is an interstate common carrier natural gas liquids pipeline originating at storage facilities in Mont Belvieu, Texas and extending 104 miles east to a connection with Westlake Chemical Corporation, a major petrochemical producer in the Lake Charles, Louisiana area. 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, Kinder Morgan Energy Partners 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 the Cypress Pipeline; however, it is expected that the transaction will 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

The 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 Kinder Morgan Energy Partners' subsidiary, Kinder Morgan Southeast Terminals LLC and its consolidated affiliate, Guilford County Terminal Company, LLC. Combined, the 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 the 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, the 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 predominantly from Plantation and Colonial pipelines with a number of terminals connected to both pipelines. To the maximum extent practicable, Kinder Morgan Energy Partners endeavors to connect its Southeast terminals to both of the Plantation and Colonial pipeline systems. In addition to pipeline supply, Kinder Morgan Energy Partners is also able to take marine receipts at both Kinder Morgan Energy Partners' 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, L.P. and TransMontaigne Product Services Inc. represent the other significant independent terminal operators in this region.

## Transmix Operations

The 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 transmix processing facilities, Kinder Morgan Energy Partners processes and separates pipeline transmix into pipeline-quality gasoline and light distillate products at six separate processing facilities located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina. Combined, 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 the East Coast transmix processing operations. The Mid-Continent area and the New York Harbor are the target markets for Kinder Morgan Energy Partners' Illinois and Pennsylvania assets, respectively. West Coast transmix processing operations support the markets served by Kinder Morgan Energy Partners' Pacific operations in Southern California.

Supply. Transmix generated by Plantation, Colonial, Explorer, Sun, Enterprise, and Kinder Morgan Energy Partners' Pacific operations provide the vast majority of the supply. These suppliers are committed to the use of the 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 Kinder Morgan Energy Partners' Pacific operations; Dorsey Junction is supplied by Colonial Pipeline Company; and Greensboro is supplied by the Plantation pipeline.



Competition. Placid Refining is Kinder Morgan Energy Partners' main competitor in the Gulf Coast area. There are various processors in the Mid-Continent area who compete with Kinder Morgan Energy Partners' transmix facilities, primarily ConocoPhillips, Gladieux Refining and Williams Energy Services. Motiva Enterprises' transmix facility located near Linden, New Jersey is the principal competition for New York Harbor transmix supply and for Kinder Morgan Energy Partners' Indianapolis facility. A number of smaller organizations operate transmix processing facilities in the western and southwestern United States. These operations compete for supply that is envisioned as the basis for growth in the west and southwest regions of the United States. Kinder Morgan Energy Partners' Colton processing facility also competes with major oil company refineries in California.

## Natural Gas Pipelines–KMP

The 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, Kinder Morgan Energy Partners owns 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. Kinder Morgan Energy Partners' 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

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

The two largest systems in the group are the Kinder Morgan Texas Pipeline and the 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.

Included in the operations of the Kinder Morgan Tejas system is the 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 Petroquímica 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.

The 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. The Mier-Monterrey Pipeline has entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for all of the pipeline’s capacity.

The 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.



The Texas intrastate natural gas pipeline group also owns and operates various gathering systems in southern and eastern Texas. These systems aggregate natural gas supplies into the Texas intrastate natural gas pipeline group's main transmission pipelines, and in certain cases, aggregate natural gas that must be processed or treated at its own or third-party facilities. The Texas intrastate natural gas pipeline group owns plants that can process up to 135 million cubic feet per day of natural gas for liquids extraction, and has contractual rights to process approximately 550 million cubic feet per day of natural gas at third-party owned facilities. The Texas intrastate natural gas pipeline group also shares in gas processing margins on gas processed at certain third-party owned facilities. Additionally, the Texas intrastate natural gas pipeline group owns and operates three natural gas treating plants that provide carbon dioxide and/or hydrogen sulfide removal. The Texas intrastate natural gas pipeline group can treat up to 85 million cubic feet per day of natural gas for carbon dioxide removal at its plant in Fandango Complex in Zapata County, Texas, 50 million cubic feet per day of natural gas at its Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic feet per day of natural gas at its Thompsonville Facility located in Jim Hogg County, Texas.

The 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. The Texas intrastate natural gas pipeline group has 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, the Texas intrastate natural gas pipeline group announced an expansion project that will significantly increase natural gas storage capacity at the 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.

The Texas intrastate natural gas pipeline group also owns the West Clear Lake natural gas storage facility located in Harris County, Texas, and it leases 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 the Texas intrastate natural gas pipeline group provides transportation service into and out of the facility. The Texas intrastate natural gas pipeline group leases 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 it can, at its 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. The Texas intrastate natural gas pipeline group leases 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, the Texas intrastate natural gas pipeline group contracts for storage services from third parties, which it then sells to customers on its pipeline system.

Additionally, effective November 1, 2009, the Texas intrastate natural gas pipeline group acquired a 40% equity ownership interest in Endeavor Gathering LLC, as discussed above in “—(a) General Development of Business—Recent Developments—Natural Gas Pipelines—KMP.”

Markets. Texas is one of the largest natural gas consuming states in the country. The natural gas demand profile in the 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, the Texas intrastate natural gas pipeline group has successfully attached many of these new generation facilities to its natural gas pipeline systems in order to maintain and grow its share of natural gas supply for power generation.

The Texas intrastate natural gas pipeline group serves the Mexico market through interconnection with the facilities of Pemex at the United States-Mexico border near Arguellas, Mexico and its 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. The Texas intrastate natural gas pipeline group primarily provides 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 its activities in Mexico are paid in U.S. dollar equivalent.

Supply. The Texas intrastate natural gas pipeline group purchases its natural gas directly from producers attached to its system in South Texas, East Texas, West Texas and along the Texas Gulf Coast. In addition, the Texas intrastate natural gas pipeline group also purchases gas at interconnects with third-party interstate and intrastate pipelines. While the Texas



intrastate natural gas 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. This 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. The Texas intrastate natural gas pipeline group competes 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.

Kinder Morgan Energy Partners' 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 the 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, Kinder Morgan Treating had approximately 200 treating and dew point control plants in operation.

Supply. Kinder Morgan Treating believes it has 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 the 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. Typically, a fixed monthly rental fee is charged, plus in those instances where Kinder Morgan Treating operates the equipment, a fixed monthly operating fee.

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 Kinder Morgan Treating believes that its treating business strategy is well suited to the producers in the Haynesville Shale.

Competition. These 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 similar plants and operations. Kinder Morgan Treating also faces competition from vendors of used equipment that occasionally operate plants for producers.

In addition, Kinder Morgan Treating may lose business to natural gas gatherers who have underutilized treating or processing capacity. It 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

The Western interstate natural gas pipeline group, which operates primarily along the Rocky Mountain region of the Western portion of the United States, consists of the following three natural gas pipeline systems: (i) Kinder Morgan Interstate Gas Transmission Pipeline, (ii) TransColorado Pipeline and (iii) Kinder Morgan Energy Partners' 50% ownership interest in the Rockies Express Pipeline.



## Kinder Morgan Interstate Gas Transmission LLC

Kinder Morgan Energy Partners' subsidiary, Kinder Morgan Interstate Gas Transmission LLC ("KMIGT") owns approximately 5,100 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska. The KMIGT pipeline system is powered by 28 transmission and storage compressor stations, which have 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 the 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.

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, with 68% 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

Kinder Morgan Energy Partners' 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 Pieceance 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.

## Rockies Express Pipeline

Kinder Morgan Energy Partners operates and currently owns 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. Kinder Morgan Energy Partners' ownership is through its 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. Kinder Morgan Energy Partners' investment in Rockies Express is accounted 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 the 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 system’s 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 NGPIL), Kansas (ANR Pipeline), and Missouri (Panhandle Eastern Pipeline), and through a connection with Kinder Morgan Energy Partners’ 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 Unita and Pieceance 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

The 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) the Trailblazer Pipeline, (ii) the Kinder Morgan Louisiana Pipeline, (iii) a 50% ownership interest in the Midcontinent Express Pipeline and (iv) a 50% ownership interest in the Fayetteville Express Pipeline.

## Trailblazer Pipeline Company LLC

Kinder Morgan Energy Partners' subsidiary, Trailblazer Pipeline Company LLC, ("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. We manage, maintain and operate the Trailblazer system for Kinder Morgan Energy Partners, for which we are 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

Kinder Morgan Energy Partners' 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.

Kinder Morgan Energy Partners 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

Kinder Morgan Energy Partners owns a 50% interest in Midcontinent Express Pipeline LLC, the sole owner of the approximate 500-mile Midcontinent Express natural gas pipeline system, and accounts for its 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.

## Fayetteville Express Pipeline LLC

Fayetteville Express Pipeline LLC is currently developing the Fayetteville Express natural gas pipeline system. Kinder Morgan Energy Partners owns a 50% interest in Fayetteville Express Pipeline LLC, and accounts for its 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

Kinder Morgan Energy Partners’ Natural Gas Pipelines’ upstream operations consists of the Casper and Douglas natural gas processing operations and a 49% ownership interest in the Red Cedar Gas Gathering Company.

## Casper and Douglas Natural Gas Processing Systems

Kinder Morgan Energy Partners owns and operates the 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 the KMIGT pipeline system. Natural gas liquids processed by the Casper plant are sold into local markets consisting primarily of retail propane dealers and oil refiners. Natural gas liquids processed by the 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 Corporation. 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 Kinder Morgan Energy Partners 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

Kinder Morgan Energy Partners owns a 49% equity interest in the Red Cedar Gathering Company (“Red Cedar”), 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.

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 Kinder Morgan Energy Partners' TransColorado pipeline system for transport to the Blanco, New Mexico-San Juan Basin Hub.

##  \( CO_{2} \) -KMP

The  \( CO_{2} \) -KMP segment consists of Kinder Morgan  \( CO_{2} \)  Company, L.P. and its consolidated affiliates, (“KMCO,”). Carbon dioxide is used in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. The carbon dioxide pipelines and related assets allow Kinder Morgan Energy Partners to market a complete package of carbon dioxide supply, transportation and technical expertise to the customer. The  \( CO_{2} \) -KMP business segment produces, transports and markets carbon dioxide for use in enhanced oil recovery operations. KMCO, also holds ownership interests in several oil-producing fields and owns a crude oil pipeline, all located in the Permian Basin region of West Texas.

## Oil Producing Activities

KMCO \( _{2} \)  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. Kinder Morgan Energy Partners has 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.

Kinder Morgan Energy Partners' 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. Kinder Morgan Energy Partners has been implementing its 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 the operations at SACROC, where carbon dioxide and water are used to drive oil to the producing wells, carbon dioxide is used 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.

Kinder Morgan Energy Partners also operates and owns 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. Kinder Morgan Energy Partners is presently evaluating operating and subsurface technical data from the Claytonville unit to further assess redevelopment opportunities including carbon dioxide flood operations.

Kinder Morgan Energy Partners also operates and owns 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, Kinder Morgan Energy Partners announced it would invest approximately $183 million over the next several years to further expand its operations in the eastern Permian Basin 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 dioxide injections into the Katz field will commence shortly thereafter.

See Note 20 of the accompanying Notes to Consolidated Financial Statements for additional information with respect to operating statistics and supplemental information on oil and gas producing activities.

## Gas and Gasoline Plant Interests

Kinder Morgan Energy Partners operates and owns an approximate 22% working interest plus an additional 28% net profits interest in the Snyder gasoline plant. It also operates and owns 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

Kinder Morgan Energy Partners owns 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.

Kinder Morgan Energy Partners also owns 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. The 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. Kinder Morgan Energy Partners is 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. The 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 Kinder Morgan Energy Partners' 50% ownership interest in Cortez Pipeline Company, it owns a 50% equity interest in, and operates, 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 Kinder Morgan Energy Partners' Central Basin pipeline and its Centerline pipeline (discussed following). The tariffs charged by Cortez Pipeline are not regulated.

The 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 McNamey, Texas. The pipeline has an ultimate throughput capacity of 700 million cubic feet per day. At its origination point in Denver City, the Central Basin pipeline interconnects with all three major carbon dioxide supply pipelines from Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO \( _{2} \) ) and the Bravo and Sheep Mountain pipelines (operated by Oxy Permian). Central Basin’s mainline terminates near McNamey, where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the Central Basin pipeline are not regulated.

Kinder Morgan Energy Partners’ 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.

Kinder Morgan Energy Partners owns 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, Kinder Morgan Energy Partners owns approximately 98% of the Canyon Reef Carriers pipeline and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline extends 139 miles from McNamey, 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 McNamey 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 Kinder Morgan Energy Partners’ 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. Kinder Morgan Energy Partners ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines. Kinder Morgan Energy Partners also competes 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

The 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 Kinder Morgan Energy Partners to better manage crude oil deliveries from its oil field interests in West Texas, and it has entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western's 120,000 barrel per day refinery in El Paso. The 20-inch pipeline segment transported approximately 117,000 barrels of oil per day in 2009 and approximately 118,000 barrels of oil per day in 2008. The Kinder Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad Commission.

## Terminals–KMP

The Terminals–KMP segment includes the operations of Kinder Morgan Energy Partners’ petroleum, chemical and other liquids terminal facilities (other than those included in its Products Pipelines segment) and all of its coal, petroleum coke, fertilizer, steel, ores and dry-bulk material services, including all transload, engineering, conveying and other in-plant services. Combined, the segment is composed of approximately 121 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

The 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, the 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.

Kinder Morgan Energy Partners' major liquids terminal assets include the following:

- the Houston, Texas terminal complex located in Pasadena and Galena Park, Texas, along the Houston Ship Channel. Recognized as a distribution hub for Houston’s refineries situated on or near the Houston Ship Channel, the Pasadena and Galena Park terminals are the western Gulf Coast refining community’s central interchange point. The complex has approximately 26.2 million barrels of capacity and is connected via pipeline to 14 refineries, four petrochemical plants and ten major outbound pipelines. Combined, the 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 Kinder Morgan Energy Partners’ acquisition of the terminal complex in January 2001, it has upgraded its 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 its fully automated truck loading rack located at its 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;

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. Kinder Morgan Energy Partners' 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 its acquisition of the terminal in January 2001, Kinder Morgan Energy Partners has 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, Kinder Morgan Energy Partners announced a major expansion to the facility, which will add over one million barrels of new liquids capacity for a large petroleum customer. Kinder Morgan Energy Partners expects the expansion to come on-line in the first quarter of 2011. Kinder Morgan Energy Partners' 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.

The 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 the acquisition of the terminal in July 2005, Kinder Morgan Energy Partners has 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;

- the 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

- the Kinder Morgan North 40 terminal, located near Edmonton, Alberta, Canada. Kinder Morgan Energy Partners constructed and placed into service its 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 Kinder Morgan Energy Partners' Trans Mountain pipeline system. The entire capacity of this terminal is contracted under long-term contracts.

Competition. Kinder Morgan Energy Partners is one of the largest independent operators of liquids terminals in North America. Kinder Morgan Energy Partners' primary competitors are IMTT, Magellan, Morgan Stanley, NuStar, Oil Tanking, Enterprise, and Vopak.

## Bulk Terminals

Kinder Morgan Energy Partners' bulk terminal operations primarily involve dry-bulk material handling services; however, it also provides 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, Kinder Morgan Energy Partners' 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. Kinder Morgan Energy Partners owns or operates approximately 95 dry-bulk terminals in the United States, Canada and the Netherlands.

Kinder Morgan Energy Partners' major bulk terminal assets include the following:

- the Vancouver Wharves bulk marine terminal, located at the entrance to the Port of Vancouver, British Columbia, Canada. Kinder Morgan Energy Partners owns certain bulk terminal buildings and equipment and operates 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, Kinder Morgan Energy Partners 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;

- approximately 32 petroleum coke or coal terminals Kinder Morgan Energy Partners operates or owns. Kinder Morgan Energy Partners is the largest independent handler of petroleum coke in the U.S., in terms of volume, and in 2009, it 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 handled is imported from or exported to foreign markets. Most of Kinder Morgan Energy Partners' customers are large integrated oil companies that choose to outsource the storage and loading of petroleum coke for a fee. All of Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners 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 translated through Kinder Morgan Energy Partners' coal terminals is destined for use in coal-fired electric generation facilities. Kinder Morgan Energy Partners' 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, 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.

The 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. The 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.

The 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, Kinder Morgan Energy Partners anticipates 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;

Kinder Morgan Energy Partners’ approximately 47 ferro alloys terminals located at strategic locations throughout the United States, which translated and handle steel, ferro chrome, ferro manganese, ferro silicon, silicon metal and many other alloys and ores. Kinder Morgan Energy Partners’ value-added services include canning, drumming, bagging and filling boxes and supersacks, and is 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 the metal handling terminals are affected by a number of business-specific factors, the primary drivers for Kinder Morgan Energy Partners’ 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 done at the Vancouver Wharves bulk marine terminal, Kinder Morgan Energy Partners handles numerous types of steel and bulk commodities at two deepwater port facilities, the Chesapeake bulk terminal facility, located on Chesapeake Bay in Sparrows Point, Maryland, and the Berkley facility, located in Huger, South Carolina. The 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. The Berkley facility provides dedicated storage to Nucor Corporation (a large domestic steel company with significant operations in the Southeast region of the U.S.) 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.

The 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.

Kinder Morgan Energy Partners’ river steel facilities include facilities on the Mississippi, Ohio, Tennessee, Missouri, and Arkansas rivers, and on other smaller inland waterways. The 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. Kinder Morgan Energy Partners’ 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. The 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, Kinder Morgan Energy Partners 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 the asset purchase, Kinder Morgan Energy Partners entered into a service contract with Nucor. It is estimated that



approximately 95% of the projected revenues and profits of these five facilities will be generated from this contract with Nucor; and

- the 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. The 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. Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners' bulk terminals were constructed pursuant to long-term contracts for specific customers. As a result, Kinder Morgan Energy Partners believes other terminal operators would face a significant disadvantage in competing for this business.

## Materials Services (rail transloading)

Kinder Morgan Energy Partners' 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. Kinder Morgan Energy Partners also designs and builds transloading facilities, performs inventory management services, and provides value-added services such as blending, heating and sparging. In 2009 and 2008, Kinder Morgan Energy Partners' materials services operations handled approximately 227,000 and 348,000 railcars, respectively.

Competition. Kinder Morgan Energy Partners' 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–KMP

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

## Trans Mountain Pipeline System

The 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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners. 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. In 2009 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 Kinder Morgan Energy Partners' 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 of Kinder Morgan Energy Partners’ petroleum pipelines, competes against other pipeline companies who could be in a position to offer different tolling structures.

## Express and Jet Fuel Pipeline Systems

Kinder Morgan Energy Partners owns a one-third ownership interest in the Express pipeline system and 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. Kinder Morgan Energy Partners operates the Express pipeline system and accounts for its 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 U.S. Rocky Mountain area 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.

Kinder Morgan Energy Partners also owns and operates 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 the Jet Fuel pipeline system. In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in the Port of Vancouver, the 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.



## NGPL PipeCo LLC ("NGPL")

In February 2008, we completed the sale of an 80% ownership interest in NGPL PipeCo LLC for approximately $5.9 billion. We account for our 20% ownership interest as an equity method investment. We continue to operate NGPL's assets pursuant to a 15-year operating agreement. NGPL owns and operates approximately 9,200 miles of interstate natural gas pipelines, storage fields, field system lines and related facilities, consisting primarily of two major interconnected natural gas transmission pipelines terminating in the Chicago, Illinois metropolitan area. NGPL's Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 4,400 miles of mainline and various small-diameter pipelines. Its other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,100 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by NGPL's approximately 800-mile Amarillo/Gulf Coast pipeline. NGPL's system has 813 points of interconnection with 34 interstate pipelines, 34 intrastate pipelines, 38 local distribution companies, 32 end users including power plants and a number of gas producers, thereby providing significant flexibility in the receipt and delivery of natural gas.

NGPL is one of the nation’s largest natural gas storage operators with approximately 600 billion cubic feet of total natural gas storage capacity, approximately 258 billion cubic feet of working gas capacity and over 4.3 billion cubic feet per day of peak deliverability from its storage facilities, which are located in major supply areas and near the markets it serves. NGPL owns and operates 13 underground storage reservoirs in eight field locations in four states. These storage assets complement its pipeline facilities and allow it to optimize pipeline deliveries and meet peak delivery requirements in its principal markets.

Competition. NGPL competes with other transporters of natural gas in virtually all of the markets it serves and, in particular, in the Chicago area, which is the northern terminus of NGPL's two major pipeline segments and its largest market. These competitors include both interstate and intrastate natural gas pipelines that transport U.S. produced natural gas along with the Alliance Pipeline, which transports Canada-produced natural gas, into the Chicago area. The Vector Pipeline provides the ability to transport Chicago area natural gas supplies to additional markets that are farther north and farther east. The overall impact of the considerable pipeline capacity into the Chicago area, combined with limited take-away capacity and the demand in the area creates a situation that is competitive and dynamic with respect to the impact on individual transporters such as NGPL. From time to time, other pipelines are proposed that would compete with NGPL. We cannot predict whether or when any such pipeline might be built, nor its impact on NGPL's operations or profitability.

NGPL Section 5 Proceeding. On November 19, 2009, NGPL was notified by the FERC of a proceeding against it pursuant to section 5 of the Natural Gas Act (the "Order"). The proceeding will set the matter for hearing and determine whether NGPL's current rates, which were approved by the FERC in NGPL's last rate case settlement, remain just and reasonable. The FERC made no findings in its Order as to what would constitute just and reasonable rates or a reasonable return for NGPL. A proceeding under section 5 of the Natural Gas Act is prospective in nature. A change in rates charged customers by NGPL would likely occur only after the FERC has issued a final order. According to the procedural schedule adopted in the case, an initial Administrative Law Judge decision is due by November 15, 2010. The final FERC decision will be based on the record developed before the Administrative Law Judge.

## Power

In January 2008, we sold our interests in three natural gas-fired power plants in Colorado. Our remaining Power operations consist of (i) an ownership interest in and operations of a 550-megawatt natural gas-fired electricity generation facility in Michigan (“Triton Power”) and (ii) operating and maintaining a 105-megawatt natural gas-fired power plant in Snyder, Texas, under a cost reimbursement agreement with the CO \( _{2} \) -KMP business segment. During 2009, most of Power’s revenues represented operating revenues from Triton Power.

Upon the adoption of Accounting Standards Update No. 2009-17, which amended the codification’s “Consolidation” topic, on January 1, 2010, Triton Power operations will no longer be consolidated into our financial statements, but be treated as an equity investment, resulting in decreases to revenues, operating expenses and noncontrolling interests with no impact to net income attributable to Kinder Morgan, Inc. See Note 18 of the accompanying Notes to Consolidated Financial Statements for “Recent Accounting Pronouncements.”

Our Michigan facility competes with other commercial wholesale generators interconnected to the Midwest Independent System Operator grid. The principal impact of this competition on our Michigan facility is the level of dispatch of the plant and the related, but minor, effect on profitability.

## Major Customers

Our total revenues are derived from a wide customer base. For each of the years ended December 31, 2009 and 2008, and seven months ended December 31, 2007 and five months ended May 31, 2007, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. Kinder Morgan Energy Partners' 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, the  \( CO_{2} \) -KMP business segment also sells natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines–KMP,  \( CO_{2} \) -KMP and NGPL (from January 1, 2007 to February 14, 2008) business segments for the year ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 accounted for 44.8%, 63.7%, 56.7% and 58.4%, respectively, of our total consolidated revenues.

As a result of Kinder Morgan Energy Partners’ 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 a fee is charged to transport gas owned by others. To the extent possible, Kinder Morgan Energy Partners’ attempts to balance the pricing and timing of its natural gas purchases to its natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

## Regulation

## Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation – U.S. Operations

Some of our U.S. refined petroleum products and crude oil pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC 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 Kinder Morgan Energy Partners charged for transportation service on its 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 Kinder Morgan Energy Partners’ 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 of the accompanying Notes to Consolidated Financial Statements.

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 Kinder Morgan Energy Partners’ crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of Canada’s National Energy Board (“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, Kinder Morgan Energy Partners’ 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 its 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.

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 Kinder Morgan Energy Partners charges shippers on its 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

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-conduct 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 Kinder Morgan Energy Partners' Pacific operations pipelines in California are subject to regulation by the California Public Utilities Commission ("CPUC"), under a "depreciated book plant" methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by Kinder Morgan Energy Partners with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the 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 Kinder Morgan Energy Partners' FERC regulated rates could also arise with respect to its intrastate rates. Certain of the Pacific operations' pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 16 of the accompanying Notes to Consolidated Financial Statements.

## Texas Railroad Commission Rate Regulation

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

## Safety Regulation

Our interstate pipelines are subject to regulation by the United States Department of Transportation (“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 (“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 $86.3 million as of December 31, 2009. Our reserve estimates range in value from approximately $86.3 million to approximately $143.7 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 16 of the accompanying Notes to Consolidated Financial Statements.

## 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 (“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 (“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 Kinder Morgan Energy Partners’ MeElmo 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 the Natural Gas Pipelines–KMP 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 U.S. EPA regulatory initiatives could stimulate demand for natural gas by increasing the relative cost of fuels such as coal and oil. In addition, we anticipate that greenhouse gas regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery operations within the  \( CO_{2} \) -KMP 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 (“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

We employed 7,931 full-time people at December 31, 2009, including employees of our indirect subsidiary KMGP Services Company, Inc., who are dedicated to the operations of Kinder Morgan Energy Partners, and employees of Kinder Morgan Canada Inc. 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. We, KMGP Services Company, Inc., and Kinder Morgan Canada Inc. each consider relations with our employees to be good. For more information on our related party transactions, see Note 11 of the accompanying Notes to Consolidated Financial Statements.

KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, a subsidiary of Kinder Morgan Management, provides centralized payroll and employee benefits services to Kinder Morgan Management, Kinder Morgan Energy Partners and Kinder Morgan Energy Partners' operating partnerships and subsidiaries (collectively, "the Group"). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of 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 their allocated shares of these direct costs. No profit or margin is charged by Kinder Morgan Services LLC to the members of the Group. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, 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 its limited



partnership agreement, Kinder Morgan Energy Partners provides reimbursement for its share of these administrative costs and such reimbursements are accounted for as described above. Kinder Morgan Energy Partners reimburses Kinder Morgan Management with respect to the costs incurred or allocated to Kinder Morgan Management in accordance with Kinder Morgan Energy Partners' limited partnership agreement, the Delegation of Control Agreement among Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy Partners and others, and Kinder Morgan Management's limited liability company agreement.

Our named executive officers and other employees that provide management or services to both us and the Group are employed by us. Additionally, other of our employees assist Kinder Morgan Energy Partners in the operation of its Natural Gas Pipeline assets. These employees' expenses are allocated without a profit component between us and the appropriate members of the Group.

We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens on the assets of Kinder Morgan, Inc. and its subsidiaries (excluding Kinder Morgan Energy Partners and its subsidiaries) incurred in connection with the financing of the Going Private transaction, liens for current taxes, liens incident to minor encumbrances, and easements and restrictions that do not materially detract from the value of such property or the interests in those properties or the use of such properties in our businesses. We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people's land for a period of time. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of 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 of the accompanying Notes to Consolidated Financial Statements.

## (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.

## Risks Related to Our Business

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

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



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

Pending Federal Energy Regulatory Commission (“FERC”) and California Public Utilities Commission proceedings seek substantial refunds and reductions in tariff rates on some of Kinder Morgan Energy Partners’ pipelines. An additional FERC proceeding to determine whether current rates are just and reasonable is pending against NGPL. If the proceedings are determined adversely to Kinder Morgan Energy Partners or NGPL, 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 Kinder Morgan Energy Partners' pipelines have filed complaints with the FERC and CPUC that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates on Kinder Morgan Energy Partners' Pacific operations' pipeline system. The FERC has also notified NGPL of a proceeding against it to determine whether NGPL's current rates remain just and reasonable. We may face challenges, similar to those described in Notes 16 and 17 of the accompanying Notes to Consolidated Financial Statements, 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 may also 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.

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 endangering 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 Kinder Morgan Energy Partners' McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.

Because our operations, including our compressor stations and natural gas processing plants in the Natural Gas Pipelines–KMP and NGPL segments, emit various types of greenhouse gases, primarily methane and carbon dioxide, such new legislation or regulation could increase our costs related to operating and maintaining our facilities and require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, they could be significant. 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.

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

Kinder Morgan Energy Partners currently has 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.

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

The revenues, profitability and future growth of the CO \( _{2} \) -KMP business segment and the carrying value of its oil, natural gas liquids and natural gas properties depend to a large degree on prevailing oil and gas prices. 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 Kinder Morgan Energy Partners' proved reserves. In the event prices fall substantially, Kinder Morgan Energy Partners may not be able to realize a profit from its 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.

Whether Kinder Morgan Energy Partners has the power of eminent domain for its 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. Kinder Morgan Energy Partners' interstate natural gas pipelines have federal eminent domain authority. In either case, Kinder Morgan Energy Partners must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect Kinder Morgan Energy Partners' business if it were to lose the right to use or occupy the property on which its 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 outstanding $13.6 billion of consolidated debt (excluding the fair value of interest rate swaps). Of this amount, $10.6 billion was debt of Kinder Morgan Energy Partners and its subsidiaries, and the remaining $3.0 billion was debt of Kinder Morgan, Inc. and its subsidiaries, other than Kinder Morgan Energy Partners and its subsidiaries. Kinder Morgan, Inc.'s debt is currently secured by most of the assets of Kinder Morgan, Inc. and its subsidiaries, but the security interest does not apply to the assets of Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, Kinder Morgan Management and their respective subsidiaries. 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, we had outstanding $13.6 billion of consolidated debt (excluding the fair value of interest rate swaps). Of this amount, approximately 48% 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, primarily at Kinder Morgan Energy Partners, require regular access to the capital markets. If current levels of market volatility continue or worsen, our access to capital markets, primarily at Kinder Morgan Energy Partners, could be disrupted making growth through acquisitions and development projects, primarily at Kinder Morgan Energy Partners, 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, primarily Kinder Morgan Energy Partners, 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 the  \( CO_{2} \) –KMP 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.

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 Kinder Morgan Energy Partners' short-term credit ratings by Standard & Poor's Rating Services, it is currently unable to access commercial paper borrowings and instead is meeting its short-term financing and liquidity needs through borrowings under its bank credit facility. The negative impact of these events may have a material adverse effect on Kinder Morgan Energy Partners resulting from, but not limited to, an inability to expand facilities or finance the acquisition of assets on favorable terms, if at all, increased financing costs or financing with increasingly restrictive covenants.

The Going Private transaction resulted in substantially more debt to us and a downgrade of the ratings of our debt securities, which has increased our cost of capital.

In connection with the Going Private transaction, Standard & Poor’s Rating Services and Moody’s Investors Service, Inc. downgraded the ratings assigned to Kinder Morgan, Inc.’s senior unsecured debt to BB- and Ba2, respectively. Upon the February 2008 80% ownership interest sale of our NGPL PipeCo LLC business segment, which resulted in Kinder Morgan, Inc.’s repayment of a substantial amount of debt; Standard & Poor’s Rating Services and Moody’s Investors Service, Inc. upgraded Kinder Morgan, Inc.’s senior unsecured debt to BB and Ba1, respectively. However, these ratings are still below investment grade. Since the Going Private transaction, Kinder Morgan, Inc. has not had access to the commercial paper market and is currently utilizing its $1.0 billion revolving credit facility for its short-term borrowing needs.

The future success of Kinder Morgan Energy Partners' oil and gas development and production operations depends in part upon its 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 the  \( CO_{2} \) -KMP business segment will decline. Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners does not realize production volumes greater than, or equal to, its hedged volumes, Kinder Morgan Energy Partners may suffer financial losses not offset by physical transactions.

Competition could ultimately lead to lower levels of profits and adversely impact our ability to reconstruct 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 reconstruct for expiring transportation capacity at favorable rates or to maintain existing customers could be impaired. In addition, our products pipelines compete against proprietary pipelines owned and operated by major oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars. Throughput on our products pipelines may decline if the rates we charge become uncompetitive compared to alternatives.

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

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



Changes in the business environment, such as a decline in crude oil or natural gas prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply such as from the Alberta oil sands. In addition, with respect to the  \( CO_{2} \) -KMP business segment, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil. Each of these factors impact our customers shipping through our pipelines, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts.

Throughput on our 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 the Kinder Morgan Canada–KMP 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 stockholder’s equity 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 on our business, financial condition and results of operations.

There is the potential for a change of control of the general partner of Kinder Morgan Energy Partners if we default on debt.

We own all of the common equity of Kinder Morgan G.P., Inc., the general partner of Kinder Morgan Energy Partners. If we default on our debt, in exercising their rights as lenders, our lenders could acquire control of Kinder Morgan G.P., Inc. or otherwise influence Kinder Morgan G.P., Inc. through their control of us. While our operations provide cash independent of the dividends we receive from Kinder Morgan G.P., Inc., a change in control could materially affect our cash flow and results of operations.

Kinder Morgan Energy Partners’ tax treatment depends on its status as a partnership for United States federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat Kinder Morgan Energy Partners as a corporation for United States federal income tax purposes or it was to become subject to a material amount of entity-level taxation for state tax purposes, then its cash available for distribution to its partners, including us, would be substantially reduced.

The anticipated after-tax economic benefit of an investment in Kinder Morgan Energy Partners depends largely on it being treated as a partnership for United States federal income tax purposes. In order for Kinder Morgan Energy Partners to be treated as a partnership for United States federal income tax purposes, current law requires that 90% or more of its gross income for every taxable year consist of “qualifying income,” as defined in Section 7704 of the Internal Revenue Code. Kinder Morgan Energy Partners may not meet this requirement or current law may change so as to cause, in either event, it to be treated as a corporation for United States federal income tax purposes or otherwise subject it to taxation as an entity.



Kinder Morgan Energy Partners has not requested, and does not plan to request, a ruling from the Internal Revenue Service, or the IRS, on this or any other matter affecting it.

If Kinder Morgan Energy Partners were treated as a corporation for United States federal income tax purposes, it would pay United States federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income tax at varying rates. Distributions by Kinder Morgan Energy Partners would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to its partners, including us. Because a tax would be imposed on Kinder Morgan Energy Partners as a corporation, the cash available for distribution would be substantially reduced. Therefore, treatment of Kinder Morgan Energy Partners as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to its partners, including us, likely causing a substantial reduction in the value of our investment in Kinder Morgan Energy Partners.

Current law or Kinder Morgan Energy Partners’ business may change so as to cause it to be treated as a corporation for United States federal income tax purposes or otherwise subject it 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, Kinder Morgan Energy Partners is now subject to an entity-level tax on the portion of its total revenue that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of Kinder Morgan Energy Partners’ total revenue that is apportioned to Texas. This tax reduces, and the imposition of such a tax on Kinder Morgan Energy Partners by any other state will reduce, the cash available for distribution by Kinder Morgan Energy Partners to its partners, including us.

Kinder Morgan Energy Partners’ partnership agreement provides that if a law is enacted that subjects it to taxation as a corporation or otherwise subjects it to entity-level taxation for United States federal income tax purposes, the minimum quarterly distribution and the target distribution levels will be adjusted to reflect the impact on it of that law.

The tax treatment of publicly traded partnerships or an investment, including that of the general partner, in Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners, or an investment in it, 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 Kinder Morgan Energy Partners to be treated as a partnership for United States federal income tax purposes, affect or cause Kinder Morgan Energy Partners to change its business activities, affect the tax considerations of an investment in it, change the character or treatment of portions of its income and adversely affect an investment, including that of the general partner, in Kinder Morgan Energy Partners. 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 Kinder Morgan Energy Partners’ tax treatment as a partnership, it is 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, including that of the general partner, in Kinder Morgan Energy Partners.

If the IRS contests the United States federal income tax positions Kinder Morgan Energy Partners takes, the market for its units may be adversely impacted and the cost of any IRS contest will reduce its cash available for distribution to its partners.

Kinder Morgan Energy Partners has not requested a ruling from the IRS with respect to its treatment as a partnership for United States federal income tax purposes or any other matter affecting it. The IRS may adopt positions that differ from the conclusions of its counsel or from the positions it takes. It may be necessary to resort to administrative or court proceedings to sustain some or all of conclusions or the positions taken by Kinder Morgan Energy Partners. A court may not agree with some or all of such conclusions or the positions taken by Kinder Morgan Energy Partners’ counsel. Any contest with the IRS may materially and adversely impact the market for Kinder Morgan Energy Partners’ units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by the partners of Kinder Morgan Energy Partners because the costs will reduce the cash available for distribution.

## Item 1B. Unresolved Staff Comments.

None.



## Item 3. Legal Proceedings.

See Note 16 of the accompanying Notes to Consolidated Financial Statements.

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

None.



## PART II

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

As a result of the Going Private transaction, our common stock ceased trading on May 30, 2007. Prior to the Going Private transaction, our common stock was listed for trading on the New York Stock Exchange under the symbol “KMI.”

On February 17, 2009, May 18, 2009, August 17, 2009 and November 16, 2009, we paid cash dividends on our common stock of $50.0 million, $100.0 million, $150.0 million and $350.0 million, respectively, to our sole stockholder, which then made dividends to Kinder Morgan Holdco LLC. Our Board of Directors declared a dividend of $150.0 million on January 20, 2010 that was paid on February 16, 2010.

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.” Also see Note 12 of the accompanying Notes to Consolidated Financial Statements “Commitments and Contingent Liabilities-Share-based Compensation.”

## Item 6. Selected Financial Data

Five-Year Review
Kinder Morgan, Inc. and Subsidiaries

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="3">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td>Seven Months Ended December 31,</td><td>Five Months Ended May 31,</td><td colspan="2">Year Ended December 31,</td></tr><tr><td>Income and Cash Flow Data</td><td>2009(a)(b)</td><td>2008(a)(b)</td><td>2007(a)(b)</td><td>2007(b)(c)</td><td>2006(b)(c)</td><td>2005(c)</td></tr><tr><td>Revenues</td><td>$ 7,185.2</td><td>$ 12,094.8</td><td>$ 6,394.7</td><td>$ 4,165.1</td><td>$ 10,208.6</td><td>$ 1,025.6</td></tr><tr><td>Operating income (loss) (d)(e)</td><td>$ 1,407.2</td><td>$ (2,472.1)</td><td>$ 1,042.8</td><td>$ 204.8</td><td>$ 1,745.2</td><td>$ 381.3</td></tr><tr><td>Earnings from equity investments</td><td>$ 221.9</td><td>$ 201.1</td><td>$ 56.8</td><td>$ 40.7</td><td>$ 104.2</td><td>$ 620.7</td></tr><tr><td>Income (loss) from continuing operations</td><td>$ 773.8</td><td>$ (3,202.3)</td><td>$ 286.1</td><td>$ (142.0)</td><td>$ 974.6</td><td>$ 564.7</td></tr><tr><td>Income (loss) from discontinued operations, net of tax (f)</td><td>$ 0.3</td><td>$ (0.9)</td><td>$ (1.5)</td><td>$ 298.6</td><td>$ (528.5)</td><td>$ 40.4</td></tr><tr><td>Net income (loss)</td><td>$ 774.1</td><td>$ (3,203.2)</td><td>$ 284.6</td><td>$ 156.6</td><td>$ 446.1</td><td>$ 605.1</td></tr><tr><td>Net income attributable to noncontrolling interests (g)</td><td>$ 278.1</td><td>$ 396.1</td><td>$ 37.6</td><td>$ 90.7</td><td>$ 374.2</td><td>$ 50.5</td></tr><tr><td>Net income (loss) attributable to Kinder Morgan, Inc.’s stockholder</td><td>$ 496.0</td><td>$ (3,599.3)</td><td>$ 247.0</td><td>$ 65.9</td><td>$ 71.9</td><td>$ 554.6</td></tr><tr><td>Capital expenditures (h)</td><td>$ 1,324.3</td><td>$ 2,545.3</td><td>$ 1,287.0</td><td>$ 652.8</td><td>$ 1,375.6</td><td>$ 134.1</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="3">Predecessor Company</td></tr><tr><td colspan="3">As of December 31,</td><td colspan="3">As of December 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007(a)</td><td>2006(b)</td><td>2005(c)</td><td></td></tr><tr><td></td><td colspan="3">(In millions)</td><td colspan="3">(In millions)</td></tr><tr><td>Balance Sheet Data</td><td colspan="3">(In millions)</td><td colspan="3">(In millions</td></tr><tr><td>Net property, plant and equipment</td><td>$ 16,803.5</td><td>$ 16,109.8</td><td>$ 14,803.9</td><td>$ 18,839.6</td><td>$ 9,545.6</td><td></td></tr><tr><td>Total assets</td><td>$ 27,586.3</td><td>$ 25,444.9</td><td>$ 36,101.0</td><td>$ 26,795.6</td><td>$ 17,451.6</td><td></td></tr><tr><td>Long-term debt(i)</td><td>$ 12,879.7</td><td>$ 11,155.8</td><td>$ 15,097.7</td><td>$ 11,014.4</td><td>$ 6,677.6</td><td></td></tr></table>

(a) Includes significant impacts resulting from the Going Private transaction. See Note 2 of the accompanying Notes to Consolidated Financial Statements for additional information.

(b) Effective January 1, 2006, the accounts, balances and results of operations of Kinder Morgan Energy Partners were consolidated into our financial statements and we ceased applying the equity method of accounting for our investments in Kinder Morgan Energy Partners. See Note 2 of the accompanying Notes to Consolidated Financial Statements.

(c) Reflects the acquisition of Terasen Inc. on November 30, 2005.

(d) Includes non-cash goodwill charges of $4,033.3 million in the year ended December 31, 2008.

(e) Includes a goodwill impairment charge of $377.1 million in the five months ended May 31, 2007 relating to Kinder Morgan Energy Partners' acquisition of Trans Mountain pipeline from us on April 30, 2007. See Note 7 of the accompanying Notes to Consolidated Financial Statements.

(f) Includes a goodwill impairment charge of $650.5 million in 2006 to reduce the carrying value of Terasen Inc.

(g) Includes application of new accounting policies for noncontrolling interests adopted in 2009 and applied to all years presented. See Note 2 of the accompanying Notes to Consolidated Financial Statements.

(h) Capital expenditures shown are for continuing operations only.

(i) Excludes value of interest rate swaps. Increases to long-term debt for value of interest rate swaps totaled $361.0 million, $971.0 million, $199.7 million, $46.4 million and $51.8 million as of December 31, 2009, 2008, 2007, 2006 and 2005, respectively.



## 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 the accompanying Consolidated Financial Statements and related Notes. 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.” In as much 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, through our direct ownership and operation of energy related assets and through our ownership interests in and operation of Kinder Morgan Energy Partners, 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 shareholder.

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 segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.

Our reportable business segments are:

Products Pipelines–KMP: 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–KMP: 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;

 \( CO_{2} \) –KMP: (i) the production, transportation and marketing of carbon dioxide, referred to as  \( CO_{2} \) , to oil fields that use  \( CO_{2} \)  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–KMP: 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;

Kinder Morgan Canada–KMP: (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;

NGPPL PipeCo LLC—consists of our 20% interest in NGPPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPPL, a major interstate natural gas pipeline and storage system, which we operate. Prior to February 15, 2008, we owned 100% of NGPPL; and

Power—which consists of two natural gas-fired electric generation facilities.

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 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.

The  \( CO_{2} \) -KMP business segment sales and transportation business, like the natural gas pipelines business, generally has take-or-pay contracts, although the contracts in the  \( CO_{2} \) -KMP business segment typically have minimum volume requirements. In the long term, the 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 the  \( CO_{2} \) -KMP 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.

In our discussions of the operating results of individual businesses that 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. Principally through Kinder Morgan Energy Partners, we have a history of making accretive acquisitions and economically advantageous expansions of existing businesses. Our ability to increase earnings and Kinder Morgan Energy Partners' ability to increase distributions to us and other investors will, to some extent, be a function of Kinder Morgan Energy Partners' success in acquisitions and expansions. Kinder Morgan Energy Partners continues to have opportunities for expansion of its facilities in many markets and expects to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict.

Kinder Morgan Energy Partners' ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates and, to some extent, its ability to raise necessary capital to fund such acquisitions, factors over which it has limited or no control. Thus, it has no way to determine the number or size of accretive acquisition candidates, in the future, or whether it 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 of the accompanying Notes to Consolidated Financial Statements. We believe that certain accounting policies are of more significance in the consolidated financial statement preparation process than others, which policies are discussed as follows.

## Environmental Matters

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

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

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

## 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 Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners' 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 of the accompanying Notes to Consolidated Financial Statements.



## 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).

In conjunction with our annual impairment test of the carrying value of goodwill, performed as of May 31, 2008, we determined that the fair value of certain reporting units that are part of our investment in Kinder Morgan Energy Partners were less than the carrying values. 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 a market multiple for the individual assets). The implied fair value of goodwill within each reporting unit was then compared to the carrying value of goodwill of each such unit, resulting in the following goodwill impairments by reporting unit: Products Pipelines–KMP (excluding associated terminals) $1.20 billion, Products Pipelines Terminals–KMP (separate from Products Pipelines–KMP for goodwill impairment purposes)—$70 million, Natural Gas Pipelines–KMP—$2.09 billion, and Terminals–KMP $677 million, for a total impairment of $4.03 billion. The goodwill impairment was a non-cash charge and did not have any impact on our cash flow. We have determined that our goodwill was not impaired as of May 31, 2009.

As of December 31, 2009 and 2008, our goodwill was $4,744.3 million and $4,698.7 million, respectively. Included in these goodwill balances are $236.0 million and $203.6 million as of December 31, 2009 and 2008, respectively, related to the Trans Mountain pipeline, which we sold to Kinder Morgan Energy Partners on April 30, 2007. This sale transaction caused us to reconsider the fair value of the Trans Mountain pipeline system in relation to its carrying value, and to make a determination as to whether the associated goodwill was impaired. As a result of our analysis, we recorded a goodwill impairment charge of $377.1 million to the accompanying Statement of Operations for the five months ended May 31, 2007.

Our remaining intangible assets, excluding goodwill, include customer relationships, contracts and agreements, technology-based assets, lease value and other long-term 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 the accompanying Consolidated Balance Sheets. As of December 31, 2009 and 2008, these intangibles totaled $259.8 million and $251.5 million, respectively

For more information on our goodwill and intangibles, see Notes 2 and 7 of the accompanying Notes to Consolidated Financial Statements.

## 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 of the accompanying Notes to Consolidated Financial Statements.

## 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 of the accompanying Notes to Consolidated Financial Statements.

## Employee Benefit Plans

With respect to the amount of income or expense we recognize in association with our pension and retiree medical plans, we must make a number of assumptions with respect to both future financial conditions (for example, medical costs, returns on fund assets and market interest rates) as well as future actions by plan participants (for example, when they will retire and how long they will live after retirement). Most of these assumptions have relatively minor impacts on the overall accounting recognition given to these plans, but two assumptions in particular, the discount rate and the assumed long-term rate of return on fund assets, can have significant effects on the amount of expense recorded and liability recognized. We review historical trends, future expectations, current and projected market conditions, the general interest rate environment and benefit payment obligations to select these assumptions. The discount rate represents the market rate for a high quality corporate bond. The selection of these assumptions is further discussed in Note 9 of the accompanying Notes to Consolidated Financial Statements. While we believe our choices for these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of pension and retiree medical funding, a change of 1% in the long-term return assumption would increase (decrease) our annual retiree medical expense by approximately $0.5 million ($0.5 million) and would increase (decrease) our annual pension expense by $1.9 million ($1.9 million) in comparison to that recorded in 2009. Similarly, a 1% change in the discount rate would increase (decrease) our accumulated postretirement benefit obligation by $6.3 million ($5.8 million) and would increase (decrease) our projected pension benefit obligation by $30.9 million ($27.6 million) compared to those balances as of December 31, 2009.

## Income Taxes

We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In addition, we do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

In determining the deferred income tax asset and liability balances attributable to our investments, we have applied an accounting policy that looks through our investments including our investment in Kinder Morgan Energy Partners. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investment in Kinder Morgan Energy Partners.

## New Basis of Accounting

The Going Private transaction was accounted for as a purchase business combination and, as a result of the application of the Securities and Exchange Commission’s “push-down” accounting requirements, this transaction has resulted in our adoption of a new basis of accounting for our assets and liabilities. Accordingly, our assets and liabilities have been recorded at their estimated fair values as of the date of the completion of the Going Private transaction, with the excess of the purchase price over these combined fair values recorded as goodwill.

Therefore, in the accompanying financial information, transactions and balances prior to the closing of the Going Private transaction (the amounts labeled “Predecessor Company”) reflect the historical basis of accounting for our assets and liabilities, while the amounts subsequent to the closing (the amounts labeled “Successor Company”) reflect the push-down of the investors’ new accounting basis to our financial statements. Additional information concerning the impact of the Going Private transaction on the accompanying financial information is contained under “Impact of the Purchase Method of Accounting on Segment Earnings (Loss)” following.



Our adoption of a new basis of accounting for our assets and liabilities as a result of the 2007 Going Private transaction, the 2007 sale of our retail natural gas distribution and related operations, and our Corridor operations, the 2008 sale of our North System, the 2008 sale of our 80% interest in NGPL PipeCo LLC, the 2008 goodwill impairments described above, and other acquisitions and divestitures (including the transfer of certain assets to Kinder Morgan Energy Partners), among other factors, affect comparisons of our financial position and results of operations between certain periods.

## Results of Operations

Consolidated

<table><tr><td rowspan="4"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31, 2007</td><td rowspan="2">Five Months Ended May 31, 2007</td><td></td></tr><tr><td>2009</td><td>2008</td><td></td></tr><tr><td colspan="3">(In millions)</td><td></td><td></td></tr><tr><td>Segment earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)</td><td>$     584.0</td><td>$      (722.0)</td><td>$     162.5</td><td>$     224.4</td><td></td></tr><tr><td>Products Pipelines-KMP(b)</td><td>788.7</td><td>(1,344.3)</td><td>373.3</td><td>228.5</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP(c)</td><td>878.5</td><td>896.1</td><td>433.0</td><td>210.0</td><td></td></tr><tr><td>CO2-KMP(d)</td><td>596.4</td><td>(156.5)</td><td>243.7</td><td>172.3</td><td></td></tr><tr><td>Terminals-KMP(e)</td><td>154.5</td><td>152.0</td><td>58.8</td><td>(332.0)</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP(f)</td><td>42.5</td><td>129.8</td><td>422.8</td><td>267.4</td><td></td></tr><tr><td>NGPL PipeCo LLC(g)</td><td>4.8</td><td>5.7</td><td>13.4</td><td>8.9</td><td></td></tr><tr><td>Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Segment earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments</td><td>3,049.4</td><td>(1,039.2)</td><td>1,707.5</td><td>779.5</td><td></td></tr><tr><td>Depreciation, depletion and amortization expense</td><td>(1,070.2)</td><td>(918.4)</td><td>(472.3)</td><td>(261.0)</td><td></td></tr><tr><td>Amortization of excess cost of equity investments</td><td>(5.8)</td><td>(5.7)</td><td>(3.4)</td><td>(2.4)</td><td></td></tr><tr><td>NGPL PipeCo LLC fixed fee revenue(h)</td><td>45.8</td><td>39.0</td><td>-</td><td>-</td><td></td></tr><tr><td>General and administrative expenses(i)</td><td>(373.0)</td><td>(352.5)</td><td>(175.6)</td><td>(283.6)</td><td></td></tr><tr><td>Unallocable interest and other, net(j)</td><td>(583.7)</td><td>(623.6)</td><td>(586.7)</td><td>(254.6)</td><td></td></tr><tr><td>Income (loss) from continuing operations before income taxes</td><td>1,062.5</td><td>(2,900.4)</td><td>469.5</td><td>(22.1)</td><td></td></tr><tr><td>Unallocable income tax expense(a)</td><td>(288.7)</td><td>(301.9)</td><td>(183.4)</td><td>(119.9)</td><td></td></tr><tr><td>Income (loss) from continuing operations</td><td>773.8</td><td>(3,202.3)</td><td>286.1</td><td>(142.0)</td><td></td></tr><tr><td>Income (loss) from discontinued operations, net of tax</td><td>0.3</td><td>(0.9)</td><td>(1.5)</td><td>298.6</td><td></td></tr><tr><td>Net (loss) income</td><td>774.1</td><td>(3,203.2)</td><td>284.6</td><td>156.6</td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>(278.1)</td><td>(396.1)</td><td>(37.6)</td><td>(90.7)</td><td></td></tr><tr><td>Net (loss) income attributable to Kinder Morgan, Inc.</td><td>$     496.0</td><td>$      (3,599.3)</td><td>$     247.0</td><td>$     65.9</td><td></td></tr></table>

(a) Kinder Morgan Energy Partners’ income taxes expenses for the years ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 were $36.9 million, $2.4 million, $44.0 million and $15.6 million, respectively, and are included in segment earnings.

(b) 2009 amount includes (i) a $23.0 million increase in expense from the amounts previously reported in Kinder Morgan Energy Partners' 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries, which is primarily non-cash 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, (v) a $0.2 million increase in income from hurricane casualty gains and (vi) $0.5 million decrease in earnings related to assets sold which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting. 2008 amount includes (i) a combined $10.0 million decrease in income from the proposed settlement of certain litigation matters related to Kinder Morgan Energy Partners' 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, (vi) non-cash goodwill impairment adjustments of $1,266.5 million and (vii) $0.4 million decrease in earnings related to assets sold which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting.

(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, (iii) a $0.1 million increase in expense from the amounts previously reported in Kinder Morgan Energy Partners' 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries and (iv) a



combined $0.9 million decrease in earnings related sales and valuation adjustments of assets which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting. 2008 amount includes (i) 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, (ii) a $0.5 million decrease in expense associated with environmental liability adjustments, (iii) a $5.0 million increase in expense related to hurricane clean-up and repair activities, (iv) a $0.3 million increase in expense associated with legal liability adjustments, (v) a non-cash goodwill impairment adjustments of $2,090.2 million, and (vi) a combined $1.7 million decrease in earnings related to sales and valuation adjustments of assets which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting.

(d) 2009 amount includes (i) a $13.5 million unrealized loss on derivative contracts used to hedge forecasted crude oil sales and (ii) increases in earnings resulting from valuation adjustments of $95.6 million related to derivative contracts in place at the time of the Going Private transaction and recorded in the application of the purchase method of accounting. 2008 amount includes (i) a $0.3 million increase in expense associated with environmental liability adjustments and (ii) increases in earnings resulting from valuation adjustments of $136.2 million related to derivative contracts in place at the time of the Going Private transaction and recorded in the application of the purchase method of accounting.

(e) 2009 amount includes (i) a combined $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 the Staten Island liquids terminal, (iii) a $0.9 million increase in expense associated with environmental liability adjustments, (iv) a $0.7 million increase in expense from the amounts previously reported in Kinder Morgan Energy Partners' 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries and (v) a decreases in earnings of $2.6 million related to assets sold, which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting. 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 Kinder Morgan Energy Partners' Elizabeth River bulk terminal and Staten Island liquids terminal, and other legal liability adjustments, (iv) a $0.6 million decrease in expense associated with environmental liability adjustments, (v) a non-cash goodwill impairment charge of $676.6 million and (vi) a decreases in earnings of $3.7 million related to assets sold, which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting.

(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.

(g) Effective February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest in NGPL PipeCo LLC as an equity method investment.

(h) General administration fixed fee charges under an Operations and Reimbursement Agreement.

(i) Includes unallocated litigation and environmental expenses. 2009 amount includes (i) a $2.3 million increase in expense for certain asset and business acquisition costs, which under prior accounting standards would have been capitalized, (ii) a $1.3 million increase in expense for certain land transfer taxes associated with the April 30, 2007 Trans Mountain acquisition and (iii) a $2.7 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season. 2008 amount includes (i) a $0.9 million increase in expense for certain Express pipeline system acquisition costs, (ii) a $0.4 million increase in expense resulting from the write-off of certain acquisition costs, which under prior accounting standards would have been capitalized, (iii) a $0.1 million increase in expense related to hurricane clean-up and repair activities and (iv) a $2.0 million decrease in expense due to the adjustment of certain insurance related liabilities.

(j) 2009 amount includes a $1.6 million increase in imputed interest expense related to the 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 the 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 Kinder Morgan Energy Partners Pacific operations' East Line pipeline.

## Year Ended December 31, 2009 vs. 2008

Our total revenues for 2009 and 2008 were $7.2 billion and $12.1 billion, respectively. For 2009 the net income attributable to Kinder Morgan, Inc. totaled $0.5 billion as compared to a loss of $3.6 billion in 2008. The increase in Kinder Morgan, Inc.'s net income for 2009 as compared to 2008 is primarily due to non-cash goodwill impairment charges that were recorded in the second quarter of 2008 to each segment as follows: Products Pipelines–KMP – $1.26 billion, Natural Gas Pipelines–KMP – $2.09 billion, and Terminals–KMP – $677 million, for a total impairment of $4.03 billion.

## Seven Months Ended December 31, 2007

Net income for the period was driven by solid contributions from  \( CO_{2} \) -KMP, NGPL PipeCo LLC, Natural Gas Pipelines–KMP and Products Pipelines–KMP, which accounted for 25.4%, 24.7%, 21.9% and 9.5%, respectively, or 81.5% collectively, of segment earnings before DD&A.  \( CO_{2} \) -KMP was driven almost equally by its sales and transport and oil and gas producing activities. The Texas Intrastate Natural Gas Pipelines Group accounted for over 50% of the Natural Gas Pipelines–KMP performance and the West Coast Products Pipelines accounted for approximately 50% of the Product Pipelines–KMP segment earnings. NGPL PipeCo LLC contributed earnings of $422.8 million with incremental earnings



coming from the re-contracting of transportation and storage services at higher rates, increased contract volumes, and recent transportation and storage expansions.

Net income was adversely impacted by (i) interest expenses related to the $4.8 billion of incremental debt resulting from the Going Private transaction (see discussion below on the impact of the purchase method of accounting on segment earnings) and (ii) DD&A expense associated with expansion capital expenditures.

Five Months Ended May 31, 2007

Net income was driven by solid performance from NGPL PipeCo LLC as well as all Kinder Morgan Energy Partners segments except Kinder Morgan Canada–KMP, as discussed below. NGPL PipeCo LLC contributed $267 million while Products Pipelines–KMP, Natural Gas Pipelines–KMP and CO \( _{2} \) –KMP each contributed over $200 million.

Offsetting these positive factors were (i) a $377.1 million goodwill impairment charge associated with the Trans Mountain Pipeline (see Note 7 of the accompanying Notes to Consolidated Financial Statements) and (ii) $141.0 million in additional general and administrative expense associated with the Going Private transaction.

Impact of the Purchase Method of Accounting on Segment Earnings (Loss)

The impacts of the purchase method of accounting on segment earnings (loss) before DD&A relate primarily to the revaluation of the accumulated other comprehensive income related to derivatives accounted for as hedges in the CO \( _{2} \) -KMP and Natural Gas Pipelines-KMP segments. Where there is an impact to segment earnings (loss) before DD&A from the Going Private transaction, the impact is described in the individual business segment discussions, which follow. The effects on DD&A expense result from changes in the carrying values of certain tangible and intangible assets to their estimated fair values as of May 30, 2007. This revaluation results in changes to DD&A expense in periods subsequent to May 30, 2007. The purchase accounting effects on "Unallocable interest and other, net" result principally from the revaluation of certain debt instruments to their estimated fair values as of May 30, 2007, resulting in changes to interest expense in subsequent periods.

Segment earnings before depreciation, depletion and amortization expenses

Certain items included in earnings from continuing operations are either not allocated to business segments or are not considered by management in its evaluation of business segment performance. In general, the items not included in segment results are interest expense, general and administrative expenses, DD&A and Kinder Morgan, Inc. income taxes. We currently evaluate business segment performance primarily based on segment earnings before DD&A in relation to the level of capital employed. Because Kinder Morgan Energy Partners' partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners' available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period's earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices. We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.



## Products Pipelines – KMP

<table><tr><td rowspan="3"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td rowspan="2">Five Months Ended May 31, 2007</td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td>2007</td></tr><tr><td></td><td colspan="5">(In millions, except operating statistics)</td></tr><tr><td>Revenues(a)</td><td>$</td><td>826.6</td><td>$</td><td>815.9</td><td>$</td></tr><tr><td>Operating expenses(b)</td><td></td><td>(269.5)</td><td></td><td>(291.0)</td><td>(320.6)</td></tr><tr><td>Other income (expense)(c)</td><td></td><td>(1.1)</td><td></td><td>(3.0)</td><td>0.8</td></tr><tr><td>Goodwill impairment(d)</td><td></td><td>-</td><td></td><td>(1,266.5)</td><td>-</td></tr><tr><td>Earnings from equity investments(e)</td><td></td><td>18.7</td><td></td><td>15.7</td><td>11.5</td></tr><tr><td>Interest income and Other, net(f)</td><td></td><td>12.4</td><td></td><td>2.0</td><td>4.7</td></tr><tr><td>Income tax benefit (expense)(g)</td><td></td><td>(3.1)</td><td></td><td>4.9</td><td>(5.4)</td></tr><tr><td>Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments</td><td>$</td><td>584.0</td><td>$</td><td>(722.0)</td><td>$</td></tr><tr><td>Gasoline (MMBbl) (h)</td><td></td><td>400.1</td><td></td><td>398.4</td><td>252.7</td></tr><tr><td>Diesel fuel (MMBbl)</td><td></td><td>143.2</td><td></td><td>157.9</td><td>97.5</td></tr><tr><td>Jet fuel (MMBbl)</td><td></td><td>111.4</td><td></td><td>117.3</td><td>73.8</td></tr><tr><td>Total refined product volumes (MMBbl)</td><td></td><td>654.7</td><td></td><td>673.6</td><td>424.0</td></tr><tr><td>Natural gas liquids (MMBbl)</td><td></td><td>26.5</td><td></td><td>27.3</td><td>16.7</td></tr><tr><td>Total delivery volumes (MMBbl)(i)</td><td></td><td>681.2</td><td></td><td>700.9</td><td>440.7</td></tr></table>

(a) 2008 amount includes a $5.1 million decrease in revenues from the proposed settlement of certain litigation matters related to the Pacific operations' East Line pipeline. (b) 2009 and 2008 amounts include increases in expense of $11.5 million and $9.2 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 Kinder Morgan Energy Partners' 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries, which is primarily non-cash 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 the Pacific operations' East Line pipeline and other legal liability adjustments, a $0.5 million increase in expense resulting from refined product inventory losses, and a $0.2 million increase in expense related to hurricane clean-up and repair activities.

(c) 2009 amount includes a gain of $0.2 million from hurricane casualty indemnifications. 2008 amount includes a $2.2 million decrease in income resulting from certain property, plant and equipment write-offs. Also, 2009 and 2008 amounts include $0.5 million and $0.4 million, respectively, of decreases in earnings related to assets sold which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting.

(d) 2008 includes non-cash goodwill impairment adjustments of $1,266.5 million.

(e) 2008 amount includes an expense of $1.3 million associated with the portion of environmental liability adjustments on Plantation Pipe Line Company, and an expense of $0.1 million reflecting Kinder Morgan Energy Partners' portion of Plantation Pipe Line Company's expenses related to hurricane clean-up and repair activities.

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

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

(h) Years ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 volumes include ethanol volumes of 23.1 million barrels, 18.7 million barrels, 7.0 million barrels and 4.8 million barrels, respectively.

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

The Products Pipelines–KMP segment’s primary businesses include transporting refined petroleum products and natural gas liquids through pipelines and operating liquid petroleum products terminals and petroleum pipeline transix 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 $51.1 million in 2009 and $1,293.5 million in 2008; accounting for $1,242.4 million increase in earnings in 2009 when compared to 2008. Following is information related to the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses (EBDA) and (ii) revenues in 2009 when compared to 2008:



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

<table><tr><td rowspan="2"></td><td colspan="2">EBDA</td><td colspan="2">Revenues</td></tr><tr><td colspan="2">Increase/(Decrease)</td><td colspan="2">Increase/(Decrease)</td></tr><tr><td>Pacific operations</td><td>$ 21.2</td><td>8%</td><td>4.2</td><td>1%</td></tr><tr><td>West Coast Terminals</td><td>13.4</td><td>25%</td><td>12.8</td><td>16%</td></tr><tr><td>Central Florida Pipeline</td><td>9.2</td><td>22%</td><td>10.7</td><td>20%</td></tr><tr><td>Transmix operations</td><td>7.7</td><td>26%</td><td>6.2</td><td>15%</td></tr><tr><td>Plantation Pipeline</td><td>3.8</td><td>10%</td><td>(24.9)</td><td>(57) %</td></tr><tr><td>Calnev Pipeline</td><td>3.3</td><td>6%</td><td>(0.2)</td><td>-</td></tr><tr><td>All others (including eliminations)</td><td>5.0</td><td>5%</td><td>(3.2)</td><td>(2) %</td></tr><tr><td>Total Products Pipelines-KMP</td><td>$ 63.6</td><td>11%</td><td>$ 5.6</td><td>1%</td></tr></table>

Although ongoing weak economic conditions continued to dampen demand for refined petroleum products at many of the 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 the Pacific operations and the 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 the Products Pipelines–KMP 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 the Pacific operations—consisting of an $18.8 million decrease in combined operating expenses, a $4.2 million increase in total revenues, and a $1.8 million decrease in other operating and non-operating income items, relative to 2008.

The decrease in the 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 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 the California products delivery revenues, and higher terminal revenues, primarily related to incremental ethanol handling services;

- a $13.4 million (25%) increase in earnings from the West Coast terminal operations—largely revenue related, driven by higher revenues from the 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 the 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 the 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 the 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 the 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 the 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;

- a $3.8 million (10%) increase in earnings from the 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 the investment in Plantation in 2009 compared to 2008 was mainly due to a restructuring of the Plantation operating agreement between ExxonMobil and Kinder Morgan Energy Partners. On January 1, 2009, both parties agreed to reduce the fixed operating fees Kinder Morgan Energy Partners earns from operating the pipeline and to charge pipeline operating expenses directly to Plantation, resulting in a minimal impact to the earnings. Accordingly, the $24.9 million reduction in the fee revenues in 2009 was offset by a corresponding decrease in the operating expenses of $26.9 million; and

- a $3.3 million (6%) increase in earnings from the 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.

Earnings Before DD&A by Major Segment Asset

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Pacific operations</td><td>(In millions)</td><td>(In millions)</td></tr><tr><td>Calnev Pipeline</td><td>$ (10.3)</td><td>$ 105.1</td></tr><tr><td>West Coast Terminals</td><td>27.5</td><td>20.1</td></tr><tr><td>Plantation Pipeline</td><td>24.3</td><td>19.3</td></tr><tr><td>Central Florida Pipeline</td><td>22.2</td><td>18.2</td></tr><tr><td>Cochin Pipeline System</td><td>21.9</td><td>15.3</td></tr><tr><td>Southeast Terminals</td><td>30.6</td><td>15.3</td></tr><tr><td>Transmix operations</td><td>24.8</td><td>16.6</td></tr><tr><td>All others</td><td>18.3</td><td>12.4</td></tr><tr><td>Segment Earnings Before DD&amp;A</td><td>3.2</td><td>2.1</td></tr><tr><td></td><td>$ 162.5</td><td>$ 224.4</td></tr></table>

Revenues by Major Segment Asset

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Pacific operations</td><td>(In millions)</td><td>(In millions)</td></tr><tr><td>Calnev Pipeline</td><td>$ 224.4</td><td>$ 156.0</td></tr><tr><td>West Coast Terminals</td><td>41.9</td><td>27.7</td></tr><tr><td>Plantation Pipeline</td><td>42.9</td><td>29.1</td></tr><tr><td>Central Florida Pipeline</td><td>24.6</td><td>17.6</td></tr><tr><td>Cochin Pipeline System</td><td>27.1</td><td>19.3</td></tr><tr><td>Southeast Terminals</td><td>42.6</td><td>32.3</td></tr><tr><td>Transmix operations</td><td>38.4</td><td>29.9</td></tr><tr><td>All others</td><td>25.8</td><td>17.5</td></tr><tr><td>Segment Revenues</td><td>$ 471.5</td><td>$ 331.8</td></tr></table>

Seven Months Ended December 31, 2007

The results for the seven months were negatively impacted by $154.9 million of legal liability adjustments primarily associated with the Pacific operations. Offsetting the charges, earnings before DD&A for this segment were positively affected by (i) approximately $15.4 million associated with Kinder Morgan Energy Partners' January 1, 2007 acquisition of the remaining ownership interest in Cochin (approximately 50.2%) that it did not already own, at which time Kinder Morgan Energy Partners became the pipeline operator, (ii) strong pipeline revenues from the Plantation Pipeline for the period, largely due to favorable oil loss allowance tariff rates, relative to pipeline operating expenses that included only minor pipeline integrity expenses, (iii) favorable margins and strong mainline delivery volumes from the 2006 East Line pipeline expansion and demand from West Coast military bases within the Pacific operations, (iv) military and commercial tariff rate



increases in 2007 on the Calnev Pipeline, (v) strong demand for terminal services at the Carson/Los Angeles Harbor terminal system, recently expanded in 2006, and the Linton and Willbridge terminals located in Portland, Oregon, included in the West Coast Terminals operations, (vi) $4.8 million of earnings before DD&A and $5.7 million of revenue generated by the Kinder Morgan Energy Partners' approximate $11 million Greensboro facility, placed in service in 2006, which is used for petroleum pipeline transmiss operations and (vii) the West Coast Terminals' $3.6 million gain on the sale of its interest in the Black Oil pipeline system in Los Angeles, California in June 2007.

Effective October 5, 2007, Kinder Morgan Energy Partners sold its North System common carrier natural gas liquids pipeline and its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7 million in cash, and used the proceeds received to pay down short-term debt borrowings. The North System business results of operations are not included in the tables and discussion above and have been classified to Discontinued Operations on the accompanying Statements of Operations for the seven months ended December 31, 2007 and five months ended May 31, 2007.

## Five Months Ended May 31, 2007

Earnings before DD&A were positively affected by (i) approximately $7.7 million associated with Kinder Morgan Energy Partners' January 1, 2007 acquisition of the remaining ownership interest in Cochin (approximately 50.2%) that it did not already own, at which time Kinder Morgan Energy Partners became the pipeline operator, (ii) an increase in average tariff rates and mainline delivery from the 2006 expansion of the East Line pipeline within the Pacific operations and demand from West Coast military bases, which contributed to the Pacific operations' revenues and earnings, (iii) strong demand for throughput volumes at the combined Carson/Los Angeles Harbor terminal system and the Linton and Willbridge terminals located in Portland, Oregon, for the West Coast Terminals operations and (iv) $2.8 million of earnings before DD&A and $3.3 million of revenue generated by the Kinder Morgan Energy Partners' Greensboro facility discussed above. The results for the five months were negatively impacted by a $2.2 million expense associated with East Line pipeline legal liability adjustments.

## Natural Gas Pipelines–KMP

<table><tr><td rowspan="4"></td><td colspan="4">Successor Company</td><td rowspan="4">Predecessor Company</td></tr><tr><td colspan="4">Seven Months</td></tr><tr><td colspan="4">Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td>2007</td></tr><tr><td></td><td colspan="4">(In millions, except operating statistics)</td><td></td></tr><tr><td>Revenues</td><td>$</td><td>(3,806.9</td><td>$</td><td>8,422.0</td><td>$ 3,825.9</td></tr><tr><td>Operating expenses(a)</td><td></td><td>(3,192.7)</td><td></td><td>(7,803.3)</td><td>(3,461.4)</td></tr><tr><td>Other income (expense) (b)</td><td></td><td>6.6</td><td></td><td>0.2</td><td>1.9</td></tr><tr><td>Goodwill impairment(c)</td><td></td><td>-</td><td></td><td>(2,090.2)</td><td>-</td></tr><tr><td>Earnings from equity investments</td><td></td><td>141.8</td><td></td><td>113.4</td><td>10.3</td></tr><tr><td>Interest income and other, net-income</td><td></td><td>31.8</td><td></td><td>16.3</td><td>-</td></tr><tr><td>Income tax expense</td><td></td><td>(5.7)</td><td></td><td>(2.7)</td><td>(3.4)</td></tr><tr><td>Earnings (loss) before depreciation, depletion and amortization</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>expense and amortization of excess cost of equity investments</td><td>$</td><td>788.7</td><td>$</td><td>(1,344.3)</td><td>$ 373.3</td></tr><tr><td>Natural gas transport volumes (Trillion Btus)(d)</td><td></td><td>2,284.8</td><td></td><td>2,008.6</td><td>1,067.0</td></tr><tr><td>Natural gas sales volumes (Trillion Btus)(e)</td><td></td><td>794.5</td><td></td><td>866.9</td><td>519.7</td></tr></table>

(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, the 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 Kinder Morgan Energy Partners' 2009 fourth quarter earnings release issued on January 20, 2010, associated with adjustments to long-term receivables for environmental cost recoveries. 2008 amount 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. Amounts also include increases in earnings of $0.3 million and $0.8 million for the years ended 2009 and 2008, respectively, resulting from valuation adjustments related to derivative contracts in place at the time of the Going Private transaction and recorded in the application of the purchase method of accounting.



(b) 2009 amount includes gains of $7.8 million from hurricane casualty indemnifications. 2009 and 2008 amounts include $1.2 million and $3.1 million, respectively, in decreased earnings related to assets sold, and 2008 amount also includes a $0.6 million increase in earnings related to valuation adjustments of assets. These assets had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting.

(c) 2008 amount include non-cash goodwill impairment adjustments of $2,090.2 million.

(d) 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. (e) Represents Texas intrastate natural gas pipeline group volumes.

The Natural Gas Pipelines–KMP 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 an increase of $1.2 million in 2009 and a decrease of $2,091.1 million in 2008 in earnings before depreciation, depletion and amortization expenses; accounting for a $2,092.3 million increase in earnings before depreciation, depletion and amortization expenses in 2009 when compared to 2008. Following is information related to the increases and decreases in the segment’s (i) remaining changes in earnings before depreciation, depletion and amortization expenses (“EBDA”) and (ii) revenues in 2009 when compared to 2008:

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

<table><tr><td></td><td>EBDA Increase/(Decrease)</td><td>Revenues Increase/(Decrease)</td></tr><tr><td></td><td colspan="2">(In millions, except percentages)</td></tr><tr><td>Kinder Morgan Louisiana Pipeline</td><td>$ 30.2</td><td>n/a</td></tr><tr><td>Midcontinent Express Pipeline</td><td>14.1</td><td>n/a</td></tr><tr><td>Rockies Express Pipeline</td><td>13.2</td><td>16%</td></tr><tr><td>Kinder Morgan Interstate Gas Transmission</td><td>9.6</td><td>8%</td></tr><tr><td>Kinder Morgan Gas Treating</td><td>9.4</td><td>n/a</td></tr><tr><td>TransColorado Pipeline</td><td>(3.5)</td><td>(6)%</td></tr><tr><td>Texas Intrastate Natural Gas Pipeline Group</td><td>(34.0)</td><td>(9)%</td></tr><tr><td>All others</td><td>1.7</td><td>2%</td></tr><tr><td>Intrasegment eliminations</td><td>-</td><td>-</td></tr><tr><td>Total Natural Gas Pipelines-KMP</td><td>$ 40.7</td><td>5%</td></tr></table>

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

The 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, due primarily 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), Kinder Morgan Energy Partners was allowed a reasonable return on the construction costs that it 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. Natural gas service to all Zone 1 delivery points occurred by May 21, 2009, and on August 1, 2009, the system’s remaining portion (Zone2) 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.

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 the 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 the Kinder Morgan Interstate Gas Transmission pipeline system (“KMIGT”)—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 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 the 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 the 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.

The 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 the 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 and 2008, 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 the 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, the intrastate group’s business strategy involves relying both on long and short-term natural gas sales and purchase agreements, and the Texas intrastate natural gas pipeline group uses this flexibility to help optimize the margins realized by capturing favorable differences due to changes in timing, location, prices and volumes. To the extent possible, the Texas intrastate natural gas pipeline group balances the pricing and timing of the natural gas purchases to the natural gas sales, and the purchase and sales contracts are frequently settled in terms of an index price for both purchases and sales. Generally, the Texas intrastate natural gas pipeline group attempts to lock-in an acceptable margin by capturing the difference between the average gas sales prices and the average gas purchase and cost of fuel prices.



## Earnings Before DD&A by Major Segment Asset

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Texas Intrastate Natural Gas Pipeline Group</td><td>$ 221.1</td><td>$ 133.0</td></tr><tr><td>Kinder Morgan Interstate Gas Transmission</td><td>65.7</td><td>43.1</td></tr><tr><td>Trailblazer Pipeline</td><td>31.9</td><td>18.1</td></tr><tr><td>TransColorado Pipeline</td><td>25.7</td><td>17.9</td></tr><tr><td>Rockies Express Pipeline</td><td>(8.3)</td><td>(4.3)</td></tr><tr><td>Casper and Douglas Gas Processing</td><td>18.0</td><td>7.3</td></tr><tr><td>All others</td><td>19.2</td><td>13.4</td></tr><tr><td>Segment Earnings Before DD&amp;A</td><td>$ 373.3</td><td>$ 228.5</td></tr></table>

Revenues by Major Segment Activities

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td></td><td>(In millions)</td><td>(In millions)</td></tr><tr><td>Texas Intrastate Natural Gas Pipeline Group</td><td>$ 3,562.0</td><td>$ 2,492.4</td></tr><tr><td>Kinder Morgan Interstate Gas Transmission</td><td>130.7</td><td>70.7</td></tr><tr><td>Trailblazer Pipeline</td><td>36.4</td><td>22.6</td></tr><tr><td>TransColorado Pipeline</td><td>30.3</td><td>20.7</td></tr><tr><td>Casper and Douglas Gas Processing</td><td>67.1</td><td>34.7</td></tr><tr><td>All others</td><td>0.2</td><td>-</td></tr><tr><td>Intrasegment eliminations</td><td>(0.8)</td><td>(0.5)</td></tr><tr><td>Segment Revenues</td><td>$ 3,825.9</td><td>$ 2,640.6</td></tr></table>

Seven Months Ended December 31, 2007

Earnings before DD&A in the seven months ended December 31, 2007 were also positively affected by (i) strong performances by the Texas intrastate natural gas pipeline group due to (a) favorable natural gas sales margins on renewal contracts, (b) increased transportation service revenue due to a new long-term contract with a major customer that became effective April 1, 2007, (c) greater value from natural gas storage activities and natural gas processing margins, (d) sales of cushion gas due to the termination of a storage facility lease and (e) storage revenues from transportation and storage under a new long term contract with a major customer that became effective April 1, 2007, (ii) strong performance from KMIGT, Trailblazer Pipeline and TransColorado Pipeline due mainly to solid earnings from transportation and natural gas park and loan services and (iii) earnings from Casper and Douglas gas processing operations that had solid natural gas liquids sales revenues driven by favorable prices and volumes.

Adversely affecting earnings before DD&A in the seven months ended December 31, 2007 was Kinder Morgan Energy Partners' share of net losses from its equity investment in Rockies Express due to depreciation and interest expenses allocable to a segment of this project that was placed in service in February 2007, and until the completion of the Rockies Express-West project which became fully operational in May 2008, generated only limited natural gas reservation revenues and volumes.

Five Months Ended May 31, 2007

Earnings before DD&A in the five months ended May 31, 2007 were positively affected by (i) strong performances by the Texas intrastate natural gas pipeline group due to (a) favorable natural gas sales margins on renewal and incremental contracts, (b) strong demand for and favorable rates on transportation services, (c) greater value from natural gas storage activities and natural gas processing margins, (d) sales of cushion gas due to the termination of a storage facility lease and (e) storage revenues from a new long-term contract with a major customer that became effective April 1, 2007, (ii) strong



performance from KMIGT, Trailblazer Pipeline and TransColorado Pipeline due mainly to solid earnings from transportation and natural gas park and loan services and (iii) earnings from Casper and Douglas gas processing operations that had solid natural gas liquids sales revenues driven by favorable prices and volumes.

Rockies Express operations adversely affected earnings before DD&A by $4.3 million for the five months ended May 31, 2007 as depreciation and interest expenses were in excess of gross profits realized on limited natural gas reservation revenues and volumes.

CO₂-KMP

<table><tr><td rowspan="3"></td><td colspan="4">Successor Company</td><td rowspan="3">Predecessor Company</td></tr><tr><td colspan="3">Seven Months Ended</td><td rowspan="2">Five Months Ended</td></tr><tr><td colspan="2">Year Ended December 31,</td><td>December 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td></td><td colspan="5">(In millions, except operating statistics)</td></tr><tr><td>Revenues(a)</td><td>$ 1,131.3</td><td>$ 1,269.2</td><td>$</td><td>605.9</td><td></td></tr><tr><td>Operating expenses(b)</td><td>(271.1)</td><td>(391.8)</td><td></td><td>(182.7)</td><td></td></tr><tr><td>Earnings from equity investments</td><td>22.3</td><td>20.7</td><td></td><td>10.5</td><td></td></tr><tr><td>Other, net income (expense)</td><td>-</td><td>1.9</td><td></td><td>0.1</td><td></td></tr><tr><td>Income tax expense</td><td>(4.0)</td><td>(3.9)</td><td></td><td>(0.8)</td><td></td></tr><tr><td>Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments</td><td>$ 878.5</td><td>$ 896.1</td><td>$ 433.0</td><td>$ 210.0</td><td></td></tr><tr><td>Carbon dioxide delivery volumes (Bcf)(c)</td><td>774.0</td><td>732.1</td><td></td><td>365.0</td><td></td></tr><tr><td>SACROC oil production (gross)(MBbl/d)(d)</td><td>30.1</td><td>28.0</td><td></td><td>26.5</td><td></td></tr><tr><td>SACROC oil production (net)(MBbl/d)(e)</td><td>25.1</td><td>23.3</td><td></td><td>22.1</td><td></td></tr><tr><td>Yates oil production (gross)(MBbl/d)(d)</td><td>26.5</td><td>27.6</td><td></td><td>27.4</td><td></td></tr><tr><td>Yates oil production (net)(MBbl/d)(e)</td><td>11.8</td><td>12.3</td><td></td><td>12.2</td><td></td></tr><tr><td>Natural gas liquids sales volumes (net)(MBbl/d)(e)</td><td>9.5</td><td>8.4</td><td></td><td>9.5</td><td></td></tr><tr><td>Realized weighted average oil price per Bbl(f)(g)</td><td>$ 49.55</td><td>$ 49.42</td><td>$ 36.80</td><td>$ 35.03</td><td></td></tr><tr><td>Realized weighted average natural gas liquids price per Bbl(g)(h)</td><td>$ 37.96</td><td>$ 63.00</td><td>$ 58.55</td><td>$ 45.04</td><td></td></tr></table>

(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. Also, amounts include increases in segment earnings resulting from valuation adjustments of $95.6 million and $136.2 million for the years ended 2009 and 2008, respectively, related to derivative contracts in place at the time of the Going Private transaction and recorded in the application of the purchase method of accounting.

(b) 2008 amount includes increases in expense associated with environmental liability adjustments of $0.3 million.

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

(d) Represents 100% of the production from the field. Kinder Morgan Energy Partners owns an approximately 97% working interest in the SACROC unit and an approximately 50% working interest in the Yates unit.

(e) Net to Kinder Morgan Energy Partners after royalties and outside working interests.

(f) Includes all Kinder Morgan Energy Partners owned 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 Kinder Morgan Energy Partners ownership in processing plants and third party processing agreements.

The  \( CO_{2} \) -KMP segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called  \( CO_{2} \) ) 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 increases in earnings before depreciation, depletion and amortization expenses of 82.1 million in 2009 and 135.9 million in 2008; accounting for decreases in earnings before depreciation, depletion and amortization expenses of 53.8 million in 2009 when compared with 2008. 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) revenues in 2009 when compared to 2008:



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

<table><tr><td rowspan="2"></td><td colspan="2">EBDA</td><td colspan="2">Revenues</td></tr><tr><td colspan="2">Increase/(Decrease)</td><td colspan="2">Increase/(Decrease)</td></tr><tr><td>Sales and transportation activities</td><td>$ (84.4)</td><td>(28) %</td><td>(78.2)</td><td>(23) %</td></tr><tr><td>Oil and gas producing activities</td><td>120.6</td><td>26%</td><td>(44.5)</td><td>(5) %</td></tr><tr><td>Intrasegment eliminations</td><td>--</td><td>-</td><td>38.9</td><td>46%</td></tr><tr><td>Total CO2-KMP</td><td>$ 36.2</td><td>5%</td><td>$ (83.8)</td><td>(7) %</td></tr></table>

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 the  \( CO_{2}-KMP \)  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 the 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.

The 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 Kinder Morgan Energy Partners has no control, and because future price changes may be volatile, the CO \( _{2} \) -KMP business segment is exposed to price risk related to the price volatility of these commodities. To some extent, however, Kinder Morgan Energy Partners is 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 the CO \( _{2} \) -KMP segment, and Kinder Morgan Energy Partners has exposure on all unhedged sales volumes, the majority of which are natural gas liquids volumes. Håd Kinder Morgan Energy Partners not used energy derivative contracts to transfer commodity price risk, the crude oil sales prices would have averaged $59.02 per barrel in 2009 and $97.70 per barrel in 2008.

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 Kinder Morgan Energy Partners purchases certain volumes of carbon dioxide on an intercompany basis for use, Kinder Morgan Energy Partners does not recognize profits on carbon dioxide sales to itself.

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 the Central Basin Pipeline and to lower crude oil transportation revenues from the 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 the 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.

For more information on Kinder Morgan Energy Partners ownership interests in the net quantities of proved oil and gas reserves and its measures of discounted future net cash flows from oil and gas reserves, please see Note 20 of the accompanying Notes to Consolidated Financial Statements.

Earnings Before DD&A by Major Segment Activities

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Sales and transportation activities</td><td>(In millions)</td><td>(In millions)</td></tr><tr><td>Oil and gas production activities</td><td>$ 110.4</td><td>$ 67.2</td></tr><tr><td>Segment Earnings Before DD&amp;A</td><td>322.6</td><td>142.8</td></tr><tr><td></td><td>$ 433.0</td><td>$ 210.0</td></tr></table>

Revenues by Major Segment Activities

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Sales and transportation activities</td><td>(In millions)</td><td>(In millions)</td></tr><tr><td>Oil and gas production activities</td><td>$ 116.1</td><td>$ 71.3</td></tr><tr><td>Intrasegment eliminations</td><td>518.7</td><td>271.7</td></tr><tr><td>Segment Revenues</td><td>(28.9)</td><td>(18.8)</td></tr><tr><td></td><td>$ 605.9</td><td>$ 324.2</td></tr></table>

Seven Months Ended December 31, 2007

For the seven months ended December 31, 2007, SACROC’s gross production averaged 26.5 thousand barrels per day and Yates’ gross production averaged 27.4 thousand barrels per day. SACROC contributed approximately 56% of earnings before DD&A for the total oil and gas producing activities. The earnings before DD&A in the seven months ended December 31, 2007 were positively affected by (i) strong average crude oil and natural gas plant product prices, (ii) strong oil production at the Yates field unit and (iii) a favorable realized weighted-average price per barrel in the SACROC field unit gas processing operations. The period’s results were also positively affected by valuation adjustments of $106.0 million for derivative contracts on crude oil hedges.

Partially offsetting these factors was a reduced average carbon dioxide realized sales price resulting from the December 2006 expiration of a large volume high-priced sales contract.

With respect to crude oil, overall sales volumes were stable, but the segment benefited from a strong realized weighted-average price per barrel. With respect to natural gas liquids, low sales volumes were more than offset by a favorable realized weighted-average price per barrel.

Five Months Ended May 31, 2007

The segment’s sales and transportation activities were adversely affected by a decrease in average carbon dioxide prices. A significant portion of the decrease in average carbon dioxide prices is timing related, as some of the segment’s carbon dioxide contracts are tied to crude oil prices in prior periods, and the 2007 contracts had been tied to lower crude oil prices, relative to 2006. These decreases in carbon dioxide prices were only partially offset by slightly higher carbon dioxide sales volumes related to increased carbon dioxide production from the McElmo Dome source field.



Highlights surrounding oil and gas producing activities for the five months ended May 31, 2007 include (i) increases in oil production at the Yates field unit, (ii) favorable weighted-average price per barrel and (iii) solid earnings from natural gas liquids sales volumes and prices, largely due to increased recoveries at the SACROC gas processing operations.

## Terminals–KMP

<table><tr><td rowspan="3"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Seven Months Ended</td><td colspan="3">Five Months Ended</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">December 31,</td><td colspan="2">May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td>2007</td><td></td></tr><tr><td></td><td colspan="6">(In millions, except operating statistics)</td></tr><tr><td>Revenues</td><td>$     1,109.0</td><td>$     1,173.6</td><td>$     599.2</td><td>$     364.5</td><td></td><td></td></tr><tr><td>Operating expenses(a)</td><td>(536.8)</td><td>(631.8)</td><td>(344.2)</td><td></td><td></td><td></td></tr><tr><td>Other income (expense)(b)</td><td>25.0</td><td>(6.4)</td><td>3.3</td><td></td><td></td><td></td></tr><tr><td>Goodwill impairment(c)</td><td>-</td><td>(676.6)</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Earnings from equity investments</td><td>0.7</td><td>2.7</td><td>0.6</td><td></td><td></td><td></td></tr><tr><td>Other, net-income</td><td>3.7</td><td>1.7</td><td>0.7</td><td></td><td></td><td></td></tr><tr><td>Income tax expense(d)</td><td>(5.2)</td><td>(19.7)</td><td>(15.9)</td><td></td><td></td><td></td></tr><tr><td>Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments</td><td>$     596.4</td><td>$      (156.5)</td><td>$     243.7</td><td>$     172.3</td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Bulk transload tonnage (MMtons)(e)</td><td>78.0</td><td>103.0</td><td>62.5</td><td></td><td></td><td></td></tr><tr><td>Ethanol (MMBbl)</td><td>32.9</td><td>30.7</td><td>15.4</td><td></td><td></td><td></td></tr><tr><td>Liquids leaseable capacity (MMBbl)</td><td>56.4</td><td>54.2</td><td>47.5</td><td></td><td></td><td></td></tr><tr><td>Liquids utilization %</td><td>96.6%</td><td>97.5%</td><td>95.9%</td><td></td><td></td><td></td></tr></table>

(a) 2009 and 2008 amounts include a $0.9 million increase in expense and a $0.6 million decrease 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 the Staten Island liquids terminal, a $0.3 million decrease in expense related to hurricane cleanup and repair activities and a $0.7 million increase in expense from the amounts previously reported in Kinder Morgan Energy Partners' 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 the Elizabeth River bulk terminal and the Staten Island liquids terminal, and other legal liability adjustments and a $1.9 million increase in expense related to fire damage and repair activities.

(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. 2009 and 2008 amounts include decreases of earnings of $2.6 million and $3.7 million, respectively, related to assets sold, which had been revalued as part of the Going Private transaction and recorded in the application of the purchase method of accounting.

(c) 2008 amount includes a non-cash goodwill impairment charge of $676.6 million.

(d) 2009 amount includes a $0.9 million increase in expense related to hurricane and fire 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.

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

The Terminals–KMP business segment includes the operations of petroleum, chemical and other liquids terminal facilities (other than those included in the Products Pipelines–KMP segment), and all of 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 $20.3 million in 2009, and decreased earnings before depreciation, depletion and amortization by $695.4 million in 2008; accounting for increases in earnings before depreciation, depletion and amortization expenses of $715.7 million in 2009, when compared with 2008. The segment’s remaining $37.2 million (22%) increase in earnings before depreciation, depletion and amortization in 2009 compared to 2008 were driven by a combination of internal asset growth and strategic business acquisitions.

Kinder Morgan Energy Partners has made and continues to seek terminal acquisitions in order to gain access to new markets and to complement and/or enlarge its existing terminal operations and since the beginning of 2007, it has 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.

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 the assets were owned in the respective prior year. For more information on acquisitions, see Note 3 of the accompanying Notes to Consolidated Financial Statements.

Following is information for the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses (EBDA) and (ii) revenues in 2009 when compared to 2008. The changes represent increases and decreases in terminal results at various locations for bulk and liquids terminal operations owned during identical periods in both pairs of comparable years. These terminal operations are grouped into regions based on geographic location and/or primary operating function. This structure allows 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

<table><tr><td rowspan="2"></td><td colspan="2">EBDA</td><td colspan="2">Revenues</td></tr><tr><td colspan="2">Increase/(Decrease)</td><td colspan="2">Increase/(Decrease)</td></tr><tr><td></td><td colspan="4">(In millions, except percentages)</td></tr><tr><td>Lower River (Louisiana)</td><td>$ 24.8</td><td>106%</td><td>$ (9.5)</td><td>(9)%</td></tr><tr><td>Gulf Coast</td><td>16.6</td><td>12%</td><td>18.5</td><td>11%</td></tr><tr><td>West</td><td>10.4</td><td>27%</td><td>7.5</td><td>9%</td></tr><tr><td>Texas Petcoke</td><td>4.1</td><td>6%</td><td>(10.2)</td><td>(7)%</td></tr><tr><td>Mid River</td><td>(10.2)</td><td>(35)%</td><td>(32.4)</td><td>(36)%</td></tr><tr><td>Ohio Valley</td><td>(7.7)</td><td>36%</td><td>(16.9)</td><td>(26)%</td></tr><tr><td>Materials Management (rail transloading)</td><td>(4.4)</td><td>(24)%</td><td>(12.8)</td><td>(26)%</td></tr><tr><td>All others</td><td>(1.0)</td><td>-</td><td>(25.7)</td><td>(5)%</td></tr><tr><td>Intrasegment eliminations</td><td>-</td><td>-</td><td>0.8</td><td>79%</td></tr><tr><td>Total Terminals - KMP</td><td>$ 32.6</td><td>6%</td><td>$ (80.7)</td><td>(7)%</td></tr></table>

The increase in earnings before depreciation, depletion and amortization expenses from the 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 the International Marine Terminals (“IMT”) facility, a Louisiana partnership located in Port Sulphur, Louisiana and owned 66 2/3% by Kinder Morgan Energy Partners, and the 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 the 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 docketage, 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 the Gulf Coast terminals reflects favorable results from the 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, the 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 the 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, the overall liquids utilization capacity rate (the ratio of the actual leased capacity to the estimated potential capacity) decreased by only 1% since the end of 2008.

The increase in earnings in 2009 from the West region terminals was driven by incremental contributions from the Kinder Morgan North 40 terminal, the crude oil tank farm constructed near Edmonton, Alberta, Canada, and from the Vancouver Wharves bulk marine terminal, located on the north shore of Vancouver, British Columbia, Canada’s main harbor. Kinder Morgan Energy Partners completed construction and placed the North 40 terminal into service in the second quarter of 2008. The increase in earnings from the 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.



The increase in earnings from the Texas petroleum coke operations was chiefly due to higher earnings realized from the 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 the 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 the 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, Kinder Morgan Energy Partners experienced significant year-over-year volume and revenue declines at various owned or operated terminal facilities in 2009, when compared to 2008. For the Terminals–KMP 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 the 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.

Earnings Before DD&A by Major Segment Asset

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td></td><td>(In millions)</td><td>(In millions)</td></tr><tr><td>Gulf Coast</td><td>$ 66.7</td><td>$ 43.3</td></tr><tr><td>Northeast</td><td>35.6</td><td>28.1</td></tr><tr><td>Texas Petcoke</td><td>30.9</td><td>22.5</td></tr><tr><td>Mid-Atlantic</td><td>24.2</td><td>14.6</td></tr><tr><td>West</td><td>19.8</td><td>3.8</td></tr><tr><td>Ferro</td><td>17.2</td><td>5.1</td></tr><tr><td>Lower River (Louisiana)</td><td>14.9</td><td>18.5</td></tr><tr><td>All others</td><td>34.4</td><td>36.4</td></tr><tr><td>Segment Earnings Before DD&amp;A</td><td>$ 243.7</td><td>$ 172.3</td></tr></table>

Revenues by Major Segment Asset

<table><tr><td></td><td>Successor Company</td><td>Predecessor Company</td></tr><tr><td></td><td>Seven Months Ended December 31, 2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td></td><td>(In millions)</td><td>(In millions)</td></tr><tr><td>Gulf Coast</td><td>$ 97.8</td><td>$ 64.0</td></tr><tr><td>Northeast</td><td>59.5</td><td>43.2</td></tr><tr><td>Texas Petcoke</td><td>68.5</td><td>43.8</td></tr><tr><td>Mid-Atlantic</td><td>59.0</td><td>38.4</td></tr><tr><td>West</td><td>43.4</td><td>9.5</td></tr><tr><td>Ferro</td><td>45.9</td><td>15.6</td></tr><tr><td>Lower River (Louisiana)</td><td>61.6</td><td>49.6</td></tr><tr><td>All others</td><td>164.4</td><td>101.0</td></tr><tr><td>Intrasegment eliminations</td><td>(0.9)</td><td>(0.6)</td></tr><tr><td>Segment Revenues</td><td>$ 599.2</td><td>$ 364.5</td></tr></table>



## Seven Months Ended December 31, 2007

Combined, the operations acquired in 2006 and 2007 referred to above contributed earnings before DD&A of $28.4 million, revenues of $73.3 million, operating expenses of $45.4 million and equity earnings of $0.5 million in the seven months ended December 31, 2007. This segment's earnings benefited from the two large Gulf Coast liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas, which contributed $18.1 million of combined earnings before DD&A. The two terminals continued to benefit from both recent expansions that have added new liquids tank and truck loading rack capacity since 2006 and business from ethanol and biodiesel storage and transfer activity. Strong earnings during the period also resulted from (i) $12.1 million of earnings before DD&A contributed from the combined operations of the Argo and Chicago, Illinois liquids terminals, due to strong ethanol throughput and increased capacity in the liquids storage and handling business, (ii) $30.9 million of earnings before DD&A contributed from the Texas Petcoke terminals, due largely to strong demand for petroleum coke at the Port of Houston facility and (iii) $5.5 million of earnings before DD&A contributed from the Pier IX bulk terminal, located in Newport News, Virginia, largely due to a favorable demand for coal transfers and increasing rail incentives.

## Five Months Ended May 31, 2007

Acquisitions in 2006 and 2007 contributed $2.8 million in earnings before DD&A during the five months ended May 31, 2007 were composed of (i) $2.0 million from Transload Services, LLC and (ii) $0.8 million from Devco USA L.L.C. Segment earnings before DD&A also included strong earnings contributions consisting of (i) $5.9 million from the Shipyard River terminal located in Charleston, South Carolina, (ii) $17.3 million from the Lower Mississippi (Louisiana) terminals (which include its 66 2/3% ownership interest in the IMT partnership and the Port of New Orleans liquids facility located in Harvey, Louisiana) and (iii) $7.8 million from the combined operations of its Argo and Chicago, Illinois liquids terminals. The increases from the Shipyard River terminal related to completed expansion projects since the middle of 2006 that increased handling capacity for imported coal volumes and the earnings increases from the Chicago liquids facilities were driven by higher revenues, due to increased ethanol throughput and incremental liquids storage and handling business.

## Kinder Morgan Canada–KMP

<table><tr><td rowspan="2"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31, 2007</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2008</td><td>2007</td><td></td><td></td></tr><tr><td></td><td colspan="6">(In millions, except operating statistics)</td></tr><tr><td>Revenues</td><td>$</td><td>226.1</td><td>$</td><td>198.9</td><td>$</td><td>100.9</td></tr><tr><td>Operating expenses</td><td>(72.5)</td><td>(68.0)</td><td></td><td>(44.3)</td><td></td><td></td></tr><tr><td>Goodwill impairment(a)</td><td>-</td><td>-</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Earnings from equity investments</td><td>(4.1)</td><td>8.3</td><td></td><td>14.4</td><td></td><td></td></tr><tr><td>Interest income and other, net-income (expense)(b)</td><td>23.9</td><td>(6.2)</td><td></td><td>6.3</td><td></td><td>1.7</td></tr><tr><td>Income tax expense(c)</td><td>(18.9)</td><td>19.0</td><td></td><td>(18.5)</td><td></td><td>(0.9)</td></tr><tr><td>Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments</td><td>$</td><td>154.5</td><td>$</td><td>152.0</td><td>$</td><td>58.8</td></tr><tr><td>Transport volumes (MMBbl)(d)</td><td>102.5</td><td>86.7</td><td></td><td>58.0</td><td></td><td>36.4</td></tr></table>

(a) Amount for the five months ended May 31, 2007 represents a non-cash goodwill impairment charge; see Note 7 of the accompanying Notes to Consolidated Financial Statements.

(b) 2008 amount includes 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 $19.3 million decrease in expense associated with favorable changes in Canadian income tax rates, and a $6.6 million increase in expense due to certain non-cash Trans Mountain regulatory accounting adjustments.

(d) Represents Trans Mountain pipeline system volumes.

The Kinder Morgan Canada–KMP segment includes operations we sold to Kinder Morgan Energy Partners: (i) Trans Mountain pipeline system transferred effective April 30, 2007, (ii) one-third interest in the Express pipeline system



(“Express”) transferred effective August 28, 2008 and (iii) Jet Fuel pipeline system (“Jet Fuel”) transferred effective August 28, 2008. These operations had been reported separately in previous reports. The information in the table above reflects the results of operations for Trans Mountain, Express and Jet Fuel for all periods presented.

The certain items related to the Kinder Morgan Canada–KMP 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 $14.1 million (9%) increase in segment earnings before depreciation, depletion and amortization consisted of (i) higher earnings of $18.1 million (13%) from Trans Mountain and (ii) higher earnings of $2.8 million (127%) from Jet Fuel. These positive impacts were partially offset by lower earnings of $6.8 million (48%) from Express.

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 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 increase in earnings from Jet Fuel in 2009 was driven by both higher pipeline transportation revenues and higher net currency gains (included within “Other, net income”). In 2009, Jet Fuel’s revenues increased $1.1 million (34%) compared to 2008.

The lower earnings from Express was primarily due to lower equity earnings from the 33 1/3% ownership interest in the Express pipeline system, higher year-over-year income tax expense and higher net currency losses (included within “Other, net income”) in 2009.

Seven Months Ended December 31, 2007

During seven months ended December 31, 2007, segment earnings before DD&A were positively impacted by the completion of a pump station expansion on April 30, 2007 and its associated positive impact to revenue for the period.

Five Months Ended May 31, 2007

During the five months ended May 31, 2007, earnings before DD&A were adversely affected by a $377.1 million goodwill impairment charge recorded against the Trans Mountain asset. Slightly offsetting this negative impact to earnings was the completion of a pump station expansion on April 30, 2007 and its associated positive impact to revenue for the period.

NGPL PipeCo LLC (“NGPL”)

<table><tr><td rowspan="2"></td><td colspan="4">Successor Company</td><td rowspan="2">Seven Months Ended December 31, 2007</td><td rowspan="2">Five Months Ended May 31, 2007 (In millions)</td><td rowspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Segment earnings before DD&amp;A</td><td></td><td></td><td>(In millions)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$</td><td>42.5</td><td>$</td><td>129.8</td><td>$</td><td>422.8</td><td>$ 267.4</td></tr></table>

On February 15, 2008, we sold an 80% ownership interest in our NGPL business segment to Myria Acquisition Inc. (“Myria”) for approximately $5.9 billion. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest as an equity method investment. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement.

Section 5 Proceeding - On November 19, 2009, NGPL was notified by the FERC of a proceeding against it pursuant to section 5 of the Natural Gas Act (the “Order”). The proceeding will set the matter for hearing and determine whether NGPL’s current rates, which were approved by the FERC in NGPL’s last rate case settlement, remain just and reasonable. The FERC made no findings in its Order as to what would constitute just and reasonable rates or a reasonable return for NGPL. A proceeding under section 5 of the Natural Gas Act is prospective in nature. A change in rates charged customers by NGPL would likely only occur after the FERC has issued a final order. According to the procedural schedule adopted in the case, an initial Administrative Law Judge decision is due by November 15, 2010. The final FERC decision will be based on the record developed before the Administrative Law Judge.



## Year Ended December 31, 2009 vs. 2008

The $87.3 million (67.3%) decrease in segment earnings before DD&A between the years ended December 31, 2009 and 2008 in the NGPL reportable segment was primarily due to the February 15, 2008, sale of an 80% ownership interest in NGPL to Myria Acquisition Inc. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest in NGPL as an equity method investment. Segment earnings before DD&A at the 100% asset ownership level were $89.7 million for the period from January 1, 2008 to February 14, 2008 and for the period February 15, 2008 to December 31, 2008 our equity earnings were $40.1 million.

NGPL’s net income, at the 100% ownership level, decreased by $17.4 million (8%) from $230.4 million in 2008 to $213.0 million in 2009. Revenues decreased by $153.3 million (12%) from $1,288.6 million in 2008 to $1,135.3 million in 2009 due principally to a decrease in natural gas prices. Gross profit (total revenues less gas purchases and other costs of sales) decreased by $21.8 million (2%) from $898.7 million in 2008 to $876.9 million in 2009. The decrease in gross profit from 2008 to 2009 was attributable to (i) a $30.2 million reduction in gross profit from operational natural gas sales due largely to lower natural gas prices, (ii) $21.0 million of charges in 2009 to reduce the carrying value of current storage gas inventories to reflect the reduced market price of natural gas and (iii) a $4.3 million net reduction in other miscellaneous gross profit items, offset by a $33.7 million increase from natural gas transportation and storage services. NGPL’s results were also impacted in 2009, relative to 2008, by (i) a $21.0 million decrease in operations and maintenance expenses due, in part, to lower costs for transmission system integrity management programs, lower electric power costs and 2009 insurance recoveries related to Hurricane Ike, (ii) the inclusion in 2008 results of $5.6 million of net gains on sales of land, (iii) a $2.8 million increase in interest expense, net of interest income, (iv) a $0.5 million increase in pre-tax income from other miscellaneous income and expenses items and (v) an $8.7 million increase in income tax expense due to an increase in the effective tax rate applicable to state income taxes, partially offset by a decrease in pre-tax earnings. NGPL’s operational natural gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and the sale of storage cushion gas volumes resulting from storage system expansion projects. Its future revenues from operational natural gas sales could be affected by, among other things, the market price of natural gas, the volume of fuel collected in-kind pursuant to its tariffs, including potential changes resulting from the current Section 5 proceeding discussed above, and its cushion gas available from future storage system expansion projects.

## Seven Months Ended December 31, 2007

NGPL revenues and earnings for the seven months ended December 31, 2007 were positively impacted primarily by (i) $334.4 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions, (ii) $116.0 million of gross profit from operational gas recoveries and sales and (iii) $61.4 million of gross profit from cushion sales. Total system throughput volumes of 1,027.2 trillion Btus during the seven months ended December 31, 2007 did not have a significant direct impact on revenues or earnings due to the fact that transportation revenues are derived primarily from “firm” contracts in which shippers pay a “demand” fee to reserve a set amount of system capacity for their use.

## Five Months Ended May 31, 2007

NGPL revenues and earnings for the five months ended May 31, 2007 were positively impacted primarily by $245.9 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions and (ii) $77.6 million of gross profit from operational gas recoveries and sales.



## Power

As discussed in Note 15 of the accompanying Notes to Consolidated Financial Statements, on January 25, 2008, we sold our interests in three natural gas-fired power plants in Colorado to Bear Stearns, including the Thermo Cogeneration Partnership and the Thermo Greeley facility. The closing of the sale was effective January 1, 2008, and we received net proceeds of $63.1 million.

The remaining operations for the Power segment are Triton Power Michigan LLC’s lease and operation of the Jackson, Michigan 550-megawatt natural gas-fired electric power plant (“Triton Power”) and a 105-megawatt natural gas-fired power plant in Snyder, Texas that generates electricity for the  \( CO_{2} \) -KMP segment’s SACROC operations, the plant’s sole customer.

<table><tr><td rowspan="3"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Seven Months</td><td rowspan="2">Five Months Ended May 31, 2007</td><td rowspan="2">Five Months Ended May 31, 2007</td><td></td></tr><tr><td colspan="2">Year Ended December 31,</td><td>2008</td><td>2007</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td></td><td></td><td></td></tr><tr><td></td><td colspan="3">(In millions)</td><td></td><td></td><td></td></tr><tr><td>Revenues(a)</td><td>$     40.4</td><td>$     44.0</td><td>$     40.2</td><td></td><td></td><td></td></tr><tr><td>Operating expenses and noncontrolling interests(a)</td><td>(35.6)</td><td>(38.3)</td><td>(34.8)</td><td></td><td></td><td></td></tr><tr><td>Equity in earnings of Thermo Cogeneration Partnership(b)</td><td>-</td><td>-</td><td>8.0</td><td></td><td></td><td></td></tr><tr><td>Segment earnings before DD&amp;A</td><td>$     4.8</td><td>$     5.7</td><td>$     13.4</td><td></td><td></td><td></td></tr></table>

(a) Upon the adoption of Accounting Standards Update No. 2009-17, which amended the codification’s “Consolidation” topic, on January 1, 2010, Triton Power operations will no longer be consolidated into our financial statements, but be treated as an equity investment, resulting in decreases to revenues, operating expenses and noncontrolling interests with no impact to segment earnings before DD&A. See Note 18 of the accompanying Notes to Consolidated Financial Statements for “Recent Accounting Pronouncements.”

(b) This equity interest was part of the sale effective January 1, 2008 as discussed above.

Year Ended December 31, 2009 vs. 2008

Power’s segment earnings before DD&A decreased by $0.9 million for the year ended December 31, 2009 as compared to 2008, primarily due to lower operating fees at the Snyder Plant, which we operate on behalf of the CO \( _{2} \) -KMP segment.

Seven Months Ended December 31, 2007

Earnings before DD&A for the seven months ended December 31, 2007 reflect the positive impacts of (i) contributions of $2.0 million of earnings before DD&A from Triton Power, (ii) $8.0 million of equity earnings from our investment in Thermo Cogeneration Partnership and (iii) $1.4 million of earnings from the Thermo Greeley facility associated with gas purchase and sale agreements. These favorable impacts to earnings were partially offset by an unfavorable impact to operating revenues associated with 2006 equipment sales.

Five Months Ended May 31, 2007

Earnings before DD&A for the five months ended May 31, 2007 reflect an unfavorable impact to revenues associated with 2006 equipment sales. These unfavorable impacts to earnings were partially offset by (i) contributions of $1.3 million of earnings from Triton Power, (ii) contributions of $1.2 million of earnings from the Thermo Greeley facility associated with gas purchase and sales agreements and (iii) our $5.1 million of equity earnings from our investment in Thermo Cogeneration Partnership.



## Other

<table><tr><td rowspan="3"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Seven Months Ended</td><td rowspan="2">Five Months Ended May 31, 2007</td><td rowspan="2">Five Months Ended May 31, 2007</td><td colspan="2">Predecessor Company</td></tr><tr><td>Year Ended December 31, 2009</td><td>2008</td><td>2007</td><td></td></tr><tr><td>Kinder Morgan, Inc. general and administrative expense</td><td>$ (42.7)</td><td>$ (54.6)</td><td>$ (33.2)</td><td>$ (138.6)</td><td></td><td></td></tr><tr><td>Kinder Morgan Energy Partners general and administrative expense</td><td>(330.3)</td><td>(297.9)</td><td>(142.4)</td><td>(136.2)</td><td></td><td></td></tr><tr><td>Terasen general and administrative expense</td><td>-</td><td>-</td><td>-</td><td>(8.8)</td><td></td><td></td></tr><tr><td>Consolidated general and administrative expense</td><td>$ (373.0)</td><td>$ (352.5)</td><td>$ (175.6)</td><td>$ (283.6)</td><td></td><td></td></tr><tr><td>Kinder Morgan, Inc. interest, net</td><td>$ (164.4)</td><td>$ (240.1)</td><td>$ (357.9)</td><td>$ (70.4)</td><td></td><td></td></tr><tr><td>Kinder Morgan Energy Partners interest, net</td><td>(409.0)</td><td>(388.2)</td><td>(236.4)</td><td>(155.0)</td><td></td><td></td></tr><tr><td>Terasen interest, net</td><td>-</td><td>-</td><td>-</td><td>(24.8)</td><td></td><td></td></tr><tr><td>Other, net (a)</td><td>(10.3)</td><td>4.7</td><td>7.6</td><td>(4.4)</td><td></td><td></td></tr><tr><td>Unallocable interest and other, net</td><td>$ (583.7)</td><td>$ (623.6)</td><td>$ (586.7)</td><td>$ (254.6)</td><td></td><td></td></tr><tr><td>Kinder Morgan Management noncontrolling interests</td><td>$ (53.6)</td><td>$ (80.5)</td><td>$ (35.8)</td><td>$ (17.1)</td><td></td><td></td></tr><tr><td>Kinder Morgan Energy Partners noncontrolling interests</td><td>(210.0)</td><td>(302.4)</td><td>7.3</td><td>(75.1)</td><td></td><td></td></tr><tr><td>Triton noncontrolling interests</td><td>(11.3)</td><td>(13.0)</td><td>(9.0)</td><td>2.3</td><td></td><td></td></tr><tr><td>Other noncontrolling interests</td><td>(3.2)</td><td>(0.2)</td><td>(0.1)</td><td>(0.8)</td><td></td><td></td></tr><tr><td>Net income attributable to noncontrolling interests(b)</td><td>$ (278.1)</td><td>$ (396.1)</td><td>$ (37.6)</td><td>$ (90.7)</td><td></td><td></td></tr></table>

(a) “Other, net” primarily represents offset to noncontrolling interests and interest income shown above and included in segment earnings.

(b) 2008 and 2007 periods restated for certain provisions concerning the accounting and reporting for noncontrolling interests; see Note 2 of the accompanying Notes to Consolidated Financial Statements.

Year Ended December 31, 2009 vs. 2008

Consolidated general and administrative expense increased $20.5 million (5.8%) in 2009 compared to 2008. The $32.4 (10.9%) million increase in Kinder Morgan Energy Partners' general and administrative expense includes $15.8 million from higher employee benefit and payroll tax expenses in 2009 and $10.7 million due to fewer overhead expenses meeting the criteria for capitalization. Kinder Morgan, Inc.'s general and administrative expense, which decreased $11.9 million (21.8%), includes an $8.4 million decrease in legal costs for 2009 as compared to 2008.

The $39.9 million (6.4%) decrease in interest and other, net for 2009 relative to 2008, was primarily due from using $5.9 billion of proceeds received from the sale of an 80% ownership interest in NGPL PipeCo LLC to pay down debt in early 2008; see Note 3 of the accompanying Notes to Consolidated Financial Statements. This reduction in our interest expense was partially offset by higher interest expense from increased debt balances at Kinder Morgan Energy Partners required to support its capital expansion programs.

Net income attributable to noncontrolling interests, which represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries (primarily Kinder Morgan Energy Partners) which are not held by us, decreased $118.0 million in 2009 (29.8%) when compared to 2008. The decrease in our noncontrolling interests was primarily due to our lower net income in 2009 from our consolidated subsidiaries.

Seven Months Ended December 31, 2007

Kinder Morgan, Inc. general and administrative expense for the seven months ended December 31, 2007 includes $19.4 million of compensation expense and Kinder Morgan Energy Partners general and administrative expense includes $108.6 million of compensation expense and $28.8 million of outside services.

Interest, net for the seven months ended December 31, 2007 includes $179.6 million of Kinder Morgan, Inc. interest expense related to additional debt incurred as part of its Going Private transaction and $165.5 million of Kinder Morgan, Inc. interest expense not related to the Going Private transaction.

Five Months Ended May 31, 2007

Kinder Morgan, Inc.’s general and administrative expense for the five months ended May 31, 2007 includes $114.8 million related to the Going Private transaction. In addition, during the five months ended May 31, 2007 Kinder Morgan,



Inc. incurred $4.3 million in selling expenses associated with the sale of its (i) U.S. based retail natural gas distribution and related operations, (ii) Terasen Gas business and (iii) Terasen Pipelines (Corridor) Inc. Kinder Morgan Energy Partners' general and administrative expense for the five months ended May 31, 2007 includes $26.2 million allocated to it related to the Going Private transaction.

## Income Taxes—Continuing Operations

Year Ended December 31, 2009 vs. 2008

The $21.2 million increase in tax expense to $325.6 million for 2009 as compared to $304.4 million for 2008 is primarily due to (i) certain one–time non-cash deferred tax expenses related to (a) the restructuring of certain subsidiaries of Kinder Morgan Canada–KMP and us, (b) the treatment of Trans Mountain Pipeline Inc., a subsidiary of Kinder Morgan Canada–KMP, as a non–regulated entity, (c) the impact on deferred taxes of a decrease in Kinder Morgan Canada–KMP’s Canadian tax rate in 2008 and (ii) higher state income taxes. The increase is partially offset by (i) the tax impact on lower pretax earnings of Kinder Morgan Management and Kinder Morgan Energy Partners’ domestic corporate subsidiaries, (ii) an increase in nondeductible goodwill related to our investment in Kinder Morgan Energy Partners, (iii) the impact on deferred taxes of a decrease in our state tax rate, (iv) lower additions in 2009 to our Uncertainty in Income Taxes (FIN 48) reserve, (v) lower adjustments in 2009 to true-up our book tax provision to the federal and state tax returns filed and (vi) small out-of-period adjustments related to current and deferred taxes.

## Seven Months Ended December 31, 2007

The seven months ended December 31, 2007 income tax expense from continuing operations of $227.4 million consists of (i) $166.5 million of federal income tax expense, (ii) $12.8 million related to Kinder Morgan Management noncontrolling interests income tax expense, (iii) $27.6 million due to income taxes on foreign earnings at different tax rates, (iv) $11.9 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners' United States income tax provision and (v) $10.9 million of state income taxes. The above income tax expense is net of $2.3 million of other income tax items.

## Five Months Ended May 31, 2007

The five months ended May 31, 2007 income tax expense from continuing operations of $135.5 million consists of (i) $34.0 million federal income tax benefit on the $97.2 million loss from continuing operations before income taxes, (ii) $16.6 million tax benefit from the Terasen acquisition financing structure and (iii) $2.0 million of other income tax items. These tax benefits and credits were offset by income tax expenses consisting of (i) $30.7 million of income taxes on non-deductible fees associated with the Going Private transaction, (ii) $132.1 million of expense related to the Trans Mountain goodwill impairment of $377.1 million, which is not deductible for tax purposes, (iii) $6.2 million related to Kinder Morgan Management noncontrolling interests income tax expense, (iv) $8.4 million due to income taxes on foreign earnings at different tax rates, (v) $4.0 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners' United States income tax provision and (vi) $6.7 million of state income taxes.

See Note 4 of the accompanying Notes to Consolidated Financial Statements for additional information on income taxes.

## Income Taxes—Realization of Deferred Tax Assets

A capital loss carryforward can be utilized to reduce capital gain during the five years succeeding the year in which a capital loss is incurred. We closed the sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of approximately $3.4 billion ($3.7 billion) including cash and assumed debt. We recorded a book gain on this disposition of $55.7 million in the second quarter of 2007. The sale resulted in a capital loss of $998.6 million for tax purposes. Approximately $223.3 million of the Terasen Inc. capital loss was utilized to reduce capital gain principally associated with the sale of our U.S.-based retail natural gas operations resulting in a tax benefit of approximately $82.2 million during 2007.

At December 31, 2007, we had a remaining capital loss carryforward of $775.1 million, all of which was utilized to reduce the capital gain associated with the sale of our 80% ownership interest in the NGPL PipeCo LLC business segment and other dispositions, resulting in a tax benefit of approximately $279.5 million during 2008.



## Liquidity and Capital Resources

## General

We believe that we and our subsidiaries and investments, including Kinder Morgan Energy Partners, have liquidity and access to financial resources, as demonstrated through our results for the year ended December 31, 2009 as discussed below, sufficient to meet future requirements for working capital, debt repayment and capital expenditures associated with existing and future expansion projects, along with payment of our dividends and Kinder Morgan Energy Partners' distributions.

We have generated $1,587.5 in cash from operations during 2009;

In 2009, Kinder Morgan Energy Partners has demonstrated its continued access to the equity market by raising approximately $1,155.6 million in net proceeds from equity offerings in the aggregate of 22.9 million additional common units;

Kinder Morgan Energy Partners has demonstrated substantial flexibility in the debt market by issuing $2 billion in principal amount of long-term senior notes in 2009 that generated $1,980.7 million in net proceeds; and

We had available credit capacity of approximately $0.8 billion and Kinder Morgan Energy Partners had available credit capacity of approximately $1.2 billion under existing bank credit facilities as of December 31, 2009.

The primary cash requirements for us and our subsidiaries, 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, Kinder Morgan Energy Partners' quarterly distributions to its public common unitholders and our stockholder dividends. In addition to utilizing cash generated from operations, Kinder Morgan Energy Partners' cash requirements for expansion capital expenditures can be met through borrowings under its senior unsecured revolving bank credit facility, issuing long-term notes or additional common units, or the proceeds from purchases of additional Kinder Morgan Energy Partners' i-units by Kinder Morgan Management with the proceeds from issuances of additional Kinder Morgan Management shares. Our cash requirements continue to be met through cash from our operations and borrowings under our secured revolving bank credit facility.

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 Kinder Morgan Energy Partners’ costs related to operating and maintaining its facilities and require it to install new emission controls on its facilities, acquire allowances for its greenhouse gas emissions, pay taxes related to its greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Kinder Morgan Energy Partners is not able at this time to estimate such increased costs; however, they could be significant.

## Dividends

We anticipate paying future quarterly dividends in amounts equal to our free cash flow subject to any reserves we believe are necessary for non-recurring and/or extraordinary items including the purchase of Kinder Morgan Energy Partners' units. We define free cash flow as cash distributions and dividends received less cash paid for interest, taxes, capital expenditures and general and administrative expenses. Our dividend philosophy, as well as the declaration and payment of dividends are subject to the sole discretion of our Board of Directors, are reconsidered every quarter and could change at any time. During the year ended December 31, 2009, we paid cash dividends on our common stock totaling $650.0 million to our sole stockholder, which then made dividends to Kinder Morgan Holdco LLC. Our Board of Directors declared a dividend of $150.0 million on January 20, 2010, which was paid on February 16, 2010.

## Credit Ratings and Capital Market Liquidity

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 Kinder Morgan Energy Partners' $1.85 billion senior unsecured revolving bank credit facility. During the first quarter of 2009, Kinder Morgan Energy Partners amended its facility to remove Lehman Brothers Commercial Bank as a lender, thus reducing the facility by $63.3 million (see Note 8 of the accompanying Notes to Consolidated Financial Statements). 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 Kinder Morgan Energy Partners' long-term credit rating to negative from stable (but affirmed its long-term credit rating at BBB), due to its previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project. At the same time, Standard & Poor's Rating Services lowered Kinder Morgan Energy Partners' short-term credit rating to A-3 from A-2. As a



result of this revision to Kinder Morgan Energy Partners' short-term credit rating and the commercial paper market conditions, it has been unable to access commercial paper borrowings.

On February 25, 2010, Standard & Poor's Rating Services updated its outlook on Kinder Morgan Energy Partners' long-term credit rating to stable from negative (and affirmed its long-term credit rating at BBB), due to Kinder Morgan Energy Partners' completion of its large pipeline projects, the lower guaranteed debt obligations and expected cash flows associated with these projects. At the same time, Standard & Poor's raised Kinder Morgan Energy Partners' short-term credit rating to A-2 from A-3.

On May 6, 2009, Moody's Investors Service downgraded Kinder Morgan Energy Partners' commercial paper rating to Prime-3 from Prime-2 and assigned a negative outlook to its long-term credit rating. The downgrade and negative outlook were primarily related to increases in Kinder Morgan Energy Partners' outstanding debt balance that have occurred since the beginning of 2009. However, Kinder Morgan Energy Partners continues to maintain an investment grade credit rating, and all of its long-term credit ratings remain unchanged since December 31, 2008. Furthermore, Kinder Morgan Energy Partners expects that its financing and short-term liquidity needs will continue to be met through borrowings made under its bank credit facility. Nevertheless, Kinder Morgan Energy Partners' ability to satisfy its financing requirements or fund its planned capital expenditures will depend upon its 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 its control.

Additionally, some of Kinder Morgan Energy Partners' 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. Kinder Morgan Energy Partners has and is 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 its credit position relating to amounts owed from these customers. Kinder Morgan Energy Partners cannot provide assurance that one or more of its current or future financially distressed customers will not default on its obligations to it or that such a default or defaults will not have a material adverse effect on its business, financial position, future results of operations, or future cash flows; however, Kinder Morgan Energy Partners believes it has provided adequate allowance for such customers.

## Short-term Liquidity

Our principal sources of short-term liquidity are our $1.0 billion secured revolving bank credit facility, Kinder Morgan Energy Partners' $1.85 billion senior unsecured revolving bank credit facility and cash provided by operations. These facilities can be used for the respective entity's general corporate or partnership purposes.

The following represents the revolving credit facilities that were available to Kinder Morgan, Inc. and Kinder Morgan Energy Partners, respectively, short-term debt outstanding under the credit facilities and available borrowing capacity under the facilities after deducting (i) outstanding letters of credit, (ii) outstanding borrowings under the credit facilities and (iii) the lending commitments made by Lehman Brothers Commercial Bank, which was cancelled in connection with the Lehman Brothers bankruptcy (as discussed above).

<table><tr><td rowspan="2"></td><td colspan="3">At December 31, 2009</td></tr><tr><td>Short-term Debt Outstanding</td><td>Available Borrowing Capacity</td><td></td></tr><tr><td>Credit Facilities</td><td></td><td></td><td></td></tr><tr><td>Kinder Morgan, Inc.</td><td></td><td></td><td></td></tr><tr><td>$1.0 billion, six-year secured revolver, due May 2013</td><td>$</td><td>171.0</td><td>$ 758.8</td></tr><tr><td>Kinder Morgan Energy Partners</td><td></td><td></td><td></td></tr><tr><td>$1.85 billion, five-year unsecured revolver, due August 2010(a)</td><td>$</td><td>300.0</td><td>$ 1,203.8</td></tr></table>

(a) Kinder Morgan Energy Partners plans to negotiate a renewal of its bank credit facility before its maturity date.

Our outstanding short-term debt as of December 31, 2009 was $768.7 million, primarily consisting of (i) $300.0 million in outstanding borrowings under Kinder Morgan Energy Partners' credit facility, (ii) $251.9 million (including $1.9 million of unamortized discounts and purchase accounting attributable to the Going Private transaction) for Kinder Morgan Energy Partners' 7.50% senior notes that mature on November 1, 2010 and (iii) $171.0 million in outstanding borrowings under our senior secured credit facility. Apart from our current portion of debt and the fair value of derivative contracts, our current



assets exceed our current liabilities by approximately $86.0 million at December 31, 2009. Given our expected cash flows from operations, our unused debt capacity of our credit facilities as discussed above, and based on our projected cash needs in the near term, we do not expect any liquidity issues to arise.

## Capital Expenditures

Our sustaining capital expenditures for the year ended December 31, 2009 were $172.7 million (including approximately $0.2 million for Kinder Morgan Energy Partners' proportionate share of Rockies Express' sustaining capital expenditures). Our forecasted expenditures for 2010 for sustaining capital expenditures are approximately $208.3 million (including $0.1 million for Kinder Morgan Energy Partners' proportionate shares of the Rockies Express Pipeline and Midcontinent Express Pipeline projects). 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 Pipeline LLC and Midcontinent Express Pipeline LLC can each fund their own cash requirements for capital expenditures through borrowings under their respective credit facilities, 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 the accompanying Consolidated Statements of Cash Flows for the years ended December 31, 2009 and 2008 were $1,151.8 million and $2,361.4 million, respectively, primarily related to Kinder Morgan Energy Partners. The year-to-year decrease in discretionary capital expenditures in 2009 versus 2008 was mainly due to higher capital expenditures made during 2008 on Kinder Morgan Energy Partners' major natural gas pipeline projects and on its Trans Mountain crude oil and refined petroleum products pipeline system. Kinder Morgan Energy Partners is forecasting $824.8 million for discretionary capital expenditures in its 2010 budget.

In addition to the discretionary capital expenditures, Kinder Morgan Energy Partners 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 in the accompanying Consolidated Balance Sheets and accounted for under the equity method of accounting), primarily to fund its proportionate share of both construction and preconstruction costs and the repayment of senior notes by Rockies Express Pipeline LLC in August 2009. Generally, we and Kinder Morgan Energy Partners fund discretionary capital expenditures and investment contributions through borrowings under our respective bank credit facilities. To the extent this source of funding is not sufficient for Kinder Morgan Energy Partners, it generally funds additional amounts through the issuance of long-term notes or common units for cash. During 2009, Kinder Morgan Energy Partners used sales of common units and the issuance of senior notes to refinance portions of its short-term borrowings under its bank credit facility.

## Capital Requirements for Recent Transactions

For the years ended December 31, 2009 and 2008, Kinder Morgan Energy Partners' net cash outlays for the acquisition of assets and investments totaled $328.9 million and $16.8 million (net of a $23.4 million cash contribution Kinder Morgan Energy Partners received in April 2008 from us as a result of a certain true-up provision in its Trans Mountain acquisition agreement). All of Kinder Morgan Energy Partners' 2009 and 2008 asset acquisitions and divestitures are discussed further in Note 3 of the accompanying Notes to Consolidated Financial Statements.



## Cash Flows

The following table summarizes our net cash flows from operating, investing and financing activities for each period presented.

<table><tr><td rowspan="4"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31,</td><td rowspan="2">Five Months Ended May 31, 2007</td><td></td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td></td></tr><tr><td colspan="3">(In millions)</td><td></td><td>(In millions)</td><td></td></tr><tr><td>Net Cash Provided by (Used in)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating activities</td><td>$     1,587.5</td><td>$     1,396.8</td><td>$     1,044.5</td><td>$     603.0</td><td></td><td></td></tr><tr><td>Investing activities</td><td>(3,477.5)</td><td>3,210.0</td><td>(15,751.1)</td><td>723.7</td><td></td><td></td></tr><tr><td>Financing activities</td><td>1,931.0</td><td>(4,628.1)</td><td>12,956.8</td><td>440.9</td><td></td><td></td></tr><tr><td>Effect of Exchange Rate Changes on Cash</td><td>6.0</td><td>(8.7)</td><td>(2.8)</td><td>7.6</td><td></td><td></td></tr><tr><td>Cash Balance Included in Assets Held for Sale</td><td>-</td><td>-</td><td>(1.1)</td><td>(2.7)</td><td></td><td></td></tr><tr><td>Net Increase (Decrease) in Cash and Cash Equivalents</td><td>$     47.0</td><td>$      (30.0)</td><td>$      (1,753.7)</td><td>$     1,772.5</td><td></td><td></td></tr></table>

Year Ended December 31, 2009 vs. 2008

Operating Activities

The net increase of $190.7 million (14%) in cash provided by operating activities in the year ended December 31, 2009 compared to the respective 2008 period was primarily attributable to:

• a $557.6 million increase in cash from overall higher net income, net of non-cash items;

- a $35.4 million increase in cash related to higher distributions received from equity investments in 2009—chiefly due to incremental distributions received from Kinder Morgan Energy Partners' equity investment in 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.

The overall increase in year-to-year distributions from equity investments includes a $43.0 million decrease in distributions received from the equity investment in the Express pipeline system, primarily attributable to the June 2008 exchange of a preferred equity interest in Express US Holdings LP for two subordinated notes from US Holdings LP (discussed in Note 11 of the accompanying Notes to Consolidated Financial Statements);

- $23.8 million of non cash expense associated with adjustments to long-term receivables for Kinder Morgan Energy Partners’ environmental cost recoveries recognized in the fourth quarter of 2009;

- a $379.4 million increase in cash outflows relative to net changes in working capital items, primarily driven by (i) 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), (ii) higher payments in 2009 for both the settlement of certain refined product imbalance liabilities owed to U.S. military customers of the Products Pipelines-KMP business segment and (iii) a net decrease in estimated current tax accruals; and

- a $46.0 million decrease in cash from settlements related to the early termination of interest rate swap agreements, primarily attributable to Kinder Morgan Energy Partners’ January 2009 termination of a fixed-to-floating interest rate swap agreement having a notional principal amount of $300 million and a maturity date of March 15, 2031, for which it received $144.4 million, compared to $194.3 million it received in 2008 for the termination of two fixed-to-variable interest rate swap agreements having a combined notional principal amount of $700 million.

## Investing Activities

The net increase in cash used of $6,687.5 million in investing activities in the year ended December 31, 2009 compared to the respective 2008 period was primarily attributable to:

• a $2,899.3 million cash inflow in 2008 for net cash proceeds received from the sale of an 80% interest in NGPL PipeCo LLC;



• a $3,106.4 million cash inflow in 2008 for proceeds received from NGPL PipeCo LLC restricted cash;

- a $1,685.6 million increase in cash used due to higher contributions to equity investees in 2009, relative to 2008. The increase was primarily driven by incremental contributions to Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Express 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 Pipeline LLC in August 2009. As discussed in Note 6 of the accompanying Consolidated Financial Statements, Kinder Morgan Energy Partners contributed a combined $2,040.8 million in 2009 compared to $342.5 million in 2008 to partially fund its proportionate share of these three pipeline projects;

- a $281.3 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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners paid to acquire a 40% membership interest in Endeavor Gathering LLC effective November 1, 2009;

- a $126.7 million net increase in cash used for investments versus proceeds from margin and restricted deposits in 2009 compared to 2008. The decrease in cash was primarily due to the return of margin deposits in 2008, which were posted in a prior period. Margin money is deposited with counterparties in order to maintain certain energy commodity hedging positions and 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 the hedging contracts;

- a $63.2 million decrease in cash received relative to 2008, due to lower net proceeds received from the sales of investments, property, plant and equipment, and other net assets (net of salvage and removal costs). The decrease in cash sales proceeds was driven primarily by $63.1 million received for the sale of our interest in three natural gas-fired power plants in Colorado in the first quarter of 2008;

- a $1,221.0 million decrease in cash used for capital expenditures—largely due to Kinder Morgan Energy Partners’ higher investment undertaken in 2008 to construct its Kinder Morgan Louisiana Pipeline and to expand its Trans Mountain crude oil and refined petroleum products pipeline system;

- a $219.2 million decrease in cash used due to Kinder Morgan Energy Partners’ receipt, in 2009, of the full repayment of a $109.6 million loan it made in December 2008 to a single customer of its Texas intrastate natural gas pipeline group;

- a $27.6 million increase in cash relative to 2008, related to returns of capital received from equity investments in excess of the equity investees' cumulative earnings, primarily consisting of (i) a $22.9 million increase from Kinder Morgan Energy Partners' equity investments, described following, and (ii) a $4.7 million increase from our equity investment in NGPL PipeCo LLC.

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 Pipeline LLC then made distributions to its two member owners (Energy Transfer Partners, L.P. and Kinder Morgan Energy Partners) to reimburse them for prior contributions made to fund its pre-construction costs for the Fayetteville Express Pipeline, and Kinder Morgan Energy Partners received returns of capital totaling $112.0 million. Prior to the establishment of its credit facility, Fayetteville Express Pipeline LLC funded its pipeline construction costs with contributions from its member owners.

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 Express Pipeline LLC 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. Kinder Morgan Energy Partners' proportionate share of these distributions was $89.1 million.

## Financing Activities

The net increase of $6,559.1 million in cash provided by financing activities in the year ended December 31, 2009 compared to the respective 2008 period was primarily attributable to:

- a $6,763.5 million decrease in cash used for overall debt financing activities, which include issuances and payments of debt and debt issuance costs. The year-to-year decrease in cash used was primarily due to (i) a $5,421.0 million decrease in cash used due to lower net repayments of senior notes, discussed following; (ii) a $589.1 million increase in cash due to net commercial paper repayments by Kinder Morgan Energy Partners in 2008; (iii) a $452.4 million increase in cash from lower net repayments under our bank credit facility and (iv) a $300.0 million increase in cash from incremental net borrowings under Kinder Morgan Energy Partners' bank credit facility in 2009.



The year-to-year increases and decreases in cash inflows from commercial paper and credit facility borrowings were related in part to Kinder Morgan Energy Partners' short-term credit rating downgrade discussed above in "Credit Ratings and Capital Market Liquidity," and in part to the year-to-year changes in working capital items. The increase in cash inflows from changes in senior notes outstanding primarily includes (i) the combined $5,789.3 million of our Going Private debt that was repaid in 2008 primarily using proceeds from the sale of an 80% interest in NGPL PipeCo LLC and (ii) the net $1,730.7 million Kinder Morgan Energy Partners received after issuing and repaying senior notes in 2009 (discussed in Note 8 of the accompanying Notes to Consolidated Financial Statements) versus the combined $2,080.2 million Kinder Morgan Energy Partners received from its three public offerings of senior notes in 2008. Kinder Morgan Energy Partners used the proceeds from its first two 2008 offerings to reduce borrowings under its commercial paper program and used the proceeds from the third 2008 debt offering and from each of the 2009 offerings to reduce the borrowings under its revolving bank credit facility;

- a $594.1 million increase in cash from noncontrolling interests contributions primarily related to Kinder Morgan Energy Partners' issuances totaling approximately 22.9 million common units in 2009 receiving combined net proceeds (after underwriting commissions and expenses) of $1,155.6 million versus issuances totaling approximately 10.7 million common units in 2008 receiving combined net proceeds (after underwriting commissions and expenses) of $560.9 million;

• $650.0 million cash used in 2009 to pay dividends;

- a $113.7 million increase in cash used for noncontrolling interests distributions, primarily due to an increase in Kinder Morgan Energy Partners' cash distributions to its common unit owners; and

- a $23.0 million decrease in cash inflows from net changes in cash book overdrafts—resulting from timing differences on checks issued but not yet presented for payment.

## 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):

<table><tr><td>Entity</td><td>Investment Type</td><td>Our Ownership Interest</td><td>Remaining Interest(s) Ownership</td><td>Total Entity Assets(a)</td><td>Total Entity Debt</td><td>Kinder Morgan Energy Partners&#x27; Contingent Share of Entity Debt(b)</td></tr><tr><td>Rockies Express Pipeline LLC(c)</td><td>Limited Liability</td><td>50%</td><td>ConocoPhillips and Sempra Energy</td><td>$ 6,606.2</td><td>$ 2,970.8(d)</td><td>$ 836.4</td></tr><tr><td>Fayetteville Express Pipeline LLC(e)</td><td>Limited Liability</td><td>50%</td><td>Energy Transfer Partners, L.P.</td><td>$ 406.1</td><td>$ 355.0</td><td>$ 177.5</td></tr><tr><td>Cortez Pipeline Company</td><td>General Partner</td><td>50%</td><td>(f)</td><td>$ 76.1</td><td>$ 152.8</td><td>$ 76.4(g)</td></tr><tr><td>Midcontinent Express Pipeline LLC(h)</td><td>Limited Liability</td><td>50%</td><td>Energy Transfer Partners, L.P.</td><td>$ 2,227.1</td><td>$ 828.3(i)</td><td>$ 14.8(j)</td></tr><tr><td>Nassau County, Florida Ocean Highway and Port Authority(k)</td><td>N/A</td><td>N/A</td><td>Nassau County, Florida Ocean Highway and Port Authority</td><td>N/A</td><td>N/A</td><td>$ 19.8</td></tr></table>

(a) Principally property, plant and equipment.

(b) Represents the portion of the entity’s debt that Kinder Morgan Energy Partners 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%). Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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) Kinder Morgan Energy Partners is severally liable for its percentage ownership share (50%) of the Cortez Pipeline Company debt. As of December 31, 2009, Shell Oil Company shares Kinder Morgan Energy Partners' several guaranty obligations jointly and severally for $42.9 million of Cortez's debt balance; however, Kinder Morgan Energy Partners is obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty. Accordingly, as of December 31, 2009 Kinder Morgan Energy Partners has a letter of credit in the amount of $21.4 million issued by JP Morgan Chase, in order to secure its 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 Pioneer, LLC 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 Pioneer, LLC 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 Kinder Morgan Energy Partners or the other member owners of Midcontinent Express Pipeline LLC for any failure by Midcontinent Express Pipeline LLC to perform or comply with its obligations pursuant to the notes or the indenture.

(j) In addition to Kinder Morgan Energy Partners' 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. Kinder Morgan Energy Partners' contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).

(k) Arose from Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement. In December 2002, Kinder Morgan Energy Partners issued a $28 million letter of credit under its 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 Kinder Morgan Energy Partners' 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 and Kinder Morgan Energy Partners' contingent debt obligations, see Note 12 of the accompanying Notes to Consolidated Financial Statements.

Kinder Morgan Energy Partners accounts for its 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, Kinder Morgan Energy Partners' share of earnings, based on its 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 of the accompanying Notes to Consolidated Financial Statements.



## Contractual Obligations and Commercial Commitments

<table><tr><td rowspan="3"></td><td colspan="6">Payments due by period</td></tr><tr><td rowspan="2">Total</td><td colspan="2">Less than</td><td rowspan="2">1-3 years</td><td rowspan="2">3-5 years</td><td rowspan="2">More than 5 years</td></tr><tr><td>1 year</td><td>(In millions)</td></tr><tr><td>Contractual obligations</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Debt borrowings-principal payments</td><td>$ 13,715.5</td><td>$ 766.8</td><td>$ 3,778.4</td><td>$ 1,008.8</td><td>$ 8,161.5</td><td></td></tr><tr><td>Interest payments(a)</td><td>10,601.2</td><td>843.0</td><td>1,469.3</td><td>1,210.3</td><td>7,078.6</td><td></td></tr><tr><td>Lease obligations(b)</td><td>238.8</td><td>43.8</td><td>67.9</td><td>44.2</td><td>82.9</td><td></td></tr><tr><td>Pension and postretirement welfare plans(c)</td><td>324.6</td><td>27.4</td><td>57.4</td><td>60.1</td><td>179.7</td><td></td></tr><tr><td>Other obligations(d)</td><td>11.5</td><td>6.5</td><td>-</td><td>5.0</td><td>-</td><td></td></tr><tr><td>Total</td><td>$ 24,891.6</td><td>$ 1,687.5</td><td>$ 5,373.0</td><td>$ 2,328.4</td><td>$ 15,502.7</td><td></td></tr><tr><td>Other commercial commitments</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Standby letters of credit(e)</td><td>$ 438.8</td><td>$ 343.2</td><td>$ 95.6</td><td>$ -</td><td>$ -</td><td></td></tr><tr><td>Capital expenditures(f)</td><td>$ 260.4</td><td>$ 260.4</td><td>$ -</td><td>$ -</td><td>$ -</td><td></td></tr></table>

(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 Kinder Morgan Energy Partners' purchase and sale agreement with Megaleet Towing Co., Inc. for the acquisition of certain marine vessels effective April 23, 2009.

(e) The $438.8 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 Kinder Morgan Energy Partners Pacific operations' pipelines in the state of California, (ii) a combined $55.5 million in two letters of credit supporting Kinder Morgan Energy Partners' pipeline and terminal operations in Canada, (iii) a combined $55.0 million in two letters of credit supporting Kinder Morgan Energy Partners' hedging of energy commodity price risks, (iv) a combined $33.1 million in four letters of credit required under provisions of our property and casualty, worker's compensation and general liability insurance policies, (v) Kinder Morgan Energy Partners' $30.3 million guarantee under letters of credit totaling $45.5 million supporting Kinder Morgan Energy Partners' International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds, (vi) a $25.4 million letter of credit supporting Kinder Morgan Energy Partners' Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds, (vii) a $24.1 million letter of credit supporting Kinder Morgan Energy Partners' Kinder Morgan Operating L.P. "B" (tax-exempt bonds, (viii) a $21.4 million letter of credit supporting Kinder Morgan Energy Partners' indemnification obligations on the Series D note borrowings of Cortez Capital Corporation, (ix) a combined total of $20.4 million of two letters of credit supporting the subordination of operating fees payable to us for the operation of the Jackson, Michigan power generation facility to payments due under the operating lease of the facilities, (x) a $19.8 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds, (xi) a combined $17.0 million in eight letters of credit supporting environmental and other obligations of Kinder Morgan Energy Partners' and its subsidiaries, (xii) a $16.2 million letter of credit to fund the debt service reserve account required under Kinder Morgan Energy Partners Express System's trust indenture and (xiii) a $5.4 million letter of credit supporting Kinder Morgan Energy Partners' Arrow Terminals, L.P. Illinois Development Revenue Bonds.

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

<table><tr><td>Other Contingent Commitments:</td><td>Contingency</td><td>Amount of Contingent Liability at December 31, 2009</td></tr><tr><td>Guarantor of the Bushton Gas processing plant lease (a)</td><td>Default by ONEOK, Inc.</td><td>Total $54.8 million; Averages $27.4 million per year through 2011</td></tr><tr><td>Jackson, Michigan power plant incremental investment</td><td>Operational performance</td><td>$3 to $8 million per year for 9 years beginning 2010 through 2018</td></tr><tr><td>Jackson, Michigan power plant incremental investment</td><td>Cash flow performance</td><td>Up to a total of $25 million beginning in 2018</td></tr></table>

(a) In conjunction with our sale of the Bushton gas processing facility to ONEOK, Inc., at December 31, 1999, ONEOK, Inc. became primarily liable under the associated operating lease and we became secondarily liable. Should ONEOK, Inc. fail to make payments as required under the lease, we would be required to make such payments, with recourse only to ONEOK, Inc.



## Investment in Kinder Morgan Energy Partners

At December 31, 2009, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management we owned, approximately 33.9 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 16.4 million common units, 5.3 million Class B units and 12.2 million i-units, represent approximately 11.4% of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole common stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 13.2% of Kinder Morgan Energy Partners' total equity interests at December 31, 2009. As of the close of the Going Private transaction, our limited partner interests and our general partner interest represented an approximate 50% economic interest in Kinder Morgan Energy Partners. This difference results from the existence of incentive distribution rights held by the general partner shareholder.

## Noncontrolling Interests Distributions to Kinder Morgan Energy Partners' Common Unit Holders

Kinder Morgan Energy Partners' partnership agreement requires that it distribute 100% of "Available Cash," as defined in its partnership agreement, to its 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 Kinder Morgan Energy Partners' cash receipts, including cash received by its 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. ("SFPP"), in respect of its remaining 0.5% interest in SFPP.

Kinder Morgan Management, as the delegate of Kinder Morgan G.P., Inc., of which we indirectly own all of the outstanding common equity, and the general partner of Kinder Morgan Energy Partners, is granted discretion, subject to the approval of Kinder Morgan G.P., Inc. in certain cases, to establish, maintain and adjust reserves for the proper conduct of its 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 Kinder Morgan Management determines Kinder Morgan Energy Partners' quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Pursuant to Kinder Morgan Energy Partners' partnership agreement, distributions to its 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 its common units, Class B units and i-units relative to the distributions retained by Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners.

Cash from Operations. Cash from operations generally refers to Kinder Morgan Energy Partners' cash balance on the date it commenced operations, plus all cash generated by the operation of its 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 Kinder Morgan Energy Partners' distributions that are funded from borrowings, sales of debt and equity securities and sales or other dispositions of its assets for cash, other than inventory, accounts receivable and other current assets and assets disposed of in the ordinary course of its business.

Rule for Characterizing Distributions. All available cash distributed by Kinder Morgan Energy Partners 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 it 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 Kinder Morgan Management, as the holder of all i-units, will be treated as distributions of available cash, even though the distributions to Kinder Morgan Management are made in additional i-units rather than cash. Kinder Morgan Energy Partners retains this cash and uses it in its business. To date, all of Kinder Morgan Energy Partners' cash distributions have been treated as distributions of cash from operations.



Allocation of Distributions from Operations. Kinder Morgan Energy Partners will distribute cash from operations for each quarter effectively as follows:

first, 98% to the owners of all classes of units pro rata and 2% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners 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 Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners 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 Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners 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 in cash and to Kinder Morgan Management as owners of i-units in the equivalent number of i-units, and 50% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners.

During the year ended December 31, 2009, Kinder Morgan Energy Partners paid distributions of $4.20 per common unit, of which $740.2 million was paid to the public holders (represented in noncontrolling interests) of Kinder Morgan Energy Partners' common units. On January 20, 2010, Kinder Morgan Energy Partners declared a quarterly distribution of $1.05 per common unit for the quarterly period ended December 31, 2009. The distribution was paid on February 12, 2010 to unitholders of record as of January 29, 2010.

Allocation of Distributions from Interim Capital Transactions. Any distribution by Kinder Morgan Energy Partners 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 Kinder Morgan Management as the sole holder of i-units in equivalent i-units; and

2% to Kinder Morgan G.P., Inc. as the general partner of Kinder Morgan Energy Partners, until Kinder Morgan Energy Partners has distributed cash from this source in respect of a common unit outstanding since its 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 Kinder Morgan G.P., Inc.

## Recent Accounting Pronouncements

Please refer to Note 18 of the accompanying Notes to Consolidated Financial Statements 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 service debt or to pay dividends 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 that 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 tariff rates charged by our or those of Kinder Morgan Energy Partners' pipeline subsidiaries implemented by the Federal Energy Regulatory Commission, or other regulatory agencies 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 the ability to expand our facilities;

- difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from Kinder Morgan Energy Partners' 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 include oil and natural gas production from exploration and production areas that we or Kinder Morgan Energy Partners 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 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 Kinder Morgan Energy Partners' ability to offer and sell equity securities and its ability to sell debt securities or obtain debt financing in sufficient amounts to implement that portion of our or Kinder Morgan Energy Partners' business plans that contemplates growth through acquisitions of operating businesses and assets and expansions of facilities;

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

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

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

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

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

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

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

- foreign exchange fluctuations;

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

- the extent of Kinder Morgan Energy Partners’ 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 Kinder Morgan Energy Partners may experience with operational equipment, in well completions and workovers, and in drilling new wells;

- the uncertainty inherent in estimating future oil and natural gas production or reserves that Kinder Morgan Energy Partners may experience;

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



- the timing and success of Kinder Morgan Energy Partners’ and our business development efforts; and

- unfavorable results of litigation and the fruition of contingencies referred to in the accompanying Notes to Consolidated Financial Statements.

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. Other than as required by applicable law, we disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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

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

## Energy Commodity Market Risk

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

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

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

<table><tr><td>J. Aron &amp; Company / Goldman Sachs</td><td>Credit Rating</td></tr><tr><td>Morgan Stanley</td><td>A</td></tr><tr><td>BNP Paribas</td><td>A</td></tr></table>

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 the accompanying Consolidated Statements of Operations, 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 the accompanying Consolidated Balance Sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs.

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

The accumulated components of other comprehensive income are reported separately as accumulated other comprehensive income or loss in the stockholders' equity section of the balance sheet. For us, the amounts included in “Accumulated other comprehensive loss” in the 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 of $167.9 million, included within the Stockholders’ Equity section of the accompanying Balance Sheet as of December 31, 2009, consisted of (i) $95.7 million representing unrecognized net losses on energy commodity price risk management activities, (ii) $12.8 million representing unrecognized net gains relating to foreign currency translation adjustments and (iii) $85.0 million representing unrecognized net losses relating to the employee benefit plans. The total “Accumulated other comprehensive loss” balance of $53.4 million included in the accompanying Consolidated Balance Sheet at December 31, 2008 consisted of (i) $82.4 million representing unrecognized net gains on energy commodity price risk management activities, (ii) $41.1 million representing unrecognized net losses relating to foreign currency translation adjustments and (iii) $94.7 million representing unrecognized net losses relating to the employee benefit plans.

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 of the accompanying Notes to Consolidated Financial Statements included in this report.

## Interest Rate Risk

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

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

As of December 31, 2009 and 2008, the carrying values of our fixed rate debt were approximately $13,083.4 million and $11,355.4 million, respectively. These amounts compare to fair values of $13,676.2 million and $9,838.1 million as of December 31, 2009 and 2008, 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 $731.0 million and $567.4 million, respectively, in the fair values of these instruments.

The carrying value and fair value of our variable rate debt, including associated accrued interest and excluding the value of interest rate swap agreements (discussed below), was $558.9 million and $95.1 million as of December 31, 2009 and 2008, respectively. A hypothetical 10% change of the weighted average interest rate on all of our borrowings (approximately 47 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 $30.2 million and $15.8 million, respectively, in our 2009 and 2008 annual pre-tax earnings.

As of December 31, 2009, we and our subsidiary, Kinder Morgan Energy Partners were party to interest rate swap agreements with a combined notional principal amount of $725.0 million and $5.2 billion, respectively. As of December 31, 2008, we and our subsidiary Kinder Morgan Energy Partners were party to interest rate swap agreements with notional principal amount of $2.8 billion. 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, Kinder Morgan Energy Partners attempts to maintain an overall target mix of approximately 50% fixed rate debt and 50% of variable rate debt, and typically Kinder Morgan, Inc., excluding Kinder Morgan Energy Partners, targets well below that level for variable rate debt. Currently, approximately 29% of our debt, excluding that of Kinder Morgan Energy Partners, is 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 Notes 8 and 13 of the accompanying Notes to Consolidated Financial Statements for additional information on activity related to our debt instruments and interest rate swap agreements.

## Foreign Currency Risk

We are exposed to foreign currency risk from our investments in businesses owned and operated outside the United States. To mitigate this risk, we have a receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreement that has been designated as a hedge of our net investment in Canadian operations. We measure our swap agreement at fair value and we report them on our balance sheet as either an asset or liability under hedge accounting.

A 1% change in the U.S. Dollar to Canadian Dollar exchange rate would impact the fair value of these swap agreements by approximately $1.1 million.

## 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 109.

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

None.

## Item 9A. Controls and Procedures.

## Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners acquired from Megafleet Towing Co., Inc. effective April 23, 2009;

- the natural gas treating business Kinder Morgan Energy Partners acquired from Crosstex Energy, L.P. and Crosstex Energy, Inc. effective October 1, 2009; and

the 40% equity ownership interest in Endeavor Gathering LLC Kinder Morgan Energy Partners acquired effective November 1, 2009.

These businesses, in the aggregate, constituted 0.33% of our total revenues for 2009 and 1.20% 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.



## PART III

Item 10. Directors, Executive Officers and Corporate Governance.

## Directors and Executive Officers

Set forth below is certain information concerning our directors and executive officers. Our directors are elected annually by, and may be removed by, Kinder Morgan Midco Inc., as our sole common shareholder. Kinder Morgan Midco Inc. is indirectly wholly owned by Kinder Morgan Holdco LLC. All of our officers serve at the discretion of our Board of Directors. The ages set forth below are as of December 31, 2009.

<table><tr><td>Name</td><td>Age</td><td>Position</td></tr><tr><td>Richard D. Kinder</td><td>65</td><td>Director, Chairman and Chief Executive Officer</td></tr><tr><td>C. Park Shaper</td><td>41</td><td>Director and President</td></tr><tr><td>Steven J. Kean</td><td>48</td><td>Executive Vice President and Chief Operating Officer</td></tr><tr><td>Kenneth A. Pontarelli</td><td>46</td><td>Director</td></tr><tr><td>Kimberly A. Dang</td><td>40</td><td>Vice President and Chief Financial Officer</td></tr><tr><td>David D. Kinder</td><td>35</td><td>Vice President, Corporate Development and Treasurer</td></tr><tr><td>Joseph Listengart</td><td>41</td><td>Vice President, General Counsel and Secretary</td></tr><tr><td>Thomas A. Martin</td><td>48</td><td>Vice President, Natural Gas Pipelines</td></tr><tr><td>James E. Street</td><td>53</td><td>Vice President, Human Resources and Administration</td></tr></table>

Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. 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 Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc.

C. Park Shaper is Director and President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Shaper was elected President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. He served as Executive Vice President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from July 2004 until May 2005. Mr. Shaper was elected Director of Kinder Morgan Management and Kinder Morgan G.P., Inc. in January 2003 and of Kinder Morgan, Inc. in May 2007. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management upon its formation in February 2001, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan, Inc. in 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 Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kean was elected Executive Vice President and Chief Operating Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. Kinder Morgan, Inc. in January 2006. He served as President, Natural Gas Pipelines of Kinder Morgan Management and Kinder Morgan G.P., Inc. from July 2008 to November 2009. He served as Executive Vice President, Operations of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from May 2005 to January 2006. He served as President, Texas Intrastate Pipeline Group from June 2002 until May 2005. He served as Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. He 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.

Kenneth A. Pontarelli is a Director of Kinder Morgan, Inc. Mr. Pontarelli is a Managing Director of Goldman Sachs & Co. See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for details regarding Goldman Sachs’ ownership of Kinder Morgan Holdco LLC units. Mr. Pontarelli was elected Director of



Kinder Morgan, Inc. upon the consummation of the Going Private transaction in May 2007. He has also served as member of the Board of Managers of Kinder Morgan Holdco LLC since May 2007. He joined Goldman Sachs & Co. in 1997 and was appointed Managing Director in 2004. Mr. Pontarelli currently serves on the board of directors of CVR Energy, Inc., CCS Inc., Cobalt International Energy, Inc. and Energy Future Holdings Corp and Expo International Group Ltd. He received a B.A. from Syracuse University and an M.B.A. from Harvard Business School.

Kimberly A. Dang is Vice President and Chief Financial Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mrs. Dang was elected Chief Financial Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, In May 2005. She served as Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from January 2004 to May 2005. She was elected Vice President, Investor Relations of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2002 and served in that role until January 2009. From November 2001 to July 2002, she served as Director, Investor Relations of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. 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.

David D. Kinder is Vice President, Corporate Development and Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder was elected Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. He was elected Vice President, Corporate Development of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in October 2002. He served as manager of corporate development for Kinder Morgan, Inc. 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 Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan Management upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of Kinder Morgan, Inc. in October 1999. Mr. Listengart was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been an employee of Kinder Morgan G.P., Inc. since March 1998. He 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.

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

James E. Street is Vice President, Human Resources and Administration of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. 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 our Chief Executive Officer since 1997 and of Kinder Morgan Management since its formation in 2001, combined with his significant equity ownership of Kinder Morgan Holdco LLC, which indirectly owns all of our common equity, uniquely qualify him to serve as the Chairman and a Director of Kinder Morgan Management and us.

Mr. Pontarelli’s over 10 years of experience as an investment banker and experience as a director of both public and private companies provide him with an understanding of strategic planning, management and financial matters applicable to us.

Mr. Shaper’s experience as our and Kinder Morgan Management’s President 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.



## Compensation Committee Interlocks and Insider Participation

Our board has no separate compensation committee. Mr. Richard D. Kinder as Chief Manager of Kinder Morgan Holdco LLC makes compensation decisions with respect to our executive officers. None of our executive officers served during 2008 on a board of directors of another entity which has employed any of the members of our board.

## Corporate Governance

Kinder Morgan Midco Inc. is our sole common shareholder. As a result, Kinder Morgan Midco Inc. elects all of our directors and our Board of Directors does not have a nominating and governance committee or a committee that serves a similar purpose.

Mr. Shaper and Mr. Pontarelli comprise our audit committee, established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934. Our board has determined that C. Park Shaper is an “audit committee financial expert.” Mr. Shaper is also our President and is therefore not independent.

We make available free of charge within the “Investors” section of our Internet website, at www.kindermorgan.com, our code of business conduct and ethics (which applies to our senior financial and accounting officers and our chief executive officer, among others). We intend to disclose any amendments to our code of business conduct and ethics, and any waiver from a provision of that code granted to our executive officers or directors, that otherwise would be required to be disclosed on a Form 8-K, on our 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 report and should not be considered part of any report that we file with or furnish to the Securities and Exchange Commission.

## Item 11. Executive Compensation

Our executive officers serve in the same capacities as executive officers of Kinder Morgan G.P., Inc., the general partner of Kinder Morgan Energy Partners, and of Kinder Morgan Management, the delegate of Kinder Morgan G.P., Inc. Certain of our executive officers also serve in the same capacities as officers of Kinder Morgan Holdco LLC, our privately owned parent company. Except as identified otherwise, all information in this Item 11 with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for services rendered to us and our affiliates, including Kinder Morgan Energy Partners, Kinder Morgan G.P., Inc., Kinder Morgan Management and Kinder Morgan Holdco LLC. In this Item 11, “we,” “our” or “us” refers to Kinder Morgan, Inc. and, where appropriate, Kinder Morgan Energy Partners, Kinder Morgan G.P., Inc. and Kinder Morgan Management.

Our board does not have a separately designated compensation committee. Mr. Richard D. Kinder as Chief Manager of Kinder Morgan Holdco LLC makes compensation decisions with respect to our executive officers; however, increases in the compensation of our officers and other management personnel who own units of Kinder Morgan Holdco LLC must be further approved by Kinder Morgan Holdco LLC’s Board of Managers.

The compensation committee of the Board of Directors of Kinder Morgan Management, which committee is generally composed of three independent directors, determines the compensation to be paid by Kinder Morgan Energy Partners to KMGP Services Company, Inc.'s employees and Kinder Morgan Management's and Kinder Morgan G.P., Inc.'s executive officers. For further information regarding KMGP Services Company, Inc., see "Narrative Description of Business—Other" within Items 1 and 2 of this report. As described below, Kinder Morgan Management's compensation committee is aware of the compensation paid to such officers by entities such as us and Kinder Morgan Holdco LLC, but makes its compensation determinations in its sole discretion.

## Compensation Discussion and Analysis

## Program Objectives

We seek to attract and retain executives who will help us achieve our primary business strategy objective of growing the value of our portfolio of businesses. 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 of growing the value of our portfolio of businesses. 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 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 Kinder Morgan Energy Partners and us. 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 us and (ii) a cash distribution per common unit target by Kinder Morgan Energy Partners.

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 our Annual Incentive Plan as a result of reaching designated financial targets established by Mr. Richard D. Kinder and Kinder Morgan Management’s compensation committee, we expect that all compensation paid to our executives would qualify for deductibility under federal income tax rules. Though we are advised that limited partnerships such as Kinder Morgan Energy Partners, and private companies, such as us, are not subject to section 162(m), we and Kinder Morgan Energy Partners have chosen to generally operate as if this code section does apply to us and Kinder Morgan Energy Partners 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 us, units of Kinder Morgan Energy Partners or shares of Kinder Morgan Management were granted to any of our named executive officers; however, as a result of the 2007 Going Private transaction, Kinder Morgan Holdco LLC awarded members of our management Class A-1 and Class B units of Kinder Morgan Holdco LLC. While not awarded by us or Kinder Morgan Energy Partners, Kinder Morgan Management’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 our agreement with our 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.

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 us. 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 the 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 Kinder Morgan Management’s compensation committee review and approve annually the financial goals and objectives of both us and Kinder Morgan Energy Partners 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 Kinder Morgan Management’s compensation committee meetings. If any of our executive officers is also an executive officer of Kinder Morgan G.P., Inc. or Kinder Morgan Management, the compensation determination or recommendation (i) may be with respect to the aggregate compensation to be received by such officer from us, Kinder Morgan Management, and Kinder Morgan G.P., Inc. 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 us, Kinder Morgan Management or Kinder Morgan G.P., Inc., as the case may be, in which case such compensation will be allocated among us, on the one hand, and Kinder Morgan Management, and Kinder Morgan G.P., 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 our 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, our and Kinder Morgan Management’s Board of Directors have approved a new Annual Incentive Plan that mirrors the current plan. The overall purpose of our Annual Incentive Plan is to increase our executive officers’ and our employees’ personal stake in the continued success of Kinder Morgan Energy Partners 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 we and our subsidiaries (including Kinder Morgan Energy Partners) 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 our and our subsidiaries’ (including Kinder Morgan Energy Partners’) 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 we and our subsidiaries (including Kinder Morgan Energy Partners) have met our overall performance objectives as well as how we 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.

All of our employees and the employees of our subsidiaries, including KMG P 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 Kinder Morgan Management’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, Kinder Morgan Management’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 Kinder Morgan Management’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:

• our EBITDA less capital spending, or the EBITDA less capital spending of one of our subsidiaries or business units;

• our free cash flow or the free cash flow of one of our subsidiaries or business units;

• our net income or the net income of one of our subsidiaries or business units;

• our revenues or the revenues of one of our subsidiaries or business units;

• our unit revenues minus unit variable costs or the unit revenues minus unit variable costs of one of our subsidiaries or business units;

- our 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 our subsidiaries or business units;

- our 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 our subsidiaries or business units;

• our capital expenditures or the capital expenditures of one of our subsidiaries or business units;

- our operations and maintenance expense or general and administrative expense, or the operations and maintenance expense or general and administrative expense of one of our subsidiaries or business units;

• our debt-equity ratios and key profitability ratios, or the debt-equity ratios and key profitability ratios of one of our subsidiaries or business units; or

• Kinder Morgan Energy Partners’ distribution per unit

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 Kinder



Morgan Energy Partners, (ii) $646 million free cash flow by us, which were distributions received from Kinder Morgan Energy Partners (including value received in the form of Kinder Morgan Management 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. Kinder Morgan Energy Partners' targets were the same as its 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 Kinder Morgan Management'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, Kinder Morgan Management’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 Kinder Morgan Management’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 us and Kinder Morgan Energy Partners 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. Kinder Morgan Management’s 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.”

Kinder Morgan, Inc. Annual Incentive Plan Bonus Opportunities for 2009

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

(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 Kinder Morgan Management 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 Kinder Morgan Management compensation committee may, in its sole discretion, reduce the award payable by us to any participant for any reason.

We 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.

## Other Compensation

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



Kinder Morgan, Inc. Cash Balance Retirement Plan. Employees of ours and KMGP Services Company, Inc., 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 the accompanying Notes to Consolidated Financial Statements. 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

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

(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.

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, our parent company. Mr. Pontarelli did not receive 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 our 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 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 our 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 our 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.

Other Potential Post-Employment Benefits. On October 7, 1999, Mr. Richard D. Kinder entered into an employment agreement with us pursuant to which he agreed to serve as our Chairman and Chief Executive Officer. His employment agreement provides for a term of three years and one year extensions on each anniversary of October 7 \( ^{th} \) . Mr. Kinder, at his initiative, accepted an annual salary of 1 to demonstrate his belief in our and Kinder Morgan Energy Partners' 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 the 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.



We believe that Mr. Kinder’s employment agreement contains provisions that are beneficial to us and our subsidiaries and accordingly, Mr. Kinder’s employment agreement is extended annually at the request of our and Kinder Morgan Management’s Board of Directors. For example, with limited exceptions, Mr. Kinder is prevented from competing in any manner with us or any of our subsidiaries, while he is employed by us and for 12 months following the termination of his employment with us. 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 us without cause or if Mr. Kinder terminated his employment with us 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.

## 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 Kinder Morgan Energy Partners and Kinder Morgan Holdco LLC (collectively referred to as the “Kinder Morgan 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 Kinder Morgan 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, which 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.

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

(a) Represents amounts paid according to the provisions of the Kinder Morgan, Inc. 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 Kinder Morgan, Inc.’s Cash Balance Retirement Plan.

(c) Amounts include value of contributions to the Kinder Morgan, Inc. 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 Kinder Morgan, Inc. Savings Plan are 2,308, 11,154 and 10,000, respectively. For 2009, Mrs. Dang also has 2,226 in imputed income from company provided cell phone. Amounts in 2007 representing the value of dividends paid on unvested restricted stock awards are as follows: for Mrs. Dang 2,187; for Mr. Kean 1,136; for Mr. Listengart 1,875; and for Mr. Shaper 1,144,375.

(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. 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.



## rants 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 Payouts Under Non-Equity Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the Kinder Morgan, Inc. 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.

<table><tr><td rowspan="2">Name</td><td colspan="4">Estimated Future Payouts Under Non-Equity Incentive Plan Awards (a)</td></tr><tr><td>Threshold</td><td>Target</td><td>Maximum</td><td></td></tr><tr><td>Richard D. Kinder</td><td>$ -</td><td>$ -</td><td>$ -</td><td>-</td></tr><tr><td>Kimberly A. Dang</td><td>500,000</td><td>1,000,000</td><td>1,500,000</td><td></td></tr><tr><td>Steven J. Kean</td><td>750,000</td><td>1,500,000</td><td>2,000,000</td><td></td></tr><tr><td>Joseph Listengart</td><td>500,000</td><td>1,000,000</td><td>1,500,000</td><td></td></tr><tr><td>C. Park Shaper</td><td>750,000</td><td>1,500,000</td><td>2,000,000</td><td></td></tr></table>

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

## Outstanding Equity Awards at Fiscal Year-End

The only unvested equity awards outstanding at the end of fiscal 2009 were the Class B units of Kinder Morgan Holdco LLC awarded in 2007 by Kinder Morgan Holdco LLC to the 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.

<table><tr><td rowspan="2">Name</td><td colspan="3">Stock Awards</td></tr><tr><td>Type of units</td><td>Number of units that have not vested</td><td>Market value of units of stock that have not vested(a)</td></tr><tr><td>Richard D. Kinder</td><td>Class B units</td><td>791,405,452</td><td>N/A</td></tr><tr><td>Kimberly A. Dang</td><td>Class B units</td><td>49,462,841</td><td>N/A</td></tr><tr><td>Steven J. Kean</td><td>Class B units</td><td>158,281,090</td><td>N/A</td></tr><tr><td>Joseph Listengart</td><td>Class B units</td><td>79,140,545</td><td>N/A</td></tr><tr><td>C. Park Shaper</td><td>Class B units</td><td>217,636,499</td><td>N/A</td></tr></table>

(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., Kinder Morgan, Inc. and Kinder Morgan Canada Inc. employ all persons necessary for the operation of our business, and in our opinion, our compensation policies and practices for all persons necessary for the operation of our business do not create risks that are reasonably likely to have a material adverse effect on our business, financial position, results of operations or cash flows.

## Director Compensation

Compensation Committee Interlocks and Insider Participation. Our board has no separate compensation committee. Mr. Richard D. Kinder as Chief Manager of Kinder Morgan Holdco LLC makes compensation decisions with respect to our executive officers. Mr. Kinder has not served during 2008 on a board of directors of another entity which has employed any of the members of our current board.

Directors Fees. None of our directors receive compensation in their capacity as directors. All directors are reimbursed for reasonable travel and other expenses incurred in attending all board and/or committee meetings.



## Compensation Committee Report

Because our Board of Directors does not have a separate compensation committee or other committee performing equivalent functions, our Board of Directors has reviewed and discussed the above Compensation Discussion and Analysis for fiscal year 2009 with management. Based on this review and discussion, the Board has concluded that this Compensation Discussion and Analysis should be included in this annual report on Form 10-K for the fiscal year 2009.

Board of Directors:
Richard D. Kinder
Kenneth A. Pontarelli
C. Park Shaper



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

## Security Ownership

Kinder Morgan Midco Inc., an indirect wholly owned subsidiary of Kinder Morgan Holdco LLC, owns 100% of our outstanding common stock. The following tables set forth information as of January 31, 2010, regarding the beneficial ownership of Kinder Morgan Energy Partners' common units, Kinder Morgan Management's shares and Kinder Morgan Holdco LLC's units by all of our directors, each of the named executive officers identified in Item 11 "Executive Compensation" and by all of our directors and executive officers as a group. Unless otherwise noted, the address of each person below is c/o Kinder Morgan, Inc., 500 Dallas Street, Suite 1000, Houston, Texas 77002.

Amount and Nature of Beneficial Ownership(a)

<table><tr><td rowspan="2">Name</td><td colspan="2">Kinder Morgan Energy Partners Common Units</td><td colspan="2">Kinder Morgan Management Shares</td></tr><tr><td>Number of Units (b)</td><td>Percent of Class</td><td>Number of Shares (c)</td><td>Percent of Class</td></tr><tr><td>Richard D. Kinder (d)</td><td>315,979</td><td>*</td><td>144,464</td><td>*</td></tr><tr><td>C. Park Shaper</td><td>4,000</td><td>*</td><td>30,652</td><td>*</td></tr><tr><td>Kenneth A. Pontarelli</td><td>1,000</td><td>*</td><td>-</td><td>-</td></tr><tr><td>Steven J. Kean</td><td>1,780</td><td>*</td><td>2,118</td><td>*</td></tr><tr><td>Joseph Listengart</td><td>5,498</td><td>*</td><td>1,414</td><td>*</td></tr><tr><td>Kimberly A. Dang</td><td>121</td><td>*</td><td>519</td><td>*</td></tr><tr><td>Directors and Executive Officers as a group (9 persons) (e)</td><td>340,564</td><td>*</td><td>202,985</td><td>*</td></tr></table>

 \( ^{*} \) 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.

(b) As of January 31, 2010, Kinder Morgan Energy Partners had 207,310,563 common units issued and outstanding.

(c) As of January 31, 2010, Kinder Morgan Management had 85,538,263 issued and outstanding shares representing limited liability company interests, including two voting shares owned by Kinder Morgan G.P., Inc.

(d) Includes 7,879 common units and 1,000 Kinder Morgan management shares owned by Mr. Kinder’s spouse. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these common units and shares.

(e) Includes 2,450 restricted common units. Also includes 7,879 common units and 1,000 Kinder Morgan Management shares owned by an executive’s spouse and 786 Kinder Morgan Management 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 Kinder Morgan Management shares.

Amount and Nature of Beneficial Ownership (a)

<table><tr><td>Name</td><td>Kinder Morgan Holdco LLC Class A Units</td><td>% of Class A Units (b)</td><td>Kinder Morgan Holdco LLC Class A-1 Units</td><td>% of Class A-1 Units (c)</td><td>Kinder Morgan Holdco LLC Class B Units</td><td>% of Class B Units (d)</td></tr><tr><td>Richard D. Kinder (e)</td><td>2,424,000,000</td><td>30.6%</td><td>-</td><td>-%</td><td>791,405,452</td><td>40.0%</td></tr><tr><td>C. Park Shaper (f)</td><td>13,598,785</td><td>*</td><td>7,799,775</td><td>28.3%</td><td>217,636,499</td><td>11.0%</td></tr><tr><td>Steven J. Kean (g)</td><td>6,684,149</td><td>*</td><td>3,833,788</td><td>13.9%</td><td>158,281,090</td><td>8.0%</td></tr><tr><td>Kimberly A. Dang (h)</td><td>750,032</td><td>*</td><td>430,191</td><td>1.6%</td><td>49,462,841</td><td>2.5%</td></tr><tr><td>Joseph Listengart (i)</td><td>6,059,449</td><td>*</td><td>3,475,483</td><td>12.6%</td><td>79,140,545</td><td>4.0%</td></tr><tr><td>Kenneth A. Pontarelli (j)</td><td>1,997,795,088</td><td>25.2%</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Directors and Executive Officers as a group (9 persons)</td><td>4,454,118,070</td><td>56.3%</td><td>18,539,303</td><td>67.2%</td><td>1,420,572,786</td><td>71.8%</td></tr></table>

 \( ^{*} \) 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.

(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. Mr. Kinder contributed 23,994,827 shares of Kinder Morgan, Inc. common stock and his wife contributed 5,173 shares of Kinder Morgan, Inc. common stock to Kinder Morgan Holdco LLC that were valued for purposes of Kinder Morgan Holdco LLC’s limited liability agreement at $2,423,477,628 and $522,372, respectively, in exchange for their respective Class A units. The Class B units



received by Mr. Kinder had a grant date fair value as calculated in accordance with the accounting provisions governing share-based compensation of $9,200,000.

(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. Mr. Shaper made a cash investment of $13,598,785 of his after-tax proceeds from the conversion in the Going Private transaction of 82,500 shares of Kinder Morgan, Inc. restricted stock and options to acquire 197,969 shares of Kinder Morgan, Inc. common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Shaper had an aggregate grant date fair value as calculated in accordance with the accounting provisions governing share-based compensation of $4,296,125.

(g) Mr. Kean made a cash investment of $6,684,149 of his after-tax proceeds from the conversion in the Going Private transaction of 78,000 shares of Kinder Morgan, Inc. restricted stock and options to acquire 25,533 shares of Kinder Morgan, Inc. common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Kean had an aggregate grant date fair value as calculated in accordance with the accounting provisions governing share-based compensation of $2,708,095.
(h) 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 Mrs. Dang has voting and disposition power of these Class B Units, but she disclaims ten percent of any beneficial and pecuniary interest in them. Mrs. Dang made a cash investment of $750,032 of her after-tax proceeds from the conversion in the Going Private transaction of 8,000 shares of Kinder Morgan, Inc. restricted stock and options to acquire 24,750 shares of Kinder Morgan, Inc. common stock in exchange for her Class A units. The Class A-1 units and Class B units received by Mrs. Dang had an aggregate grant date fair value as calculated in accordance with the accounting provisions governing share-based compensation of $672,409.

(i) Mr. Listengart made a cash investment of $6,059,449 of his after-tax proceeds from the conversion in the Going Private transaction of 52,500 shares of Kinder Morgan, Inc. restricted stock and options to acquire 48,459 shares of Kinder Morgan, Inc. common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Listengart had an aggregate grant date fair value as calculated in accordance with the accounting provisions governing share-based compensation of $1,706,963.

(j) Consists of 240,454,180 units owned by GS Capital Partners V Fund, L.P., a Delaware limited partnership; 124,208,587 units owned by GS Capital Partners V Offshore Fund, L.P., a Cayman Islands exempted limited partnership; 82,455,031 units owned by GS Capital Partners V Institutional, L.P., a Delaware limited partnership; 9,533,193 units owned by GS Capital Partners V GmbH & Co. KG, a German limited partnership; 234,596,750 units owned by GS Capital Partners VI Fund, L.P., a Delaware limited partnership; 194,297,556 units owned by GS Capital Partners VI Offshore Fund, L.P., a Cayman Islands exempted limited partnership; 64,235,126 units owned by GS Capital Partners VI Parallel, L.P., a Delaware limited partnership; 8,302,031 units owned by GS Capital Partners VI GmbH & Co. KG, a German limited partnership; 250,215,732 units owned by Goldman Sachs KMI Investors, L.P., a Delaware limited partnership; 344,448,791 units owned by GSCP KMI Investors, L.P., a Delaware limited partnership; 49,873,203 units owned by GSCP KMI Investors Offshore, L.P., a Cayman Islands exempted limited partnership; 100,534,014 units owned by GS Global Infrastructure Partners I, L.P., a Delaware limited partnership; 10,740,192 units owned by GS Institutional Infrastructure Partners I, L.P., a Delaware limited partnership; and 284,900,702 units owned by GS Infrastructure Knight Holdings, L.P., a Delaware limited partnership (collectively the "GS Entities"). The GS Entities, of which affiliates of The Goldman Sachs Group, Inc. ("GSG") are the general partner, managing general partner or investment manager, share voting and investment power with certain of its respective affiliates. Mr. Pontarelli is a managing director of Goldman, Sachs & Co. ("GS"), which is a direct and indirect wholly owned subsidiary of GSG. Each of GS, GSG and Mr. Pontarelli disclaims beneficial ownership of the equity interests and the units held directly or indirectly by the GS Entities except to the extent of their pecuniary interest therein, if any. GS, a FINRA member, is an investment banking firm that regularly performs services such as acting as a financial advisor and serving as principal or agent in the purchase and sale of securities. In the future, GS may be called upon to provide similar or other services for us or our affiliates. Each of Mr. Pontarelli, GS and GSG has a mailing address of c/o Goldman, Sachs & Co., 85 Broad Street, 10th Floor, New York, NY 10004. GSG's affiliates that are registered broker-dealers (including specialists and market makers) may from time to time engage in brokerage and trading activities with respect to our securities or those of our affiliates. J. Aron & Company, a wholly-owned subsidiary of GSG, in its ordinary course of business, may enter into commodity hedging transactions with us or our affiliates.

## Equity Compensation Plan Information

The following table sets forth information regarding our equity compensation plans as of December 31, 2009. Specifically, the table provides information regarding Kinder Morgan Energy Partners' Common Unit Compensation Plan for Non-employee Directors, described in Note 12 of the accompanying Notes to Consolidated Financial Statements.

<table><tr><td>Plan category</td><td>Number of securities remaining available for future issuance under equity compensation plans</td></tr><tr><td>Equity compensation plans approved by security holders</td><td>-</td></tr><tr><td>Equity compensation plans not approved by security holders</td><td>74,682</td></tr><tr><td>Total</td><td>74,682</td></tr></table>



## 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 information regarding our related party transactions, see Note 11 of the accompanying Notes to Consolidated Financial Statements.

## Director Independence

Subsequent to the Going Private transaction, our common stock is no longer registered with the SEC or traded on any national securities exchange. However, based upon the listing standards of the New York Stock Exchange, Mr. Pontarelli would be considered an “independent” director. Mr. Richard Kinder, our Chairman and Chief Executive Officer, in his role as Chief Manager of Kinder Morgan Holdco LLC, makes compensation decisions with respect to our executive officers. We do not have a nominating committee or a committee that serves a similar purpose.

## Item 14. Principal Accounting Fees and Services

The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP (in dollars):

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td></td></tr><tr><td>Audit fees (a)</td><td>$ 4,521,218</td><td>$ 4,875,799</td><td></td></tr><tr><td>Tax fees (b)</td><td>2,421,694</td><td>2,568,523</td><td></td></tr><tr><td>Total</td><td>$ 6,942,912</td><td>$ 7,444,322</td><td></td></tr></table>

(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) Includes fees for professional services rendered for tax return review services and Internal Revenue Service assistance, and for general state, local and foreign tax compliance and consulting services. For 2009 and 2008, amounts include fees of $2,231,537 and $2,113,318, respectively, billed to Kinder Morgan Energy Partners for professional services rendered for tax processing and preparation of Forms K-1 for its unitholders.

All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and were pre-approved by our audit committee. Pursuant to the charter of our audit committee, 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.



## PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) (1) Financial Statements

Reference is made to the index of financial statements and supplementary data under Item 8 in Part II.

(2) Financial Statement Schedules

Schedule II - Valuation and Qualifying Accounts is omitted because the required information is shown in Note 2 of the accompanying Notes to Consolidated Financial Statements.

The financial statements, including the notes thereto, of Kinder Morgan Energy Partners, a consolidated subsidiary of Kinder Morgan, Inc., are incorporated herein by reference to pages 112 through 195 of Kinder Morgan Energy Partners' Annual Report on Form 10-K for the year ended December 31, 2009.

(3) Exhibits

Any references made to K N Energy, Inc. in the exhibit listing that follows is a reference to the former name of Kinder Morgan, Inc. and is made because the exhibit being listed and incorporated by reference was originally filed before October 7, 1999, the date of change in the Registrant’s name.

<table><tr><td>Exhibit Number</td><td>Description</td></tr><tr><td>2.1</td><td>— Agreement and Plan of Merger dated August 28, 2006, among Kinder Morgan, Inc., Kinder Morgan Holdco LLC and Kinder Morgan Acquisition Co. (filed as Exhibit 2.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on August 28, 2006 and incorporated herein by reference)</td></tr><tr><td>3.1</td><td>— Amended and Restated Articles of Incorporation of Kinder Morgan, Inc. and amendments thereto (filed as Exhibit 3.1 to Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference)</td></tr><tr><td>3.2</td><td>— Bylaws of Kinder Morgan, Inc. (filed as Exhibit 3.2 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on June 5, 2007 and incorporated herein by reference)</td></tr><tr><td>4.1</td><td>— Indenture dated as of September 1, 1988, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (filed as Exhibit 4(a) to Kinder Morgan, Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 (File No. 1-06446) filed on May 23, 2000 and incorporated herein by reference)</td></tr><tr><td>4.2</td><td>— First supplemental indenture dated as of January 15, 1992, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (filed as Exhibit 4.2 to the Registration Statement on Form S-3 (File No. 33-45091) of K N Energy, Inc. filed on January 17, 1992 and incorporated herein by reference)</td></tr><tr><td>4.3</td><td>— Second supplemental indenture dated as of December 15, 1992, between K N Energy, Inc. and Continental Bank, National Association (filed as Exhibit 4(c) to Kinder Morgan, Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 (File No. 1-06446) filed on May 23, 2000 and incorporated herein by reference)</td></tr><tr><td>4.4</td><td>— Indenture dated as of November 20, 1993, between K N Energy, Inc. and Continental Bank, National Association (filed as Exhibit 4.1 to the Registration Statement on Form S-3 (File No. 33-51115) of K N Energy, Inc. filed on November 19, 1993 and incorporated herein by reference)</td></tr><tr><td>4.5</td><td>— Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. dated May 18, 2001 (filed as Exhibit 4.7 to Kinder Morgan, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-06446) and incorporated herein by reference)</td></tr><tr><td>4.6</td><td>— Form of Indenture dated as of August 27, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 (File No. 333-100338) filed on October 4, 2002 and incorporated herein by reference)</td></tr></table>



4.7 — Form of First Supplemental Indenture dated as of December 6, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan, Inc.'s Registration Statement on Form S-4 (File No. 333-102873) filed on January 31, 2003 and incorporated herein by reference)

4.8 — Form of 6.50% Note (included in the Indenture filed as Exhibit 4.6 hereto and incorporated herein by reference)

4.9 — Form of Senior Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan, Inc.'s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003 and incorporated herein by reference)

4.10 — Form of Senior Note of Kinder Morgan, Inc. (included in the Form of Senior Indenture filed as Exhibit 4.9 hereto and incorporated herein by reference)

4.11 — Form of Subordinated Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.4 to Kinder Morgan, Inc.'s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003 and incorporated herein by reference)

4.12 — Form of Subordinated Note of Kinder Morgan, Inc. (included in the Form of Subordinated Indenture filed as Exhibit 4.11 hereto and incorporated herein by reference)

4.13 — Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company, LLC, Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan, Inc.'s Current Report on Form 8-K filed on December 15, 2005 and incorporated herein by reference)

4.14 — Forms of Kinder Morgan Finance Company, LLC notes (included in the Indenture filed as Exhibit 4.13 hereto and incorporated herein by reference)

4.15 — Certificate of the President and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.00% senior notes due 2017 and 6.50% senior notes due 2037 (filed as Exhibit 1.01 to Kinder Morgan Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference)

4.16 — 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.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference)

4.17 — Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference)

4.18 — 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.'s Annual Report on Form 10-K for 2007 and incorporated herein by reference)

4.19 — Indenture dated as of December 21, 2007, between NGLP PipeCo LLC and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan, Inc.'s Current Report on Form 8-K filed on December 21, 2007 and incorporated herein by reference)

4.20 — Forms of notes of NGPL PipeCo LLC (included in the Indenture filed as Exhibit 4.19 hereto and incorporated herein by reference)

4.21 — 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.'s Annual Report on Form 10-K for 2008 and incorporated herein by reference)

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



10.1* — 2010 Annual Incentive Plan of Kinder Morgan, Inc.

10.2 — Employment Agreement dated October 7, 1999, between Kinder Morgan, Inc. and Richard D. Kinder (filed as Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November 16, 1999 and incorporated herein by reference)

10.3 — Form of Purchase Provisions between Kinder Morgan Management, LLC and Kinder Morgan, Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement of Kinder Morgan Management, LLC filed as Exhibit 3.1 to Kinder Morgan Management, LLC’s Current Report on Form 8-K filed on May 30, 2007 and incorporated herein by reference)

10.4 — Credit Agreement, dated as of May 30, 2007, among Kinder Morgan, Inc. and Kinder Morgan Acquisition Co., as the borrower, the several lenders from time to time parties thereto, and Citibank, N.A., as administrative agent and collateral agent (filed as Exhibit 4.1 to Kinder Morgan, Inc.'s Current Report on Form 8-K, filed on June 5, 2007 and incorporated herein by reference)

10.5 — Form of Indemnification Agreement between Kinder Morgan, Inc. and each member of the Special Committee of the Board of Directors (filed as Exhibit 10.1 to Kinder Morgan, Inc.'s Current Report on Form 8-K filed on June 16, 2006 and incorporated herein by reference)

10.6 — Acquisition Agreement dated as of February 26, 2007, by and among Kinder Morgan, Inc., 3211953 Nova Scotia Company and Fortis Inc. (filed as Exhibit 1.01 to Kinder Morgan, Inc.'s Current Report on Form 8-K filed on March 1, 2007 and incorporated herein by reference)

10.8 — Purchase Agreement, dated as of December 10, 2007, between Kinder Morgan, Inc. and Myria Acquisition Inc. (filed as Exhibit 10.1 to Kinder Morgan, Inc.'s Current Report on Form 8-K filed on December 11, 2007 and incorporated herein by reference)

21.1* — Subsidiaries of the Registrant

31.1* — Certification of Chief Executive Officer 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 of Chief Financial Officer 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 of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2* — Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1 — The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries (incorporated by reference to pages 112 through 195 of the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2009)

99.2* — Estimates of the net reserves and future net revenues as of December 31, 2009 to Kinder Morgan CO \( _{2} \)  Company, L.P.'s interests in certain oil and gas properties located in the state of Texas.



## INDEX TO FINANCIAL STATEMENTS

<table><tr><td>KINDER MORGAN, INC. AND SUBSIDIARIES</td><td>Page</td></tr><tr><td>Report of Independent Registered Public Accounting Firm</td><td>109</td></tr><tr><td>Consolidated Statements of Operations</td><td>112</td></tr><tr><td>Consolidated Statements of Comprehensive Income</td><td>113</td></tr><tr><td>Consolidated Balance Sheets</td><td>114</td></tr><tr><td>Consolidated Statements of Cash Flows</td><td>115</td></tr><tr><td>Consolidated Statements of Stockholders&#x27; Equity</td><td>117</td></tr><tr><td>Notes to Consolidated Financial Statements</td><td>119</td></tr></table>



# Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Kinder Morgan, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan, Inc. and its subsidiaries (the "Company") at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years ended December 31, 2009 and 2008 and the period from June 1, 2007 to December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company 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 Company'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 Company's 2009 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Company'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 terminal assets acquired from Megafeet 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



(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 Company 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 1.20% and 0.33%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2009.

As discussed in Note 2 (to the financial statements in the Company’s Current Report on Form 8-K filed on September 18, 2009 which is not presented herein), the Company changed the manner in which it accounts for noncontrolling interests effective January 1, 2009.

PricewaterhouseCoopers LLP
Houston, Texas
March 5, 2010



# Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Kinder Morgan, Inc.:

In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of stockholders' equity and of cash flows present fairly, in all material respects, the results of their operations and their cash flows for the period from January 1, 2007 to May 31, 2007 of Kinder Morgan, Inc. and its subsidiaries (the "Company") in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 2 (to the financial statements in the Company’s Current Report on Form 8-K filed on September 18, 2009 which is not presented herein), the Company changed the manner in which it accounts for noncontrolling interests effective January 1, 2009.

PricewaterhouseCoopers LLP

Houston, Texas

March 28, 2008, except with respect to Note 15 (to the financial statements in the Company’s Registration Statement on Form S-1 filed on January 16, 2009 which is not presented herein), for which the date is January 8, 2009 and to the change in the Company’s accounting for noncontrolling interests as discussed in Note 2 (to the financial statements in the Company’s Current Report on Form 8-K filed on September 18, 2009 which is not presented herein), as to which the date is September 18, 2009.



## KINDER MORGAN, INC. AND SUBSIDIARIES

## CONSOLIDATED STATEMENTS OF OPERATIONS

<table><tr><td rowspan="4"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31, 2007</td><td rowspan="2">Five Months Ended May 31, 2007</td></tr><tr><td>2009</td><td>2008</td><td></td></tr><tr><td colspan="3">(In millions)</td><td></td><td>(In millions)</td></tr><tr><td>Revenues</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas sales</td><td>$ 3,137.2</td><td>$ 7,705.8</td><td>$ 3,623.1</td><td>$ 2,430.6</td><td></td></tr><tr><td>Services</td><td>2,739.1</td><td>2,904.0</td><td>2,049.8</td><td>1,350.5</td><td></td></tr><tr><td>Product sales and other</td><td>1,308.9</td><td>1,485.0</td><td>721.8</td><td>384.0</td><td></td></tr><tr><td>Total Revenues</td><td>7,185.2</td><td>12,094.8</td><td>6,394.7</td><td>4,165.1</td><td></td></tr><tr><td>Operating Costs, Expenses and Other</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gas purchases and other costs of sales</td><td>3,068.5</td><td>7,744.0</td><td>3,656.6</td><td>2,490.4</td><td></td></tr><tr><td>Operations and maintenance</td><td>1,159.9</td><td>1,318.0</td><td>943.3</td><td>476.1</td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>1,070.2</td><td>918.4</td><td>472.3</td><td>261.0</td><td></td></tr><tr><td>General and administrative</td><td>373.0</td><td>352.5</td><td>175.6</td><td>283.6</td><td></td></tr><tr><td>Taxes, other than income taxes</td><td>137.0</td><td>191.4</td><td>110.1</td><td>74.4</td><td></td></tr><tr><td>Goodwill impairment expense</td><td>-</td><td>4,033.3</td><td>-</td><td>377.1</td><td></td></tr><tr><td>Other expense (income)</td><td>(30.6)</td><td>9.3</td><td>(6.0)</td><td>(2.3)</td><td></td></tr><tr><td>Total Operating Costs, Expenses and Other</td><td>5,778.0</td><td>14,566.9</td><td>5,351.9</td><td>3,960.3</td><td></td></tr><tr><td>Operating Income (Loss)</td><td>1,407.2</td><td>(2,472.1)</td><td>1,042.8</td><td>204.8</td><td></td></tr><tr><td>Other Income (Expense)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Earnings from equity investments</td><td>221.9</td><td>201.1</td><td>56.8</td><td>40.7</td><td></td></tr><tr><td>Amortization of excess cost of equity investments</td><td>(5.8)</td><td>(5.7)</td><td>(3.4)</td><td>(2.4)</td><td></td></tr><tr><td>Interest, net</td><td>(573.4)</td><td>(628.3)</td><td>(594.3)</td><td>(250.2)</td><td></td></tr><tr><td>Other, net</td><td>49.5</td><td>7.0</td><td>11.6</td><td>0.6</td><td></td></tr><tr><td>Total Other Income (Expense)</td><td>(307.8)</td><td>(425.9)</td><td>(529.3)</td><td>(211.3)</td><td></td></tr><tr><td>Income (Loss) from Continuing Operations Before Income Taxes</td><td>1,099.4</td><td>(2,898.0)</td><td>513.5</td><td>(6.5)</td><td></td></tr><tr><td>Income Taxes</td><td>(325.6)</td><td>(304.3)</td><td>(227.4)</td><td>(135.5)</td><td></td></tr><tr><td>Income (Loss) from Continuing Operations</td><td>773.8</td><td>(3,202.3)</td><td>286.1</td><td>(142.0)</td><td></td></tr><tr><td>Income (Loss) from Discontinued Operations, net of tax</td><td>0.3</td><td>(0.9)</td><td>(1.5)</td><td>298.6</td><td></td></tr><tr><td>Net Income (Loss)</td><td>774.1</td><td>(3,203.2)</td><td>284.6</td><td>156.6</td><td></td></tr><tr><td>Net Income Attributable to Noncontrolling Interests</td><td>(278.1)</td><td>(396.1)</td><td>(37.6)</td><td>(90.7)</td><td></td></tr><tr><td>Net Income (Loss) Attributable to Kinder Morgan, Inc.</td><td>$ 496.0</td><td>$ (3,599.3)</td><td>$ 247.0</td><td>$ 65.9</td><td></td></tr></table>

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



## KINDER MORGAN, INC. AND SUBSIDIARIES

## CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<table><tr><td rowspan="4"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31,</td><td rowspan="2">Five Months Ended May 31, 2007</td></tr><tr><td>2009</td><td>2008</td><td>2007</td></tr><tr><td colspan="5">(In millions)</td></tr><tr><td>Kinder Morgan, Inc.</td><td></td><td></td><td></td><td></td><td>(In millions)</td></tr><tr><td>Net income (loss)</td><td>$ 496.0</td><td>$ (3,599.3)</td><td>$ 247.0</td><td>$ 65.9</td><td></td></tr><tr><td>Other comprehensive income (loss), net of tax (see Note 10)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes</td><td>(138.7)</td><td>212.0</td><td>(249.6)</td><td></td><td>(21.3)</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>(39.4)</td><td>117.1</td><td>-</td><td></td><td>10.3</td></tr><tr><td>Foreign currency translation adjustments</td><td>53.9</td><td>(68.7)</td><td>27.6</td><td></td><td>40.1</td></tr><tr><td>Benefit plan adjustments</td><td>2.8</td><td>(66.5)</td><td>(28.4)</td><td></td><td>9.7</td></tr><tr><td>Benefit plan amortization</td><td>6.9</td><td>0.4</td><td>(0.2)</td><td></td><td>1.0</td></tr><tr><td>Total other comprehensive income (loss)</td><td>(114.5)</td><td>194.3</td><td>(250.6)</td><td></td><td>39.8</td></tr><tr><td>Total comprehensive income (loss)</td><td>381.5</td><td>(3,405.0)</td><td>(3.6)</td><td></td><td>105.7</td></tr><tr><td>Noncontrolling Interests</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>278.1</td><td>396.1</td><td>37.6</td><td></td><td>90.7</td></tr><tr><td>Other comprehensive income (loss), net of tax (see Note 10)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes</td><td>(208.8)</td><td>295.4</td><td>(389.0)</td><td></td><td>(50.1)</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>45.7</td><td>301.1</td><td>137.2</td><td></td><td>56.5</td></tr><tr><td>Foreign currency translation adjustments</td><td>114.9</td><td>(149.6)</td><td>40.3</td><td></td><td>18.8</td></tr><tr><td>Benefit plan adjustments</td><td>(1.2)</td><td>1.9</td><td>(1.4)</td><td></td><td>(0.2)</td></tr><tr><td>Benefit plan amortization</td><td>0.1</td><td>(0.3)</td><td>-</td><td></td><td>-</td></tr><tr><td>Total other comprehensive income (loss)</td><td>(49.3)</td><td>448.5</td><td>(212.9)</td><td></td><td>25.0</td></tr><tr><td>Total comprehensive income (loss)</td><td>228.8</td><td>844.6</td><td>(175.3)</td><td></td><td>115.7</td></tr><tr><td>Total</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss)</td><td>774.1</td><td>(3,203.2)</td><td>284.6</td><td></td><td>156.6</td></tr><tr><td>Other comprehensive income (loss), net of tax (see Note 10)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes</td><td>(347.5)</td><td>507.4</td><td>(638.6)</td><td></td><td>(71.4)</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>6.3</td><td>418.2</td><td>137.2</td><td></td><td>66.8</td></tr><tr><td>Foreign currency translation adjustments</td><td>168.8</td><td>(218.3)</td><td>67.9</td><td></td><td>58.9</td></tr><tr><td>Benefit plan adjustments</td><td>1.6</td><td>(64.6)</td><td>(29.8)</td><td></td><td>9.5</td></tr><tr><td>Benefit plan amortization</td><td>7.0</td><td>0.1</td><td>(0.2)</td><td></td><td>1.0</td></tr><tr><td>Total other comprehensive income (loss)</td><td>(163.8)</td><td>642.8</td><td>(463.5)</td><td></td><td>64.8</td></tr><tr><td>Total comprehensive income (loss)</td><td>$ 610.3</td><td>$ (2,560.4)</td><td>$ (178.9)</td><td>$ 221.4</td><td></td></tr></table>

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



## KINDER MORGAN, INC. AND SUBSIDIARIES

## CONSOLIDATED BALANCE SHEETS

<table><tr><td rowspan="3"></td><td colspan="3">December 31,</td></tr><tr><td>2009</td><td>2008</td><td></td></tr><tr><td colspan="3">(In millions)</td></tr><tr><td>ASSETS</td><td></td><td></td><td></td></tr><tr><td>Current Assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     165.6</td><td>$     118.6</td><td></td></tr><tr><td>Restricted deposits</td><td>52.5</td><td>-</td><td></td></tr><tr><td>Accounts, notes and interest receivable, net</td><td>921.6</td><td>992.5</td><td></td></tr><tr><td>Inventories</td><td>71.9</td><td>44.2</td><td></td></tr><tr><td>Gas in underground storage</td><td>43.5</td><td>-</td><td></td></tr><tr><td>Fair value of derivative contracts</td><td>20.8</td><td>115.2</td><td></td></tr><tr><td>Other current assets</td><td>109.7</td><td>46.7</td><td></td></tr><tr><td>Total Current Assets</td><td>1,385.6</td><td>1,317.2</td><td></td></tr><tr><td>Property, plant and equipment, net</td><td>16,803.5</td><td>16,109.8</td><td></td></tr><tr><td>Investments</td><td>3,695.6</td><td>1,827.4</td><td></td></tr><tr><td>Notes receivable</td><td>190.6</td><td>178.1</td><td></td></tr><tr><td>Goodwill</td><td>4,744.3</td><td>4,698.7</td><td></td></tr><tr><td>Other intangibles, net</td><td>259.8</td><td>251.5</td><td></td></tr><tr><td>Fair value of derivative contracts</td><td>293.3</td><td>828.0</td><td></td></tr><tr><td>Deferred charges and other assets</td><td>213.6</td><td>234.2</td><td></td></tr><tr><td>Total Assets</td><td>$     27,586.3</td><td>$     25,444.9</td><td></td></tr><tr><td>LIABILITIES AND STOCKHOLDERS&#x27; EQUITY</td><td></td><td></td><td></td></tr><tr><td>Current Liabilities</td><td></td><td></td><td></td></tr><tr><td>Current portion of debt</td><td>$     768.7</td><td>$     302.5</td><td></td></tr><tr><td>Cash book overdrafts</td><td>36.6</td><td>45.2</td><td></td></tr><tr><td>Accounts payable</td><td>620.8</td><td>849.8</td><td></td></tr><tr><td>Accrued interest</td><td>292.1</td><td>241.9</td><td></td></tr><tr><td>Accrued taxes</td><td>58.6</td><td>152.1</td><td></td></tr><tr><td>Deferred revenues</td><td>76.1</td><td>41.2</td><td></td></tr><tr><td>Fair value of derivative contracts</td><td>272.0</td><td>129.5</td><td></td></tr><tr><td>Accrued other current liabilities</td><td>194.6</td><td>252.5</td><td></td></tr><tr><td>Total Current Liabilities</td><td>2,319.5</td><td>2,014.7</td><td></td></tr><tr><td>Long-term Liabilities and Deferred Credits</td><td></td><td></td><td></td></tr><tr><td>Long-term Debt</td><td></td><td></td><td></td></tr><tr><td>Outstanding</td><td>12,779.7</td><td>11,055.8</td><td></td></tr><tr><td>Preferred interest in general partner of Kinder Morgan Energy Partners</td><td>100.0</td><td>100.0</td><td></td></tr><tr><td>Value of interest rate swaps</td><td>361.0</td><td>971.0</td><td></td></tr><tr><td>Total Long-term Debt</td><td>13,240.7</td><td>12,126.8</td><td></td></tr><tr><td>Deferred income taxes</td><td>2,039.9</td><td>2,081.3</td><td></td></tr><tr><td>Fair value of derivative contracts</td><td>469.6</td><td>92.2</td><td></td></tr><tr><td>Other long-term liabilities and deferred credits</td><td>670.5</td><td>653.0</td><td></td></tr><tr><td>Total Long-Term Liabilities and Deferred Credits</td><td>16,420.7</td><td>14,953.3</td><td></td></tr><tr><td>Total Liabilities</td><td>18,740.2</td><td>16,968.0</td><td></td></tr><tr><td>Commitments and Contingencies (Notes 12 and 16)</td><td></td><td></td><td></td></tr><tr><td>Stockholders&#x27; Equity</td><td></td><td></td><td></td></tr><tr><td>Common stock - authorized and outstanding - 100 shares, par value $0.01 per share</td><td>-</td><td>-</td><td></td></tr><tr><td>Additional paid-in capital</td><td>7,845.7</td><td>7,810.0</td><td></td></tr><tr><td>Retained deficit</td><td>(3,506.3)</td><td>(3,352.3)</td><td></td></tr><tr><td>Accumulated other comprehensive loss</td><td>(167.9)</td><td>(53.4)</td><td></td></tr><tr><td>Total Kinder Morgan, Inc. Stockholder&#x27;s Equity</td><td>4,171.5</td><td>4,404.3</td><td></td></tr><tr><td>Noncontrolling interests</td><td>4,674.6</td><td>4,072.6</td><td></td></tr><tr><td>Total Stockholders&#x27; Equity</td><td>8,846.1</td><td>8,476.9</td><td></td></tr><tr><td>Total Liabilities and Stockholders&#x27; Equity</td><td>$     27,586.3</td><td>$     25,444.9</td><td></td></tr></table>

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



## KINDER MORGAN, INC. AND SUBSIDIARIES

## CONSOLIDATED STATEMENTS OF CASH FLOWS

<table><tr><td rowspan="4"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31, 2007</td><td rowspan="2">Five Months Ended May 31, 2007</td><td></td></tr><tr><td>2009</td><td>2008</td><td>2007</td></tr><tr><td colspan="4">(In millions)</td><td>(In millions)</td></tr><tr><td>Cash Flows From Operating Activities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss)</td><td>$     774.1</td><td>$    (3,203.2)</td><td>$     284.6</td><td>$     156.6</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash from operating activities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Loss (income) from discontinued operations, net of tax</td><td>(0.3)</td><td>0.9</td><td>11.9</td><td>(287.9)</td><td></td></tr><tr><td>Loss on early extinguishment of debt</td><td>-</td><td>23.6</td><td>-</td><td>4.4</td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>1,070.2</td><td>918.4</td><td>476.2</td><td>264.9</td><td></td></tr><tr><td>Impairment of goodwill</td><td>-</td><td>4,033.3</td><td>-</td><td>377.1</td><td></td></tr><tr><td>Deferred income taxes</td><td>59.0</td><td>(496.4)</td><td>(89.8)</td><td>138.7</td><td></td></tr><tr><td>Amortization of excess cost of equity investments</td><td>5.8</td><td>5.7</td><td>3.4</td><td>2.4</td><td></td></tr><tr><td>Income from the allowance for equity funds used during construction</td><td>(22.7)</td><td>(10.9)</td><td>-</td><td>-</td><td></td></tr><tr><td>(Income) loss from the sale or casualty of property, plant and equipment and other net assets</td><td>(30.4)</td><td>9.2</td><td>(6.3)</td><td>(4.4)</td><td></td></tr><tr><td>Earnings from equity investments</td><td>(221.9)</td><td>(201.1)</td><td>(57.7)</td><td>(41.5)</td><td></td></tr><tr><td>Mark-to-market interest rate swap gain</td><td>-</td><td>(19.8)</td><td>-</td><td>-</td><td></td></tr><tr><td>Distributions from equity investments</td><td>277.0</td><td>241.6</td><td>86.5</td><td>48.2</td><td></td></tr><tr><td>Proceeds from (payment for) termination of interest rate swap agreements</td><td>146.0</td><td>192.0</td><td>(2.2)</td><td>51.9</td><td></td></tr><tr><td>Pension contributions in excess of expense</td><td>(7.7)</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Changes in components of working capital</td><td>47.6</td><td>60.6</td><td>(64.3)</td><td>(31.9)</td><td></td></tr><tr><td>Accounts receivable</td><td>(20.0)</td><td>(7.9)</td><td>(8.1)</td><td>(1.7)</td><td></td></tr><tr><td>Inventories</td><td>(93.6)</td><td>(16.9)</td><td>(13.9)</td><td>(83.7)</td><td></td></tr><tr><td>Other current assets</td><td>(180.5)</td><td>(99.3)</td><td>68.7</td><td>26.3</td><td></td></tr><tr><td>Accounts payable</td><td>50.2</td><td>0.7</td><td>65.9</td><td>(22.5)</td><td></td></tr><tr><td>Accrued interest</td><td>(131.0)</td><td>109.0</td><td>142.5</td><td>(114.0)</td><td></td></tr><tr><td>Accrued taxes</td><td>(125.0)</td><td>(119.1)</td><td>(35.5)</td><td>(59.6)</td><td></td></tr><tr><td>Accrued liabilities</td><td>2.5</td><td>(13.7)</td><td>140.0</td><td>-</td><td></td></tr><tr><td>Rate reparations, refunds and other litigation reserve adjustments</td><td>(11.3)</td><td>(9.1)</td><td>45.8</td><td>69.9</td><td></td></tr><tr><td>Other, net</td><td>1,588.0</td><td>1,397.6</td><td>1,047.7</td><td>493.2</td><td></td></tr><tr><td>Net Cash Flows Provided by Continuing Operations</td><td>(0.5)</td><td>(0.8)</td><td>(3.2)</td><td>109.8</td><td></td></tr><tr><td>Net Cash Flows (Used in) Provided by Discontinued Operations</td><td>1,587.5</td><td>1,396.8</td><td>1,044.5</td><td>603.0</td><td></td></tr><tr><td>Net Cash Provided by Operating Activities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash Flows From Investing Activities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchase of Predecessor Stock</td><td>-</td><td>-</td><td>(11,534.3)</td><td>-</td><td></td></tr><tr><td>Proceeds from sale of 80% interest in NGPL PipeCo LLC, net of $1.1 cash sold</td><td>-</td><td>2,899.3</td><td>-</td><td>-</td><td></td></tr><tr><td>Proceeds from (investments in) NGPL PipeCo LLC restricted cash</td><td>-</td><td>3,106.4</td><td>(3,030.0)</td><td>-</td><td></td></tr><tr><td>Acquisitions of assets and equity investments</td><td>(328.9)</td><td>(47.6)</td><td>(122.0)</td><td>(42.1)</td><td></td></tr><tr><td>Repayments from (loans to) customers</td><td>109.6</td><td>(109.6)</td><td>-</td><td>-</td><td></td></tr><tr><td>Capital expenditures</td><td>(1,324.3)</td><td>(2,545.3)</td><td>(1,287.0)</td><td>(652.8)</td><td></td></tr><tr><td>Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs</td><td>47.9</td><td>111.1</td><td>301.3</td><td>6.5</td><td></td></tr><tr><td>(Investments in) net proceeds from margin deposits</td><td>(18.5)</td><td>71.0</td><td>(39.3)</td><td>(54.8)</td><td></td></tr><tr><td>Investments in Restricted deposits</td><td>(37.2)</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Contributions to investments</td><td>(2,051.8)</td><td>(366.2)</td><td>(246.4)</td><td>(29.7)</td><td></td></tr><tr><td>Distributions from equity investments in excess of cumulative earnings</td><td>125.7</td><td>98.1</td><td>-</td><td>-</td><td></td></tr><tr><td>Other, net</td><td>-</td><td>(7.2)</td><td>10.0</td><td>8.4</td><td></td></tr><tr><td>Net Cash Flows (Used in) Provided by Continuing Investing Activities</td><td>(3,477.5)</td><td>3,210.0</td><td>(15,947.7)</td><td>(764.5)</td><td></td></tr><tr><td>Net Cash Flows Provided by Discontinued Investing Activities</td><td>-</td><td>-</td><td>196.6</td><td>1,488.2</td><td></td></tr><tr><td>Net Cash (Used in) Provided by Investing Activities</td><td>$    (3,477.5)</td><td>$   3,210.0</td><td>$    (15,751.1)</td><td>$   723.7</td><td></td></tr></table>



## KINDER MORGAN, INC. AND SUBSIDIARIES

## CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

<table><tr><td rowspan="4"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31, 2007</td></tr><tr><td colspan="2">2009</td><td colspan="2">2008</td><td>2007</td><td>(In millions)</td></tr><tr><td colspan="5">(In millions)</td><td>(In millions)</td></tr><tr><td>Cash Flows From Financing Activities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Issuance of debt</td><td>$</td><td>7,920.8</td><td>$</td><td>10,495.8</td><td>$</td><td>3,038.9</td></tr><tr><td>Payment of debt</td><td></td><td>(5,728.8)</td><td></td><td>(15,136.5)</td><td></td><td>(5,115.7)</td></tr><tr><td>Proceeds from issuance of Kinder Morgan, G.P., Inc. preferred stock</td><td></td><td>-</td><td></td><td>-</td><td></td><td>100.0</td></tr><tr><td>Repayments from related party</td><td></td><td>3.7</td><td></td><td>2.7</td><td></td><td>10.9</td></tr><tr><td>Discount (premium) on early extinguishment of debt</td><td></td><td>-</td><td></td><td>69.2</td><td></td><td>-</td></tr><tr><td>Debt issue costs</td><td></td><td>(16.9)</td><td></td><td>(15.9)</td><td></td><td>(81.5)</td></tr><tr><td>(Decrease) increase in cash book overdrafts</td><td></td><td>(8.5)</td><td></td><td>14.5</td><td></td><td>(14.0)</td></tr><tr><td>Proceeds from issuance of shares by Kinder Morgan Management, LLC</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Excess tax benefits from share-based payments</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Cash paid to share-based award holders due to Going Private transaction</td><td></td><td>-</td><td></td><td>-</td><td></td><td>(181.1)</td></tr><tr><td>Contributions from Successor Investors</td><td></td><td>-</td><td></td><td>-</td><td></td><td>5,112.0</td></tr><tr><td>Proceeds from issuance of other common stock</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Cash dividends</td><td></td><td>(650.0)</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Contributions from noncontrolling interests</td><td></td><td>1,155.6</td><td></td><td>561.5</td><td></td><td>342.9</td></tr><tr><td>Distributions to noncontrolling interests</td><td></td><td>(744.0)</td><td></td><td>(630.3)</td><td></td><td>(259.6)</td></tr><tr><td>Other, net</td><td></td><td>(0.9)</td><td></td><td>10.9</td><td></td><td>4.0</td></tr><tr><td>Net Cash Provided by (Used in) Continuing Financing Activities</td><td></td><td>1,931.0</td><td></td><td>(4,628.1)</td><td></td><td>12,956.8</td></tr><tr><td>Net Cash Provided by Discontinued Financing Activities</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Net Cash Provided by (Used in) Financing Activities</td><td></td><td>1,931.0</td><td></td><td>(4,628.1)</td><td></td><td>12,956.8</td></tr><tr><td>Effect of Exchange Rate Changes on Cash and Cash Equivalents</td><td></td><td>6.0</td><td></td><td>(8.7)</td><td></td><td>(2.8)</td></tr><tr><td>Cash Balance Included in Assets Held for Sale</td><td></td><td>-</td><td></td><td>-</td><td></td><td>(1.1)</td></tr><tr><td>Increase (decrease) in Cash and Cash Equivalents</td><td></td><td>47.0</td><td></td><td>(30.0)</td><td></td><td>(1,753.7)</td></tr><tr><td>Cash and Cash Equivalents, beginning of period</td><td></td><td>118.6</td><td></td><td>148.6</td><td></td><td>1,902.3</td></tr><tr><td>Cash and Cash Equivalents, end of period</td><td></td><td>165.6</td><td></td><td>118.6</td><td></td><td>148.6</td></tr><tr><td>Noncash Investing and Financing Activities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets acquired by the assumption or incurrence of liabilities</td><td></td><td>7.7</td><td></td><td>4.8</td><td></td><td>1.2</td></tr><tr><td>Assets acquired by contributions from noncontrolling interests</td><td></td><td>5.0</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Interest expense recognized from early extinguishment of debt</td><td></td><td>-</td><td></td><td>87.5</td><td></td><td>-</td></tr><tr><td>Subordinated notes acquired by exchange of preferred equity interest</td><td></td><td>-</td><td></td><td>111.4</td><td></td><td>-</td></tr><tr><td>Supplemental Disclosures of Cash Flow Information</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash paid during the period for interest (net of capitalized interest)</td><td></td><td>572.8</td><td></td><td>649.9</td><td></td><td>586.5</td></tr><tr><td>Cash paid during the period for income taxes</td><td></td><td>401.1</td><td></td><td>657.3</td><td></td><td>146.4</td></tr></table>

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



## KINDER MORGAN, INC. AND SUBSIDIARIES

## CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<table><tr><td rowspan="4"></td><td colspan="6">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="4">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,2007</td><td colspan="2">Five Months Ended May 31, 2007</td></tr><tr><td colspan="2">2009</td><td colspan="2">2008</td><td colspan="2">2007</td><td colspan="2">2006</td></tr><tr><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td></tr><tr><td>Common Stock</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning balance</td><td>100</td><td>$ -</td><td>100</td><td>$ -</td><td>100</td><td>$ -</td><td>149,166,709</td><td>$ 745.8</td></tr><tr><td>Employee benefit plans</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>149,894</td><td>0.8</td></tr><tr><td>Ending balance</td><td>100</td><td>-</td><td>100</td><td>-</td><td>100</td><td>-</td><td>149,316,603</td><td>746.6</td></tr><tr><td>Additional Paid-in Capital</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning balance</td><td></td><td>7,810.0</td><td></td><td>7,822.2</td><td></td><td>-</td><td></td><td>3,048.9</td></tr><tr><td>MBO purchase price</td><td></td><td>-</td><td></td><td>-</td><td></td><td>7,831.2</td><td></td><td>-</td></tr><tr><td>Impact of Kinder Morgan Energy Partners&#x27; equity transactions (Note 10)</td><td></td><td>28.1</td><td></td><td>(19.8)</td><td></td><td>(13.4)</td><td></td><td>3.4</td></tr><tr><td>A-1 and B unit amortization</td><td></td><td>7.6</td><td></td><td>7.6</td><td></td><td>4.4</td><td></td><td>-</td></tr><tr><td>Employee benefit plans</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td><td></td><td>7.7</td></tr><tr><td>Tax benefits from employee benefit plans</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td><td></td><td>56.7</td></tr><tr><td>Deferred compensation (Note 12)</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td><td></td><td>21.9</td></tr><tr><td>Ending balance</td><td></td><td>7,845.7</td><td></td><td>7,810.0</td><td></td><td>7,822.2</td><td></td><td>3,138.6</td></tr><tr><td>Retained Earnings (Deficit)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning balance</td><td></td><td>(3,352.3)</td><td></td><td>247.0</td><td></td><td>-</td><td></td><td>778.7</td></tr><tr><td>Net income (loss)</td><td></td><td>496.0</td><td></td><td>(3,599.3)</td><td></td><td>247.0</td><td></td><td>65.9</td></tr><tr><td>Cash dividends</td><td></td><td>(650.0)</td><td></td><td>-</td><td></td><td>-</td><td></td><td>(234.9)</td></tr><tr><td>Initialization of income tax reserves (Note 4)</td><td></td><td>-</td><td></td><td>-</td><td></td><td>-</td><td></td><td>(4.8)</td></tr><tr><td>Ending balance</td><td></td><td>(3,506.3)</td><td></td><td>(3,352.3)</td><td></td><td>247.0</td><td></td><td>604.9</td></tr><tr><td>Treasury Stock</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning balance</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(15,022,751)</td><td>(915.9)</td></tr><tr><td>Employee benefit plans</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(7,384)</td><td>(0.5)</td></tr><tr><td>Ending balance</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(15,030,135)</td><td>(916.4)</td></tr><tr><td>Accumulated Other Comprehensive Income (Loss)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning balance</td><td></td><td>(53.4)</td><td></td><td>(247.7)</td><td></td><td>2.9</td><td></td><td>(135.9)</td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes</td><td></td><td>(138.7)</td><td></td><td>212.0</td><td></td><td>(249.6)</td><td></td><td>(21.3)</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td></td><td>(39.4)</td><td></td><td>117.1</td><td></td><td>-</td><td></td><td>10.3</td></tr><tr><td>Foreign currency translation adjustments</td><td></td><td>53.9</td><td></td><td>(68.7)</td><td></td><td>27.6</td><td></td><td>40.1</td></tr><tr><td>Benefit plan adjustments</td><td></td><td>2.8</td><td></td><td>(66.5)</td><td></td><td>(28.4)</td><td></td><td>9.7</td></tr><tr><td>Benefit plan amortization</td><td></td><td>6.9</td><td></td><td>0.4</td><td></td><td>(0.2)</td><td></td><td>1.0</td></tr><tr><td>Ending balance</td><td></td><td>(167.9)</td><td></td><td>(53.4)</td><td></td><td>(247.7)</td><td></td><td>(96.1)</td></tr><tr><td>Total Kinder Morgan, Inc. Stockholder&#x27;s Equity</td><td>100</td><td>4,171.5</td><td>100</td><td>4,404.3</td><td>100</td><td>7,821.5</td><td>134,286,468</td><td>3,477.6</td></tr></table>



## KINDER MORGAN, INC. AND SUBSIDIARIES

## CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (continued)

<table><tr><td rowspan="3"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,2007</td><td colspan="2">Five Months Ended May 31, 2007</td></tr><tr><td>2009</td><td>2008</td><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td></tr><tr><td>Noncontrolling interests</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Beginning balance</td><td>$ 4,072.6</td><td>$ 3,314.0</td><td></td><td>$ 3,343.9</td><td></td><td>$ 3,095.4</td></tr><tr><td>Impact from equity transactions of Kinder Morgan Energy Partners</td><td>(43.8)</td><td>(21.4)</td><td></td><td>(12.9)</td><td></td><td>(22.7)</td></tr><tr><td>Issuance of shares by Kinder Morgan Management, LLC</td><td>-</td><td>-</td><td></td><td>-</td><td></td><td>317.0</td></tr><tr><td>Gain on sale of discontinued operations</td><td>-</td><td>-</td><td></td><td>(56.1)</td><td></td><td></td></tr><tr><td>Distributions to noncontrolling interests</td><td>(745.5)</td><td>(630.7)</td><td></td><td>(260.5)</td><td></td><td>(248.9)</td></tr><tr><td>Contributions from noncontrolling interests</td><td>1,160.6</td><td>561.5</td><td></td><td>343.5</td><td></td><td>15.0</td></tr><tr><td>Kinder Morgan Energy Partners&#x27; TransMountain Pipeline Acquisition</td><td>0.2</td><td>-</td><td></td><td>(4.7)</td><td></td><td>72.1</td></tr><tr><td>Net income included in discontinued operations</td><td>-</td><td>-</td><td></td><td>141.6</td><td></td><td>-</td></tr><tr><td>Other</td><td>1.7</td><td>4.6</td><td></td><td>(5.5)</td><td></td><td>0.3</td></tr><tr><td>Comprehensive income (loss)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>278.1</td><td>396.1</td><td></td><td>37.6</td><td></td><td>90.7</td></tr><tr><td>Change in fair value of derivatives used for hedging purposes</td><td>(208.8)</td><td>295.4</td><td></td><td>(389.0)</td><td></td><td>(50.1)</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>45.7</td><td>301.1</td><td></td><td>137.2</td><td></td><td>56.5</td></tr><tr><td>Foreign currency translation adjustments</td><td>114.9</td><td>(149.6)</td><td></td><td>40.3</td><td></td><td>18.8</td></tr><tr><td>Benefit plan adjustments</td><td>(1.2)</td><td>1.9</td><td></td><td>(1.4)</td><td></td><td>(0.2)</td></tr><tr><td>Benefit plan amortization</td><td>0.1</td><td>(0.3)</td><td></td><td>-</td><td></td><td>-</td></tr><tr><td>Total comprehensive income (loss)</td><td>228.8</td><td>844.6</td><td></td><td>(175.3)</td><td></td><td>115.7</td></tr><tr><td>Ending balance</td><td>4,674.6</td><td>4,072.6</td><td></td><td>3,314.0</td><td></td><td>3,343.9</td></tr><tr><td>Total Stockholders&#x27; Equity</td><td>100</td><td>$ 8,846.1</td><td>100</td><td>$ 8,476.9</td><td>100</td><td>$ 11,135.5</td></tr></table>

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



# KINDER MORGAN, INC.

# NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

## 1. General

## Organization

We are a large energy transportation and storage company, operating or owning an interest in approximately 37,000 miles of pipelines and approximately 180 terminals. We have both regulated and nonregulated operations. We also own all the common equity of the general partner of, and a significant limited partner interest in, Kinder Morgan Energy Partners, L.P., a publicly traded pipeline limited partnership. We are a wholly owned subsidiary of Kinder Morgan Holdco LLC, a private company (formerly Knight Holdco LLC). Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000. Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Unless the context requires otherwise, references to “Kinder Morgan Energy Partners” and “KMP” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries.

Kinder Morgan Management, LLC, referred to in this report as “Kinder Morgan Management,” is a publicly traded Delaware limited liability company. Kinder Morgan G.P., Inc., the general partner of Kinder Morgan Energy Partners and a wholly owned subsidiary of ours, owns all of Kinder Morgan Management’s voting shares. Kinder Morgan Management, pursuant to a delegation of control agreement, has been delegated, to the fullest extent permitted under Delaware law, all of Kinder Morgan G.P., Inc.’s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, subject to Kinder Morgan G.P., Inc.’s right to approve certain transactions.

## 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$.

The 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.

Our consolidated financial statements include the accounts of Kinder Morgan, Inc. and our majority-owned subsidiaries, as well as those of (i) Kinder Morgan Energy Partners, (ii) Kinder Morgan Management and (iii) Triton Power Company LLC, in which we have a preferred investment. Except for Kinder Morgan Energy Partners, Kinder Morgan Management and Triton Power Company LLC, investments in 50% or less owned operations are accounted for under the equity method. All material intercompany transactions and balances have been eliminated.

Notwithstanding the consolidation of Kinder Morgan Energy Partners and its subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of Kinder Morgan Energy Partners and/or its subsidiaries and vice versa, except as discussed in the following paragraph. Responsibility for payments of obligations reflected in our or Kinder Morgan Energy Partners' financial statements is a legal determination based on the entity that incurs the liability.

In conjunction with Kinder Morgan Energy Partners' acquisition of certain natural gas pipelines from us, we agreed to indemnify Kinder Morgan Energy Partners with respect to approximately $733.5 million of its debt. We would be obligated to perform under this indemnity only if Kinder Morgan Energy Partners' assets were unable to satisfy its obligations.

## Going Private Transaction

On May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of Kinder Morgan Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal entity and subsequently renamed Knight Inc. On July 15, 2009, the Company’s name was changed back to Kinder Morgan, Inc. Kinder Morgan Holdco LLC is a private company owned by Richard D. Kinder, our Chairman and Chief Executive Officer; our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez Sarofim and Michael C. Morgan; other members of its senior management, most of whom are also senior officers of Kinder Morgan G.P., Inc. and us and affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar Capital, (iii) The Carlyle Group, and (iv) Riverstone Holdings LLC. This transaction is referred to in this report as the Going Private



transaction. As a result of this transaction, the company became privately owned, our stock ceased being traded on the New York Stock Exchange, and we adopted a new basis of accounting for our assets and liabilities. The acquisition was accounted for under the purchase method of accounting with the assets acquired and liabilities assumed recorded at their fair market values as of the acquisition date, resulting in a new basis of accounting effective with the closing of the Going Private transaction.

Therefore, in the accompanying Consolidated Financial Statements, transactions and balances prior to the closing of the Going Private transaction (the amounts labeled “Predecessor Company”) reflect the historical accounting basis in our assets and liabilities, while the amounts subsequent to the closing (labeled “Successor Company”) reflect the push down of the investors’ new accounting basis to our financial statements. Hence, there is a blackline division on the financial statements and relevant notes, which is intended to signify that the amounts shown for periods prior to and subsequent to the Going Private transaction are not comparable.

As discussed above, effective with the closing of the Going Private transaction, all of our assets and liabilities were recorded at their estimated fair market values based on an allocation of the aggregate purchase price paid in the Going Private transaction. To the extent that we consolidate less than wholly owned subsidiaries (such as Kinder Morgan Energy Partners, Kinder Morgan Management and Triton Power Company LLC), the reported assets and liabilities for these entities have been given a new accounting basis only to the extent of our economic ownership interest in those entities. Therefore, the assets and liabilities of these entities are included in our financial statements, in part, at a new accounting basis reflecting the investors' purchase of our economic interest in these entities (approximately 50% in the case of Kinder Morgan Energy Partners and 14% in the case of Kinder Morgan Management). The remaining percentage of these assets and liabilities, reflecting the continuing noncontrolling ownership interest, is included at its historical accounting basis. The purchase price paid in the Going Private transaction and the allocation of that purchase price is as follows (in millions):

<table><tr><td>The total purchase price consisted of the following</td><td></td></tr><tr><td>Cash paid</td><td>$ 5,112.0</td></tr><tr><td>Kinder Morgan, Inc. shares contributed</td><td>2,719.2</td></tr><tr><td>Equity contributed</td><td>7,831.2</td></tr><tr><td>Cash from issuances of long-term debt</td><td>4,696.2</td></tr><tr><td>Total purchase price</td><td>$ 12,527.4</td></tr><tr><td>The allocation of the purchase price is as follows</td><td></td></tr><tr><td>Current assets</td><td>$ 1,551.2</td></tr><tr><td>Investments</td><td>897.8</td></tr><tr><td>Goodwill</td><td>13,786.1</td></tr><tr><td>Property, plant and equipment, net</td><td>15,281.6</td></tr><tr><td>Deferred charges and other assets</td><td>1,639.8</td></tr><tr><td>Current liabilities</td><td>(3,279.5)</td></tr><tr><td>Deferred income taxes</td><td>(2,392.8)</td></tr><tr><td>Other long-term liabilities and deferred credits</td><td>(1,786.3)</td></tr><tr><td>Long-term debt</td><td>(9,855.9)</td></tr><tr><td>Noncontrolling interests</td><td>(3,314.6)</td></tr><tr><td></td><td>$ 12,527.4</td></tr></table>

The following is a reconciliation of shares purchased and contributed and the Going Private transaction purchase price (in millions except per share information):

<table><tr><td></td><td>Number of Shares</td><td>Price per Share</td><td>Total Value</td></tr><tr><td>Shares purchased with cash</td><td>107.6</td><td>$ 107.50</td><td>$ 11,561.3</td></tr><tr><td>Shares contributed</td><td></td><td></td><td></td></tr><tr><td>Richard D. Kinder</td><td>24.0</td><td>$ 101.00</td><td>2,424.0</td></tr><tr><td>Other Kinder Morgan, Inc. management and board members</td><td>2.7</td><td>$ 107.50</td><td>295.2</td></tr><tr><td>Total shares contributed</td><td>26.7</td><td></td><td>2,719.2</td></tr><tr><td>Total shares outstanding as of May 31, 2007</td><td>134.3</td><td></td><td>14,280.5</td></tr><tr><td>Less: portion of shares acquired using Kinder Morgan, Inc. cash on hand</td><td></td><td></td><td>(1,756.8)</td></tr><tr><td>Add: cash contributions by management at or after May 30, 2007</td><td></td><td></td><td>3.7</td></tr><tr><td>purchase price</td><td></td><td></td><td>$ 12,527.4</td></tr></table>

The shares contributed by members of management and the board members other than Richard D. Kinder who were investors in the Going Private transaction were valued at $107.50 per share, the same as the amount per share paid to the



public shareholders in the Going Private transaction. Richard D. Kinder agreed to value the shares he contributed at $101.00 per share because Mr. Kinder agreed to participate in the transaction at less than the merger price in order to help increase the merger price for the other public shareholders.

## 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.

## Accounts Receivable

The amounts reported as “Accounts, notes and interest receivable, net” on the accompanying Consolidated Balance Sheets as of December 31, 2009 and 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.

In addition, the balances of “Accrued other current liabilities” in the accompanying Consolidated Balance Sheets include amounts related to customer prepayments of approximately $10.9 million and $10.8 million as of December 31, 2009 and 2008, respectively.

## 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 the CO \( _{2} \) –KMP 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 the 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 the 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 the 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 the accompanying Consolidated Balance Sheets.



## Property, Plant and Equipment

## Capitalization, Depreciation and Depletion and Disposals

We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition, 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 market 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 the accompanying Consolidated Balance Sheets), and this unrecoverable portion is depreciated over the facility’s estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.



## Impairments

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

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

Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment. Due to the decline in crude oil and natural gas prices during 2008, on December 31, 2008, we conducted an impairment test on our oil and gas producing properties in the  \( CO_{2} \) -KMP 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 (“FERC”), 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 on debt resulting from the capitalization of interest expense in 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 was $32.9 million, $49.5 million, $25.7 million and $12.3 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 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007, we also capitalized approximately $22.7 million, $10.8 million, $7.8 million and $1.5 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 the acquired net assets, and such amounts are reported separately as “Goodwill” on the accompanying Consolidated Balance Sheets. The Company tests for impairment of goodwill on an annual basis and at any other time if events occur or circumstances indicate that the carrying amount of goodwill may not be recoverable. See Note 7 for more information about Goodwill and our annual impairment test.



## 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 as services are provided, based on the terms negotiated under these contracts.

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

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

Revenues from the sale of 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 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. In the accompanying Consolidated Statements of Operations, the noncontrolling interests 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 the accompanying Consolidated Balance Sheets, noncontrolling interests represent the ownership interests in our consolidated subsidiaries’ net assets held by parties other than us. It is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”

## Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of 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 we do not expect to be realized. Note 4 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities.

In determining the deferred income tax asset and liability balances attributable to our investments, we have applied an accounting policy that looks through our investments including our investment in Kinder Morgan Energy Partners. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investment in Kinder Morgan Energy Partners.

## 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. Foreign currency transaction gains and losses are included within “Other Income (Expense) – Other, net” in the accompanying Consolidated Statements of Operations.



We translate the assets and liabilities of each of our consolidating foreign subsidiaries to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders' equity accounts are translated by using historical exchange rates. Translation adjustments result from translating all assets and liabilities at current year-end rates, while stockholders' equity is translated by using historical and weighted-average rates. The cumulative translation adjustments balance is reported as a component of the "Accumulated other comprehensive loss" caption in the accompanying Consolidated Balance Sheets.

## 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 and cross-currency interest rate swap agreements to mitigate foreign currency risk from our investments in businesses owned and operated outside the United States. 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 are 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 the accompanying Consolidated Balance Sheets as of December 31, 2009 and 2008 are not material.

## Transfer of Net Assets Between Entities Under Common Control

We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.

## Subsequent Events

We have evaluated subsequent events, which are events or transactions that occurred after December 31, 2009 through the issuance of the accompanying Consolidated Financial Statements.

## 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 interests 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, Kinder Morgan Energy Partners completed the following acquisitions from unrelated entities. For each of these acquisitions, Kinder Morgan Energy Partners 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 the accompanying Consolidated Financial Statements from the acquisition date.

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

## (1) Interest in Cochin Pipeline

Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximate 50.2% interest in the Cochin pipeline system that it 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 Kinder Morgan Energy Partners for certain pipeline integrity management costs over a five-year period in an aggregate amount not to exceed $50 million. Upon closing, Kinder Morgan Energy Partners 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 the Products Pipelines–KMP business segment.

## (2) Vancouver Wharves Terminal

On May 30, 2007, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' existing West region terminal operations, and all of the acquired assets are included in the Terminals–KMP business segment. In the first half of 2008, Kinder Morgan Energy Partners made its final purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities. The 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.

## (3) Marine Terminals, Inc. Assets

Effective September 1, 2007, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' existing ferro alloy terminal operations and provides customers further access to its growing national network of marine and rail terminals. All of the acquired assets are included in the Terminals–KMP business segment. In the first nine months of 2008, Kinder Morgan Energy Partners paid an additional $0.5 million for purchase price settlements, and made purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities. The 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 Kinder Morgan Energy Partners’ existing ferro alloy terminal operations and will provide Nucor and other customers further access to its growing national network of marine and rail terminals. Kinder Morgan Energy Partners believes 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, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' existing Southeast region terminal operations, and all of the acquired assets are included in the Terminals–KMP business segment.

In the fourth quarter of 2008, Kinder Morgan Energy Partners allocated its 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 the Terminals–KMP business segment and the entire amount is expected to be deductible for tax purposes. Kinder Morgan Energy Partners believes this acquisition resulted in the recognition of goodwill primarily because of certain advantageous factors (including the synergies provided by increasing its liquids storage capacity in the Southeast region of the U.S.) that contributed to its 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, Kinder Morgan Energy Partners’ 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 Kinder Morgan Energy Partners’ existing Phoenix liquids assets, and the acquired incremental storage increased Kinder Morgan Energy Partners’ combined storage capacity in the Phoenix market by approximately 13%. The acquired terminal is included as part the Products Pipelines–KMP business segment.

## (6) Mega Fleet Towing Co., Inc. Assets

Effective April 23, 2009, Kinder Morgan Energy Partners acquired certain terminals assets from Mega Fleet Towing Co., Inc. for an aggregate consideration of approximately $21.7 million. Kinder Morgan Energy Partners’ 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 Kinder Morgan Energy Partners 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.

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 Kinder Morgan Energy Partners' existing Gulf Coast and Texas petroleum coke terminal operations, and all of the acquired assets are included in the Terminals–KMP business segment. We allocated $10.6 million of the purchase price to “Goodwill,” and we expect that approximately $5.0 million of goodwill will be deductible for tax purposes. Kinder Morgan Energy Partners believes the primary item that generated the goodwill is the value of the synergies created between the acquired assets and its pre-existing terminal assets (resulting from the increase in services now offered by its Texas petroleum coke operations).

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

On October 1, 2009, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners the largest provider of contract-provided treating plants in the U.S. and complemented and expanded the existing natural gas treating operations offered by its Texas intrastate natural gas pipeline group. All of the acquired assets are included in the Natural Gas Pipelines–KMP business segment.

Kinder Morgan Energy Partners measured the identifiable intangible assets acquired at fair value on the acquisition date and accordingly, 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. Kinder Morgan Energy Partners estimates 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, Kinder Morgan Energy Partners 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. Kinder Morgan Energy Partners believes the primary item that generated the goodwill is its ability to grow the business by leveraging its pre-existing natural gas operations (resulting from the increase in services now offered by its natural gas processing and treating operations in the state of Texas), and Kinder Morgan Energy Partners believes that this value contributed to its 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, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' existing natural gas gathering and transportation business located in the state of Texas. Kinder Morgan Energy Partners accounts for this investment under the equity method of accounting, and the investment is included in the Natural Gas Pipelines–KMP 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 the accompanying Consolidated Statements of Operations.

## Divestitures

## North System Natural Gas Liquids Pipeline System—Discontinued Operations

In October 2007, Kinder Morgan Energy Partners completed the sale of its North System and its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6 million in cash. For the year ended December 31, 2008, Kinder Morgan Energy Partners paid $2.4 million to ONEOK Partners, L.P. to fully settle both the sale of working capital items and the allocation of pre-acquisition investee distributions, and to partially settle the sale of liquids inventory balances. Due to the fair market valuation resulting from the Going Private transaction (see Note 2), the consideration Kinder Morgan Energy Partners received from the sale of its North System was equal to its carrying value; therefore no gain or loss was recorded on this disposal transaction. The North System consists of an approximately 1,600-mile interstate common carrier pipeline system that delivers natural gas liquids and refined petroleum products from south central Kansas to the Chicago area. Also included in the sale were eight propane truck-loading terminals located at various points in three states along the pipeline system, and one multi-product terminal complex located in Morris, Illinois. All of these assets were included in the Products Pipelines–KMP business segment.

## Thunder Creek Gas Services, LLC

Effective April 1, 2008, Kinder Morgan Energy Partners sold its 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, Kinder Morgan Energy Partners accounted for its investment in Thunder Creek under the equity method of accounting and included its financial results within the Natural Gas Pipelines–KMP business segment. In the second quarter of 2008, Kinder Morgan Energy Partners received cash proceeds, net of closing costs and settlements, of approximately $50.7 million for its investment, and recognized a gain of $13.0 million with respect to this transaction. Kinder Morgan



Energy Partners used the proceeds from this sale to reduce the outstanding balance on its commercial paper borrowings, and we included the amount of the gain within the caption “Other, net” in the accompanying Consolidated Statement of Operations for the year ended December 31, 2008.

## Cypress Pipeline

On July 14, 2009 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' Cypress Pipeline. Kinder Morgan Energy Partners expects the transaction to close no earlier than the end of the first quarter of 2010. As of December 31, 2009, the net assets of the Cypress Pipeline totaled approximately $21.3 million. The sale of 50% of Kinder Morgan Energy Partners' Cypress Pipeline will not have a material impact on our business, financial position, results of operations or our cash flows.

## NGPL PipeCo LLC

On February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC (formerly MidCon Corp.), which owns Natural Gas Pipeline Company of America LLC and certain affiliates, collectively referred to as “NGPL,” to Myriac Acquisition Inc. (“Myriac”) for approximately $2.9 billion. We also received approximately $3.0 billion of cash previously held in escrow related to a notes offering by NGPL PipeCo LLC in December 2007, the net proceeds of which were distributed to us principally as repayment of intercompany indebtedness and partially as a dividend, immediately prior to the closing of the sale to Myriac. Pursuant to the purchase agreement, Myriac acquired all 800 Class B shares and we retained all 200 Class A shares of NGPL PipeCo LLC. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. The total proceeds from this sale of $5.9 billion were used to pay off the entire outstanding balances of our senior secured credit facility’s Tranche A and Tranche B term loans, to repurchase $1.67 billion of our outstanding debt securities and to reduce balances outstanding under our $1.0 billion revolving credit facility.

## Terasen Pipelines (Corridor) Inc. – Discontinued Operations

In June 2007, we completed the sale of Terasen Pipelines (Corridor) Inc. (“Corridor”) to Inter Pipeline Fund, a Canada-based company. Corridor transports diluted bitumen from the Athabasca Oil Sands Project near Fort McMurray, Alberta, to the Scotford Upgrader near Fort Saskatchewan, Alberta. The sale did not include any other assets of Kinder Morgan Canada (formerly Terasen Pipelines). The sale price was approximately $711 million (C$760 million) plus the buyer’s assumption of all of the debt related to Corridor, including the debt associated with the expansion taking place on Corridor at the time of the sale. The consideration was equal to Corridor’s carrying value, therefore no gain or loss was recorded on this disposal transaction.

## Terasen Inc. – Discontinued Operations

We closed the sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of approximately $3.4 billion (C$3.7 billion) including cash plus the buyers' assumption of debt. The sale did not include the assets of Kinder Morgan Canada (formerly Terasen Pipelines) discussed in the preceding paragraph. We recorded a book gain on this disposition of $55.7 million in the second quarter of 2007. The sale resulted in a capital loss of $998.6 million for tax purposes. Approximately $223.3 million of this loss was utilized to reduce capital gains principally associated with the sale of our U.S.-based retail gas operations (see below) resulting in a tax benefit of approximately $82.2 million. The remaining capital loss carryforward of $775.3 million was utilized to reduce the capital gain associated with our sale of an 80% ownership interest in NGPL PipeCo LLC.

## Natural Gas Distribution and Retail Operations – Discontinued Operations

In March 2007, we completed the sale of our U.S.-based retail natural gas distribution and related operations to GE Energy Financial Services, a subsidiary of General Electric Company and Alinda Investments LLC for $710 million and an adjustment for working capital. In conjunction with this sale, we recorded a pre-tax gain of $251.8 million (net of $3.9 million of transaction costs) in the first quarter of 2007. The Natural Gas Pipelines–KMP business segment (i) provides natural gas transportation and storage services and sells natural gas to and (ii) receives natural gas transportation and storage services, natural gas and natural gas liquids and other gas supply services from the discontinued U.S.-based retail natural gas distribution business. These transactions are continuing after the sale of this business and will likely continue to a similar extent into the future. For the five months ended May 31, 2007, revenues and expenses of our continuing operations totaling $3.1 million and $1.2 million, respectively for products and services sold to and purchased from our discontinued U.S.-based retail natural gas distribution operations prior to its sale in March 2007, have been eliminated in the accompanying Consolidated Statements of Operations. We are currently receiving fees from SourceGas, a subsidiary of General Electric Company, to provide certain administrative functions for a limited period of time and for the lease of office space. We do not have any significant continuing involvement in or retain any ownership interest in these operations and, therefore, the continuing cash flows discussed above are not considered direct cash flows of the disposed assets.



## Other Divestitures

In January 2008, we completed the sale of our interests in three natural gas-fired power plants in Colorado to Bear Stearns. We received proceeds of $63.1 million.

## Earnings of Discontinued Operations

The financial results of discontinued operations have been reclassified for all periods presented and reported in the caption, “Income (loss) from Discontinued Operations, net of tax” in the accompanying Consolidated Statements of Operations. Summarized financial results of these operations are as follows (in millions):

<table><tr><td rowspan="2"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Seven Months Ended December 31, 2009</td><td colspan="2">Five Months Ended May 31, 2007</td><td></td></tr><tr><td>Revenues</td><td>2009</td><td>2008</td><td>2007</td><td></td><td></td><td></td></tr><tr><td></td><td>$ -</td><td>$ -</td><td>$ 24.1</td><td>$ 921.8</td><td></td><td></td></tr><tr><td>Income (loss) from discontinued operations before income taxes</td><td>$ 0.5</td><td>$ (0.9)</td><td>$ (10.2)</td><td>$ 393.2</td><td></td><td></td></tr><tr><td>Income taxes</td><td>(0.2)</td><td>-</td><td>8.7</td><td>(94.6)</td><td></td><td></td></tr><tr><td>Income (loss) from discontinued operations</td><td>$ 0.3</td><td>$ (0.9)</td><td>$ (1.5)</td><td>$ 298.6</td><td></td><td></td></tr></table>

The cash flows attributable to discontinued operations are included in the accompanying Consolidated Statements of Cash Flows for the years ended December 31, 2009 and 2008, seven months ended December 31, 2007, and five months ended May 31, 2007 in the captions “Net Cash Flows (Used in) Provided by Discontinued Operations,” “Net Cash Flows Provided by Discontinued Investing Activities” and “Net Cash Flows Provided by Discontinued Financing Activities.”

## Acquisitions Subsequent to December 31, 2009

## USD Terminal Acquisition

On January 15, 2010, Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners already owns and operates, and other terminal projects currently under development by both parties. The acquisition complemented and expanded the ethanol and rail terminal operations Kinder Morgan Energy Partners previously owned, and all of the acquired assets are included in the Terminals–KMP business segment. In the first quarter of 2010, Kinder Morgan Energy Partners expects 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 March 5, 2010, Kinder Morgan Energy Partners acquired four terminals from Slay Industries for approximately $98 million in cash. The facilities include (i) a marine terminal located in Saugett, 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, Kinder Morgan Energy Partners and Slay Industries entered into joint venture agreements at both the Kellogg Dock coal bulk terminal, located in Modock, Illinois, and at the newly created North Cakobia terminal, located in Saugett, Illinois, which has approximately 175 acres to develop. All of the assets in Saugett have access to the Mississippi River and five rail carriers. The acquisition complemented and expanded Kinder Morgan Energy Partners' pre-existing Midwest terminal operations by adding a diverse mix of liquid and bulk capabilities, and all of the acquired assets are included in the Terminals-KMP business segment. In the first quarter of 2010, Kinder Morgan Energy Partners expects 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 March 5, 2010.



## 4. Income Taxes

The components of income (loss) before income taxes from continuing operations are as follows (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Seven Months Ended December 31,</td><td colspan="2">Five Months Ended May 31,</td></tr><tr><td>United States</td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Foreign</td><td>$ 1,023.3</td><td>$ (2,978.7)</td><td>$ 511.8</td><td>$ 369.9</td><td></td></tr><tr><td>Total</td><td>$ 76.1</td><td>80.7</td><td>1.7</td><td>(376.4)</td><td></td></tr><tr><td></td><td>$ 1,099.4</td><td>$ (2,898.0)</td><td>$ 513.5</td><td>$ (6.5)</td><td></td></tr></table>

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

<table><tr><td rowspan="3"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Seven Months Ended December 31,</td><td colspan="2">Five Months Ended May 31,</td></tr><tr><td>Year Ended December 31,</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Current tax provision</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$ 249.6</td><td>$ 786.6</td><td>$ 268.6</td><td>$ (7.0)</td><td></td></tr><tr><td>State</td><td>16.9</td><td>18.6</td><td>25.1</td><td>3.2</td><td></td></tr><tr><td>Foreign</td><td>-</td><td>(4.5)</td><td>23.5</td><td>0.6</td><td></td></tr><tr><td></td><td>266.5</td><td>800.7</td><td>317.2</td><td>(3.2)</td><td></td></tr><tr><td>Deferred tax provision</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>28.4</td><td>(439.5)</td><td>(95.2)</td><td>134.0</td><td></td></tr><tr><td>State</td><td>0.2</td><td>11.5</td><td>0.5</td><td>6.4</td><td></td></tr><tr><td>Foreign</td><td>30.5</td><td>(68.4)</td><td>4.9</td><td>(1.7)</td><td></td></tr><tr><td></td><td>59.1</td><td>(496.4)</td><td>(89.8)</td><td>138.7</td><td></td></tr><tr><td>Total tax provision</td><td>$ 325.6</td><td>$ 304.3</td><td>$ 227.4</td><td>$ 135.5</td><td></td></tr></table>

The difference between the statutory federal income tax expense (and rate) and our actual income tax expense (and effective income tax rate) is summarized as follows (in millions, except percentages):

<table><tr><td rowspan="3"></td><td colspan="6">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Year Ended December 31,</td><td colspan="3">Seven Months Ended December 31, 2007</td><td colspan="2">Five Months Ended May 31, 2007</td></tr><tr><td>2009</td><td>2008</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal income tax</td><td>$ 384.8</td><td>35.0%</td><td>$ (1,014.3)</td><td>(35.0)%</td><td>$ 179.7</td><td>35.0%</td><td>$ (2.3)</td><td>(35.0)%</td></tr><tr><td>Increase (decrease) as a result of:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Nondeductible goodwill impairment</td><td>-</td><td>-%</td><td>1,411.7</td><td>48.7%</td><td>(3.5)</td><td>(0.7)%</td><td>132.0</td><td>2,039.8%</td></tr><tr><td>Terasen acquisition financing structure</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(16.6)</td><td>(257.0)%</td></tr><tr><td>Nondeductible going private costs</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>30.8</td><td>475.6%</td></tr><tr><td>Deferred tax rate change</td><td>(10.4)</td><td>(0.9)%</td><td>17.8</td><td>0.6%</td><td>-</td><td>-</td><td>0.5</td><td>(0.2)%</td></tr><tr><td>Taxes on foreign earnings</td><td>30.2</td><td>2.7%</td><td>(68.2)</td><td>(2.4)%</td><td>27.7</td><td>5.4%</td><td>8.4</td><td>129.5%</td></tr><tr><td>Net effects of consolidating Kinder Morgan Energy Partners&#x27; United States income tax provision</td><td>(93.5)</td><td>(8.5)%</td><td>(77.4)</td><td>(2.7)%</td><td>14.6</td><td>2.8%</td><td>(22.5)</td><td>(348.3)%</td></tr><tr><td>State income tax, net of federal benefit</td><td>24.6</td><td>2.2%</td><td>17.1</td><td>0.6%</td><td>11.1</td><td>2.2%</td><td>6.9</td><td>105.6%</td></tr><tr><td>Other</td><td>(10.1)</td><td>(0.9)%</td><td>17.6</td><td>0.7%</td><td>(2.2)</td><td>(0.4)%</td><td>(1.7)</td><td>(25.4)%</td></tr><tr><td>Total</td><td>$ 325.6</td><td>29.6%</td><td>$ 304.3</td><td>10.5%</td><td>$ 227.4</td><td>44.3%</td><td>$ 135.5</td><td>2,084.6%</td></tr></table>



Deferred tax assets and liabilities result from the following (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Deferred tax assets</td><td></td><td></td></tr><tr><td>Employee benefits</td><td>$ 57.6</td><td>$ 79.8</td></tr><tr><td>Book accruals</td><td>21.3</td><td>14.3</td></tr><tr><td>Net operating loss carryforwards</td><td>11.4</td><td>-</td></tr><tr><td>Interest rate and currency swaps</td><td>24.3</td><td>7.0</td></tr><tr><td>Other</td><td>25.9</td><td>7.9</td></tr><tr><td>Total deferred tax assets</td><td>140.5</td><td>109.0</td></tr><tr><td>Deferred tax liabilities</td><td></td><td></td></tr><tr><td>Property, plant and equipment</td><td>239.9</td><td>160.0</td></tr><tr><td>Investments</td><td>1,880.2</td><td>1,937.2</td></tr><tr><td>Book accruals</td><td>4.7</td><td>-</td></tr><tr><td>Derivative instruments</td><td>12.5</td><td>5.7</td></tr><tr><td>Prepaid pension costs</td><td>-</td><td>16.6</td></tr><tr><td>Debt adjustment</td><td>19.4</td><td>23.0</td></tr><tr><td>Other</td><td>9.5</td><td>47.8</td></tr><tr><td>Total deferred tax liabilities</td><td>2,166.2</td><td>2,190.3</td></tr><tr><td>Net deferred tax liabilities</td><td>$ 2,025.7</td><td>$ 2,081.3</td></tr><tr><td>Current deferred tax asset</td><td>$ 14.2</td><td>$ -</td></tr><tr><td>Non-current deferred tax liability</td><td>2,039.9</td><td>2,081.3</td></tr><tr><td>Net deferred tax liabilities</td><td>$ 2,025.7</td><td>$ 2,081.3</td></tr></table>

During 2007, our sale of Terasen Inc. resulted in a capital loss of $998.6 million of which approximately $223.3 million was utilized to reduce capital gain principally associated with the sale of our U.S.-based retail natural gas operations. The remaining capital loss was carried forward and utilized to reduce the capital gain on the sale of our 80% ownership interest in the NGPL PipeCo LLC business segment.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation of our gross unrecognized tax benefit excluding interest and penalties for the years ended December 31, 2009, 2008 and 2007 is as follows (in millions):

<table><tr><td></td><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Balance at beginning of period</td><td>$ 26.2</td><td>$ 41.5</td><td>$ 63.1</td></tr><tr><td>Additions based on current year tax positions</td><td>1.4</td><td>2.1</td><td>9.8</td></tr><tr><td>Additions based on prior year tax positions</td><td>19.3</td><td>15.9</td><td>0.5</td></tr><tr><td>Settlements with taxing authority</td><td>14.0</td><td>(10.2)</td><td>(21.4)</td></tr><tr><td>Reductions due to lapse in statute of limitations</td><td>(8.9)</td><td>(3.7)</td><td>(2.7)</td></tr><tr><td>Reductions for tax positions related to prior year</td><td>-</td><td>(19.4)</td><td>(7.8)</td></tr><tr><td>Balance at end of period</td><td>$ 52.0</td><td>$ 26.2</td><td>$ 41.5</td></tr></table>

Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of December 31, 2009, we had $6.5 million of accrued interest and $0.8 million in accrued penalties. As of December 31, 2008, we had $2.9 million of accrued interest and $0.8 million of accrued penalties. As of December 31, 2007, we had $8.1 million of accrued interest and no penalties. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by $2.2 million during the next twelve months, and that approximately $40.6 million included in the total $52.0 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. Such amounts exclude interest, while the latter amount of $52.0 million includes both temporary and permanent differences.

We are subject to taxation, and have tax years open to examination for the periods 2006-2009 in the United States and Mexico, 2005-2009 in Canada, and 1999-2009 in various states.



## 5. Property, Plant and Equipment

## Classes and Depreciation

Our property, plant and equipment, net consisted of the following (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Kinder Morgan, Inc.</td><td></td><td></td></tr><tr><td>General and other</td><td>$ 45.7</td><td>$ 44.4</td></tr><tr><td>Kinder Morgan Energy Partners(a)</td><td></td><td></td></tr><tr><td>Natural gas, liquids, crude oil and carbon dioxide pipelines</td><td>6,503.6</td><td>5,641.5</td></tr><tr><td>Natural gas, liquids, carbon dioxide, and terminals station equipment.</td><td>9,271.8</td><td>7,577.0</td></tr><tr><td>Natural gas, liquids (including linefill), and transmiss processing</td><td>220.3</td><td>210.3</td></tr><tr><td>Other</td><td>1,671.3</td><td>2,084.5</td></tr><tr><td>Accumulated depreciation, depletion and amortization</td><td>(2,002.8)</td><td>(979.0)</td></tr><tr><td></td><td>15,709.9</td><td>14,578.7</td></tr><tr><td>Land and land right-of-way</td><td>519.5</td><td>201.7</td></tr><tr><td>Construction work in process</td><td>574.1</td><td>1,329.4</td></tr><tr><td>Property, plant and equipment, net</td><td>$ 16,803.5</td><td>$ 16,109.8</td></tr></table>

(a) Includes the allocation of purchase accounting adjustments associated with the Going Private transaction (see Note 2).

Depreciation and depletion expense charged against property, plant and equipment consisted of $1,047.5 million in 2009, $897.2 million in 2008, $464.3 million in the seven months ended December 31, 2007 and $256.5 million in the five months ended May 31, 2007.

## Asset Retirement Obligations

As of December 31, 2009 and 2008, we have recognized asset retirement obligations in the aggregate amount of $100.9 million and $76.5 million, respectively. The majority of our recorded asset retirement obligations are associated with the CO \( _{2} \) -KMP business segment, where Kinder Morgan Energy Partners is required to plug and abandon oil and gas wells that have been removed from service and to remove its surface wellhead equipment and compressors. We have included $2.5 million of asset retirement obligations as of both December 31, 2009 and 2008 within “Accrued other current liabilities” in the accompanying Consolidated Balance Sheets. The remaining amounts are included within “Other long-term liabilities and deferred credits” at each reporting date.

A reconciliation of the beginning and ending aggregate carrying amount of recorded asset retirement obligations is as follows (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Balance at beginning of period</td><td>$ 76.5</td><td>$ 55.0</td></tr><tr><td>Liabilities incurred/revised</td><td>26.0</td><td>26.2</td></tr><tr><td>Liabilities settled</td><td>(6.2)</td><td>(8.2)</td></tr><tr><td>Accretion expense</td><td>4.6</td><td>3.5</td></tr><tr><td>Balance at end of period</td><td>$ 100.9</td><td>$ 76.5</td></tr></table>

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

## 6. Investments

We reported a combined $3,695.6 million and $1,827.4 million as “Investments” in the accompanying Consolidated Balance Sheet as of December 31, 2009 and 2008, respectively. 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.



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

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Rockies Express Pipeline LLC</td><td>$ 1,693.4</td><td>$ 501.1</td></tr><tr><td>NGPL PipeCo LLC</td><td>698.5</td><td>717.3</td></tr><tr><td>Midcontinent Express Pipeline LLC</td><td>662.3</td><td>-</td></tr><tr><td>Plantation Pipe Line Company</td><td>340.4</td><td>343.6</td></tr><tr><td>Red Cedar Gathering Company</td><td>145.8</td><td>138.9</td></tr><tr><td>Express pipeline system</td><td>68.0</td><td>64.9</td></tr><tr><td>Cortez Pipeline Company</td><td>11.2</td><td>13.6</td></tr><tr><td>Endeavor Gathering LLC</td><td>36.2</td><td>-</td></tr><tr><td>Subsidiary trusts holding solely debentures of Kinder Morgan</td><td>8.6</td><td>8.6</td></tr><tr><td>All others</td><td>18.0</td><td>26.2</td></tr><tr><td>Total equity investments</td><td>3,682.4</td><td>1,814.2</td></tr><tr><td>Gulf Opportunity Zone Bonds</td><td>13.2</td><td>13.2</td></tr><tr><td>Total long-term investments</td><td>$ 3,695.6</td><td>$ 1,827.4</td></tr></table>

The increase in the carrying amounts of our equity investments since December 31, 2008 was primarily driven by Kinder Morgan Energy Partners' 2009 equity capital contributions of $2,051.8 million, 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 Kinder Morgan Energy Partners has made with respect to its equity investees, see Note 12 "Commitments and Contingent Liabilities—Contingent Debt."

As shown in the table above, our significant equity investments, including those of Kinder Morgan Energy Partners, as of December 31, 2009 consisted of the following:

Rockies Express Pipeline LLC (“Rockies Express”)—Kinder Morgan Energy Partners operates and owns a 50% ownership interest in Rockies Express, the surviving legal entity from its December 30, 2009 merger with its parent entity, West2East Pipeline LLC. Rockies Express 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 are owned by Sempra Energy and ConocoPhillips.

Effective December 1, 2009, Kinder Morgan Energy Partners' 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. Kinder Morgan Energy Partners received $31.9 million for the 1% reduction in 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 the 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. Additionally, in 2009 and 2008, Kinder Morgan Energy Partners made capital contributions of $1,273.1 million and $306.0 million, respectively, to Rockies Express (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, Kinder Morgan Energy Partners also received, from Rockies Express, cash distributions of $148.8 million and $82.9 million, respectively;

NGPL PipeCo LLC (“NGPL”)—On February 15, 2008, we sold an 80% ownership interest in NGPL (formerly MidCon Corp.), which owns Natural Gas Pipeline of America and certain affiliates, collectively referred to as “NGPL,” to Myria Acquisition Inc. (“Myria”). Pursuant to the purchase agreement, Myria acquired all 800 Class B shares and we retained all 200 Class A shares of NGPL. We will continue to operate NGPL’s assets pursuant to a 15-year operating agreement. See Note 3 for further discussion regarding this transaction;

Midcontinent Express Pipeline LLC (“Midcontinent Express”)—Kinder Morgan Energy Partners operates and owns a 50% ownership interest in Midcontinent Express, which was 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, Kinder Morgan Energy Partners began making cash contributions for its share of the construction costs for the Midcontinent Express pipeline system, and in 2009 and 2008, Kinder Morgan Energy Partners made capital contributions of $664.5 million and $27.5 million, respectively, to Midcontinent Express to partially fund its pipeline construction costs. Kinder Morgan Energy Partners received cash distributions of $16.2.



million and $1.9 million in 2009 and 2008, respectively; however, as of December 31, 2008, Kinder Morgan Energy Partners had no net investment in Midcontinent Express 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, Kinder Morgan Energy Partners 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 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—Kinder Morgan Energy Partners acquired its 49% ownership interest in the Red Cedar Gathering Company from us 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—Kinder Morgan Energy Partners operates and owns 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, Kinder Morgan Energy Partners does not control Plantation Pipe Line Company, and it accounts for its investment under the equity method;

Express pipeline system—Kinder Morgan Energy Partners acquired our 33 1/3% ownership interest in the Express pipeline system effective August 28, 2008 (discussed in Note 11 “Related Party Transactions”);

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

Cortez Pipeline Company—Kinder Morgan Energy Partners operates and owns a 50% ownership interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. Kinder Morgan Energy Partners acquired its 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, Kinder Morgan Energy Partners significant equity investments included a 25% ownership interest in Thunder Creek Gas Services, LLC until it sold its ownership interest to PVR Midstream LLC on April 1, 2008. The divestiture of the investment in Thunder Creek Gas Services, LLC is discussed in Note 3 “Acquisitions and Divestitures”.

Kinder Morgan Energy Partners also owns a 50% ownership interest in Fayetteville Express Pipeline LLC (“Fayetteville Express”), which was formed in August 2008. Fayetteville Express 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 and will operate the Fayetteville Express pipeline system. In 2009 and 2008, Kinder Morgan Energy Partners made capital contributions of $103.2 million and $9.0 million, respectively, to Fayetteville Express to partially fund certain pre-construction pipeline costs. As of December 31, 2009, however, Kinder Morgan Energy Partners had no material net investment in Fayetteville Express because in November 2009, Fayetteville Express 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, Kinder Morgan Energy Partners received cash distributions of $115.6 million from Fayetteville Express in 2009.



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

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Seven Months Ended December 31, 2009</td><td colspan="2">Five Months Ended May 31, 2007</td></tr><tr><td>Rockies Express</td><td>98.5</td><td>84.9</td><td>(8.2)</td><td>(4.2)</td><td></td></tr><tr><td>NGPL</td><td>42.5</td><td>40.1</td><td>-</td><td>-</td><td></td></tr><tr><td>Red Cedar Gathering Company</td><td>24.9</td><td>26.7</td><td>16.1</td><td>11.9</td><td></td></tr><tr><td>Cortez Pipeline Company</td><td>22.3</td><td>20.8</td><td>10.5</td><td>8.7</td><td></td></tr><tr><td>Plantation Pipe Line Company</td><td>16.5</td><td>13.6</td><td>10.8</td><td>11.9</td><td></td></tr><tr><td>Thunder Creek Gas Services, LLC</td><td>-</td><td>1.3</td><td>1.2</td><td>1.0</td><td></td></tr><tr><td>Midcontinent Express</td><td>14.7</td><td>0.5</td><td>1.2</td><td>0.2</td><td></td></tr><tr><td>Express pipeline system</td><td>(4.1)</td><td>8.2</td><td>14.9</td><td>5.0</td><td></td></tr><tr><td>Thermo Companies</td><td>-</td><td>-</td><td>8.0</td><td>5.1</td><td></td></tr><tr><td>Horizon Pipeline Company</td><td>-</td><td>0.2</td><td>1.0</td><td>0.6</td><td></td></tr><tr><td>Endeavor Gathering LLC</td><td>0.1</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>All others</td><td>6.5</td><td>4.8</td><td>1.3</td><td>0.5</td><td></td></tr><tr><td>Total</td><td>221.9</td><td>201.1</td><td>36.8</td><td>40.7</td><td></td></tr><tr><td>Amortization of excess costs</td><td>(5.8)</td><td>(5.7)</td><td>(3.4)</td><td>(2.4)</td><td></td></tr></table>

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):

<table><tr><td colspan="4">Year Ended December 31,</td></tr><tr><td>Income Statement (a)</td><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Revenues</td><td>2,351.9</td><td>2,170.4</td><td>738.4</td></tr><tr><td>Costs and expenses</td><td>1,754.8</td><td>1,649.6</td><td>534.4</td></tr><tr><td>Earnings before extraordinary items and cumulative effect of a change in accounting principle</td><td>597.1</td><td>520.8</td><td>204.0</td></tr><tr><td>Net income</td><td>597.1</td><td>520.8</td><td>204.0</td></tr></table>

<table><tr><td rowspan="2">Balance Sheet</td><td colspan="2">December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Current assets</td><td>501.8</td><td>501.7</td></tr><tr><td>Non-current assets</td><td>16,687.5</td><td>13,582.1</td></tr><tr><td>Current liabilities</td><td>2,299.7</td><td>3,876.4</td></tr><tr><td>Non-current liabilities</td><td>6,275.6</td><td>5,306.0</td></tr><tr><td>Minority interest in equity of subsidiaries</td><td>-</td><td>0.6</td></tr><tr><td>Shareholders&#x27; equity</td><td>8,614.0</td><td>4,900.8</td></tr></table>

(a) Amounts exclude NGPL earnings prior to sale of our 80% interest on February 15, 2008.

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

Changes in the gross amounts of our goodwill for each of the two years ended December 31, 2009 and 2008 are summarized as follows (in millions):

<table><tr><td></td><td>Products Pipelines-KMP</td><td>Natural Gas Pipelines-KMP</td><td>CO2-KMP</td><td>Terminals-KMP</td><td>Kinder Morgan Canada-KMP</td><td>Total</td></tr><tr><td>Balance as of December 31, 2007</td><td>$ 2,179.4</td><td>$ 3,201.0</td><td>$ 1,077.6</td><td>$ 1,465.9</td><td>$ 250.1</td><td>$ 8,174.0</td></tr><tr><td>Acquisitions and purchase price adjustment</td><td>(54.8)</td><td>251.2</td><td>450.9</td><td>(9.5)</td><td>-</td><td>637.8</td></tr><tr><td>Disposals.</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Impairments</td><td>(1,266.5)</td><td>(2,090.2)</td><td>-</td><td>(676.6)</td><td>-</td><td>(4,033.3)</td></tr><tr><td>Other</td><td>(8.1)</td><td>(12.8)</td><td>(6.8)</td><td>(5.6)</td><td>(46.5)</td><td>(79.8)</td></tr><tr><td>Balance as of December 31, 2008</td><td>850.0</td><td>1,349.2</td><td>1,521.7</td><td>774.2</td><td>203.6</td><td>4,698.7</td></tr><tr><td>Acquisitions and purchase price adjustment</td><td>-</td><td>48.6</td><td>-</td><td>(35.4)</td><td>-</td><td>13.2</td></tr><tr><td>Disposals.</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Impairments</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><tr><td>Currency translation adjustments</td><td>-</td><td>-</td><td>-</td><td>-</td><td>32.4</td><td>32.4</td></tr><tr><td>Balance as of December 31, 2009</td><td>$ 850.0</td><td>$ 1,397.8</td><td>$ 1,521.7</td><td>$ 738.8</td><td>$ 236.0</td><td>$ 4,744.3</td></tr></tr></table>

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

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 the accompanying Consolidated Balance Sheets. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount.

We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines–KMP (excluding associated terminals), (ii) Products Pipelines Terminals–KMP (evaluated separately from Products Pipelines–KMP for goodwill purposes), (iii) Natural Gas Pipelines–KMP, (iv) CO \( _{2} \) –KMP, (v) Terminals–KMP and (vi) Kinder Morgan Canada–KMP. 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.

In the second quarter of 2008, we finalized the purchase price allocation associated with our May 2007 Going Private transaction, establishing the fair values of our individual assets and liabilities including assigning the associated goodwill to our six reporting units, in each case as of the May 31, 2007 acquisition date. A significant portion of the goodwill that arose in conjunction with this acquisition was determined to be associated with the general partner and significant limited partner interests in Kinder Morgan Partners (a publicly traded master limited partnership, or “MLP”), attributable, in part, to the difference between the market multiples that might be paid to acquire the general partner and limited interests in an MLP and the market multiples that might be paid to acquire the individual assets that comprise that MLP. This market premium is partially attributable to the incentive distribution right that is embedded in the Kinder Morgan Energy Partners general partner interest for which a separate intangible asset was not recognized in purchase accounting because this right cannot be detached or transferred apart from the entire general partner interest.

In conjunction with our first annual impairment test of the carrying value of this goodwill, performed as of May 31, 2008, we determined that the fair value of certain reporting units that are part of our investment in Kinder Morgan Energy Partners were less than the carrying values. 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. Thus, any value generated from the inclusion of these assets in an MLP structure was not captured in the valuation of these reporting units. This resulted in several of the reporting units having fair values less than their carrying values as the incremental value created by the inclusion of these assets in an MLP structure was taken into account in the Going Private transaction and thus was used in allocating the purchase price. To capture this value at the reporting unit level, we believe it would be necessary to recreate the MLP structure at the reporting unit level. We believe this is not feasible for Kinder Morgan, Inc. or for any market participant, as further discussed below.



Recreating such structure would involve separating each of our reporting units into separate entities so that each reporting unit could be valued on a stand alone basis assuming each such unit was sold as an MLP. Creating separate MLPs would involve significant structural difficulties including potentially numerous adverse state and federal tax consequences to Kinder Morgan Energy Partners and its unitholders. In addition, it would involve a significant amount of tax, legal and commercial analysis, and based on that analysis may also require customer and/or joint venture consents, lender consents, and regulatory approvals and/or unitholder approval. As a result of these factors, we believe that it is not feasible to apply the MLP structure related value to the individual reporting unit level.

For the reporting units where the fair value was determined to be less than the carrying value, we determined the implied fair value of goodwill. The implied fair value of goodwill within each reporting unit was then compared to the carrying value of goodwill of each such unit, resulting in the following goodwill impairment charges by reporting units: Products Pipelines–KMP (excluding associated terminals) – $1.20 billion, Products Pipelines Terminals–KMP (separate from Products Pipelines–KMP for goodwill impairment purposes) – $70 million, Natural Gas Pipelines–KMP – $2.09 billion, and Terminals–KMP – $677 million, for a total impairment of $4.03 billion. The goodwill impairment charges were non-cash charges and did not have any impact on our cash flows.

On April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain pipeline system from us. This transaction caused us to evaluate the fair value of the Trans Mountain pipeline system in determining whether goodwill related to these assets was impaired. Accordingly, based on our consideration of supporting information obtained regarding the fair values of the Trans Mountain pipeline system assets, a goodwill impairment non-cash charge of $377.1 million was recorded in five months ended May 31, 2007.

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 the 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.



## Other Intangibles

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, technology-based assets, and lease value. These intangible assets have definite lives and are reported separately as “Other intangibles, net” in the accompanying Consolidated Balance Sheets. Following is information related to our intangible assets subject to amortization (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">December 31,</td></tr><tr><td>2009</td><td>2008</td><td></td></tr><tr><td>Customer relationships, contracts and agreements</td><td></td><td></td><td></td></tr><tr><td>Gross carrying amount</td><td>$     297.9</td><td>$     270.9</td><td></td></tr><tr><td>Accumulated amortization</td><td>(50.9)</td><td>(30.3)</td><td></td></tr><tr><td>Net carrying amount</td><td>247.0</td><td>240.6</td><td></td></tr><tr><td>Technology-based assets, lease value and other</td><td></td><td></td><td></td></tr><tr><td>Gross carrying amount</td><td>14.1</td><td>11.7</td><td></td></tr><tr><td>Accumulated amortization</td><td>(1.3)</td><td>(0.8)</td><td></td></tr><tr><td>Net carrying amount</td><td>12.8</td><td>10.9</td><td></td></tr><tr><td>Total other intangibles, net</td><td>$     259.8</td><td>$     251.5</td><td></td></tr></table>

Our customer relationships, contracts and agreements relate primarily to the Terminals–KMP 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 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007, the amortization expense on our intangibles totaled $21.1 million, $19.2 million, $11.9 million and $6.3 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 $24.2 million, $22.1 million, $20.5 million, $19.6 million and $18.8 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 15.1 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 the accompanying Consolidated Statements of Operations.

## Short-Term Debt

Our outstanding short-term debt balance as of December 31, 2009 was $768.7 million. The balance consisted of (i) $171.0 million in outstanding borrowings under our senior secured credit facility, (ii) $1.1 million remaining portion of our 6.50% series debentures, due September 1, 2013, (iii) $300 million in outstanding borrowings under Kinder Morgan Energy Partners' bank credit facility, (iv) $251.9 million (including $1.9 million of unamortized discounts and purchase accounting attributable to the Going Private transaction) for Kinder Morgan Energy Partners' 7.50% senior notes due November 1, 2010, (v) $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 (Kinder Morgan Energy Partners' subsidiary Kinder Morgan Operating L.P. "B" is the obligor on the bonds), (vi) an $8.9 million portion of a 5.40% long-term note payable (Kinder Morgan Energy Partners' subsidiaries Kinder Morgan Operating L.P. "A" and Kinder Morgan Canada Company are the obligors on the note), (vii) a $6.8 million portion of 5.23% senior notes (Kinder Morgan Energy Partners' subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes) and (viii) $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 Kinder Morgan Energy Partners' subsidiary Arrow Terminals L.P. was the obligor on the bonds).

Our outstanding short-term debt as of December 31, 2008 was $302.5 million, consisting of (i) $8.8 million in outstanding borrowings under our senior secured credit facility, (ii) a $5.0 million current portion of our 6.50% series debentures, due September 1, 2013, (iii) $250 million in principal amount of Kinder Morgan Energy Partners' 6.30% senior notes due February 1, 2009, (iv) the $23.7 million in principal amount of tax-exempt bonds due from Kinder Morgan Energy Partners' subsidiary Kinder Morgan Operating L.P. "B", (v) an $8.5 million portion of the 5.40% long-term note payable due from Kinder Morgan Energy Partners' subsidiaries Kinder Morgan Operating L.P. "A" and Kinder Morgan Canada Company and (vi) a $6.5 million portion of the 5.23% senior notes due from Kinder Morgan Energy Partners' subsidiary Kinder Morgan Texas Pipeline, L.P.

## Credit Facilities

<table><tr><td rowspan="2"></td><td colspan="2">As of December 31, 2009</td></tr><tr><td>Short-term Notes Payable</td><td>Weighted-Average Interest Rate</td></tr><tr><td>Kinder Morgan, Inc. - Secured debt(a)</td><td>$ 171.0</td><td>1.61%</td></tr><tr><td>Kinder Morgan Energy Partners - Unsecured debt(b)</td><td>$ 300.0</td><td>0.59%</td></tr></table>

(a) The average short-term debt outstanding (and related weighted-average interest rate) was $77.7 million (2.09%) during the twelve months ended December 31, 2009. (b) The average short-term debt outstanding (and related weighted-average interest rate) was $442.1 million (1.43%) during the twelve months ended December 31, 2009.

Our $1.0 billion six-year senior secured revolving credit facility matures on May 30, 2013 and includes a sublimit of $300 million for the issuance of letters of credit and a sublimit of $50 million for swingline loans. We do not have a commercial paper program. We had $8.8 million outstanding under our credit facility at December 31, 2008.

The applicable margin for the revolving credit facility is subject to change pursuant to a leverage-based pricing grid. In addition, the credit agreement provides for customary commitment fees and letter of credit fees under the revolving credit facility. The credit agreement contains customary terms and conditions and is unconditionally guaranteed by each of our wholly owned material domestic restricted subsidiaries, to the extent permitted by applicable law and contract. Voluntary prepayments can be made at any time on revolving credit loans and swingline loans, in each case without premium or penalty, and on LIBOR Loans (as defined in the credit agreement) on the interest payment date without premium or penalty.

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 may not exceed:

7.00: 1.00 during January 1, 2009 and December 31, 2009; and

6.00: 1.00 thereafter;

• certain limitations on indebtedness, including payments and amendments;

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

• limitations on granting liens; and

• prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.

Kinder Morgan Energy Partners' $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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' credit facility accrues at its 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 Kinder Morgan Energy Partners' long-term senior unsecured debt. Borrowings under Kinder Morgan Energy Partners' credit facility can be used for general partnership purposes and as a backup for its commercial paper program.

As of December 31, 2008, there were no borrowings under the Kinder Morgan Energy Partners credit facility. The credit facility matures August 18, 2010, and currently, Kinder Morgan Energy Partners plans 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; Kinder Morgan Energy Partners amended the credit facility to remove Lehman Brothers Commercial Bank as a lender, thus reducing the borrowing capacity under its credit facility by $63.3 million. The commitments of the other banks remain unchanged, and the credit facility is not defaulted.

Additionally, as of December 31, 2009, the amount available for borrowing under Kinder Morgan Energy Partners' credit facility was reduced by an aggregate amount of $282.8 million, consisting of the 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 Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners and its subsidiaries.

Kinder Morgan Energy Partners' 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;

• 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 Kinder Morgan Energy Partners' credit facility, the occurrence at any time of any of the following would constitute an event of default: (i) Kinder Morgan Energy Partners' 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) Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners' credit facility, there are no provisions protecting against a situation where Kinder Morgan Energy Partners is 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, Kinder Morgan Energy Partners' credit facility does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin Kinder Morgan Energy Partners will pay with respect to borrowings, and the facility fee that it will pay on the total commitment, will vary based on its senior debt investment rating. None of Kinder Morgan Energy Partners' debt is subject to payment acceleration as a result of any change to its credit ratings.

## Commercial Paper Program

On October 13, 2008, Standard & Poor's Rating Services lowered Kinder Morgan Energy Partners' short-term credit rating to A-3 from A-2. Additionally, on May 6, 2009, Moody's Investor Services, Inc. downgraded Kinder Morgan Energy Partners' commercial paper rating to Prime-3 from Prime-2. As a result of these revisions and the commercial paper market conditions, Kinder Morgan Energy Partners has been unable to access commercial paper borrowings, and as of December 31, 2009 and 2008, it had no commercial paper borrowings.

On February 25, 2010, Standard & Poor's Rating Services raised Kinder Morgan Energy Partners' short-term credit rating to A-2 from A-3 which may allow Kinder Morgan Energy Partners access to the commercial paper market. However, Kinder Morgan Energy Partners expects that it will continue to meet its financing and liquidity needs primarily through borrowings made under its bank credit facility described above.



## Long-Term Debt

Our long-term debt balance at December 31, 2009 and 2008 was $13,240.7 million and $12,126.8 million, respectively. Total long-term debt consisted of the balances shown in the table below (in millions).

<table><tr><td rowspan="2">Kinder Morgan, Inc.</td><td colspan="3">December 31,</td></tr><tr><td>2009</td><td>2008</td><td></td></tr><tr><td>Debentures</td><td></td><td></td><td></td></tr><tr><td>6.50% Series, due September 1, 2013</td><td>$ 1.1</td><td>$ 6.1</td><td></td></tr><tr><td>6.67% Series, due November 1, 2027</td><td>7.0</td><td>7.0</td><td></td></tr><tr><td>7.25% Series, due March 1, 2028</td><td>32.0</td><td>32.0</td><td></td></tr><tr><td>7.45% Series, due March 1, 2098</td><td>25.9</td><td>25.9</td><td></td></tr><tr><td>Senior Notes</td><td></td><td></td><td></td></tr><tr><td>6.50% Series, due September 1, 2012</td><td>844.1</td><td>846.2</td><td></td></tr><tr><td>5.15% Series, due March 1, 2015</td><td>235.6</td><td>233.3</td><td></td></tr><tr><td>Deferrable Interest Debentures Issued to Subsidiary Trusts</td><td></td><td></td><td></td></tr><tr><td>8.56% Junior Subordinated Deferrable Interest Debentures due April 15, 2027</td><td>15.8</td><td>15.8</td><td></td></tr><tr><td>7.63% Junior Subordinated Deferrable Interest Debentures due April 15, 2028</td><td>19.9</td><td>19.9</td><td></td></tr><tr><td>Bank credit facility borrowings</td><td>171.0</td><td>8.8</td><td></td></tr><tr><td>Unamortized gain on termination of interest rate swap</td><td>4.6</td><td>6.4</td><td></td></tr><tr><td>Kinder Morgan Finance Company, LLC</td><td></td><td></td><td></td></tr><tr><td>5.35% Series, due January 5, 2011</td><td>745.9</td><td>742.0</td><td></td></tr><tr><td>5.70% Series, due January 5, 2016</td><td>811.6</td><td>806.6</td><td></td></tr><tr><td>6.40% Series, due January 5, 2036</td><td>34.4</td><td>33.8</td><td></td></tr><tr><td>Carrying value adjustment for interest rate swap(a)</td><td>13.5</td><td>-</td><td></td></tr><tr><td>Unamortized gain on termination of interest rate swap</td><td>10.5</td><td>12.8</td><td></td></tr><tr><td>Kinder Morgan G.P., Inc.</td><td></td><td></td><td></td></tr><tr><td>$1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock</td><td>100.0</td><td>100.0</td><td></td></tr><tr><td>Kinder Morgan Energy Partners, L.P. borrowings:</td><td></td><td></td><td></td></tr><tr><td>6.30% senior notes due February 1, 2009</td><td>-</td><td>250.1</td><td></td></tr><tr><td>7.50% senior notes due November 1, 2010</td><td>251.8</td><td>253.8</td><td></td></tr><tr><td>6.75% senior notes due March 15, 2011</td><td>704.3</td><td>707.6</td><td></td></tr><tr><td>7.125% senior notes due March 15, 2012</td><td>456.2</td><td>458.7</td><td></td></tr><tr><td>5.85% senior notes due September 15, 2012</td><td>500.0</td><td>500.0</td><td></td></tr><tr><td>5.00% senior notes due December 15, 2013</td><td>492.8</td><td>491.3</td><td></td></tr><tr><td>5.125% senior notes due November 15, 2014</td><td>491.7</td><td>490.2</td><td></td></tr><tr><td>5.625% senior notes due February 15, 2015</td><td>300.0</td><td>-</td><td></td></tr><tr><td>6.00% senior notes due February 1, 2017</td><td>598.0</td><td>597.8</td><td></td></tr><tr><td>5.95% senior notes due February 15, 2018</td><td>975.0</td><td>975.0</td><td></td></tr><tr><td>9.00% senior notes due February 1, 2019(b)</td><td>500.0</td><td>500.0</td><td></td></tr><tr><td>6.85% senior notes due February 15, 2020</td><td>700.0</td><td>-</td><td></td></tr><tr><td>5.80% senior notes due March 1, 2021</td><td>400.0</td><td>-</td><td></td></tr><tr><td>7.40% senior notes due March 15, 2031</td><td>310.1</td><td>310.3</td><td></td></tr><tr><td>7.75% senior notes due March 15, 2032</td><td>316.1</td><td>316.4</td><td></td></tr><tr><td>7.30% senior notes due August 15, 2033</td><td>513.7</td><td>513.9</td><td></td></tr><tr><td>5.80% senior notes due March 15, 2035</td><td>477.7</td><td>477.4</td><td></td></tr><tr><td>6.50% senior notes due February 1, 2037</td><td>395.8</td><td>395.8</td><td></td></tr><tr><td>6.95% senior notes due January 15, 2038</td><td>1,175.0</td><td>1,175.0</td><td></td></tr><tr><td>6.50% senior notes due September 1, 2039</td><td>600.0</td><td>-</td><td></td></tr><tr><td>Bank credit facility borrowings</td><td>300.0</td><td>-</td><td></td></tr><tr><td>Carrying value adjustment for interest rate swaps</td><td>10.0</td><td>754.2</td><td></td></tr><tr><td>Unamortized gain on termination of interest rate swaps</td><td>322.4</td><td>197.6</td><td></td></tr><tr><td>Subsidiary borrowings:</td><td></td><td></td><td></td></tr><tr><td>Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010</td><td>5.3</td><td>5.3</td><td></td></tr><tr><td>Kinder Morgan Louisiana Pipeline LLC-6.0% LA Development Revenue note due January 1, 2011</td><td>5.0</td><td>5.0</td><td></td></tr><tr><td>Kinder Morgan Operating L.P. “A”-5.40% BP note, due March 31, 2012</td><td>14.9</td><td>19.4</td><td></td></tr><tr><td>Kinder Morgan Canada Company-5.40% BP note, due March 31, 2012</td><td>13.2</td><td>17.2</td><td></td></tr><tr><td>Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014</td><td>30.5</td><td>37.0</td><td></td></tr></table>



<table><tr><td>Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due January 15, 2018</td><td>25.0</td><td>25.0</td></tr><tr><td>Kinder Morgan Columbus LLC-5.50% MS Development Revenue note due September 1, 2022</td><td>8.2</td><td>8.2</td></tr><tr><td>Kinder Morgan Operating L.P. “B”-Jackson-Union Cos. IL Revenue Bonds due April 1, 2024</td><td>23.7</td><td>23.7</td></tr><tr><td>International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025</td><td>40.0</td><td>40.0</td></tr><tr><td>Other miscellaneous subsidiary debt</td><td>1.3</td><td>1.3</td></tr><tr><td>Unamortized Debt Discount on Long-term Debt</td><td>(21.2)</td><td>(14.5)</td></tr><tr><td>Current Maturities of Long-term Debt</td><td>(768.7)</td><td>(302.5)</td></tr><tr><td>Total Long-term Debt</td><td>$ 13,240.7</td><td>$ 12,126.8</td></tr></table>

(a) Adjustment of carrying value of long-term securities subject to outstanding interest rate swaps; see Note 13.

(b) Kinder Morgan Energy Partners issued its $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 Kinder Morgan Energy Partners 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.

In February 2008, approximately $4.6 billion of the proceeds from the completed sale of an 80% ownership interest in NGPL PipeCo LLC were used to pay off and retire our senior secured credit facility’s Tranche A and Tranche B term loans and to pay down amounts outstanding at that time under our $1.0 billion revolving credit facility as follows (in millions):

<table><tr><td></td><td>Debt Paid Down and/or Retired</td></tr><tr><td>Kinder Morgan, Inc.</td><td></td></tr><tr><td>Senior Secured Credit Term Loan Facilities</td><td></td></tr><tr><td>Tranche A Term Loan, Due 2013</td><td>$ 995.0</td></tr><tr><td>Tranche B Term Loan, Due 2014</td><td>3,183.5</td></tr><tr><td>Credit Facility</td><td></td></tr><tr><td>$1.0 billion Secured Revolver, Due May 2013</td><td>375.0</td></tr><tr><td>Total Paid Down and/or Retired</td><td>$ 4,553.5</td></tr></table>

In March 2008, using primarily proceeds from the completed sale of an 80% ownership interest in NGPL PipeCo LLC, along with cash on hand and borrowings under our $1.0 billion revolving credit facility, we repurchased approximately $1.67 billion par value of our outstanding debt securities for $1.6 billion in cash as follows (in millions):

<table><tr><td></td><td>Par Value of Debt Repurchased</td></tr><tr><td>Kinder Morgan, Inc.</td><td></td></tr><tr><td>Debentures</td><td></td></tr><tr><td>6.50% Series, Due 2013</td><td>$ 18.9</td></tr><tr><td>6.67% Series, Due 2027</td><td>143.0</td></tr><tr><td>7.25% Series, Due 2028</td><td>461.0</td></tr><tr><td>7.45% Series, Due 2098</td><td>124.1</td></tr><tr><td>Senior Notes</td><td></td></tr><tr><td>6.50% Series, Due 2012</td><td>160.7</td></tr><tr><td>Kinder Morgan Finance Company, LLC</td><td></td></tr><tr><td>6.40% Series, Due 2036</td><td>513.6</td></tr><tr><td>Deferrable Interest Debentures Issued to Subsidiary Trusts</td><td></td></tr><tr><td>8.56% Junior Subordinated Deferrable Interest Debentures Due 2027</td><td>87.3</td></tr><tr><td>7.63% Junior Subordinated Deferrable Interest Debentures Due 2028</td><td>160.6</td></tr><tr><td>Repurchase of Outstanding Debt Securities</td><td>$ 1,669.2</td></tr></table>

Kinder Morgan, Inc.

The 2013 debentures are not redeemable prior to maturity. The 2028 and 2098 debentures and the 2012 and 2015 senior notes are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. The 2027 debentures are redeemable in whole or in part, at our option after November 1, 2004 at redemption prices defined in the associated prospectus supplements.



On each of the dates of September 4, 2009 and September 5, 2008, we made $5.0 million payments on our 6.50% series debentures, due 2013.

Kinder Morgan Finance Company, LLC

The 2011, 2016 and 2036 senior notes issued by Kinder Morgan Finance Company, LLC are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. Each series of these notes is fully and unconditionally guaranteed by Kinder Morgan, Inc. on a senior unsecured basis as to principal, interest and any additional amounts required to be paid as a result of any withholding or deduction for Canadian taxes.

## Kinder Morgan Energy Partners

All of Kinder Morgan Energy Partners' fixed rate senior notes provide that it may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.

During 2009, Kinder Morgan Energy Partners completed two separate public offerings of senior notes. With regard to these offerings, Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners completed three separate public offerings of senior notes. With regard to the three offerings, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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.

Kinder Morgan Energy Partners used the proceeds from its first two 2008 debt offerings to reduce the borrowings under its commercial paper program. Kinder Morgan Energy Partners used the proceeds from its December 2008 debt offering and from all of its 2009 debt offerings to reduce the borrowings under its bank credit facility.

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

## Interest Rate Swaps

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

## Kinder Morgan Energy Partners' Subsidiary Debt

Kinder Morgan Energy Partners' subsidiaries are obligors on the following debt. The agreements governing these obligations contain various affirmative and negative covenants and events of default. Kinder Morgan Energy Partners does not believe that these provisions will materially affect distributions to its 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.

Kinder Morgan Energy Partners' 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.

## Kinder Morgan Operating L.P. "A" Debt

Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximately 50.2% interest in the Cochin pipeline system that it did not already own. As part of the purchase price consideration, two of Kinder Morgan Energy Partners' subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. Kinder Morgan Energy Partners valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%. Kinder Morgan Energy Partners' 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. The second installment was paid 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

Kinder Morgan Energy Partners' 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%. Kinder Morgan Energy Partners assumed this debt on August 1, 2005 when it acquired a natural gas storage facility located in Liberty County, Texas from a third party, and it 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%. Kinder Morgan Energy Partners has 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, Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners was fully reimbursed for its prior payments. As of December 31, 2009, the interest rate on these bonds was 0.21%. Kinder Morgan Energy Partners' 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

Kinder Morgan Energy Partners owns a 66 2/3% interest in the International Marine Terminals partnership (“IMT”). 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, Kinder Morgan Energy Partners agreed to guarantee the obligations of IMT in proportion to its ownership interest. Kinder Morgan Energy Partners' obligation is approximately $30.3 million for principal, plus interest and other fees.

## Gulf Opportunity Zone Bonds

To help fund Kinder Morgan Energy Partners' business growth in the states of Mississippi and Louisiana, it 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 ("MBFC"), a public, non-profit corporation that coordinates a variety of resources used to assist business and industry in the state of Mississippi and (ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued by the Louisiana Community Development Authority, 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. Kinder Morgan Energy Partners holds an option to redeem in full (and settle the note payable to MBFC) the principal amount of bonds it holds 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 and Kinder Morgan Energy Partners' outstanding debt balances, excluding the value of interest rate swaps, as of December 31, 2009, are summarized as follows (in millions):

<table><tr><td>Year</td><td>Commitment</td></tr><tr><td>2010</td><td>$ 768.7</td></tr><tr><td>2011</td><td>1,471.7</td></tr><tr><td>2012</td><td>2,317.2</td></tr><tr><td>2013</td><td>500.2</td></tr><tr><td>2014</td><td>492.3</td></tr><tr><td>Thereafter</td><td>8,098.3</td></tr><tr><td>Total</td><td>$ 13,648.4</td></tr></table>

## Kinder Morgan G.P., Inc. Preferred Shares

As of December 31, 2009, Kinder Morgan G.P., Inc. had outstanding 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057. Until August 18, 2012, dividends will accumulate, commencing on the issue date, at a fixed rate of 8.33% per annum and will be payable quarterly in arrears, when and if declared by Kinder Morgan G.P., Inc.'s Board of Directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2007. After August 18, 2012, dividends on the preferred stock will accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and will be payable quarterly in arrears, when and if declared by Kinder Morgan G.P., Inc.'s Board of Directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by Kinder Morgan Energy Partners or its SFPP, L.P. or Calnev Pipe Line LLC subsidiaries.

During 2009, $8.3 million in cash dividends, or $83.30 per share, was paid on Kinder Morgan G.P. Inc.'s Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock. On January 20, 2010, Kinder Morgan G.P., Inc.'s Board of Directors declared a quarterly cash dividend on its Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock of $20.825 per share that was paid on February 18, 2010 to shareholders of record as of January 29, 2010.



## 9. Employee Benefits

Pension and Postretirement Benefit Plans

Kinder Morgan, Inc.

Retirement Plans

We have defined benefit pension plans covering eligible full-time employees. These plans provide pension benefits that are based on the employees' compensation during the period of employment, age and years of service. These plans are tax-qualified subject to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended. Our funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds. The Plan did not have any material investments in our company or affiliates as of December 31, 2009 and 2008.

Total amounts recognized in net periodic pension cost include the following components (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31, 2007</td><td colspan="2">Five Months Ended May 31, 2007</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td></tr><tr><td>Net periodic pension benefit cost</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$     4.8</td><td>$     10.8</td><td>$     5.6</td><td>$     4.5</td><td></td></tr><tr><td>Interest cost</td><td>15.8</td><td>14.5</td><td>8.1</td><td>5.6</td><td></td></tr><tr><td>Expected return on assets</td><td>(16.2)</td><td>(23.2)</td><td>(14.0)</td><td>(9.6)</td><td></td></tr><tr><td>Amortization of prior service cost</td><td>0.1</td><td>0.1</td><td>-</td><td>0.1</td><td></td></tr><tr><td>Amortization of loss</td><td>7.9</td><td>0.3</td><td>-</td><td>0.2</td><td></td></tr><tr><td>Net periodic pension benefit cost</td><td>$     12.4</td><td>$     2.5</td><td>$     0.3</td><td>$     0.8</td><td></td></tr></table>

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Benefit obligation at beginning of period</td><td>$     255.0</td><td>$     258.0</td></tr><tr><td>Service cost</td><td>4.8</td><td>10.8</td></tr><tr><td>Interest cost</td><td>15.8</td><td>14.5</td></tr><tr><td>Actuarial loss (gain)</td><td>12.4</td><td>(14.2)</td></tr><tr><td>Plan amendments</td><td>-</td><td>0.8</td></tr><tr><td>Benefits paid</td><td>(13.6)</td><td>(14.9)</td></tr><tr><td>Benefit obligation at end of period</td><td>$     274.4</td><td>$     255.0</td></tr></table>

The accumulated benefit obligation at December 31, 2009 and 2008 was $265.2 million and $248.6 million, respectively.

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of the plans’ assets and the plans’ funded status (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td></td><td colspan="2">(In millions)</td></tr><tr><td>Fair value of plan assets at beginning of period</td><td>$     179.7</td><td>$     264.7</td></tr><tr><td>Actual return on plan assets during the period</td><td>34.0</td><td>(70.1)</td></tr><tr><td>Contributions by employer</td><td>20.0</td><td>-</td></tr><tr><td>Benefits paid during the period</td><td>(13.6)</td><td>(14.9)</td></tr><tr><td>Fair value of plan assets at end of period</td><td>220.1</td><td>179.7</td></tr><tr><td>Benefit obligation at end of period</td><td>(274.4)</td><td>(255.0)</td></tr><tr><td>Funded status at end of period</td><td>$      (54.3)</td><td>$      (75.3)</td></tr></table>



The accompanying Consolidated Balance Sheets at December 31, 2009 and 2008 include a balance of $54.3 million and $75.3 million, respectively, under the caption “Other Long-term Liabilities and Deferred Credits” related to our pension plans.

The following table sets forth by level, within the fair value hierarchy, the Plan’s assets at fair value (in millions):

<table><tr><td rowspan="2"></td><td colspan="5">Assets at fair value at December 31, 2009</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td></tr><tr><td>Money market funds</td><td>$ -</td><td>$ 20.1</td><td>$ -</td><td>$ 20.1</td><td></td></tr><tr><td>Insurance contracts</td><td>-</td><td>12.2</td><td>-</td><td>12.2</td><td></td></tr><tr><td>Mutual funds</td><td>-</td><td>61.1</td><td>-</td><td>61.1</td><td></td></tr><tr><td>Common and preferred stocks</td><td>75.6</td><td>-</td><td>-</td><td>75.6</td><td></td></tr><tr><td>Corporate bonds</td><td>-</td><td>23.8</td><td>-</td><td>23.8</td><td></td></tr><tr><td>U.S. government securities</td><td>-</td><td>15.2</td><td>-</td><td>15.2</td><td></td></tr><tr><td>Asset backed securities</td><td>-</td><td>3.2</td><td>-</td><td>3.2</td><td></td></tr><tr><td>Limited partnerships</td><td>-</td><td>-</td><td>5.2</td><td>5.2</td><td></td></tr><tr><td>Private equity</td><td>-</td><td>-</td><td>3.2</td><td>3.2</td><td></td></tr><tr><td>Total asset fair value</td><td>$ 75.6</td><td>$ 135.6</td><td>$ 8.4</td><td>$ 219.6(a)</td><td></td></tr></table>

(a) Excludes $0.5 million in interest, dividend and security receivables.

An asset’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

Following is a description of the valuation methodologies used for assets measured at fair value:

Common stocks and fixed income: Valued at the closing price reported on the active market on which the individual securities are traded.

Money market funds: Valued at amortized cost, which approximates fair value.

Mutual funds: Valued at the net asset value (“NAV”) of shares held by the plan at year end.

Limited partnership and private equity investments: Valued at net fair value utilizing discounted present value.

Insurance contracts: Valued at contract value, which approximates fair value.

The table below sets forth a summary of changes in the fair value of the Plan’s level 3 assets (in millions):

<table><tr><td rowspan="2"></td><td colspan="4">Level 3 assets at fair value at December 31, 2009</td></tr><tr><td>Limited Partnerships</td><td>Private Equity</td><td>Total</td><td></td></tr><tr><td>Balance, beginning of year</td><td>$ 4.6</td><td>$ 2.6</td><td>$ 7.2</td><td></td></tr><tr><td>Realized and unrealized gains/(losses)</td><td>0.4</td><td>(0.5)</td><td>(0.1)</td><td></td></tr><tr><td>Purchases and sales</td><td>0.2</td><td>1.1</td><td>1.3</td><td></td></tr><tr><td>Level 3 end of year balance</td><td>$ 5.2</td><td>$ 3.2</td><td>$ 8.4</td><td></td></tr></table>



Changes in the underlying value of level 3 assets due to the effect of measurement were immaterial for the year ended December 31, 2009.

Amounts recognized in “Accumulated Other Comprehensive Loss” consist of:

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Beginning balance</td><td>109.9</td><td>30.6</td></tr><tr><td>Net (gain)/loss arising during period</td><td>(5.3)</td><td>79.1</td></tr><tr><td>Prior service cost arising during period</td><td>-</td><td>0.7</td></tr><tr><td>Amortization of (gain)/loss</td><td>(7.9)</td><td>(0.4)</td></tr><tr><td>Amortization of prior service cost</td><td>(0.1)</td><td>(0.1)</td></tr><tr><td>Ending balance</td><td>96.6</td><td>109.9</td></tr></table>

Our actuarial estimates allocate costs based on projected employee costs. As experience develops under our plan, actuarial gains (losses) result from experience more favorable (unfavorable) than assumed.

The estimated net loss for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic pension benefit cost over the next fiscal year is $6.1 million.

We expect to contribute approximately $20 million to the Plan during 2010.

The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in millions):

<table><tr><td>Fiscal year</td><td>Expected net benefit payments</td></tr><tr><td>2010</td><td>$ 14.9</td></tr><tr><td>2011</td><td>$ 15.9</td></tr><tr><td>2012</td><td>$ 16.6</td></tr><tr><td>2013</td><td>$ 17.2</td></tr><tr><td>2014</td><td>$ 18.1</td></tr><tr><td>2015-2019</td><td>$ 115.0</td></tr></table>

Effective January 1, 2001, we created the Kinder Morgan, Inc. Retirement Plan (“Retirement Plan”), a cash balance plan. Certain collectively bargained employees and “grandfathered” employees continue to accrue benefits through the defined pension benefit plan described above. The remainder of the employees accrue benefits through a Personal Retirement Account (“PRA”) in the Retirement Plan. Employees converting to the Retirement Plan were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. We allocate contributions equivalent to 3% of eligible compensation every pay period to participants’ PRA. Interest is credited to the PRA at the 30-year U.S. Treasury bond rate determined on November 30 of the prior year. Employees become 100 percent vested in the plan after three years (five years prior to January 1, 2008) and may take a lump sum distribution upon termination of employment or retirement.

Commencing April 12, 2009, we suspended the 3% contributions to employees' PRAs for the 2009 year. We began allocating contributions equivalent to 3% of eligible compensation into the PRA effective January 1, 2010. Those employees who were grandfathered or accruing under the prior defined benefit pension plan continued to accrue pension benefits with no interruption in 2009.

In addition to the Retirement Plan described above, we have the Kinder Morgan, Inc. Savings Plan (the "Plan"), a defined contribution 401(k) plan. The Plan permits all eligible Plan participants to contribute between 1% and 50% of eligible compensation, on a pre-tax or after-tax (Roth 401k) basis, into their accounts. In addition to a Company contribution equal to 4% of eligible compensation per year for most of the Plan participants, Kinder Morgan may make discretionary contributions. Certain Plan participant's contributions and Company contributions are based on collective bargaining agreements. The contributions are made each pay period on behalf of each eligible participant. Participants may direct the investment of their contributions and all Company contributions, including discretionary contributions, into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. The total amount contributed for the year ended December 31, 2009, the year ended December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 was $19.8 million, $20.8 million, $11.0 million and $8.1 million, respectively.



Company contributions for participants vest on the second anniversary of the date of hire. Effective October 1, 2005, a tiered Company contribution schedule was implemented for new employees of the Terminals–KMP segment. This tiered schedule provides for Company 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 Company contributions for Terminals–KMP employees hired after October 1, 2005 vest on the fifth anniversary of the date of hire. Effective January 1, 2008, this five-year anniversary date for Terminals–KMP employees was changed to three-year anniversary vest schedule to comply with changes in federal regulations. Effective July 16, 2008, we changed the vesting schedule for Terminals-KMP back to two years of service. Vesting on Company contributions for bargaining employees will follow the collective bargaining agreements.

At its July 2008 meeting, the Compensation Committee of our Board of Directors approved a special contribution of an additional 1% of base pay into the Plan for each eligible participant. Each eligible participant 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 participants received and the vesting schedule mirrored the Company’s 4% contribution. Since this additional 1% Company contribution is discretionary, Compensation Committee approval will be required annually for each additional contribution.

Commencing February 1, 2009 through February 1, 2010, the Company suspended both the annual 4% contribution as well as the discretionary 1% contribution for participants with a title of Vice President or greater.

Additionally, participants have an option to make after-tax “Roth” contributions (Roth 401(k) option) to a separate participant account. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option and (ii) attainment of age 59 \( ^{1/2} \) , death or disability. The Company contribution will still be considered taxable income at the time of withdrawal.

Beginning in 2006, we elected not to make any restricted stock awards as a result of the Going Private transaction. To ensure that certain key employees who had previously received restricted stock and restricted stock unit awards continued under a long-term retention and incentive program, the Company implemented the Long-term Incentive Retention Award plan. The plan provides cash awards approved by the compensation committees of the Company which are granted in July of each year to recommended key employees. Senior management is not eligible for these awards. These grants require the employee to sign a grant agreement. The grants vest 100% after the third year anniversary of the grant provided the employee remains with the Company. Grants were made in July of 2007, 2008 and 2009. During the year ended December 31, 2009, December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 we amortized $2.3 million, $6.9 million, $5.3 million and $1.3 million, respectively, related to these grants.

## Other Postretirement Employee Benefits

We have a postretirement plan providing medical and life insurance benefits upon retirement. For certain eligible employees and their eligible dependents that are “grandfathered,” we also provide a subsidized premium. All others who are eligible pay the full cost. NGPL PipeCo funds a portion of the future expected postretirement benefit cost under the plan by making payments to Voluntary Employee Benefit Association trusts. Plan assets are invested in a mix of equity funds and fixed income instruments similar to the investments in our pension plans.

Total amounts recognized in net periodic postretirement benefit cost include the following components (in millions):

<table><tr><td rowspan="3"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="3">Seven Months Ended</td><td colspan="2">Five Months Ended</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">December 31,</td><td colspan="2">May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Net periodic postretirement benefit cost</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 0.3</td><td>$ 0.3</td><td>$ 0.3</td><td>$ 0.2</td><td>$ 0.2</td><td></td></tr><tr><td>Interest cost</td><td>4.5</td><td>4.6</td><td>2.7</td><td>1.9</td><td></td><td></td></tr><tr><td>Expected return on assets</td><td>(4.6)</td><td>(6.5)</td><td>(3.9)</td><td>(2.7)</td><td></td><td></td></tr><tr><td>Amortization of prior service credit</td><td>-</td><td>-</td><td>-</td><td>(0.7)</td><td></td><td></td></tr><tr><td>Amortization of loss</td><td>2.5</td><td>0.5</td><td>-</td><td>2.0</td><td></td><td></td></tr><tr><td>Net periodic postretirement benefit cost</td><td>$ 2.7</td><td>$ (1.1)</td><td>$ (1.0)</td><td>$ 0.7</td><td></td><td></td></tr></table>



The following table sets forth the reconciliation of the beginning and ending balances of the accumulated postretirement benefit obligation (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Benefit obligation at beginning of period</td><td>$     78.0</td><td>$     82.0</td></tr><tr><td>Service cost</td><td>0.3</td><td>0.3</td></tr><tr><td>Interest cost</td><td>4.5</td><td>4.6</td></tr><tr><td>Actuarial loss (gain)</td><td>1.1</td><td>2.0</td></tr><tr><td>Benefits paid</td><td>(11.7)</td><td>(13.8)</td></tr><tr><td>Retiree contributions</td><td>3.4</td><td>2.9</td></tr><tr><td>Benefit obligation at end of period</td><td>$     75.6</td><td>$     78.0</td></tr></table>

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets and the plan’s funded status (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Fair value of plan assets at beginning of period</td><td>$     49.1</td><td>$     69.2</td></tr><tr><td>Actual return on plan assets</td><td>6.8</td><td>(17.5)</td></tr><tr><td>Contributions</td><td>7.0</td><td>8.7</td></tr><tr><td>Retiree contributions</td><td>3.4</td><td>2.9</td></tr><tr><td>Benefits paid</td><td>(12.2)</td><td>(14.2)</td></tr><tr><td>Fair value of plan assets at end of period</td><td>54.1</td><td>49.1</td></tr><tr><td>Benefit obligation at end of period</td><td>(75.6)</td><td>(78.0)</td></tr><tr><td>Funded status at end of period</td><td>$ (21.5)</td><td>$ (28.9)</td></tr></table>

The accompanying Consolidated Balance Sheets at December 31, 2009 and 2008 include balances of $21.5 million and $28.9 million, respectively, under the caption “Other Long-term Liabilities and Deferred Credits,” related to our other postretirement benefit plans.

The following table sets forth by level, within the fair value hierarchy, the fair value of postretirement benefit assets:

<table><tr><td rowspan="2"></td><td colspan="5">Assets at fair value at December 31, 2009</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td></tr><tr><td>Money market funds</td><td>$ -</td><td>$ 5.5</td><td>$ -</td><td>$ 5.5</td><td></td></tr><tr><td>Insurance contracts</td><td>-</td><td>41.6</td><td>-</td><td>41.6</td><td></td></tr><tr><td>Mutual funds</td><td>7.0</td><td>-</td><td>-</td><td>7.0</td><td></td></tr><tr><td>Total asset fair value</td><td>$ 7.0</td><td>$ 47.1</td><td>$ -</td><td>$ 54.1</td><td></td></tr></table>

Amounts recognized in “Accumulated Other Comprehensive Loss” consist of (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Beginning balance</td><td>$ 37.9</td><td>$ 12.0</td></tr><tr><td>Net (gain)/loss arising during period</td><td>(0.5)</td><td>26.4</td></tr><tr><td>Amortization of (gain)/loss</td><td>(2.5)</td><td>(0.5)</td></tr><tr><td>Amortization of prior service cost</td><td>-</td><td>-</td></tr><tr><td>Ending balance</td><td>$ 34.9</td><td>$ 37.9</td></tr></table>

The estimated net loss for the postretirement benefit plans that will be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost over the next fiscal year is $2.8 million. NGPL PipeCo LLC contributed approximately $8.7 million to the plan in February 2010.

A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2009 net periodic postretirement benefit cost by approximately $5 (5) thousand and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2009 by approximately $78 (73) thousand.



The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in millions):

<table><tr><td>Fiscal year</td><td>Expected net benefit payments</td></tr><tr><td>2010</td><td>$ 7.2</td></tr><tr><td>2011</td><td>$ 6.9</td></tr><tr><td>2012</td><td>$ 6.6</td></tr><tr><td>2013</td><td>$ 6.4</td></tr><tr><td>2014</td><td>$ 6.2</td></tr><tr><td>2015-2018</td><td>$ 28.6</td></tr></table>

## Actuarial Assumptions

The assumptions used to determine benefit obligations for the pension and postretirement benefit plans were:

<table><tr><td rowspan="2"></td><td colspan="2">Successor Company</td><td rowspan="2">Predecessor Company</td></tr><tr><td colspan="2">Seven Months Ended December 31,</td></tr><tr><td></td><td>Year Ended December 31,</td><td>December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td>Discount rate</td><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Expected long-term return on assets</td><td>(a)</td><td>6.25%</td><td>5.75%</td></tr><tr><td>Rate of compensation increase (pension plan only)</td><td>8.90%</td><td>8.75%</td><td>9.00%</td></tr><tr><td></td><td>3.50%</td><td>3.50%</td><td>3.50%</td></tr></table>

(a) Discount rates of 5.75% and 6.00% are used to determine obligations for other postretirement benefits and pension benefits, respectively.

The assumptions used to determine net periodic benefit cost for the pension and postretirement benefits were:

<table><tr><td rowspan="2"></td><td colspan="2">Successor Company</td><td rowspan="2">Predecessor Company</td></tr><tr><td colspan="2">Seven Months Ended December 31,</td></tr><tr><td></td><td>Year Ended December 31,</td><td>December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Discount rate</td><td>6.25%</td><td>5.75%</td><td>6.00%</td></tr><tr><td>Expected long-term return on assets</td><td>8.75%</td><td>9.00%</td><td>9.00%</td></tr><tr><td>Rate of compensation increase (pension plan only)</td><td>3.50%</td><td>3.50%</td><td>3.50%</td></tr></table>

The assumed healthcare cost trend rates for the postretirement plan were:

<table><tr><td rowspan="2"></td><td colspan="2">Successor Company</td><td rowspan="2">Predecessor Company</td></tr><tr><td colspan="2">Seven Months Ended December 31,</td></tr><tr><td></td><td>Year Ended December 31,</td><td>December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Healthcare cost trend rate assumed for next year</td><td>3.00%</td><td>3.00%</td><td>3.00%</td></tr><tr><td>Rate to which the cost trend rate is assumed to decline (ultimate trend rate)</td><td>3.00%</td><td>3.00%</td><td>3.00%</td></tr><tr><td>Year the rate reaches the ultimate trend rate</td><td>2009</td><td>2008</td><td>2007</td></tr></table>

## Plan Investment Policies

The investment policies and strategies for the assets of our pension and retiree medical and retiree life insurance plans are established by the Fiduciary Committee (the “Committee”), which is responsible for investment decisions and management oversight of each plan. The stated philosophy of the Committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return on assets within established risk tolerance guidelines and liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committee



recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee has adopted a strategy of using multiple asset classes.

As of December 31, 2009, the following target asset allocation ranges were in effect for our pension plans (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income – 20%/30%/40%; Equity – 55%/65%/75% and Alternative Investments – 0%/5%/10%. As of December 31, 2009, the following target asset allocation ranges were in effect for our retiree medical and retiree life insurance plans (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income – 20%/30%/40% and Equity – 60%/70%/80%. In order to achieve enhanced diversification, the equity category is further subdivided into subcategories with respect to small cap vs. large cap, value vs. growth and international vs. domestic, each with its own target asset allocation.

In implementing its investment policies and strategies, the Committee has engaged a professional investment advisor to assist with its decision making process and has engaged professional money managers to manage plan assets. The Committee believes that such active investment management will achieve superior returns with comparable risk in comparison to passive management. Consistent with its goal of reasonable diversification, no manager of an equity portfolio for the plan is allowed to have more than 10% of the market value of the portfolio in a single security or weight a single economic sector more than twice the weighting of that sector in the appropriate market index. Finally, investment managers are not permitted to invest or engage in the following equity transactions unless specific permission is given in writing (which permission has not been requested or granted by the Committee to-date): derivative instruments, except for the purpose of asset value protection (such as the purchase of protective puts), direct ownership of letter stock, restricted stock, limited partnership units (unless the security is registered and listed on a domestic exchange), venture capital, short sales, margin purchases or borrowing money, stock loans and commodities. In addition, fixed income holdings in the following investments are prohibited without written permission: private placements, except medium-term notes and securities issued under SEC Rule 144a; foreign bonds (non-dollar denominated); municipal or other tax exempt securities, except taxable municipalities; margin purchases or borrowing money to effect leverage in the portfolio; inverse floaters, interest only and principle only mortgage structures; and derivative investments (futures or option contracts) used for speculative purposes. Certain other types of investments such as hedge funds and land purchases are not prohibited as a matter of policy but have not, as yet, been adopted as an asset class or received any allocation of fund assets.

## Return on Plan Assets

For the year ending December 31, 2009, our defined benefit pension plan yielded a weighted-average rate of return of 20.18%, above the expected rate of return on assets of 8.90%. Investment performance for a balanced fund comprised of a similar mix of assets yielded a weighted-average return of 18.82%, so our plans outperformed the benchmark balanced fund index. For the year ending December 31, 2009, our retiree medical and retiree life insurance plans yielded a weighted-average rate of return of 19.62%, above the expected rate of return on assets of 8.90%. Investment performance for a balanced fund comprised of a similar mix of assets yielded a weighted-average return of 17.27%, so our plans outperformed the benchmark balanced fund index.

At December 31, 2009, our pension plan assets consisted of 64.6% equity, 26.0% fixed income and 9.4% cash and cash equivalents, and our retiree medical and retiree life insurance plan assets consisted of 63.4% equity, 26.2% fixed income and 10.4% cash and cash equivalents. Historically over long periods of time, widely traded large cap equity securities have provided a return of 10%, while fixed income securities have provided a return of 6%, indicating that a long term expected return predicated on the asset allocation as of December 31, 2009 would be approximately 8.73% to 9.30% if investments were made in the broad indexes for our defined benefit pension plan, and 8.36% to 8.88% for our retiree medical and retiree life insurance plan. We arrived at an overall expected return of 8.75% for our periodic benefit cost calculations and an overall expected return of 8.90% for our benefit obligation calculations as of December 31, 2009.

## Kinder Morgan Energy Partners

## Pension and Postretirement Benefit Plans

Two of Kinder Morgan Energy Partners’ 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. Kinder Morgan Energy Partners also provides postretirement benefits other than pensions for retired employees. Kinder Morgan Energy Partners’ combined net periodic benefit costs for these Trans Mountain pension and postretirement benefit plans for 2009, 2008, the seven months ended December 31, 2007 and the five months ended May 31, 2007 were approximately $2.9 million, $3.5 million, $1.9 million and $1.3 million, respectively, recognized ratably over each year.



As of December 31, 2009, Kinder Morgan Energy Partners estimates its 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. Kinder Morgan Energy Partners expects to contribute approximately $4.8 million to these benefit plans in 2010.

Additionally, in connection with Kinder Morgan Energy Partners' acquisition of SFPP, L.P. and Kinder Morgan Bulk Terminals, Inc. in 1998, Kinder Morgan Energy Partners acquired certain liabilities for pension and postretirement benefits. Kinder Morgan Energy Partners provides medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. Kinder Morgan Energy Partners also provides the same benefits to former salaried employees of SFPP. Additionally, Kinder Morgan Energy Partners 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.

Kinder Morgan Energy Partners' net periodic benefit cost for the SFPP postretirement benefit plan was a credit of less than $0.1 million in 2009, a credit of less than $0.1 million in 2008, a credit of $0.1 million for the seven months ended December 31, 2007 and a credit of $0.1 million for the five months ended May 31, 2007. The credits in all periods resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost. As of December 31, 2009, Kinder Morgan Energy Partners estimates its 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, Kinder Morgan Energy Partners expects to contribute approximately $0.3 million to this postretirement benefit plan in 2010.

As of December 31, 2009 and 2008, the recorded value of Kinder Morgan Energy Partners' pension and postretirement benefit obligations for these plans was a combined $37.4 million and $33.4 million, respectively. Kinder Morgan Energy Partners considers its pension and postretirement benefit liability exposure and the fair value of its pension and postretirement plan assets to be minimal in relation to the value of its total consolidated assets and net income.

## Multiemployer Plans

As a result of acquiring several terminal operations, primarily Kinder Morgan Energy Partners' acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, Kinder Morgan Energy Partners participates in several multi-employer pension plans for the benefit of employees who are union members. Kinder Morgan Energy Partners does 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, $7.8 million, $2.5 million and $4.2 million for the years ended December 31, 2009 and 2008, the seven months ended December 31, 2007 and the five months ended May 31, 2007, respectively.

## 10. Stockholders' Equity

During the years ended December 31, 2009 and 2008, seven months ended December 31, 2007, and five months ended May 31, 2007, there were no material changes in our ownership interests in subsidiaries, in which we retained a controlling financial interest.

During the year ended December 31, 2009, we paid cash dividends on our common stock totaling $650.0 million to our sole stockholder, which then made dividends to Kinder Morgan Holdco LLC. On January 20, 2010, our Board of Directors declared a dividend of $150.0 million for the fourth quarter of 2009 that was paid on February 16, 2010.



## Comprehensive Income – Income Tax Expense

The following table sets forth the tax amounts included in the respective components of other comprehensive income (loss) (in millions):

Tax Benefit (Expense) Included in Other Comprehensive Income (Loss)

<table><tr><td rowspan="3"></td><td colspan="4">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="4">Seven Months Ended</td><td colspan="2">Five Months Ended</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">December 31,</td><td colspan="2">May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Kinder Morgan, Inc.</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes</td><td>$     85.5</td><td>$      (121.3)</td><td>$     140.8</td><td>$     19.1</td><td></td><td></td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>24.5</td><td>(69.4)</td><td>0.6</td><td>(12.8)</td><td></td><td></td></tr><tr><td>Foreign currency translation adjustments</td><td>(34.7)</td><td>31.0</td><td>(8.3)</td><td>(3.9)</td><td></td><td></td></tr><tr><td>Benefit plan adjustments</td><td>(1.6)</td><td>37.7</td><td>15.3</td><td>(5.7)</td><td></td><td></td></tr><tr><td>Benefit plan amortization</td><td>(3.7)</td><td>(0.2)</td><td>-</td><td>(0.6)</td><td></td><td></td></tr><tr><td>Tax benefit (expense) included in total other comprehensive income (loss) attributable to Kinder Morgan, Inc.</td><td>70.0</td><td>(122.2)</td><td>148.4</td><td>(3.9)</td><td></td><td></td></tr><tr><td>Noncontrolling interests</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes</td><td>20.7</td><td>(34.1)</td><td>0.9</td><td>2.4</td><td></td><td></td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>(4.5)</td><td>(34.6)</td><td>(0.3)</td><td>(2.7)</td><td></td><td></td></tr><tr><td>Foreign currency translation adjustments</td><td>(11.4)</td><td>17.2</td><td>(0.1)</td><td>(0.9)</td><td></td><td></td></tr><tr><td>Benefit plan adjustments</td><td>0.1</td><td>(0.2)</td><td>-</td><td>-</td><td></td><td></td></tr><tr><td>Benefit plan amortization</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td><td></td></tr><tr><td>Tax benefit (expense) included in total other comprehensive income (loss) attributable to noncontrolling interests</td><td>4.9</td><td>(51.7)</td><td>0.5</td><td>(1.2)</td><td></td><td></td></tr><tr><td>Total</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes</td><td>106.2</td><td>(155.4)</td><td>141.7</td><td>21.5</td><td></td><td></td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>20.0</td><td>(104.0)</td><td>0.3</td><td>(15.5)</td><td></td><td></td></tr><tr><td>Foreign currency translation adjustments</td><td>(46.1)</td><td>48.2</td><td>(8.4)</td><td>(4.8)</td><td></td><td></td></tr><tr><td>Benefit plan adjustments</td><td>(1.5)</td><td>37.5</td><td>15.3</td><td>(5.7)</td><td></td><td></td></tr><tr><td>Benefit plan amortization</td><td>(3.7)</td><td>(0.2)</td><td>-</td><td>(0.6)</td><td></td><td></td></tr><tr><td>Tax benefit (expense) included in total other comprehensive income (loss)</td><td>$     74.9</td><td>$      (173.9)</td><td>$     148.9</td><td>$      (5.1)</td><td></td><td></td></tr></table>

## Noncontrolling Interests

The caption “Noncontrolling interests” in the accompanying Consolidated Balance Sheets consists of interests in the following subsidiaries (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Kinder Morgan Energy Partners</td><td>$ 2,746.4</td><td>$ 2,198.2</td></tr><tr><td>Kinder Morgan Management</td><td>1,870.7</td><td>1,826.5</td></tr><tr><td>Triton Power Company LLC</td><td>45.9</td><td>39.0</td></tr><tr><td>Other</td><td>11.6</td><td>8.9</td></tr><tr><td></td><td>$ 4,674.6</td><td>$ 4,072.6</td></tr></table>

Kinder Morgan Energy Partners' Common Units

2009 Issuances

On January 16, 2009, Kinder Morgan Energy Partners entered into an equity distribution agreement with UBS Securities LLC (“UBS”). According to the provisions of this agreement, which was amended and restated on October 1, 2009, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners and UBS. Under the terms of this agreement, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners and UBS.



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

In 2009, Kinder Morgan Energy Partners issued 5,488,947 of its common units pursuant to this agreement. After commissions of $4.0 million, Kinder Morgan Energy Partners received net proceeds from the issuance of these common units of approximately $281.2 million. The proceeds were used to reduce the borrowings under Kinder Morgan Energy Partners' bank credit facility.

Kinder Morgan Energy Partners also completed three separate underwritten public offerings of its common units in 2009, receiving net proceeds of $874.4 million as discussed following, and in April 2009, it 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 the first 2009 public offering, completed in March, Kinder Morgan Energy Partners issued 5,666,000 of its common units at a price of $46.95 per unit, less underwriting commissions and expenses. Net proceeds of $258.0 million were received for the issuance of these common units. In the second offering, completed in July, 6,612,500 common units were issued at a price of $51.50 per unit, less underwriting commissions and expenses, and net proceeds of $329.9 million. In its final 2009 public offering, completed in December, Kinder Morgan Energy Partners issued 5,175,000 common units at a price of $57.15 per unit, less underwriting commissions and expenses, and received net proceeds of $286.5 million for the issuance of these common units. Kinder Morgan Energy Partners used the proceeds from each of these three public offerings to reduce the borrowings under its bank credit facility.

These Kinder Morgan Energy Partners’ issuances of common units during the year ended December 31, 2009, collectively, had the associated effects of increasing our (i) noncontrolling interests associated with Kinder Morgan Energy Partners by $1,116.9 million, (ii) accumulated deferred income taxes by $15.6 million and (iii) additional paid-in capital by $28.1 million.

## 2008 Issuances

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

In March 2008, Kinder Morgan Energy Partners issued, in a public offering, 5,750,000 of its common units at a price of $57.70 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, Kinder Morgan Energy Partners received net proceeds of $324.2 million for the issuance of these common units, and used the proceeds to reduce the borrowings under its commercial paper program.

In connection with the August 28, 2008 sale of our one-third ownership interest in the Express pipeline system and the full interest in the net assets of the Jet Fuel pipeline system, Kinder Morgan Energy Partners issued 2,014,693 of its common units to us. These units, as agreed by Kinder Morgan Energy Partners and us, were valued at $116.0 million. For more information on this transaction; see Note 11.

On December 22, 2008, Kinder Morgan Energy Partners issued, in a public offering, 3,900,000 of its common units at a price of $46.75 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, Kinder Morgan Energy Partners received net proceeds of $176.6 million for the issuance of these common units, and used the proceeds to reduce the borrowings under its bank credit facility.

These Kinder Morgan Energy Partners’ issuances of common units during the year ended December 31, 2008, collectively, had the associated effects of increasing our (i) noncontrolling interests associated with Kinder Morgan Energy Partners by $539.4 million and (ii) associated accumulated deferred income taxes by $7.8 million, and reducing our (i) goodwill by $33.4 million and (ii) additional paid-in capital by $19.7 million.



## Kinder Morgan Management, LLC

Kinder Morgan Management’s distributions are paid in the form of additional shares or fractions thereof calculated by dividing the Kinder Morgan Energy Partners cash distribution per common unit by the average of the market closing prices of a Kinder Morgan Management share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Kinder Morgan Management has paid share distributions totaling 7,540,357, 5,565,424, 2,402,439 and 2,028,367 shares in the years ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007, respectively. On February 12, 2010, Kinder Morgan Management made a share distribution of 0.018430 shares per outstanding share (1,576,470 total shares) to shareholders of record as of January 29, 2010, based on the $1.05 per common unit distribution declared by Kinder Morgan Energy Partners.

At December 31, 2009, we owned 12.2 million Kinder Morgan Management shares representing approximately 14.3% of Kinder Morgan Management’s outstanding shares.

## Common Stock – Financing of the Going Private Transaction

On May 30, 2007, investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, completed the Going Private transaction. As of the closing date of the Going Private transaction, Kinder Morgan, Inc. had 149,316,603 common shares outstanding, before deducting 15,030,135 shares held in treasury. The Going Private transaction, including associated fees and expenses, was financed through (i) $5.0 billion in new equity financing from private equity funds and other entities providing equity financing, (ii) approximately $2.9 billion from rollover investors, who were certain current or former directors, officers or other members of management of Kinder Morgan, Inc. (or entities controlled by such persons) that directly or indirectly reinvested all or a portion of their equity interests in Kinder Morgan, Inc. and/or cash in exchange for equity interests in Kinder Morgan Holdco LLC, the parent of the surviving entity of the Going Private transaction, (iii) approximately $4.8 billion of new debt financing, (iv) approximately $4.5 billion of our existing indebtedness (excluding debt of Terasen Pipelines (Corridor) Inc., which was divested on June 15, 2007 and (v) $1.7 billion of cash on hand resulting principally from the sale of our U.S.-based and Canada-based retail natural gas distribution operations; see Note 2.

## 11. Related Party Transactions

Related-party revenues included in the accompanying Consolidated Statements of Operations for the years ended December 31, 2009 and 2008, seven months ended December 31, 2007, and five months ended May 31, 2007 were $10.9 million, $11.5 million, $6.7 million and $4.5 million, respectively, and were primarily attributable to transactions with Plantation Pipeline Company.

The caption “Gas purchases and other costs of sales” in the accompanying Consolidated Statements of Operations includes related-party costs totaling $5.4 million, $5.4 million, $0.8 million and $0.3 million for the years ended December 31, 2009 and 2008, seven months ended December 31, 2007, and five months ended May 31, 2007, respectively. During 2009, related party “Gas purchases and other costs of sales” is primarily related to purchases from NGPL PipeCo LLC.

The caption “Interest, net” in the accompanying Consolidated Statements of Operations includes related-party net interest income totaling $16.1 million, $5.5 million, $2.6 million and $1.8 million for the years ended December 31, 2009 and 2008, seven months ended December 31, 2007, and five months ended May 31, 2007, respectively. Related party “Interest, net” is primarily related to interest income from Plantation Pipe Line Company and Express US Holdings LP.

## Significant Investors

Two of Kinder Morgan Holdco LLC’s investors are considered “related parties” to us as that term is defined in the authoritative accounting literature. The two related parties are (i) American International Group, Inc. and certain of its affiliates (“AIG”) and (ii) Goldman Sachs Capital Partners and certain of its affiliates (“Goldman Sachs”). 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. In addition, Goldman Sachs has acted in the past, and may act in the future, as an underwriter for equity and/or debt issuances for us, Kinder Morgan Energy Partners and Kinder Morgan Management. Also, on January 15, 2010, Kinder Morgan Energy Partners acquired three ethanol handling train terminals from U.S. Development Group, of which Goldman Sachs effectively owned 49%, for an aggregate consideration of $197.4 million, consisting of $115.7 million in cash and $81.7 million in its common units. The three train terminals are located in Linden, New Jersey, Baltimore, Maryland, and Dallas, Texas. As part of the transaction, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners already owns and operates, and other terminal projects currently under development by both parties. 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 recorded 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” in the accompanying Consolidated Balance Sheets (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">December 31,</td></tr><tr><td>2009</td><td>2008</td><td></td></tr><tr><td>Derivative Assets (Liabilities)</td><td></td><td></td><td></td></tr><tr><td>Current Assets: Fair value of derivative contracts</td><td>$     4.3</td><td>$     60.4</td><td></td></tr><tr><td>Assets: Fair value of derivative contracts</td><td>$     18.4</td><td>$     20.1</td><td></td></tr><tr><td>Current Liabilities: Fair value of derivative contracts</td><td>$      (96.8)</td><td>$      (13.2)</td><td></td></tr><tr><td>Long-term Liabilities and Deferred Credits: Fair value of derivative contracts</td><td>$      (190.8)</td><td>$      (24.1)</td><td></td></tr></table>

## Kinder Morgan Holdco LLC

Our parent, Kinder Morgan Holdco LLC, recognizes compensation expense in connection with its Class A-1 and Class B units over the expected life of such units. As a subsidiary of Kinder Morgan Holdco LLC, we and certain of our subsidiaries are allocated this compensation expense, which totaled $7.6 million, $7.6 million and $4.4 million for the years ended December 31, 2009 and 2008, and seven months ended December 31, 2007, respectively, 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.

## Plantation Pipe Line Company

Kinder Morgan Energy Partners has a seven-year note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, its 51.17%-owned equity investee. The outstanding note receivable balance was $84.8 million and $88.5 million as of December 31, 2009 and 2008, respectively. Of these amounts, $2.6 million and $3.7 million are included within “Accounts, notes and interest receivable, net” of the accompanying Consolidated Balance Sheets as of December 31, 2009 and 2008, respectively, and the remainder is included within “Notes receivable” at each reporting date.

## Express US Holdings LP

On June 30, 2008, we exchanged our C$113.6 million preferred equity interest in Express US Holdings LP for two subordinated notes from Express US Holdings LP (the obligor) with a combined face value of $111.4 million (C$113.6 million). The debentures, denominated in Canadian dollars, are due in full on January 9, 2023, each bearing an interest rate of 12.0% per annum and providing for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year.

On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system (“Express”), as well as our full ownership of the net assets of the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners. This transaction included the sale of our subordinated notes described above. We accounted for this transaction as a transfer of net assets between entities under common control. Therefore, following our sale of Express and Jet Fuel to Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer.

As of December 31, 2009 and 2008, the outstanding note receivable balance, representing the translated amount included in the accompanying Consolidated Financial Statements in U.S. dollars, was $108.1 million and $93.3 million, respectively, and we included these amounts within “Notes receivable” in the accompanying Consolidated Balance Sheets.

## NGPL PipeCo LLC

On February 15, 2008, Kinder Morgan, Inc. entered into an Operations and Reimbursement Agreement (“Agreement”) with Natural Gas Pipeline Company of America LLC, a wholly owned subsidiary of NGPL PipeCo LLC. The Agreement provides for Kinder Morgan, Inc. to be reimbursed, at cost, for pre-approved operations and maintenance costs, plus a $43.2 million annual general and administration fixed fee charge (“Fixed Fee”), for services provided under the Agreement. This Fixed Fee escalates at 3% each year until 2011 and is billed monthly. For the years ended December 31, 2009 and 2008, these Fixed Fees totaled $45.8 million and $38.9 million, respectively. In addition, Kinder Morgan Energy Partners purchases natural gas transportation and storage services from NGPL PipeCo LLC. For each of the years ended December 31, 2009 and 2008, these expenses totaled $8.8 million and $8.1 million, respectively, and we include these amounts within “Gas purchases and other costs of sales” in the accompanying Consolidated Statements of Operations.



## 12. Commitments and Contingent Liabilities

## Operating Leases

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):

<table><tr><td>Year</td><td>Commitment</td></tr><tr><td>2010</td><td>$ 43.8</td></tr><tr><td>2011</td><td>38.3</td></tr><tr><td>2012</td><td>29.6</td></tr><tr><td>2013</td><td>23.6</td></tr><tr><td>2014</td><td>20.6</td></tr><tr><td>Thereafter</td><td>82.9</td></tr><tr><td>Total minimum payments</td><td>$ 238.8</td></tr></table>

We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $3.7 million. Total lease and rental expenses were $73.1 million, $84.2 million, $43.8 million and $32.2 million for the years ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007, respectively.

## Share-based Compensation

Kinder Morgan, Inc.

In March 2007, all stock options and restricted stock held by employees of our discontinued U.S. Retail operations became fully vested. In May 2007, all restricted stock units held by employees of our discontinued Terasen gas operations became fully vested and any contingent stock unit grants were fully expensed. Finally, on May 30, 2007, all remaining stock options and restricted stock became fully vested and were exercised upon the closing of the Going Private transaction. We recorded expense of $25.7 million during the five months ended May 31, 2007 related to the accelerated vesting of these awards.

## Kinder Morgan Energy Partners

Kinder Morgan Energy Partners has two common unit-based compensation plans: The Directors' Unit Appreciation Rights Plan and the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors.

The Directors’ Unit Appreciation Rights Plan was established on April 1, 2003. Pursuant to this plan, and on this date of adoption, each of Kinder Morgan Management’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 Kinder Morgan Management’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, Kinder Morgan Energy Partners 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.

During 2007, 7,500 unit appreciation rights were exercised at an aggregate fair value of $53.00 per unit. During 2008, 10,000 unit appreciation rights were exercised at an aggregate fair value of $60.32 per unit. During 2009, 17,500 unit appreciation rights were exercised at an aggregate fair value of $53.75 per unit. As of December 31, 2009, 17,500 unit appreciation rights had been granted, vested and remained outstanding.



The Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors recognizes that the compensation to be paid to each non-employee director is fixed by the Kinder Morgan Management 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. 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. All common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. A total of 14,818 common units were issued to non-employee directors in 2009, 2008 and 2007 as a result of their elections to receive common units in lieu of cash compensation.

On January 20, 2010, one of Kinder Morgan Management’s directors elected to receive his 2010 compensation in the form of 3,200 Kinder Morgan Energy Partner’s common units.

## Contingent Debt

Kinder Morgan Energy Partners’ contingent debt disclosures pertain to certain types of guarantees or indemnifications Kinder Morgan Energy Partners has made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring Kinder Morgan Energy Partners’ performance under such guarantee is remote. The following is a description of Kinder Morgan Energy Partners’ 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 CO, 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 Kinder Morgan Energy Partners' indirect ownership of Cortez Pipeline Company through Kinder Morgan CO, Company, L.P., Kinder Morgan Energy Partners severally guarantees 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, Kinder Morgan Energy Partners' contingent share of Cortez's debt was $76.4 million (50% of total guaranteed borrowings).

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 Kinder Morgan Energy Partners’ several guaranty obligations jointly and severally; however, Kinder Morgan Energy Partners is 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 Kinder Morgan Energy Partners’ behalf in the amount of $21.4 million to secure Kinder Morgan Energy Partners’ 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

Kinder Morgan Energy Partners has 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. Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners' letter of credit and accordingly, Kinder Morgan Energy Partners paid this amount pursuant to the letter of credit reimbursement provisions. This payment reduced the face amount of Kinder Morgan Energy Partners' letter of credit from $22.5 million to $10.7 million. In December 2008, the bonds that were put back were re-sold, and Kinder Morgan Energy Partners was fully reimbursed for its 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 Kinder Morgan Energy Partners, and the three member owners and their respective ownership interests consist of the following: Kinder Morgan Energy Partners' subsidiary Kinder Morgan West2East 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, Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners (51% of total principal repayments, corresponding to Kinder Morgan Energy Partners' percentage ownership at that time).

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 Kinder Morgan Energy Partners, Sempra Energy or ConocoPhillips, or against any of Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners, and the two member owners and their respective ownership interests consist of the following: Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners, Energy Transfer Partners, or against any of Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners, and the two member owners and their respective ownership interests consist of the following: Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners' 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.

## 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 $1.5 million during 2008. We recognized a pre-tax gain of approximately $0.5 million and a pre-tax loss of approximately $0.7 million in the seven months ended December 31, 2007 and five months ended May 31, 2007, respectively.

Furthermore, during the years ended December 31, 2009 and 2008 and the five months ended May 31, 2007, we reclassified gains of $39.4 million, losses of $117.1 million and losses of $10.3 million, respectively, of the “Accumulated other comprehensive loss” balance included in our Stockholder’s Equity into earnings. With the exception of a $1.1 million net gain reclassified during the five months ended May 31, 2007 into earnings as a result of 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, 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 Stockholder’s Equity was $167.9 million as of December 31, 2009, and $53.4 million as of December 31, 2008. These totals included “Accumulated other comprehensive loss” amounts associated with energy commodity price risk management activities of $95.7 million of losses as of December 31, 2009 and $82.4 million of gains as of December 31, 2008. Approximately $42.6 million of the total amount associated with energy commodity price risk management activities and included in our Stockholder’s Equity 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.

As of December 31, 2009, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

<table><tr><td></td><td>Notional quantity</td></tr><tr><td>Derivatives designated as hedging contracts</td><td></td></tr><tr><td>Crude oil</td><td>25.6 million barrels</td></tr><tr><td>Natural gas(a)</td><td>44.3 billion cubic feet</td></tr><tr><td>Derivatives not designated as hedging contracts</td><td></td></tr><tr><td>Natural gas(a)</td><td>0.1 billion cubic feet</td></tr></table>

(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 operations during the current period. These types of transactions include basis spreads, basis-only positions and gas daily swap positions. Kinder Morgan Energy Partners primarily enters 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 associated with Kinder Morgan Energy Partners.

Effective at the beginning of the second quarter of 2008, Kinder Morgan Energy Partners determined that the derivative contracts of its 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, it 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 not party to any interest rate swap agreements, and our subsidiary, Kinder Morgan Energy Partners, was a party to interest rate swap agreements with a total notional principal amount of $2.8 billion. During 2009, we entered into two fixed-to-variable interest swap agreements having a combined notional principal amount of $725.0 million related to our 5.70% senior notes due January 5, 2016. During 2009, Kinder Morgan Energy Partners both 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 interest swap agreements having a combined notional principal amount of $2.95 billion. Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners' $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 and our subsidiary, Kinder Morgan Energy Partners, had a notional principal amount of $725.0 million and $5.2 billion of fixed-to-variable interest rate swap agreements, respectively, that effectively convert the interest expense associated with certain senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. All of our and Kinder Morgan Energy Partners' 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 through January 15, 2038.

## 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 the accompanying Consolidated Balance Sheets. The following table summarizes the fair values of our derivative contracts included on the accompanying Consolidated Balance Sheets as of December 31, 2009 and 2008 (in millions):

Fair Value of Derivative Contracts

<table><tr><td rowspan="3"></td><td colspan="3">Asset derivatives</td><td colspan="4">Liability derivatives</td></tr><tr><td colspan="2">December 31, 2009</td><td colspan="2">December 31, 2008</td><td colspan="2">December 31, 2009</td><td colspan="2">December31, 2008</td></tr><tr><td>Balance sheet location</td><td>Fair value</td><td>Balance sheet location</td><td>Fair value</td><td>Balance sheet location</td><td>Fair value</td><td></td></tr><tr><td>Derivatives designated as hedging contracts</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts</td><td>Current</td><td>$ 19.1</td><td>Current</td><td>$ 113.5</td><td>Current</td><td>$ (270.8)</td><td>Current</td><td>$ (129.4)</td></tr><tr><td></td><td>Non-current</td><td>57.3</td><td>Non-current</td><td>48.9</td><td>Non-current</td><td>(241.5)</td><td>Non-current</td><td>(92.2)</td></tr><tr><td>Subtotal</td><td></td><td>76.4</td><td></td><td>162.4</td><td></td><td>(512.3)</td><td></td><td>(221.6)</td></tr><tr><td>Interest rate swap agreements</td><td>Non-current</td><td>236.0</td><td>Non-current</td><td>747.1</td><td>Non-current</td><td>(218.5)</td><td>Non-current</td><td>-</td></tr><tr><td>Cross currency swap agreements</td><td>Non-current</td><td>-</td><td>Non-current</td><td>32.0</td><td>Non-current</td><td>(9.6)</td><td>Non-current</td><td>-</td></tr><tr><td>Total</td><td></td><td>312.4</td><td></td><td>941.5</td><td></td><td>(740.4)</td><td></td><td>(221.6)</td></tr><tr><td>Derivatives not designated as hedging contracts</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts</td><td>Current</td><td>1.7</td><td>Current</td><td>1.8</td><td>Current</td><td>(1.2)</td><td>Current</td><td>(0.1)</td></tr><tr><td>Total derivatives</td><td></td><td>$ 314.1</td><td></td><td>$ 943.3</td><td></td><td>$ (741.6)</td><td></td><td>$ (221.7)</td></tr></table>

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 the 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 2008, this unamortized premium totaled $337.5 million and $216.8 million, respectively.



## Effect of Derivative Contracts on the Income Statement

The following three tables summarize the impact of our derivative contracts on the accompanying Consolidated Statements of Operations (in millions):

<table><tr><td>Derivatives in fair value hedging relationships</td><td>Location of gain/ (loss) recognized in income on derivative</td><td colspan="2">Amount of gain/(loss) recognized in income on derivative(a)</td><td>Hedged items in fair value hedging relationships</td><td>Location of gain/ (loss) recognized in income on related hedged item</td><td colspan="2">Amount of gain/(loss) recognized in income on related hedged items(a)</td></tr><tr><td></td><td></td><td colspan="2">Year Ended December 31, 2009</td><td>Fixed rate debt</td><td>Interest, net - income/ (expense)</td><td>Year Ended December 31, 2009</td><td>2008</td></tr><tr><td>Interest rate swap agreements</td><td>Interest, net - income/ (expense)</td><td>$ (585.1)</td><td>$ 609.1</td><td></td><td></td><td>$ 585.1</td><td>$ (609.1)</td></tr><tr><td>Total</td><td></td><td>$ (585.1)</td><td>$ 609.1</td><td>Total</td><td></td><td>$ 585.1</td><td>$ (609.1)</td></tr></table>

(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.

<table><tr><td rowspan="2">Derivatives in cash flow hedging relationships</td><td rowspan="2">Amount of gain/(loss) recognized in OCI on derivative (effective portion)</td><td rowspan="2">Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)</td><td colspan="2">Amount of gain/(loss) recognized in income (effective portion)</td><td rowspan="2">Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)</td><td rowspan="2">Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effective testing)</td></tr><tr><td colspan="2">Year Ended December 31, 2009</td></tr><tr><td>Energy commodity derivative contracts</td><td>$ (138.7)</td><td>$ 212.0</td><td>Revenues-natural gas sales</td><td>$ 13.1</td><td>$ 6.0</td><td>Revenues</td></tr><tr><td>Total</td><td>$ (138.7)</td><td>$ 212.0</td><td>Revenues-product sales and other</td><td>25.7</td><td>(97.6)</td><td>Gas purchases and other costs of sales</td></tr><tr><td></td><td></td><td></td><td>Gas purchases and other costs of sales</td><td>0.6</td><td>(25.5)</td><td>Total</td></tr><tr><td></td><td></td><td></td><td></td><td>$ 39.4</td><td>$ (117.1)</td><td>Total</td></tr><tr><td>Derivatives in cash flow hedging relationships</td><td>Amount of gain/(loss) recognized in OCI on derivative (effective portion)</td><td>Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)</td><td colspan="2">Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)</td><td>Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)</td><td>Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effective testing)</td></tr><tr><td></td><td>Year Ended December 31, 2009</td><td>2008</td><td>2009</td><td>2008</td><td>2009</td><td>2008</td></tr><tr><td>Cross currency swap agreements</td><td>$ (41.6)</td><td>$ 83.2</td><td>Other, net</td><td>$ -</td><td>$ -</td><td>Revenues</td></tr><tr><td>Total</td><td>$ (41.6)</td><td>$ 83.2</td><td>Total</td><td>$ -</td><td>$ -</td><td>Total</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Derivatives not designated as hedging contracts</td><td colspan="3">Location of gain/(loss) recognized in income on derivative</td><td colspan="3">Amount of gain/(loss) recognized in income on derivative</td></tr><tr><td></td><td></td><td></td><td></td><td colspan="3">Year Ended December 31, 2009</td></tr><tr><td>Energy commodity derivative contracts</td><td>Gas purchases and other costs of sales</td><td></td><td></td><td>$ (4.2)</td><td>$ 5.6</td><td></td></tr><tr><td>Total</td><td></td><td></td><td></td><td>$ (4.2)</td><td>$ 3.0</td><td></td></tr></table>

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.



## Net Investment Hedges

We are exposed to foreign currency risk from our investments in businesses owned and operated outside the United States. To hedge the value of our investment in Canadian operations, we have entered into various cross-currency interest rate swap transactions that have been designated as net investment hedges. The effective portion of the changes in fair value of these swap transactions is reported as a cumulative translation adjustment included in the caption “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheets. The combined notional value of our remaining cross currency interest rate swaps at December 31, 2009 was approximately C$96.3 million.

In June 2009, we terminated cross currency interest rate swaps with a notional value of C29.2 million. In connection with this termination, we received $0.5 million in July 2009. Additionally in July 2009, we received $1.0 million for the termination of another portion of our cross currency interest rate swaps with a notional value of C29.2 million.

## Credit Risks

We and our subsidiary, Kinder Morgan Energy Partners, 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.

The maximum potential exposure to credit losses on our derivative contracts as of December 31, 2009 was (in millions):

<table><tr><td></td><td>Asset position</td></tr><tr><td>Interest rate swap agreements</td><td>$ 236.0</td></tr><tr><td>Energy commodity derivative contracts</td><td>78.1</td></tr><tr><td>Gross exposure</td><td>314.1</td></tr><tr><td>Netting agreement impact</td><td>(74.7)</td></tr><tr><td>Net exposure</td><td>$ 239.4</td></tr></table>

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 2008, Kinder Morgan Energy Partners had outstanding letters of credit totaling $55.0 million and $40.0 million, respectively, in support of its 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, Kinder Morgan Energy Partners had cash margin deposits associated with its 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, Kinder Morgan Energy Partners’ counterparties associated with its 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.

Kinder Morgan Energy Partners also has agreements with certain counterparties to its derivative contracts that contain provisions requiring it to post additional collateral upon a decrease in its credit rating. Based on contractual provisions as of December 31, 2009, Kinder Morgan Energy Partners estimates that if its credit rating was downgraded, it would have the following additional collateral obligations (in millions):



<table><tr><td>Credit Ratings Downgraded(a)</td><td>Incremental obligations</td><td>Cumulative Obligations(b)</td></tr><tr><td>One notch to BBB-/Baa3</td><td>$ 58.1</td><td>$ 128.3</td></tr><tr><td>Two notches to below BBB-/Baa3 (below investment grade)</td><td>$ 76.9</td><td>$ 205.2</td></tr></table>

(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 operation, 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 operations, 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 hierarchical disclosure framework that ranks the quality and reliability of information used to determine fair values. The hierarchy is associated with the level of pricing observability utilized in measuring fair value and defines three levels of inputs to the fair value measurement process—quoted prices are the most reliable valuation inputs, whereas model values that include inputs based on unobservable data are the least reliable. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.

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

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

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

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



## Fair Value of Derivative Contracts

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts, (ii) interest rate swap agreements and (iii) cross currency interest rate swap agreements as of December 31, 2009 and 2008, based on the three levels established by the Codification and does not include cash margin deposits, which are reported as “Restricted deposits” in the accompanying Consolidated Balance Sheets (in millions):

<table><tr><td rowspan="2"></td><td colspan="6">Asset fair value measurements using</td></tr><tr><td>Total</td><td colspan="3">Quoted prices in active markets for identical assets (Level 1)</td><td>Significant other observable inputs (Level 2)</td><td>Significant unobservable inputs (Level 3)</td></tr><tr><td>As of December 31, 2009</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(a)</td><td>$     78.1</td><td>$      -</td><td>$     14.4</td><td>$     63.7</td><td></td><td></td></tr><tr><td>Interest rate swap agreements</td><td>236.0</td><td>-</td><td>236.0</td><td>-</td><td></td><td></td></tr><tr><td>Cross currency interest rate swap agreements</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td><td></td></tr><tr><td>As of December 31, 2008</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(b)</td><td>$     164.2</td><td>$     0.1</td><td>$     108.9</td><td>$     55.2</td><td></td><td></td></tr><tr><td>Interest rate swap agreements</td><td>747.1</td><td>-</td><td>747.1</td><td>-</td><td></td><td></td></tr><tr><td>Cross currency interest rate swap agreements</td><td>32.0</td><td>-</td><td>32.0</td><td>-</td><td></td><td></td></tr><tr><td></td><td></td><td colspan="5">Liability fair value measurements using</td></tr><tr><td></td><td>Total</td><td colspan="3">Quoted prices in active markets for identical liabilities (Level 1)</td><td>Significant other observable inputs (Level 2)</td><td>Significant unobservable inputs (Level 3)</td></tr><tr><td>As of December 31, 2009</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(c)</td><td>$      (513.5)</td><td>$      -</td><td>$      (462.8)</td><td>$      (50.7)</td><td></td><td></td></tr><tr><td>Interest rate swap agreements</td><td>(218.5)</td><td>-</td><td>(218.5)</td><td>-</td><td></td><td></td></tr><tr><td>Cross currency interest rate swap agreements</td><td>(9.6)</td><td>-</td><td>(9.6)</td><td>-</td><td></td><td></td></tr><tr><td>As of December 31, 2008</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(d)</td><td>$      (221.7)</td><td>$      -</td><td>$      (210.6)</td><td>$      (11.1)</td><td></td><td></td></tr><tr><td>Interest rate swap agreements</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td><td></td></tr></table>

(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.

(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 (in millions):

Significant unobservable inputs (Level 3)

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td></tr><tr><td>Derivatives-net asset (liability)</td><td></td><td></td></tr><tr><td>Beginning of period</td><td>$ 44.1</td><td>$ (100.3)</td></tr><tr><td>Realized and unrealized net gains (losses)</td><td>(48.4)</td><td>69.6</td></tr><tr><td>Purchases and settlements</td><td>17.3</td><td>74.8</td></tr><tr><td>Transfers in (out) of Level 3</td><td>-</td><td>-</td></tr><tr><td>End of period</td><td>$ 13.0</td><td>$ 44.1</td></tr><tr><td>Change in unrealized net gains (losses) relating to contracts still held at end of period</td><td>$ (42.1)</td><td>$ 88.8</td></tr></table>



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 (both short-term and long-term, but excluding the value of interest rate swaps), is disclosed below (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">December 31, 2009</td><td colspan="3">December 31, 2008</td></tr><tr><td>Carrying Value</td><td colspan="2">Estimated Fair Value</td><td>Carrying Value</td><td colspan="2">Estimated Fair Value</td></tr><tr><td>Total Debt</td><td>$ 13,648.4</td><td>$ 14,158.2</td><td>$ 11,458.3</td><td>$ 9,813.9</td><td></td><td></td></tr></table>

## 15. Reportable Segments

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

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

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

CO \( _{2} \) –KMP: 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–KMP: 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;

Kinder Morgan Canada–KMP: the transportation of crude oil and refined products;

- NGPL PipeCo LLC: consists of our 20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system, which we operate. Prior to February 15, 2008, we owned 100% of NGPL; and

• Power: consists of a natural gas-fired electric generation facility.

On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system (“Express”), as well as our full ownership of the net assets of the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners. We accounted for this transaction as a transfer of net assets between entities under common control. Therefore, following our sale of Express and Jet Fuel to Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. The results of Express and Jet Fuel are reported in the Kinder Morgan Canada–KMP segment for all periods presented.

On February 15, 2008, we sold an 80% ownership interest in our NGPL PipeCo LLC business segment to Myria (see Note 3). We continue to operate NGPL PipeCo LLC’s assets pursuant to a 15-year operating agreement. Effective February 15, 2008, we began to account for the results of operations of the NGPL PipeCo LLC segment as an equity investment. See Note 17 in regards to NGPL’s Section 5 proceeding.



On April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain pipeline system from us. This transaction caused us to evaluate the fair value of the Trans Mountain pipeline system in determining whether goodwill related to these assets was impaired. Accordingly, based on our consideration of supporting information obtained regarding the fair values of the Trans Mountain pipeline system assets, a goodwill impairment non-cash charge of $377.1 million was recorded in five months ended May 31, 2007. The results of Trans Mountain are reported in the Kinder Morgan Canada–KMP segment for all periods presented.

In 2007, we completed the sales of our (i) U.S. retail natural gas distribution and related operations (March 2007), (ii) Terasen Pipeline (Corridor) Inc. (March 2007), (iii) Terasen Inc. (May 2007) and (iv) interests in three natural gas-fired power plants in Colorado (effective January 1, 2008). Kinder Morgan Energy Partners sold the North System and also its 50% ownership interest in the Heartland Pipeline Company (October 2007). The financial results for these entities and investments have been reclassified to discontinued operations for all periods presented, also see Note 3.

The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to our consolidated operations and described in Note 2, except that (i) certain items below the “Operating Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance, (ii) equity in earnings of equity method investees are included in segment earnings (these equity method earnings are included in “Other Income and (Expenses)” in the accompanying Consolidated Statements of Operations), (iii) certain items included in operating income (such as general and administrative expenses and depreciation, depletion and amortization (“DD&A”)) are not considered by management in its evaluation of business segment performance and, thus, are not included in reported performance measures, (iv) gains and losses from incidental sales of assets are

included in segment earnings and (v) our business segments that are also segments of Kinder Morgan Energy Partners include certain other income and expenses and income taxes in their segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on segment earnings before DD&A in relation to the level of capital employed.

Because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

During 2009, 2008, the seven months ended December 31, 2007 and five months ended May 31, 2007, we did not have revenues from any single customer that exceeded 10% of our consolidated revenues.



Financial information by segment follows (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31, 2007</td><td colspan="2">Five Months Ended May 31, 2007</td></tr><tr><td></td><td>2009</td><td>2008</td><td></td><td></td></tr><tr><td>Revenues</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>$     826.6</td><td>$     815.9</td><td>$     471.5</td><td>$     331.8</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>3,806.9</td><td>8,422.0</td><td>3,825.9</td><td>2,637.6</td><td></td></tr><tr><td>Intersegment revenues</td><td>-</td><td>-</td><td>-</td><td>3.0</td><td></td></tr><tr><td>CO2-KMP</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>1,131.3</td><td>1,269.2</td><td>605.9</td><td>324.2</td><td></td></tr><tr><td>Terminals-KMP</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>1,108.1</td><td>1,172.7</td><td>598.8</td><td>364.2</td><td></td></tr><tr><td>Intersegment revenues</td><td>0.9</td><td>0.9</td><td>0.4</td><td>0.3</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>226.1</td><td>198.9</td><td>100.0</td><td>62.9</td><td></td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>-</td><td>132.1</td><td>752.4</td><td>424.5</td><td></td></tr><tr><td>Revenues from external customers</td><td>-</td><td>0.9</td><td>4.8</td><td>2.0</td><td></td></tr><tr><td>Intersegment revenues</td><td>-</td><td></td><td></td><td></td><td></td></tr><tr><td>Power(b)</td><td>40.4</td><td>44.0</td><td>40.2</td><td>19.9</td><td></td></tr><tr><td>Revenues from external customers</td><td>45.8</td><td>40.0</td><td>-</td><td>-</td><td></td></tr><tr><td>Other</td><td>-</td><td>(0.9)</td><td>-</td><td>-</td><td></td></tr><tr><td>Revenues from other customers(c)</td><td>-</td><td></td><td></td><td></td><td></td></tr><tr><td>Intersegment revenues</td><td>7,186.1</td><td>12,095.7</td><td>6,399.9</td><td>4,170.4</td><td></td></tr><tr><td>Total segment revenues</td><td>(0.9)</td><td>(0.9)</td><td>(5.2)</td><td>(5.3)</td><td></td></tr><tr><td>Less: Total intersegment revenues</td><td>7,185.2</td><td>$     12,094.8</td><td>$     6,394.7</td><td>$     4,165.1</td><td></td></tr><tr><td>Total consolidated revenues</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td></td><td colspan="2">Year Ended December 31,</td><td rowspan="2">Seven Months Ended December 31, 2007</td><td colspan="2">Five Months Ended May 31, 2007</td></tr><tr><td></td><td>2009</td><td>2008</td><td></td><td></td></tr><tr><td>Operating expenses(d)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$     269.5</td><td>$     291.0</td><td>$     320.6</td><td>$     116.4</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>3,192.7</td><td>7,803.3</td><td>3,461.4</td><td>2,418.5</td><td></td></tr><tr><td>CO2-KMP</td><td>271.1</td><td>391.8</td><td>182.7</td><td>121.5</td><td></td></tr><tr><td>Terminals-KMP</td><td>536.8</td><td>631.8</td><td>344.2</td><td>192.2</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>72.5</td><td>68.0</td><td>44.3</td><td>23.1</td><td></td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>-</td><td>43.5</td><td>335.4</td><td>159.7</td><td></td></tr><tr><td>Power(b)</td><td>23.6</td><td>24.8</td><td>25.7</td><td>18.2</td><td></td></tr><tr><td>Other</td><td>0.1</td><td>0.1</td><td>0.9</td><td>(3.4)</td><td></td></tr><tr><td>Total segment operating expenses</td><td>4,366.3</td><td>9,254.3</td><td>4,715.2</td><td>3,046.2</td><td></td></tr><tr><td>Less: Total intersegment operating expenses</td><td>(0.9)</td><td>(0.9)</td><td>(5.2)</td><td>(5.3)</td><td></td></tr><tr><td>Total consolidated operating expenses</td><td>$     4,365.4</td><td>$     9,253.4</td><td>$     4,710.0</td><td>$     3,040.9</td><td></td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Other expense (income)</td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Products Pipelines-KMP(e)</td><td>$ 1.1</td><td>$ 1,269.5</td><td>$ (0.8)</td><td>$ 0.6</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP(e)</td><td>(6.6)</td><td>2,090.0</td><td>(1.9)</td><td>0.1</td><td></td></tr><tr><td>CO2-KMP</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Terminals-KMP(e)</td><td>(25.0)</td><td>683.0</td><td>(3.3)</td><td>(3.0)</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP(f)</td><td>-</td><td>-</td><td>-</td><td>377.1</td><td></td></tr><tr><td>Other</td><td>(0.1)</td><td>0.1</td><td>-</td><td>-</td><td></td></tr><tr><td>Total consolidated other expense (income)</td><td>(30.6)</td><td>$ 4,042.6</td><td>$ (6.0)</td><td>$ 374.8</td><td></td></tr><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Depreciation, depletion and amortization</td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$ 121.3</td><td>$ 116.9</td><td>$ 58.1</td><td>$ 33.6</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>120.5</td><td>99.9</td><td>52.3</td><td>26.8</td><td></td></tr><tr><td>CO2-KMP</td><td>620.6</td><td>498.1</td><td>243.5</td><td>116.3</td><td></td></tr><tr><td>Terminals-KMP</td><td>169.1</td><td>157.4</td><td>62.1</td><td>34.4</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>38.5</td><td>36.7</td><td>13.5</td><td>8.2</td><td></td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>-</td><td>9.3</td><td>42.3</td><td>45.3</td><td></td></tr><tr><td>Power</td><td>-</td><td>-</td><td>0.2</td><td>(4.2)</td><td></td></tr><tr><td>Other</td><td>0.2</td><td>0.1</td><td>0.3</td><td>0.6</td><td></td></tr><tr><td>Total consolidated depreciation, depletion and amortization</td><td>$ 1,070.2</td><td>$ 918.4</td><td>$ 472.3</td><td>$ 261.0</td><td></td></tr><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Earnings from equity investments</td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$ 18.7</td><td>$ 15.7</td><td>$ 11.5</td><td>$ 12.4</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>141.8</td><td>113.4</td><td>10.3</td><td>8.9</td><td></td></tr><tr><td>CO2-KMP</td><td>22.3</td><td>20.7</td><td>10.5</td><td>8.7</td><td></td></tr><tr><td>Terminals-KMP</td><td>0.7</td><td>2.7</td><td>0.6</td><td>-</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>(4.1)</td><td>8.3</td><td>14.4</td><td>5.4</td><td></td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>42.5</td><td>40.3</td><td>1.0</td><td>0.6</td><td></td></tr><tr><td>Power</td><td>-</td><td>-</td><td>8.0</td><td>5.1</td><td></td></tr><tr><td>Other</td><td>-</td><td>-</td><td>0.5</td><td>(0.4)</td><td></td></tr><tr><td>Total consolidated equity earnings</td><td>$ 221.9</td><td>$ 201.1</td><td>$ 56.8</td><td>$ 40.7</td><td></td></tr><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Amortization of excess cost of equity investments</td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$ 3.4</td><td>$ 3.3</td><td>$ 2.0</td><td>$ 1.4</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>0.4</td><td>0.4</td><td>0.2</td><td>0.2</td><td></td></tr><tr><td>CO2-KMP</td><td>2.0</td><td>2.0</td><td>1.2</td><td>0.8</td><td></td></tr><tr><td>Terminals-KMP</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Total consol. amortization of excess cost of invest.</td><td>$ 5.8</td><td>$ 5.7</td><td>$ 3.4</td><td>$ 2.4</td><td></td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Interest income</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$ 4.1</td><td>$ 4.3</td><td>$ 2.6</td><td>$ 1.8</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>6.2</td><td>1.2</td><td>-</td><td>-</td><td></td></tr><tr><td>CO2-KMP</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Terminals-KMP</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>12.0</td><td>3.9</td><td>-</td><td>-</td><td></td></tr><tr><td>Total segment interest income</td><td>22.3</td><td>9.4</td><td>2.6</td><td>1.8</td><td></td></tr><tr><td>Unallocated interest income</td><td>3.4</td><td>38.1</td><td>4.6</td><td>9.5</td><td></td></tr><tr><td>Total consolidated interest income</td><td>$ 25.7</td><td>$ 47.5</td><td>$ 7.2</td><td>$ 11.3</td><td></td></tr><tr><td></td><td colspan="2">Successor Company</td><td colspan="2">Predecessor Company</td><td></td></tr><tr><td></td><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Other, net-income (expense)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$ 8.3</td><td>$ (2.3)</td><td>$ 2.1</td><td>$ 2.9</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>25.6</td><td>15.1</td><td>-</td><td>0.2</td><td></td></tr><tr><td>CO2-KMP</td><td>-</td><td>1.9</td><td>0.1</td><td>(0.1)</td><td></td></tr><tr><td>Terminals-KMP</td><td>3.7</td><td>1.7</td><td>0.7</td><td>0.3</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>11.9</td><td>(10.1)</td><td>6.3</td><td>1.7</td><td></td></tr><tr><td>Other</td><td>-</td><td>0.7</td><td>2.4</td><td>(4.4)</td><td></td></tr><tr><td>Total consolidated other, net-income (expense)</td><td>$ 49.5</td><td>$ 7.0</td><td>$ 11.6</td><td>$ 0.6</td><td></td></tr><tr><td></td><td colspan="2">Successor Company</td><td colspan="2">Predecessor Company</td><td></td></tr><tr><td></td><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Income tax benefit (expense)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$ (3.1)</td><td>$ 4.9</td><td>$ (5.4)</td><td>$ (7.5)</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>(5.7)</td><td>(2.7)</td><td>(3.4)</td><td>(2.6)</td><td></td></tr><tr><td>CO2-KMP</td><td>(4.0)</td><td>(3.9)</td><td>(0.8)</td><td>(1.3)</td><td></td></tr><tr><td>Terminals-KMP</td><td>(5.2)</td><td>(19.7)</td><td>(15.9)</td><td>(3.3)</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>(18.9)</td><td>19.0</td><td>(18.5)</td><td>(0.9)</td><td></td></tr><tr><td>Total segment income tax benefit (expense)</td><td>(36.9)</td><td>(2.4)</td><td>(44.0)</td><td>(15.6)</td><td></td></tr><tr><td>Unallocated income tax benefit (expense)</td><td>(288.7)</td><td>(301.9)</td><td>(183.4)</td><td>(119.9)</td><td></td></tr><tr><td>Total consolidated income tax benefit (expense)</td><td>$ (325.6)</td><td>$ (304.3)</td><td>$ (227.4)</td><td>$ (135.5)</td><td></td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(g)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$     584.0</td><td>$    (722.0)</td><td>$     162.5</td><td>$     224.4</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>788.7</td><td>(1,344.3)</td><td>373.3</td><td>228.5</td><td></td></tr><tr><td>CO2-KMP</td><td>878.5</td><td>896.1</td><td>433.0</td><td>210.0</td><td></td></tr><tr><td>Terminals-KMP</td><td>596.4</td><td>(156.5)</td><td>243.7</td><td>172.3</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>154.5</td><td>152.0</td><td>58.8</td><td>(332.0)</td><td></td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>42.5</td><td>129.8</td><td>422.8</td><td>267.4</td><td></td></tr><tr><td>Power</td><td>4.8</td><td>5.7</td><td>13.4</td><td>8.9</td><td></td></tr><tr><td>Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments</td><td>3,049.4</td><td>(1,039.2)</td><td>1,707.5</td><td>779.5</td><td></td></tr><tr><td>Total segment depreciation, depletion and amortization</td><td>(1,070.2)</td><td>(918.4)</td><td>(472.3)</td><td>(261.0)</td><td></td></tr><tr><td>Total segment amortization of excess cost of equity investments</td><td>(5.8)</td><td>(5.7)</td><td>(3.4)</td><td>(2.4)</td><td></td></tr><tr><td>NGPL PipeCo LLC fixed fee revenue</td><td>45.8</td><td>39.0</td><td>-</td><td>-</td><td></td></tr><tr><td>General and administrative expenses</td><td>(373.0)</td><td>(352.5)</td><td>(175.6)</td><td>(283.6)</td><td></td></tr><tr><td>Unallocable interest and other, net(h)</td><td>(583.7)</td><td>(623.6)</td><td>(586.7)</td><td>(254.6)</td><td></td></tr><tr><td>Unallocable income tax expense</td><td>(288.7)</td><td>(301.9)</td><td>(183.4)</td><td>(119.9)</td><td></td></tr><tr><td>Income (loss) from continuing operations</td><td>$     773.8</td><td>$    (3,202.3)</td><td>$     286.1</td><td>$     142.0</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td colspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td colspan="2">Seven Months Ended December 31,</td><td>Five Months Ended May 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>2007</td><td></td></tr><tr><td>Capital expenditures(i)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$     199.8</td><td>$     221.7</td><td>$     179.9</td><td>$     79.5</td><td></td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>372.0</td><td>946.5</td><td>197.4</td><td>66.6</td><td></td></tr><tr><td>CO2-KMP</td><td>341.8</td><td>542.6</td><td>249.2</td><td>133.3</td><td></td></tr><tr><td>Terminals-KMP</td><td>378.2</td><td>454.1</td><td>310.1</td><td>169.9</td><td></td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>32.0</td><td>368.1</td><td>196.7</td><td>109.0</td><td></td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>-</td><td>10.3</td><td>152.0</td><td>77.3</td><td></td></tr><tr><td>Power</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Other</td><td>0.5</td><td>2.0</td><td>1.7</td><td>17.2</td><td></td></tr><tr><td>Total consolidated capital expenditures</td><td>$     1,324.3</td><td>$     2,545.3</td><td>$     1,287.0</td><td>$     652.8</td><td></td></tr></table>

<table><tr><td></td><td>2009</td><td>2008</td></tr><tr><td>Investments at December 31</td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$     346.9</td><td>$     349.6</td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>2,542.8</td><td>654.0</td></tr><tr><td>CO2-KMP</td><td>11.2</td><td>13.6</td></tr><tr><td>Terminals-KMP</td><td>18.7</td><td>18.6</td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>68.7</td><td>65.5</td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>698.5</td><td>717.3</td></tr><tr><td>Total segment investments</td><td>3,686.8</td><td>1,818.6</td></tr><tr><td>Other</td><td>8.8</td><td>8.8</td></tr><tr><td>Total consolidated investments</td><td>$     3,695.6</td><td>$     1,827.4</td></tr></table>



<table><tr><td></td><td>2009</td><td>2008</td></tr><tr><td>Assets at December 31</td><td></td><td></td></tr><tr><td>Products Pipelines-KMP</td><td>$ 5,614.7</td><td>$ 5,526.4</td></tr><tr><td>Natural Gas Pipelines-KMP</td><td>9,956.7</td><td>7,748.1</td></tr><tr><td>CO2-KMP</td><td>4,230.5</td><td>4,478.7</td></tr><tr><td>Terminals-KMP</td><td>4,537.3</td><td>4,327.8</td></tr><tr><td>Kinder Morgan Canada-KMP</td><td>1,797.7</td><td>1,583.9</td></tr><tr><td>NGPL PipeCo LLC(a)</td><td>698.5</td><td>717.3</td></tr><tr><td>Power</td><td>67.6</td><td>58.9</td></tr><tr><td>Total segment assets</td><td>26,903.0</td><td>24,441.1</td></tr><tr><td>Other(j)</td><td>683.3</td><td>1,003.8</td></tr><tr><td>Total consolidated assets</td><td>$ 27,586.3</td><td>$ 25,444.9</td></tr></table>

(a) Effective February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC to Myria. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest in NGPL PipeCo LLC as an equity method investment and 100% of NGPL revenues, earnings and assets prior to the sale, are included in the above tables.

(b) Upon the adoption of Accounting Standards Update No. 2009-17, which amended the codification’s “Consolidation” topic, on January 1, 2010, Triton Power operations will no longer be consolidated into our financial statements, but be treated as an equity investment, resulting in decreases to revenues, operating expenses and noncontrolling interests with no impact to segment earnings before DD&A (see Note 18).

(c) 2009 and 2008 includes NGPL fixed fee revenues of $45.8 million and $39.0 million, respectively (see Note 11).

(d) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes.

(e) 2008 includes non-cash goodwill impairment charges (see Note 7).
(f) Five months ended May 31, 2007 includes non-cash goodwill impairment charge (see Note 7).

(g) Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(h) Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments.

(i) Sustaining capital expenditures, including Kinder Morgan Energy Partners' share of Rockies Express' sustaining capital expenditures, for each of the years ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007, were $172.7 million, $183.9 million, $164.6 million and $78.6 million, respectively.

(j) Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, and risk management assets related to the fair value of interest rate swaps.

We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 2007, we reported total consolidated interest expense of $599.1 million, $675.8 million, $601.5 million and $261.5 million, respectively.

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

<table><tr><td rowspan="2"></td><td colspan="4">Successor Company</td><td rowspan="2">Predecessor Company</td></tr><tr><td colspan="3">Year Ended December 31,</td><td>Seven Months Ended December 31,</td></tr><tr><td></td><td colspan="2">2009</td><td>2008</td><td>2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Revenues from external customers</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$</td><td>6,862.3</td><td>$</td><td>11,804.2</td><td>$ 6,239.7</td></tr><tr><td>Canada</td><td></td><td>301.9</td><td></td><td>269.3</td><td>143.5</td></tr><tr><td>Mexico and other(a)</td><td></td><td>21.0</td><td></td><td>21.3</td><td>11.5</td></tr><tr><td>Total consolidated revenues from external customers</td><td>$</td><td>7,185.2</td><td>$</td><td>12,094.8</td><td>$ 6,394.7</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

(a) Includes operations in Mexico and the Netherlands.

(b) Long-lived assets exclude (i) goodwill and (ii) other intangibles, net.



## 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 SFPP, L.P. (a Kinder Morgan Energy Partners subsidiary) as SFPP; Calnew Pipe Line LLC as Calnew; 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; Kinder Morgan Energy Partners' subsidiary Kinder Morgan CO \( _{2} \)  Company, L.P. (the successor to Shell CO \( _{2} \) , Company, Ltd.) as Kinder Morgan CO \( _{2} \) ; 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;

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—Defendants: 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—Defendants: 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;

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 the 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 may be included in its 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 a review of these FERC proceedings and the information available, Kinder Morgan Energy Partners estimates 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. Kinder Morgan Energy Partners assumes that, with respect to its 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 a review of these CPUC proceedings, Kinder Morgan Energy Partners estimates that shippers are seeking approximately 10 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 CO \( _{2} \) , 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.

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.

##  \( CO_{2} \)  Claims Arbitration

Kinder Morgan CO \( _{2} \)  and Cortez Pipeline Company were among the named defendants in CO \( _{2} \)  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 ( \( CO_{2} \)  Committee, Inc. v. Shell CO \( _{2} \)  Company, Ltd., aka Kinder Morgan CO \( _{2} \)  Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO \( _{2} \) , 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 CO \( _{2} \)  received a “Notice of Noncompliance and Civil Penalty: Knowing or Willful Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO \( _{2} \)  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 CO \( _{2} \)  has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO \( _{2} \)  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 CO \( _{2} \) 's alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO \( _{2} \)  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 CO \( _{2} \)  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 CO \( _{2} \)  filed a motion seeking to stay the accrual of civil penalties during the appeal, which was denied.

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 CO \( _{2} \)  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 CO \( _{2} \)  received an “Order to Report and Pay” from the MMS. The MMS contends that Kinder Morgan CO \( _{2} \)  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 CO \( _{2} \)  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 CO \( _{2} $ ’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 CO \( _{2} $  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 CO \( _{2} \)  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 CO \( _{2} \)  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 CO \( _{2} \)  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 CO \( _{2} \)  Company, L.P., No. 04-26-CL (8 \( ^{th} \)  Judicial District Court, Union County New Mexico)

This case involved a purported class action against Kinder Morgan CO \( _{2} \)  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 not expired and it 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  \( CO_{2} \) . The Notices of Deficiency assessed additional state severance tax against Kinder Morgan  \( CO_{2} \)  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  \( CO_{2} \)  protested the Notices of Deficiency and paid the tax and interest under protest. Kinder Morgan  \( CO_{2} \)  is now awaiting the Colorado Department of Revenue's response to the protest.

## Montezuma County, Colorado Property Tax Assessment

In November of 2009, the County Treasurer of Montezuma County, Colorado, issued to Kinder Morgan  \( CO_{2} \) , 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  \( CO_{2} \) '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  \( CO_{2} \)  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  \( CO_{2} \) '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 Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners defendants. In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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. A decision is still pending on Defendants' Motions for Sanctions and Requests for Attorney Fees.

## Several Sparrows Point Crane Collapse

On June 4, 2008, a bridge crane owned by Several Sparrows Point, LLC and located in Sparrows Point, Maryland collapsed while being operated by KMBT, a subsidiary of Kinder Morgan Energy Partners. According to Kinder Morgan Energy Partners' investigation, the collapse was caused by unexpected, sudden and extreme winds. On June 24, 2009, Several filed suit against KMBT in the United States District Court for the District of Maryland, cause no. WMN 09CV1668. Several 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. Several seeks unspecified damages for value of the crane and lost profits. KMBT denies each of Several's allegations.

## JR Nicholls Tug Incident

On February 10, 2010, the JR Nicholls, a tugboat operated by one of Kinder Morgan Energy Partners' 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 Kinder Morgan Energy Partners and several Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners related defendants with prejudice in exchange for the Kinder Morgan Energy Partners defendants' agreement that they would not seek to recover their defense costs against the plaintiffs. The Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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 G.P., Inc. employee, filed suit in January 2010 against various Kinder Morgan G.P., Inc. affiliates. On behalf of himself and other, similarly situated current and former employees, Mr. Lugliani claims that the Kinder Morgan G.P., Inc. 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. The defendants filed their answer in February 2010 and intend to vigorously defend the case.

## Pipeline Integrity and Releases

From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

## Midcontinent Express Pipeline LLC Construction Incident

On July 15, 2009, a Midcontinent Express Pipeline LLC contractor and subcontractor were conducting a nitrogen pressure test on facilities at a Midcontinent Express Pipeline delivery meter station that was under construction-in 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 (“OSHA”) completed their investigation. Neither Midcontinent Express Pipeline LLC nor Kinder Morgan Energy Partners were cited for any violations by OSHA.

## Pasadena Terminal Fire

On September 23, 2008, a fire occurred in the pit 3 manifold area of Kinder Morgan Energy Partners' 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 133 \( ^{rd} \)  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 (“KMLT”), Case # D1GV10000017, 53 \( ^{rd} \)  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. KMLT is currently in discussions with TCEQ legal representatives and the Texas Attorney General’s office regarding resolution of this matter. KMLT does 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 it is not expected 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 Kinder Morgan Energy Partners, 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. Kinder Morgan Energy Partners has 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, Kinder Morgan Energy Partners entered into a settlement agreement with one of the plaintiffs, the decedent's daughter, resolving any and all of her claims against it, Rockies Express and its contractors. In January 2010, Kinder Morgan Energy Partners entered into a settlement agreement with each of the remaining plaintiffs, effectively concluding this matter. Kinder Morgan Energy Partners was indemnified for the full amount of both settlements by one of Rockies Express' contractors.

## Charlotte, North Carolina

On January 17, 2010, Kinder Morgan Energy Partners’ subsidiary, Southeast Terminals LLC’s Charlotte #2 Terminal experienced an issue with a pollution control device known as the Vapor Recovery Unit, which led to a fire and release of gasoline from the facility to adjacent property and a small creek. There were no injuries. Kinder Morgan Energy Partners is 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 (“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 (“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 Kinder Morgan Energy Partners' 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, Kinder Morgan Energy Partners 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 Federal Transportation Safety Board. Cleanup and environmental remediation is complete and Kinder Morgan Energy Partners has received a British Columbia Ministry of Environment Certificate of Compliance confirming complete remediation.

The National Transportation Safety Board released its investigation report (“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 Kinder Morgan Energy Partners’ 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 Trans Mountain L.P. (the last two of which are subsidiaries of Kinder Morgan Energy Partners). 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. Kinder Morgan Energy Partners is of the view that the charges have been improperly laid against it, and it intends to vigorously defend against them.

## Litigation Relating to the “Going Private” Transaction

Beginning on May 29, 2006, the day after the proposal for the Going Private transaction was announced, and in the days following, eight putative Class Action lawsuits were filed in Harris County (Houston), Texas and seven putative Class Action lawsuits were filed in Shawnee County (Topeka), Kansas against, among others, Kinder Morgan, Inc., its Board of Directors, the Special Committee of the Board of Directors, and several corporate officers.

By order of the Harris County District Court dated June 26, 2006, each of the eight Harris County cases were consolidated into the Crescente v. Kinder Morgan, Inc. et al case, Cause No. 2006-33011, in the 164 \( ^{th} \)  Judicial District Court, Harris County, Texas, which challenges the proposed transaction as inadequate and unfair to Kinder Morgan, Inc.'s public



stockholders. On September 8, 2006, interim class counsel filed their Consolidated Petition for Breach of Fiduciary Duty and Aiding and Abetting in which they alleged that Kinder Morgan, Inc.'s Board of Directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They sought, among other things, to enjoin the merger, rescission of the merger agreement, disgorgement of any improper profits received by the defendants, and attorneys' fees. Defendants filed Answers to the Consolidated Petition on October 9, 2006, denying the plaintiffs' substantive allegations and denying that the plaintiffs are entitled to relief.

By order of the District Court of Shawnee County, Kansas dated June 26, 2006, each of the seven Kansas cases were consolidated into the Consol. Case No. 06 C 801; In Re Kinder Morgan, Inc. Shareholder Litigation; in the District Court of Shawnee County, Kansas, Division 12. On August 28, 2006, the plaintiffs filed their Consolidated and Amended Class Action Petition in which they alleged that Kinder Morgan's Board of Directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They sought, among other things, to enjoin the stockholder vote on the merger agreement and any action taken to effect the acquisition of Kinder Morgan and its assets by the buyout group, damages, disgorgement of any improper profits received by the defendants, and attorney's fees.

In late 2006, the Kansas and Texas Courts appointed the Honorable Joseph T. Walsh to serve as Special Master in both consolidated cases “to control all of the pretrial proceedings in both the Kansas and Texas Class Actions arising out of the proposed private offer to purchase the stock of the public shareholders of Kinder Morgan, Inc.” On November 21, 2006, the plaintiffs in In Re Kinder Morgan, Inc. Shareholder Litigation filed a Third Amended Class Action Petition with Special Master Walsh. This Petition was later filed under seal with the Kansas District Court on December 27, 2006.

Following extensive expedited discovery, the Plaintiffs in both consolidated actions filed an application for a preliminary injunction to prevent the holding of a special meeting of shareholders for the purposes of voting on the proposed merger, which was scheduled for December 19, 2006.

On December 18, 2006, Special Master Walsh issued a Report and Recommendation concluding, among other things, that “plaintiffs have failed to demonstrate the probability of ultimate success on the merits of their claims in this joint litigation.” Accordingly, the Special Master concluded that the plaintiffs were “not entitled to injunctive relief to prevent the holding of the special meeting of Kinder Morgan, Inc. shareholders scheduled for December 19, 2006.”

Plaintiffs moved for class certification in January 2008.

In August, September and October 2008, the Plaintiffs in both consolidated cases voluntarily dismissed without prejudice the claims against those Kinder Morgan, Inc. directors who did not participate in the buyout (including the dismissal of the members of the special committee of the board of directors), Kinder Morgan, Inc. and Knight Acquisition, Inc. In addition, on November 19, 2008, by agreement of the parties, the Texas trial court issued an order staying all proceedings in the Texas actions until such time as a final judgment shall be issued in the Kansas actions. The effect of this stay is that the consolidated matters will proceed only in the Kansas trial court.

In February 2009, the parties submitted an agreed upon order which has been entered by the Kansas trial court certifying a class consisting of “All holders of Kinder Morgan, Inc. common stock, during the period of August 28, 2006, through May 30, 2007, and their transferees, successors and assigns. Excluded from the class are defendants, members of their immediate families or trusts for the benefit of defendants or their immediate family members, and any majority-owned affiliates of any defendant.” The parties agreed that the certification and definition of the above class was subject to revision and without prejudice to defendants’ right to seek decertification of the class or modification of the class definition.

The parties are currently engaged in consolidated discovery in these matters.

On August 24, 2006, a civil action entitled City of Inkster Policeman and Fireman Retirement System, Derivatively on Behalf of Kinder Morgan, Inc., Plaintiffs v. Richard D. Kinder, Michael C. Morgan, William V. Morgan, Fazey Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True, III, James M. Stanford, Stewart A. Bliss, Edward Randall, III, Douglas W.G. Whitehead, Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group, Riverstone Holdings LLC, C. Park Shaper, Steven J. Kean, Scott E. Parker and R. Tim Bradley, Defendants and Kinder Morgan, Inc., Nominal Defendant; Case 2006-52653, was filed in the 270th Judicial District Court, Harris County, Texas. This putative derivative lawsuit was brought against certain of Kinder Morgan, Inc.'s senior officers and directors, alleging that the proposal constituted a breach of fiduciary duties owed to Kinder Morgan, Inc. The plaintiff also contends that the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty. The plaintiff seeks, among other things, to enjoin the defendants from consummating the proposal, a declaration that the proposal is unlawful and unenforceable, the imposition of a constructive trust upon any benefits improperly received by the defendants, and attorney's fees. In November 2007, defendants filed a Joint Motion to Dismiss for Lack of Jurisdiction, or in the Alternative, Motion for Final Summary Judgment. Plaintiffs opposed the motion. In February 2008, the court entered a Final Order



granting defendants' motion in full, ordering that plaintiff, the City of Inkster Policeman and Fireman Retirement System, take nothing on any and all of its claims against any and all defendants. In April 2008, Plaintiffs filed an appeal of the judgment in favor of all defendants in the Texas Court of Appeal, First District. In June 2009, the Texas Court of Appeal affirmed the decision of the trial court dismissing the case in full.

## Natural Gas Pipeline Company of America's (“NGPL”) Fire

On October 28, 2009, an explosion and resulting fire occurred in a 10,000 barrel water tank at NGPL’s compressor station located near St. Elmo, Illinois. Three Kinder Morgan, Inc. employees were injured as a result of the explosion and fire. This incident is being investigated by OSHA, PHMSA and the Chemical Safety Board. To date, no citations have been issued by any of the investigating agencies and no lawsuits have been filed.

## 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 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 Kinder Morgan Energy Partners' 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.

## 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.

Kinder Morgan Liquids Terminals LLC, a subsidiary of Kinder Morgan Energy Partners, 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 Support Terminals Services, Inc.

On April 23, 2003, Exxon Mobil Corporation (“ExxonMobil”) 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 Corporation (“GATX”) from 1989 through September 2000, later owned by Support Terminals Services, Inc (“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 and Kinder Morgan Energy Partners' subsidiary Kinder Morgan Liquids Terminals LLC, formerly known as GATX. 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, Kinder Morgan Energy Partners believes 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 Kinder Morgan Energy Partners 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, Kinder Morgan Energy Partners removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. On October 3, 2007, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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.

## Kinder Morgan Port Manatee Terminal LLC, Palmetto, Florida

On June 18, 2009, Kinder Morgan Port Manatee Terminal LLC (“KM PMT”) a Kinder Morgan Energy Partners’ subsidiary, received a Revised Warning Letter from the Florida Department of Environmental Protection, referred to in this note as the Florida DEP, advising it of possible regulatory and air permit violations regarding operations at the Kinder Morgan Port Manatee Florida Terminal LLC. Kinder Morgan Energy Partners 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. Kinder Morgan Energy Partners reported its findings from this audit in a self-disclosure letter to the Florida DEP in March, 2008. Following the submittal of its 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 the 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. Kinder Morgan Energy Partners has fully cooperated with the government’s investigation, and has 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.

## 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 (“EPA”) Region V. This information request requires that we provide the EPA with air permit and various other information related to 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.

## 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 $86.3 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 $85.0 million and our estimated receivable for environmental cost recoveries totaled $20.9 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.

## NGPL Section 5 Proceeding

On November 19, 2009, NGPL was notified by the FERC of a proceeding against it pursuant to section 5 of the Natural Gas Act (the "Order"). The proceeding will set the matter for hearing and determine whether NGPL's current rates, which



were approved by the FERC in NGPL's last rate case settlement, remain just and reasonable. The FERC made no findings in its Order as to what would constitute just and reasonable rates or a reasonable return for NGPL. A proceeding under section 5 of the Natural Gas Act is prospective in nature. A change in rates charged customers by NGPL would likely only occur after the FERC has issued a final order. According to the procedural schedule adopted in the case, an initial Administrative Law Judge decision is due by November 15, 2010. The final FERC decision will be based on the record developed before the Administrative Law Judge.

## Natural Gas Pipeline Expansion Filings

## Rockies Express Pipeline-East Project

On November 12, 2009, Kinder Morgan Energy Partners 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, Rockies Express Pipeline 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 and a Kinder Morgan Energy Partners 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.

Kinder Morgan Energy Partners owns 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, the current estimate of total Rockies Express Pipeline project construction costs is approximately $6.8 billion.

## 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 July 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 – Docket No. CP06-449-000

On April 16, 2009, Kinder Morgan Energy Partners' 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).

The Midcontinent Express Pipeline is owned by Midcontinent Express Pipeline LLC, a 50/50 joint venture between Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners 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. The estimate of the total costs of this pipeline project is approximately $1.2 billion (consistent with Kinder Morgan Energy Partners' January 20, 2010 fourth quarter earnings press release).

## 18. Recent Accounting Pronouncements

In August 2009, the FASB issued Accounting Standards Update (“ASU”) ASU No. 2009-05, “Measuring Liabilities at Fair Value.” This 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 a material impact on our consolidated financial statements.

On January 6, 2010, the FASB issued ASU No. 2010-03, “Extractive Industries-Oil and Gas: Oil and Gas Reserve Estimation and Disclosure (Topic 932),” which aligns U.S. GAAP with the Security and Exchange Commission’s (“SEC”) final rule on the “Modernization of Oil and Gas Reporting.” The FASB and 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 the new requirements 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 and ASU No. 2010-03; however, we are not able to disclose the impact of these new 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.

In January 2010, the FASB issued ASU 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 in 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, except ASU No. 2010-17’s impact on the Power segment as described in Items 1 and 2, preceding.

## 19. Quarterly Financial Data (Unaudited)

<table><tr><td rowspan="3"></td><td colspan="5">Three Months Ended</td></tr><tr><td>March 31, 2009</td><td>June 30, 2009</td><td>September 30, 2009</td><td>December 31, 2009</td><td></td></tr><tr><td colspan="5">(In millions)</td></tr><tr><td>Revenues</td><td>$ 1,828.9</td><td>$ 1,693.3</td><td>$ 1,712.3</td><td>$ 1,950.7</td><td></td></tr><tr><td>Operating income</td><td>$ 309.9</td><td>$ 346.7</td><td>$ 391.2</td><td>$ 359.4</td><td></td></tr><tr><td>Income from continuing operations before income taxes</td><td>$ 225.7</td><td>$ 275.4</td><td>$ 329.1</td><td>$ 269.2</td><td></td></tr><tr><td>Income from continuing operations</td><td>$ 145.1</td><td>$ 208.4</td><td>$ 229.5</td><td>$ 190.8</td><td></td></tr><tr><td>Net income</td><td>$ 144.9</td><td>$ 209.1</td><td>$ 229.4</td><td>$ 190.7</td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>$ 29.6</td><td>$ 79.3</td><td>$ 106.6</td><td>$ 62.6</td><td></td></tr><tr><td>Net income attributable to Kinder Morgan, Inc.</td><td>$ 115.3</td><td>$ 129.8</td><td>$ 122.8</td><td>$ 128.1</td><td></td></tr></table>

<table><tr><td rowspan="3"></td><td colspan="5">Three Months Ended</td></tr><tr><td>March 31, 2008</td><td>June 30, 2008</td><td>September 30, 2008</td><td>December 31, 2008</td><td></td></tr><tr><td colspan="5">(In millions)</td></tr><tr><td>Revenues</td><td>$ 2,895.0</td><td>$ 3,560.5</td><td>$ 3,296.6</td><td>$ 2,342.7</td><td></td></tr><tr><td>Operating income (loss)</td><td>$ 476.2</td><td>$ (3,638.1)</td><td>$ 398.3</td><td>$ 291.5</td><td></td></tr><tr><td>Income (loss) from continuing operations before income taxes</td><td>$ 319.1</td><td>$ (3,714.5)</td><td>$ 303.6</td><td>$ 193.8</td><td></td></tr><tr><td>Income (loss) from continuing operations</td><td>$ 232.0</td><td>$ (3,733.9)</td><td>$ 215.7</td><td>$ 83.9</td><td></td></tr><tr><td>Net income (loss)</td><td>$ 231.9</td><td>$ (3,734.2)</td><td>$ 215.5</td><td>$ 83.6</td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>$ 126.2</td><td>$ 126.4</td><td>$ 106.8</td><td>$ 36.7</td><td></td></tr><tr><td>Net income (loss) attributable to Kinder Morgan, Inc.</td><td>$ 105.7</td><td>$ (3,860.6)</td><td>$ 108.7</td><td>$ 46.9</td><td></td></tr></table>



## 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 Kinder Morgan Energy Partners own interests as of December 31, 2009. These oil and gas producing fields 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 it has a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by Kinder Morgan Energy Partners:

<table><tr><td colspan="3">Productive Wells (a)</td><td colspan="3">Service Wells (b)</td><td colspan="2">Drilling Wells (c)</td></tr><tr><td></td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td></td></tr><tr><td>Crude Oil</td><td>2,290</td><td>1,423</td><td>983</td><td>759</td><td>4</td><td>4</td><td></td></tr><tr><td>Natural Gas</td><td>5</td><td>2</td><td>31</td><td>15</td><td>-</td><td>-</td><td></td></tr><tr><td>Total Wells</td><td>2,295</td><td>1,425</td><td>1,014</td><td>774</td><td>4</td><td>4</td><td></td></tr></table>

(a) Includes active wells and wells temporarily shut-in. As of December 31, 2009, Kinder Morgan Energy Partners 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 net productive and dry wells that were completed in each of the three years ended December 31, 2009, 2008 and 2007:

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Productive</td><td></td><td></td><td></td></tr><tr><td>Development</td><td>42</td><td>47</td><td>31</td></tr><tr><td>Exploratory</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Dry</td><td></td><td></td><td></td></tr><tr><td>Development</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Exploratory</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total Wells</td><td>42</td><td>47</td><td>31</td></tr></table>

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 reservoir.

The following table reflects the developed and undeveloped oil and gas acreage that were held as of December 31, 2009:

<table><tr><td></td><td>Gross</td><td>Net</td></tr><tr><td>Developed Acres</td><td>72,435</td><td>67,748</td></tr><tr><td>Undeveloped Acres</td><td>9,715</td><td>9,056</td></tr><tr><td>Total</td><td>82,150</td><td>76,804</td></tr></table>



## Operating Statistics

Operating statistics from Kinder Morgan Energy Partners’ 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

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td></tr><tr><td>Production costs per barrel of oil equivalent(b)(c)(d)</td><td>$ 11.44</td><td>$ 15.70</td><td>$ 12.84</td></tr><tr><td>Crude oil production (MBbl/d)</td><td>37.4</td><td>36.2</td><td>35.6</td></tr><tr><td>SACROC crude oil production (MBbl/d)</td><td>25.1</td><td>23.3</td><td>23.0</td></tr><tr><td>Yates crude oil production (MBbl/d)</td><td>11.8</td><td>12.3</td><td>12.0</td></tr><tr><td>Natural gas liquids production (MBbl/d)(d)</td><td>5.4</td><td>4.8</td><td>5.5</td></tr><tr><td>Natural gas liquids production from gas plants(MBbl/d)(e)</td><td>4.0</td><td>3.5</td><td>4.1</td></tr><tr><td>Total natural gas liquids production(MBbl/d)</td><td>9.5</td><td>8.3</td><td>9.6</td></tr><tr><td>SACROC natural gas liquids production (MBbl/d)(d)</td><td>5.3</td><td>4.6</td><td>5.2</td></tr><tr><td>Yates natural gas liquids production (MBbl/d)(d)</td><td>0.1</td><td>0.2</td><td>0.2</td></tr><tr><td>Natural gas production (MMcf/d)(d)(f)</td><td>0.9</td><td>1.4</td><td>0.8</td></tr><tr><td>Natural gas production from gas plants(MMcf/d)(e)(f)</td><td>0.7</td><td>0.2</td><td>0.3</td></tr><tr><td>Total natural gas production(MMcf/d)(f)</td><td>1.6</td><td>1.6</td><td>1.1</td></tr><tr><td>Yates natural gas production (MMcf/d)(d)(f)</td><td>0.8</td><td>1.3</td><td>0.7</td></tr><tr><td>Average sales prices including hedge gains/losses:</td><td></td><td></td><td></td></tr><tr><td>Crude oil price per Bbl(g)</td><td>$ 49.55</td><td>$ 49.42</td><td>$ 36.05</td></tr><tr><td>Natural gas liquids price per Bbl(g)</td><td>$ 37.70</td><td>$ 63.48</td><td>$ 52.22</td></tr><tr><td>Natural gas price per Mcf(h)</td><td>$ 3.45</td><td>$ 7.73</td><td>$ 6.08</td></tr><tr><td>Total natural gas liquids price per Bbl(e)</td><td>$ 37.96</td><td>$ 63.00</td><td>$ 52.91</td></tr><tr><td>Total natural gas price per Mcf(e)</td><td>$ 3.53</td><td>$ 7.63</td><td>$ 5.89</td></tr><tr><td>Average sales prices excluding hedge gains/losses:</td><td></td><td></td><td></td></tr><tr><td>Crude oil price per Bbl(g)</td><td>$ 59.03</td><td>$ 97.70</td><td>$ 69.63</td></tr><tr><td>Natural gas liquids price per Bbl(g)</td><td>$ 37.70</td><td>$ 63.48</td><td>$ 52.22</td></tr><tr><td>Natural gas price per Mcf(h)</td><td>$ 3.45</td><td>$ 7.73</td><td>$ 6.08</td></tr></table>

(a) Amounts relate to Kinder Morgan CO \( _{2} \)  Company, L.P. and its consolidated subsidiaries.

(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 Kinder Morgan Energy Partners' 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.

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.



Capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing Activities

<table><tr><td rowspan="2"></td><td colspan="4">As of December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td></td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Wells and equipment, facilities and other</td><td>$ 2,920.7</td><td>$ 2,595.4</td><td>$ 2,081.3</td><td></td></tr><tr><td>Leasehold</td><td>433.5</td><td>429.8</td><td>449.3</td><td></td></tr><tr><td>Total proved oil and gas properties</td><td>3,354.2</td><td>3,025.2</td><td>2,530.6</td><td></td></tr><tr><td>Accumulated depreciation and depletion</td><td>(1,764.0)</td><td>(1,155.6)</td><td>(787.6)</td><td></td></tr><tr><td>Net capitalized costs</td><td>$ 1,590.2</td><td>$ 1,869.6</td><td>$ 1,743.0</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan  \( CO_{2} \)  Company, L.P. and its consolidated subsidiaries. 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.

The costs incurred for property acquisition, exploration and development were as follows (in millions):

Costs Incurred in Exploration, Property Acquisitions and Development

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td rowspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td>Seven Months Ended December 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Property Acquisition</td><td></td><td></td><td></td><td></td></tr><tr><td>Proved oil and gas properties</td><td>$ 5.3</td><td>$ -</td><td>$ -</td><td>$ -</td></tr><tr><td>Development</td><td>330.3</td><td>495.2</td><td>156.9</td><td>87.5</td></tr></table>

(a) Amounts relate to Kinder Morgan  \( CO_{2} \)  Company, L.P. and its consolidated subsidiaries. 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.

Kinder Morgan Energy Partners' results of operations from oil and gas producing activities are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing Activities

<table><tr><td rowspan="2"></td><td colspan="3">Successor Company</td><td rowspan="2">Predecessor Company</td></tr><tr><td colspan="2">Year Ended December 31,</td><td>Seven Months Ended December 31,</td></tr><tr><td></td><td>2009</td><td>2008</td><td>2007</td><td>Five Months Ended May 31, 2007</td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues(b)</td><td>$ 767.0</td><td>$ 785.5</td><td>$ 352.0</td><td>$ 237.7</td></tr><tr><td>Expenses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Production costs(c)</td><td>188.8</td><td>308.4</td><td>147.2</td><td>96.7</td></tr><tr><td>Other operating expense</td><td>53.3</td><td>99.0</td><td>34.9</td><td>22.0</td></tr><tr><td>Depreciation, depletion and amortization expenses</td><td>441.4</td><td>342.2</td><td>151.9</td><td>106.6</td></tr><tr><td>Total expenses</td><td>683.5</td><td>749.6</td><td>334.0</td><td>225.3</td></tr><tr><td>Results of operations for oil and gas producing activities</td><td>$ 83.5</td><td>$ 35.9</td><td>$ 18.0</td><td>$ 12.4</td></tr></table>

(a) Amounts relate to Kinder Morgan CO₂ Company, L.P. and its consolidated subsidiaries.

(b) Revenues include losses attributable to Kinder Morgan Energy Partners' hedging contracts of $129.5 million, $693.3 million, $311.5 million and $122.7 million for the years ended December 31, 2009 and 2008, seven months ended December 31, 2007 and five months ended May 31, 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.

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 CO \( _{2} \)  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 its reserve estimates are made by independent 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 the  \( CO_{2} \) -KMP business segment managers and the Vice President (President,  \( CO_{2} \) -KMP) reviews all significant reserves changes and all new proved developed and undeveloped reserves additions; and

• our  \( CO_{2} \) -KMP business segment reports independently of our other six 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 reported 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 Kinder Morgan Energy Partner operated properties only, regardless of its net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this report exceeds 5%.



## Reserve Quantity Information

<table><tr><td rowspan="2"></td><td colspan="3">Consolidated Companies(a)</td></tr><tr><td>Crude Oil (MBbls)</td><td>NGLs (MBbls)</td><td>Natural Gas (MMcf)(b)</td></tr><tr><td>Proved developed and undeveloped reserves:</td><td></td><td></td><td></td></tr><tr><td>As of December 31, 2006</td><td>123,978</td><td>10,333</td><td>291</td></tr><tr><td>Revisions of previous estimates(c)</td><td>10,361</td><td>2,784</td><td>1,077</td></tr><tr><td>Production</td><td>(12,984)</td><td>(2,005)</td><td>(290)</td></tr><tr><td>As of December 31, 2007</td><td>121,355</td><td>11,112</td><td>1,078</td></tr><tr><td>Revisions of previous estimates(d)</td><td>(29,536)</td><td>(2,490)</td><td>695</td></tr><tr><td>Production</td><td>(13,240)</td><td>(1,762)</td><td>(499)</td></tr><tr><td>As of December 31, 2008</td><td>78,579</td><td>6,860</td><td>1,274</td></tr><tr><td>Revisions of previous estimates(e)</td><td>15,900</td><td>1,018</td><td>(293)</td></tr><tr><td>Production</td><td>(13,688)</td><td>(1,995)</td><td>(298)</td></tr><tr><td>Purchases of reserves in place</td><td>53</td><td>37</td><td>15</td></tr><tr><td>As of December 31, 2009</td><td>80,844</td><td>5,920</td><td>698</td></tr><tr><td>Proved developed reserves:</td><td></td><td></td><td></td></tr><tr><td>As of December 31, 2006</td><td>69,073</td><td>5,877</td><td>291</td></tr><tr><td>As of December 31, 2007</td><td>70,868</td><td>5,517</td><td>1,078</td></tr><tr><td>As of December 31, 2008</td><td>53,346</td><td>4,308</td><td>1,274</td></tr><tr><td>As of December 31, 2009</td><td>47,058</td><td>2,665</td><td>698</td></tr><tr><td>Proved undeveloped reserves:</td><td></td><td></td><td></td></tr><tr><td>As of December 31, 2006</td><td>54,905</td><td>4,456</td><td>-</td></tr><tr><td>As of December 31, 2007</td><td>50,487</td><td>5,595</td><td>-</td></tr><tr><td>As of December 31, 2008</td><td>25,233</td><td>2,552</td><td>-</td></tr><tr><td>As of December 31, 2009</td><td>33,786</td><td>3,255</td><td>-</td></tr></table>

(a) Amounts relate to Kinder Morgan CO \( _{2} \)  Company, L.P. and its consolidated subsidiaries.

(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.



The 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

<table><tr><td rowspan="2"></td><td colspan="4">As of December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td></td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows from production</td><td>$ 4,898.0</td><td>$ 3,498.0</td><td>$ 12,099.5</td><td></td></tr><tr><td>Future production costs</td><td>(1,951.5)</td><td>(1,671.6)</td><td>(3,536.2)</td><td></td></tr><tr><td>Future development costs(b)</td><td>(1,179.7)</td><td>(910.3)</td><td>(1,919.2)</td><td></td></tr><tr><td>Undiscounted future net cash flows</td><td>1,766.8</td><td>916.1</td><td>6,644.1</td><td></td></tr><tr><td>10% annual discount</td><td>(503.5)</td><td>(257.7)</td><td>(2,565.7)</td><td></td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 1,263.3</td><td>$ 658.4</td><td>$ 4,078.4</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan CO \( _{2} \)  Company, L.P. and its consolidated subsidiaries.

(b) Includes abandonment costs.

The following table represents the 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

<table><tr><td rowspan="2"></td><td colspan="4">As of December 31,</td></tr><tr><td>2009</td><td>2008</td><td>2007</td><td></td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Present value as of January 1</td><td>$ 658.4</td><td>$ 4,078.4</td><td>$ 2,207.8</td><td></td></tr><tr><td>Changes during the year:</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues less production and other costs(b)</td><td>(652.7)</td><td>(1,012.4)</td><td>(722.1)</td><td></td></tr><tr><td>Net changes in prices, production and other costs(b)</td><td>915.7</td><td>(3,076.9)</td><td>2,153.2</td><td></td></tr><tr><td>Development costs incurred</td><td>330.3</td><td>495.2</td><td>244.5</td><td></td></tr><tr><td>Net changes in future development costs</td><td>(445.4)</td><td>231.1</td><td>(547.8)</td><td></td></tr><tr><td>Purchases of reserves in place</td><td></td><td></td><td>-</td><td></td></tr><tr><td>Revisions of previous quantity estimates(c)</td><td>391.1</td><td>(417.1)</td><td>510.8</td><td></td></tr><tr><td>Accretion of discount</td><td>65.9</td><td>392.9</td><td>198.1</td><td></td></tr><tr><td>Timing differences and other</td><td>-</td><td>(32.8)</td><td>33.9</td><td></td></tr><tr><td>Net change for the year</td><td>604.9</td><td>(3,420.0)</td><td>1,870.6</td><td></td></tr><tr><td>Present value as of December 31</td><td>$ 1,263.3</td><td>$ 658.4</td><td>$ 4,078.4</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan CO \( _{2} \)  Company, L.P. and its consolidated subsidiaries.

(b) Excludes the effect of losses attributable to Kinder Morgan Energy Partners' 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 predominantly due to lower product prices used to determine reserve volumes. 2007 revisions are associated with an expansion of the carbon dioxide flood project area for the SACROC unit.



## 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, INC.

(Registrant)

By /s/ Kimberly A. Dang

Kimberly A. Dang

Vice President and Chief Financial Officer

Date: March 5, 2010

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities set forth below and as of the date set forth above.

/s/ Kimberly A. Dang
Vice President and Chief Financial Officer (Principal

Kimberly A. Dang

Financial Officer and Principal Accounting Officer)

/s/ Richard D. Kinder
Director, Chairman and Chief Executive Officer

Richard D. Kinder

Director, Chairman and Chief Executive Officer

/s/ Kenneth A. Pontarelli
Director

Kenneth A. Pontarelli

/s/ C. Park Shaper
Director

C. Park Shaper