Kinder Morgan, Inc. (KMI, NYSE)
Industry: Oil & Gas Midstream
Annual report, fiscal year 2012


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

Form 10-K

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

For the fiscal year ended December 31, 2012

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: 001-35081



Kinder Morgan, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)

80-0682103
(I.R.S. Employer Identification No.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices) (zip code)

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

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

Title of each class
Class P Common Stock
Warrants to Purchase Class P Common Stock

Name of each exchange on which registered
New York Stock Exchange
New York Stock Exchange

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

None

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

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

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 ☐

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 ( \( § $ 232.405 of this chapter) 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(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑

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

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 29, 2012 was approximately $16,375,009,661. This value is based on our Class P shares held by non-affiliates as of June 30, 2012, because the market value of our class A, Class B and Class C shares, which were not publicly traded but were outstanding as of June 30, 2012, was not readily determinable. As of January 31, 2013, the registrant had 1,035,669,044 Class P shares outstanding and no Class A, Class B or Class C shares outstanding.



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

PART I
Items 1. and 2. Business and Properties
General Development of Business
Organizational Structure
Recent Developments
Financial Information about Segments
Narrative Description of Business
Business Strategy
Business Segments
Natural Gas Pipelines
Products Pipelines—KMP
CO2—KMP
Terminals—KMP
Kinder Morgan Canada—KMP
Other
Major Customers
Regulation
Environmental Matters
Other
Financial Information about Geographic Areas
Available Information
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
Critical Accounting Policies and Estimates
Results of Operations
Income Taxes—Continuing Operations
Liquidity and Capital Resources
Recent Accounting Pronouncements
Information Regarding Forward-Looking Statements
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Energy Commodity Market Risk
Interest Rate Risk
Item 8. Financial Statements and Supplementary Data



Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 93
Item 9A. Controls and Procedures 93
Item 9B. Other Information 94

PART III
Item 10. Directors, Executive Officers and Corporate Governance 95
Item 11. Executive Compensation 95
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 95
Item 13. Certain Relationships and Related Transactions, and Director Independence 95
Item 14. Principal Accounting Fees and Services 95

PART IV
Item 15. Exhibits, Financial Statement Schedules 96
Index to Financial Statements 101
Signatures 214



## PART I

## Items 1 and 2. Business and Properties.

Kinder Morgan, Inc. is the largest midstream and the third largest energy company in North America with a combined enterprise value (including its two publicly traded master limited partnership subsidiaries) of approximately $100 billion and unless the context requires otherwise, references to “we,” “us,” “our,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. We own an interest in or operate approximately 75,000 miles of pipelines and 180 terminals. Our pipelines transport natural gas, gasoline, crude oil, CO \( _{2} \)  and other products, and our terminals store petroleum products and chemicals and handle such products as ethanol, coal, petroleum coke and steel. Our common stock trades on the New York Stock Exchange under the symbol “KMI.”

Effective on May 25, 2012, we completed the acquisition of all of the outstanding shares of El Paso Corporation, referred to as “EP.” EP owns one of North America’s largest interstate natural gas pipeline systems and an emerging midstream business. EP also owns a 41% limited partner interest and the 2% general partner interest in El Paso Pipeline Partners, L.P. referred to as “EPB,” as well as certain natural gas pipeline assets.

In connection with our acquisition of EP, we issued approximately 330 million shares of common stock and approximately 505 million warrants to purchase our common stock and paid approximately $11.6 billion in cash to former EP stockholders and equity award holders. Each warrant entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017 (see Notes 3 and 10 to our consolidated financial statements included elsewhere in this report).

We also own the general partner and approximately 11% of the limited partner interests of Kinder Morgan Energy Partners, L.P., referred to as “KMP,” one of the largest publicly-traded pipeline limited partnerships in America.

## (a) General Development of Business

## Organizational Structure

On February 10, 2011, we converted from a Delaware limited liability company named Kinder Morgan Holdco LLC to a Delaware corporation named Kinder Morgan, Inc. and our outstanding units were converted into classes of our capital stock. These transactions are referred to herein as the “Conversion Transaction.” On February 16, 2011, we completed the initial public offering of our Class P common stock, which is sometimes referred to herein as our “common stock.” All of the common stock that was sold in the offering was sold by our existing investors consisting of funds advised by or affiliated with Goldman Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC, referred to herein as the “Sponsor Investors.” No members of management sold shares in the offering, and we did not receive any proceeds from the offering.

Upon the completion of our initial public offering of Class P common stock we were owned by the public, and by individuals and entities that were the owners of Kinder Morgan Holdco LLC, which are referred to collectively in this report as the “Investors.” The Investors were Richard D. Kinder, our Chairman and Chief Executive Officer; the Sponsor Investors; Fayez Sarofim, one of our directors, and investment entities affiliated with him, and an investment entity affiliated with Michael C. Morgan, another of our directors, and William V. Morgan, one of our founders, whom we refer to collectively as the “Original Stockholders”; and a number of other members of our management, who are referred to collectively as “Other Management.”

The Investors owned all of our outstanding Class A shares, Class B shares and Class C shares, which are sometimes referred to in this report as the “investor retained stock.” Our Class A shares represented the total capital contributed by the Investors (and a notional amount of capital allocated to the contribution of the holders of the Class C shares) at the time of the Going Private Transaction. The Class B shares and Class C shares represented incentive compensation that were held by members of our management, including Mr. Kinder only in the case of the Class B shares.

During the year ended December 31, 2012, certain of the Sponsor Investors (the Selling Stockholders) completed underwritten public offerings (the Offerings) of an aggregate of 198,996,921 shares of our Class P common stock (including 8,700,000 shares that were the subject of an underwriters' option to purchase additional shares). Neither we nor our management sold any shares of common stock in the Offerings, and we did not receive any of the proceeds from the offerings of shares by the Selling Stockholders. As a result of these offerings, the Sponsor Investors advised by or affiliated with



## Items 1 and 2. Business and Properties. (continued)

Goldman Sachs & Co., The Carlyle Group, and Riverstone Holdings LLC no longer own any of our shares, and representatives of these Sponsor Investors are no longer on our board.

On December 26, 2012, the remaining series of the Class A, Class B and Class C shares held by the Investors automatically converted into shares of Class P common stock upon the election of the holders of at least two-thirds of the shares of each such series of Class A common stock and the holders of at least two-thirds of the shares of each such series of Class B common stock. Subsequent to these conversions, all our Class A, Class B and Class C shares were fully converted and as a result, only our Class P common stock was outstanding as of December 31, 2012. Additionally, as Class A, Class B and Class C shares converted, certain holders of the Class P shares were paid out in cash and their Class P shares were immediately canceled. During the years ended December 31, 2012 and 2011, approximately 2 million and less than 1 million, respectively, Class P shares were canceled resulting in payments totaling approximately $71 million and $2 million, respectively, to the holders of those shares.

We conduct most of our business through our master limited partnerships (KMP and EPB). KMP is a Delaware limited partnership formed in August 1992, and its common units are listed on the New York Stock Exchange under the symbol "KMP." Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company formed in February 2001. KMP's general partner, Kinder Morgan G.P., Inc., owns all of KMR's voting securities. Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has delegated to KMR, to the fullest extent permitted under Delaware law and KMP's partnership agreement, all of its power and authority to manage and control KMP's business and affairs, except that KMR cannot take certain specified actions without the approval of KMP's general partner. KMR's shares representing limited liability company interests are listed on the New York Stock Exchange under the symbol "KMR." EPB is a Delaware limited partnership formed in 2007, and its common units are listed on the New York Stock Exchange under the symbol "EPB." EPB's general partner is El Paso Pipeline GP Company, L.L.C., all of whose stock we indirectly own.

The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public are reflected within “noncontrolling interests” in our accompanying consolidated balance sheets. The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares, respectively, held by the public are reported as noncontrolling interests” in our accompanying consolidated statements of income.

Additional information concerning the business of, and our investment in and obligations to, KMP, EPB and KMR is contained in Notes 2 and 10 to our consolidated financial statements included elsewhere in this report and KMP's, EPB's and KMR's individual Annual Report on Form 10-K for the year ended December 31, 2012.

You should read the following in conjunction with our audited consolidated financial statements and the notes thereto included elsewhere in this report. We have prepared our accompanying consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission (SEC). Our accounting records are maintained in United States (U.S.) dollars and all references to dollars in this report are U.S. dollars, except where stated otherwise. Canadian dollars are designated as C$. Our consolidated financial statements include our accounts and those of our majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive offices is 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000.

## Recent Developments

The following is a brief listing of significant developments since December 31, 2011. We begin with developments pertaining to our reportable business segments. Additional information regarding most of these items may be found elsewhere in this report.

Natural Gas Pipelines

KMP

- Effective November 1, 2012, we sold KMP's FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, L.P. for approximately $1.8 billion (before selling costs), or $3.3 billion including our share of joint venture debt, to satisfy terms of a March 15, 2012 agreement with the U.S. Federal Trade Commission (FTC) to divest certain of KMP's assets in order to receive regulatory approval for our EP acquisition. KMP's FTC Natural Gas Pipelines disposal group's assets included (i) Kinder Morgan Interstate Gas Transmission natural gas pipeline system; (ii) Trailblazer natural gas pipeline system; (iii) Casper and Douglas natural gas processing operations; and (iv) 50% equity investment in the Rockies Express natural gas pipeline system. In this report, we refer to this combined group of assets as KMP's FTC Natural Gas Pipelines disposal group. During 2012, we recognized a combined $937 million loss from both the



## Items 1 and 2. Business and Properties. (continued)

remeasurement and sale of net assets. Pursuant to current accounting principles, we reclassified and reported the FTC Natural Gas Pipelines disposal group's results of operations as discontinued operations for all periods presented in this report. For more information about this divestiture, see Note 3 to our consolidated financial statements included elsewhere in this report;

- On June 1, 2012, KMP acquired a 50% equity ownership interest in El Paso Midstream Investment Company, LLC, referred to in this report as EPMIC, from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. for an aggregate consideration of $289 million in common units. The remaining 50% of the joint venture we acquired as part of our acquisition of EP on May 25, 2012. EPMIC owns the Altamont natural gas gathering, processing and treating assets located in the Unita Basin in Utah, and the Camino Real natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas. Additionally, we have offered to sell both our 50% ownership interest in EPMIC and our 50% ownership interest in the El Paso Natural Gas pipeline system (discussed following) to KMP in 2013 (in a future drop-down transaction);

- On August 1, 2012, KMP acquired the full ownership interest in the Tennessee Gas natural gas pipeline system and a 50% ownership interest in the El Paso Natural Gas pipeline system from us for an aggregate consideration of approximately $6.2 billion, consisting of the combined amount of cash paid, common units issued and debt assumed. In this report, we refer to transfer of assets from us to KMP as the drop-down transaction, the combined group of assets acquired from us as the drop-down asset group, the Tennessee Gas natural gas pipeline system or Tennessee Gas Pipeline Company, L.L.C. as TGP, and the El Paso Natural Gas pipeline system or El Paso Natural Gas Pipeline Company, LLC as EPNG.

We acquired the drop-down asset group as part of the EP acquisition on May 25, 2012, and current accounting principles require us to account for the drop-down transaction as a transfer of net assets between entities under common control. Accordingly, we prepared our consolidated financial statements and the related financial information contained in this report to reflect the transfer of the drop-down asset group from us to KMP as if such transfer had taken place on May 25, 2012. For further information about the drop-down transaction, see Note 3 to our consolidated financial statements included elsewhere in this report;

- On October 1, 2012, following approval by the Federal Energy Regulatory Commission (FERC), TGP placed in service a portion of its approximately $55 million Northeast Supply Diversification project to support interim customer capacity requirements. The fully subscribed project provides a bi-directional meter on the Niagara Spur with approximately six miles of pipeline looping on TGP's system. Fully placed in service in November 2012, the project creates an additional approximately 245 million cubic feet per day of firm service capacity from the Marcellus shale region along TGP's system to serve existing markets in New England and the Niagara Falls area of New York;

- On October 10, 2012, TGP filed a certificate application with the FERC, proposing its Rose Lake expansion project, which would provide long-term firm natural gas transportation service for two shippers that have fully subscribed approximately 225 million cubic feet per day of firm capacity offered in TGP's Zone 4 in Pennsylvania. The capacity was offered in a binding open season held in the summer of 2012. TGP proposes to retire older compressor units, add new, more efficient and cleaner burning units, and make other modifications involving three existing compressor stations that serve its 300 Line, all located in northeastern Pennsylvania. The anticipated in service date for the approximately $92 million project is November 1, 2014;

- In the fourth quarter of 2012, KMP's wholly owned subsidiary, Sierra's Gas Pipeline LLC (a newly created interstate natural gas pipeline company) entered into a 25-year transportation agreement in connection with plans to build a new pipeline to serve customers in Mexico. Pursuant to the terms of the agreement, Sierra's will construct new facilities that will initially provide approximately 200 million cubic feet per day of firm natural gas transportation capacity via a new, 60-mile, 36-inch diameter lateral pipeline that would extend from EPNG's existing south mainlines (near the City of Tucson, Arizona) to the U.S.-Mexico border (near the town of Sasabe, Arizona). The proposed $200 million Sierra's Gas pipeline would interconnect with a new 36-inch diameter natural gas pipeline to be built in Mexico. Sierra's Gas Pipeline LLC filed an application with the FERC on February 7, 2013, and subject to FERC approval, we expect that construction of the Sierra's pipeline would begin in the first quarter of 2014. We anticipate that the pipeline would be placed into service in the fall of 2014;

- In December 2012, TGP received notices to proceed from the FERC for its proposed approximately $86 million Marcellus Pooling project. The fully subscribed project will provide approximately 240 million cubic feet per day of additional firm transportation capacity from the prolific Marcellus natural gas shale formation. The expansion includes approximately eight miles of 30-inch diameter pipeline looping, system modifications and upgrades to allow bi-directional flow at four existing compressor stations in Pennsylvania. Construction is anticipated to occur primarily this



## Items 1 and 2. Business and Properties. (continued)

summer and the project is expected to be in service in November of 2013;

- In December 2012, TGP received notices to proceed from the FERC for portions of its proposed approximately $450 million Northeast Upgrade project and, in January 2013, the FERC issued an order denying rehearing of the certificate order and denying requests for stay of the construction. Following issuance of the rehearing order, the U.S. Court of Appeals for the District of Columbia denied motions to stay the FERC certificate and rehearing orders in two separate appeals in February 2013, and authorized construction activities for the project are continuing. The two appeals of the certificate and rehearing orders (which are now consolidated) remain pending before the DC Circuit, but construction activities will continue as those appeals are considered. The Pennsylvania Environmental Hearing Board in January 2013 denied a petition to stay permits for the project issued by the Pennsylvania Department of Environmental Protection, and the U.S. District Court for the Middle District of Pennsylvania issued a preliminary injunction in favor of TGP and enjoining further consideration of the appeal of the permits in February 2013. Additional approvals for the remaining construction activities in both Pennsylvania and New Jersey are currently pending, however, we anticipate that construction of the mainline pipeline and compressor stations will begin in spring 2013. The fully subscribed project will boost system capacity by approximately 636 million cubic feet per day via five segment loops and system upgrades at four existing compressor stations, and will provide for additional takeaway capacity from the Marcellus shale formation. With no stay of construction granted, and subject to receipt of final FERC and other regulatory agency approval, we expect to complete construction and place the project into service in November 2013; and

- On January 29, 2013, KMP and Copano Energy, L.L.C., referred to in this report as Copano, announced a definitive agreement whereby KMP has agreed to acquire all of Copano's outstanding units, including convertible preferred units, for a total purchase price of approximately $5 billion, including the assumption of debt. The transaction, which has been approved by the board of directors of Kinder Morgan G.P., Inc., KMP's general partner, and the board of directors of Copano, will be a 100% unit for unit transaction with an exchange ratio of 0.4563 KMP common units per each Copano common unit. The transaction is subject to customary closing conditions, regulatory approvals, and a vote of the Copano unitholders. TPG Advisors VI, Inc., Copano's largest unitholder, has agreed to support the transaction, and we expect the transaction to close in the third quarter of 2013.

Copano is a midstream natural gas company that provides comprehensive services to natural gas producers, including natural gas gathering, processing, treating and natural gas liquids fractionation. Copano owns an interest in or operates approximately 6,900 miles of pipelines with 2.7 billion cubic feet per day of natural gas transportation capacity, and also owns nine natural gas processing plants with more than 1.0 billion cubic feet per day of natural gas processing capacity and 315 million cubic feet per day of natural gas treating capacity. Its operations are located primarily in Texas, Oklahoma and Wyoming.

The acquisition of Copano is expected to be accretive to cash available for distribution to KMP’s unitholders, and it is expected to be accretive to our cash available to pay dividends, upon closing. We, as the parent of KMP’s general partner, have agreed to forego a portion of our incremental incentive distributions in 2013 in an amount dependent on the time of closing. Additionally, we intend to forego $120 million in 2014, $120 million in 2015, $110 million in 2016 and annual amounts thereafter decreasing by $5 million per year. The transaction is expected to be modestly accretive to KMP in 2013, given the partial year, and about $0.10 per unit accretive for at least the next five years beginning in 2014.

## EPB

- On May 24, 2012, EPB acquired from EP the remaining 14% interest in Colorado Interstate Gas Company, L.L.C. and all of Cheyenne Plains Investment Company, L.L.C., and Cheyenne Plains Gas Pipeline Company, L.L.C., which we refer to in this report as CIG, CPI and CPG, respectively. CPI owns CPG. CPG is a pipeline system that extends from the Cheyenne hub in Weld County, Colorado and extends southerly to a variety of delivery locations in the vicinity of the Greensburg Hub in Kiowa County, Kansas. CPG provides pipeline take-away capacity from the natural gas basins in the Central Rocky Mountain area to the major natural gas markets in the Mid-Continent region; and

- On January 28, 2013, Shell US Gas & Power and Southern Liquefaction Company, L.L.C., a subsidiary of EPB, announced their intent to develop a natural gas liquefaction plant through a joint venture, Elba Liquefaction Company (Elba Liquefaction). The project will occur in two phases at EPB's existing Elba terminal near Savannah, Georgia. Subject to various corporate and regulatory approvals, Elba Liquefaction has agreed to modify EPB's Elba Express Pipeline and Elba Island LNG terminal to physically transport natural gas to the terminal and load the liquefied natural gas (LNG) onto ships for export. Once finalized, EPB affiliates will own 51% of the venture and be its operator and Shell affiliates will own the remaining 49% and contract for 100% of the liquefaction capacity.



## Items 1 and 2. Business and Properties. (continued)

## Products Pipelines-KMP

- In August 2012, KMP and Valero Energy Corporation began construction on their previously announced Parkway Pipeline, a new 141-mile, 16-inch diameter pipeline, which is expected to cost $220 million, that will transport refined petroleum products from refineries located in Norco, Louisiana, to Plantation Pipe Line Company's (KMP's approximately 51%-owned equity investee) petroleum transportation hub located in Collins, Mississippi. KMP has substantially completed the Lake Pontchartrain portion of the pipeline, and construction activities continue on land in Louisiana and Mississippi. Upon completion, KMP will operate and own a 50% equity interest in the Parkway Pipeline, which will have an initial capacity of 110,000 barrels per day, with the ability to expand to over 200,000 barrels per day. The pipeline project is supported by a long-term throughput agreement with a credit-worthy shipper and is scheduled to be in service in September 2013;

- On August 23, 2012, KMP announced that it would invest approximately $90 million to build a 27-mile, 12-inch diameter lateral pipeline that will extend its Kinder Morgan crude oil/condensate pipeline to Phillips 66's Sweeny refinery located in Brazoria County, Texas. KMP will provide Phillips 66 with a significant portion of the lateral's initial capacity of 30,000 barrels per day, which is expandable to 100,000 barrels per day. KMP will also add associated receipt facilities by constructing a five-bay truck offloading facility and three new storage tanks with approximately 360,000 barrels of crude oil/condensate capacity at stations located in DeWitt and Wharton counties in Texas. KMP began construction in December 2012, and expects to place the lateral into service in the second quarter of 2013;

- In October 2012, KMP began transporting crude oil and condensate volumes on previously announced Kinder Morgan crude oil/condensate pipeline, which transports available capacity from the production area in the Eagle Ford shale gas formation in South Texas to the Houston Ship Channel. The approximately $213 million pipeline, which has a capacity of 300,000 barrels per day, was completed on time and under budget, and is supported by long-term contractual commitments. The pipeline consists of approximately 65 miles of new pipeline construction and 109 miles of converted natural gas pipeline, and it delivers product to multiple terminaling facilities that provide access to local refineries, petrochemical plants and docks along the Texas Gulf Coast;

- In December 2012, KMP completed its previously announced refined petroleum products storage expansion project at its West Coast Terminals' Carson, California products terminal. The approximately $77 million expansion project added seven storage tanks with a combined capacity of 560,000 barrels. KMP completed and placed into service the first two storage tanks in October 2011 and the remaining five tanks in the third and fourth quarters of 2012. The project was completed on budget and ahead of schedule, and all seven tanks have been leased under long-term agreements with large U.S. oil refiners. By year-end 2012, KMP also completed facility modifications to provide for the receipt, storage and blending of biodiesel at the Las Vegas, Nevada; Phoenix, Arizona; and Fresno, California terminals and began blending operations by the end of January 2013;

- KMP continues design and pre-construction activities for its approximately $200 million petroleum condensate processing facility, located near its Galena Park terminal on the Houston Ship Channel. The facility which is supported by a fee-based contract with BP North America has an anticipated throughput capacity of about 50,000 barrels per day and can be expanded to process 100,000 barrels per day. KMP expects the facility to be in service in the first quarter of 2014. Through a fee structure, BP North America is underwriting the initial throughput of the facility. In light of the growth of Eagle Ford shale NGL production and the associated need for additional condensate processing capacity, KMP expects to obtain additional customer commitments to underwrite an expansion at this facility; and

- As of the date of this report, KMP is in the final permitting stage for its previously announced Cochin Pipeline reversal project, which will allow KMP to offer a new service to move light condensate from Kankakee County, Illinois to existing terminal facilities located near Fort Saskatchewan, Alberta, Canada. KMP received more than 100,000 barrels per day of binding commitments for a minimum ten-year term during a successful open season completed in June 2012. The approximately $260 million project involves both modifying the Western leg of the Cochin Pipeline to Fort Saskatchewan from a point of interconnection with Explorer Pipeline Company's pipeline in and building a one million barrel tank farm and associated piping and interconnect with Explorer Pipeline Company's pipeline at the Kankakee County point of interconnection. Subject to the timely receipt of necessary regulatory approvals, light condensate shipments could begin as early as July 1, 2014.

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

- On January 18, 2012, KMP announced an approximately $255 million investment to expand the carbon dioxide capacity of its approximately 87%-owned Doe Canyon Deep unit in southwestern Colorado. The expansion project will include the installation of both primary and booster compression and is expected to increase Doe Canyon's production rate from



105 million cubic feet of carbon dioxide per day to 170 million cubic feet per day. As of the date of this report, construction continues on both primary and booster compression. KMP expects to complete and place in service the primary compression in the fourth quarter of 2013, and complete the booster compression in the second quarter of 2014. Additionally, KMP plans to drill approximately 19 more wells during the next ten years, with one well completed in 2012 and four more wells to be drilled in 2013; and

- On January 31, 2012, KMP acquired a carbon dioxide source field and related assets located in Apache County, Arizona, and Catron County, New Mexico from a subsidiary of Enhanced Oil Resources for $30 million in cash. The acquisition included all of Enhanced Oil's rights, title, and interest in the carbon dioxide and helium located in the St. Johns gas unit and the Cottonwood Canyon carbon dioxide unit. KMP refers to this combined group of assets as the St. Johns CO \( _{2} \)  source field, and as of the date of this report, continues to test wells and perform predevelopment activities. KMP anticipates that carbon dioxide production from this potential new source field would be transported to the Permian Basin for use by customers in tertiary oil recovery.

## Terminals-KMP

- On July 17, 2012, KMP and Peabody Energy announced that they had entered into certain long-term agreements to secure and expand the export platform for Peabody Energy's Colorado, Powder River Basin and Illinois Basin coal products. Pursuant to the provisions of these agreements, Peabody will gain additional access to export coal (i) through 2021 at KMP's Houston Bulk and Deepwater terminal facilities located near Houston and (ii) through 2020 at KMP's International Marine Terminals facility (IMT), a multi-product, import-export facility located in Myrtle Grove, Louisiana and owned 66 2/3% by KMP.

Due to the finalization of these agreements, and to previously announced coal throughput agreements with Arch Coal Company, KMP is proceeding with Phase 3 of its export coal expansion project at IMT. The project entails adding a new continuous barge unloader, a new reclaim system and an additional 5 million tons of coal storage capacity. We expect the new Phase 3 project to be operational in the second quarter 2014. We estimate KMP's share of the total expansion project at IMT (including all phases) will cost approximately $150 million. When completed, KMP's total export coal capacity (for all terminals combined) will be approximately 44.7 million short-tons per year;

- On July 19, 2012, KMP and BP North America announced the execution of a long-term lease agreement whereby BP will lease an additional 750,000 barrels of refined products capacity at KMP's Galena Park, Texas liquids terminal located on the Houston Ship Channel. BP's products will be processed at the condensate splitter that KMP is also currently building near the Galena Park facility and, in conjunction with the lease agreement, KMP agreed to build five new tanks, which will provide storage for BP's product. As of the date of this report, construction continues on the approximately $75 million investment;

- Effective December 1, 2012, TransMontaigne exercised its previously announced option to acquire up to 50% of KMP's Class A member interest in Battleground Oil Specialty Terminal Company LLC (BOSTCO). On this date, TransMontaigne acquired a 42.5% Class A member interest in BOSTCO from KMP for an aggregate consideration of $79 million, and following this acquisition, KMP now owns a 55% Class A member interest in BOSTCO (KMP sold a 2.5% Class A member interest in BOSTCO to a third party on January 1, 2012. As of the date of this report, construction continues on the previously announced approximately $430 million BOSTCO oil terminal located on the Houston Ship Channel. The first phase of the project includes construction of 52 storage tanks with a capacity of 6.5 million barrels for handling residual fuels, feedstocks, distillates and other black oils. Terminal service agreements or letters of intent have been executed with customers for almost all of the capacity. Commercial operations are expected to begin in the third quarter of 2013;

- On January 14, 2013, KMP announced an expansion project and an acquisition that will provide additional infrastructure to help meet growing demand for liquids storage and dock services along the Texas Gulf Coast. The combined investment will cost approximately $170 million will include the purchase of 42 acres of land, construction of a new ship dock to handle ocean going vessels, and construction of 1.2 million barrels of liquids storage tanks (six 150,000-barrel tanks and four 75,000-barrel tanks). KMP has entered into a letter of intent with a major oil refiner to develop the tanks with connectivity between our Galena Park liquids terminal and the refiner's Houston Ship Channel refinery. The property will be used to provide dock services for up to eight vessels a month for the refinery and up to four vessels a month for KMP's Galena Park terminal; and

- As of the date of this report, construction also continues on the previously announced Edmonton terminal expansion in Strathcona County, Alberta, Canada. The approximately $310 million phase one project entails building ten tanks with combined new merchant and system tank storage capacity of approximately 3.6 million barrels. The project is expected



## Items 1 and 2. Business and Properties. (continued)

to be fully completed in December 2013 and is underpinned by long-term commercial agreements with major Canadian oil producers. On January 23, 2013, KMP announced that it had entered into long-term contracts to support the construction of an additional 1.2 million barrels consisting of four new tanks of merchant storage capacity at the Edmonton terminal. This phase two project is scheduled to commence in the spring of 2013, following receipt of supporting permits, and KMP expects to complete construction in the late third quarter of 2014. It is estimated that this phase two project will cost approximately $112 million and, when complete, will bring total storage capacity at the Edmonton facility to 9.4 million barrels (including the existing Trans Mountain system facility and KMP's North 40 crude oil tank farm).

## Kinder Morgan Canada -KMP

- On May 23, 2012, Kinder Morgan Canada’s subsidiary, Trans Mountain Pipeline L.P., (Trans Mountain) confirmed binding commercial support for its previously announced proposed expansion of its Trans Mountain pipeline system and, on January 10, 2013, Trans Mountain updated the binding commercial support following the completion of a supplemental open season. A total of thirteen companies in the Canadian producing and oil marketing business have signed firm contracts bringing the total volume of committed shippers to approximately 710,000 barrels per day. Trans Mountain is currently in the final stages of securing approval for the commercial terms of this expansion from Canada’s National Energy Board, referred to in this report as the NEB. Failure to secure NEB approval of this project at a reasonable toll rate could require us to either delay or cancel this project. We anticipate NEB’s approval in the second quarter of 2013.

Originating in Edmonton, Alberta, Kinder Morgan Canada’s Trans Mountain system is currently designed to carry up to 300,000 barrels per day of crude oil and refined petroleum products to destinations in the northwest U.S. and on the west coast of British Columbia and based on the current confirmed shipper response, Kinder Morgan Canada would complete the construction of a twin pipeline that could boost system capacity to over 890,000 barrels per day. Trans Mountain plans to file a Facilities Application with the NEB in late 2013 to seek authorization to build and operate the necessary facilities for the expansion. This filing will initiate a comprehensive regulatory and public review of the proposed expansion. If the application is approved, construction is currently forecast to commence in 2015 or 2016 with the proposed expansion commencing operations in late 2017. The current estimate of total project construction costs is approximately $5.4 billion; and

- On December 11, 2012, Kinder Morgan Canada announced that it had entered into a definitive agreement to sell both its one-third equity ownership interest in the Express pipeline system and the subordinated debt investment in Express to Spectra Energy Corp. for approximately $380 million (before tax). The Express pipeline system is a 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 system connects Canadian and U.S. producers to refineries located in the U.S. Rocky Mountain and Midwest regions. Based on the structure of the investment with its Express-Platte partners, Kinder Morgan Canada receives approximately $15 million of cash flow on an annual basis from this investment, which is primarily debenture interest. Kinder Morgan Canada will redeploy the proceeds from this sale into various growth projects to further benefit unitholders. The transaction is subject to customary consents and regulatory approvals and is expected to close in the second quarter of 2013. In December 2012, Spectra also announced that it will acquire the remaining ownership interests in Express and, following its acquisitions, will fully own the Express pipeline system.

## Other Segment

- On January 18, 2013, we completed the sale of our equity interests in the Bolivia to Brazil Pipeline that we had acquired as part of the EP acquisition for $88 million. See Note 3 "Acquisitions and Divestitures" to our consolidated financial statements included elsewhere in this report.

## Financings

- For information about our 2012 debt offerings and retirements, see Note 8 “Debt-Changes in Debt” to our consolidated financial statements included elsewhere in this report. For information about our 2012 equity offerings, see Note 10 “Non-Controlling Interests-Contributions” to our consolidated financial statements included elsewhere in this report.



## Items 1 and 2. Business and Properties. (continued)

## 2013 Outlook

## KMP

- As KMP previously announced, it anticipates that for the year 2013 (i) it will declare cash distributions of $5.28 per unit, a 6% increase over its cash distributions of $4.98 per unit for 2012; (ii) its business segments will generate approximately $5.4 billion in earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments and its proportionate share of all non-cash depreciation, depletion and amortization expenses of certain joint ventures accounted for under the equity-method of accounting; (iii) it will distribute over $2.0 billion to its limited partners; (iv) it will produce excess cash flow of more than $30 million above its cash distribution target of $5.28 per unit; and (v) it will invest approximately $2.9 billion for its capital expansion program (including small acquisitions and contributions to joint ventures, but excluding acquisitions from us). KMP's anticipated 2013 expansion investment will help drive earnings and cash flow growth in 2013 and beyond, and it is estimated that approximately $625 million of the equity required for its 2013 investment program will be funded by cash retained as a function of distributions to KMR being paid in additional units rather than in cash.

KMP’s expectations assume an average West Texas Intermediate (WTI) crude oil price of approximately $91.68 per barrel in 2013. Although the overwhelming majority of the cash generated by KMP’s assets is fee based and is not sensitive to commodity prices, the CO_{2}-KMP business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. KMP 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 2013, it is expected that every $1 change in the average WTI crude oil price per barrel will impact the CO_{2}-KMP segment’s cash flows by approximately $6 million (or approximately 0.1% of the combined business segments’ anticipated earnings before depreciation, depletion and amortization expenses).

## EPB

- EPB estimates that in 2013 it will declare cash distributions of $2.55 per unit, a 13% increase over its 2012 distribution of $2.25 per unit. EPB’s 2013 budget includes the expected acquisition of 50% of Gulf LNG Energy LLC from us. EPB’s growth is expected to be driven by its stable, regulated natural gas pipelines and storage assets, its LNG businesses and incremental cost savings and synergies relative to our purchase of EP. EPB estimates that it will produce excess cash flow of more than $25 million above its 2013 cash distribution target.

## KMI

- In 2013, we expect to sell our remaining 50% interest in EPNG and 50% interest in EPMIC to KMP, and our 50% interest in Gulf LNG Holdings Group LLC to EPB.

- KMI expects to declare dividends of $1.57 per share for 2013, a 16% increase over its budgeted 2012 declared dividend of $1.35 per share and a 12% increase from its actual 2012 declared dividend of $1.40 per share. Growth at KMI in 2013 is expected to be driven by the continued strong performance at KMP, along with contributions from EPB and the natural gas assets KMI acquired in the EP transaction

## (b) Financial Information about Segments

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

## (c) Narrative Description of Business

## Business Strategy

Our business strategy is to:

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

• increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound



## Items 1 and 2. Business and Properties. (continued)

operating practices;

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

• maximize the benefits of our financial structure to create and return value to our stockholders.

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 KMP and EPB) 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, if applicable, 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 the following reportable business segments:

- Natural Gas Pipelines—for all periods presented in our financial statements this segment consists of approximately 62,000 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 and equity earnings from our 20% interest in NGPL Holdco LLC. Following our May 25, 2012 EP acquisition, this segment also includes the natural gas operations of EP, its subsidiaries (including EPB) and its equity investments;

- Products Pipelines—KMP—which consists of approximately 8,600 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 62 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the U.S.;

- CO \( _{2} \) —KMP—which produces, markets and transports, through approximately 1,500 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates seven 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 113 owned or operated liquids and bulk terminal facilities and approximately 35 rail transloading and materials handling facilities located throughout the U.S. 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 U.S. and Canada;

- Kinder Morgan Canada—KMP—which transports crude oil and refined petroleum products through over 2,500 miles of pipelines from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the U.S.; plus five associated product terminal facilities; and

- Other—in 2010, this segment primarily consisted of our Power facility which was sold on October 22, 2010. Following our May 25, 2012 EP acquisition, this segment primarily includes several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028. This segment also included an interest in the Bolivia to Brazil Pipeline, which we sold for $88 million on January 18, 2013.

## Natural Gas Pipelines

Our Natural Gas Pipelines segment includes interstate and intrastate pipelines and our liquefied natural gas (LNG) terminals, and includes both FERC regulated and non-FERC regulated assets. Our non-FERC regulated assets are contained in KMP’s Midstream Group.

Our primary businesses in this segment consist of natural gas sales, transportation, storage, gathering, processing and treating, and the terminaling of LNG. Within this segment, are: (i) KMP’s assets - approximately 34,000 miles of natural gas pipelines; and (ii) EPB’s assets - approximately 13,000 miles of natural gas pipelines; and (iii) our equity interests in entities that have approximately 15,000 miles of natural gas pipelines (excludes KMI’s 50% interest in EPNG, which is included in KMP’s mileage), along with associated storage and supply lines for these transportation networks, that are strategically located



## Items 1 and 2. Business and Properties. (continued)

throughout the North American natural gas pipeline grid. KMP’s transportation network provides access to the major natural gas supply areas in the western U.S., Texas, the Midwest and Northeast, as well as major consumer markets. EPB’s transportation network provides access to the major gas supply areas and consumer markets in the Rocky Mountain, Midwest and Southeastern regions. EPB’s LNG storage and regasification terminal also serves natural gas supply areas in the southeast.

## KMP

## KMP Midstream Group

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 Kinder Morgan Texas Pipeline and our Kinder Morgan Tejas Pipeline. These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability. The combined system includes approximately 5,800 miles of intrastate natural gas pipelines with a peak transport and sales capacity of approximately 5.5 billion cubic feet per day of natural gas and approximately 130 billion cubic feet of on-system natural gas storage capacity, including approximately 11 billion cubic feet contracted from third parties. In addition, the combined system (i) has facilities to both treat approximately 180 million cubic feet per day of natural gas for carbon dioxide and hydrogen sulfide removal, and to process approximately 85 million cubic feet per day of natural gas for liquids extraction and (ii) holds contractual rights to process natural gas at certain third party facilities.

The Mier-Monterrey Pipeline consists of a 95-mile natural gas pipeline that stretches from the international border between the U.S. and Mexico in Starr County, Texas, to Monterrey, Mexico and can transport up to 425 million cubic feet per day. The pipeline connects to the Pemex natural gas transportation system and serves a 1,000-megawatt power plant complex. KMP has entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for substantially all of the pipeline’s capacity.

KMP’s Kinder Morgan North Texas Pipeline consists of an 82-mile pipeline that transports natural gas from an interconnect with the facilities of Natural Gas Pipeline Company of America LLC (a 20%-owned equity investee of us and referred to in this report as NGPL) in Lamar County, Texas to a 1,750-megawatt electricity generating facility located in Forney, Texas, 15 miles east of Dallas, Texas and to a 1,000 megawatt facility located near Paris, 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.

Texas is one of the largest natural gas consuming states in the country. The natural gas demand profile in KMP’s 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 a 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.

Collectively, KMP’s Texas intrastate natural gas pipeline system primarily serves the Texas Gulf Coast by selling, transporting, processing and treating natural gas from multiple onshore and offshore supply sources to serve the Houston/Beaumont/Port Arthur/Austin industrial markets, local natural 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. In 2012, the four natural gas pipeline systems in the Texas intrastate group provided an average of approximately 2.69 billion cubic feet per day of natural gas transport services. The Texas intrastate group also sold approximately 879.1 billion cubic feet of natural gas in 2012.

The purchases and sales of natural gas are primarily priced with reference to market prices in the consuming region of the system. The difference between the purchase and sale prices is the rough equivalent of a transportation fee and fuel costs. Generally, KMP purchases natural gas directly from producers with reserves connected to its intrastate natural gas system in South Texas, East Texas, West Texas, and along the Texas Gulf Coast. In addition, KMP also purchase gas at interconnects with third-party interstate and intrastate pipelines. While the intrastate group does not produce gas, it does maintain an active well connection program in order to offset natural declines in production along its system and to secure



## Items 1 and 2. Business and Properties. (continued)

supplies for additional demand in its market area. KMP’s intrastate system has access to both onshore and offshore sources of supply, and is interconnected with both liquefied natural gas import terminals located on the Texas Gulf Coast. The intrastate group also has access to markets within and outside of Texas through interconnections with numerous interstate natural gas pipelines.

## Kinder Morgan Treating L.P.

KMP’s subsidiary, Kinder Morgan Treating, L.P., owns and operates (or leases to producers for operation) treating plants that remove impurities (such as carbon dioxide and 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. Additionally, its subsidiary KM Treating Production LLC, acquired on November 30, 2011, designs, constructs, and sells custom and stock natural gas treating plants and condensate stabilizers. KMP’s rental fleet of treating assets includes approximately 212 natural gas amine-treating plants, approximately 55 hydrocarbon dew point control plants, and more than 178 mechanical refrigeration units that are used to remove impurities and hydrocarbon liquids from natural gas streams prior to entering transmission pipelines.

## KinderHawk Field Services LLC

KinderHawk Field Services LLC gathers and treats natural gas in the Haynesville shale gas formation located in northwest Louisiana. Its assets currently consist of approximately 479 miles of natural gas gathering pipeline currently in service and natural gas amine treating plants having a current capacity of approximately 2,600 gallons per minute. The system is designed to have approximately 2.0 billion cubic feet per day of throughput capacity. The 2012 average annual throughput was approximately 1.0 billion cubic feet per day of natural gas; however, volumes on the system are declining due to reduced drilling activities.

KinderHawk owns life of lease dedications to gather and treat substantially all of Petrohawk Energy Corporation’s (a subsidiary of BHP Billiton) operated Haynesville and Bossier shale gas production in northwest Louisiana at agreed upon rates, as well as minimum volume commitments for a five year term that expires in May 2015. KinderHawk also holds additional third-party gas gathering and treating commitments.

## EagleHawk Field Services LLC.

EagleHawk Field Services LLC provides natural gas and condensate gathering, treating, condensate stabilization and transportation services in the Eagle Ford shale formation in South Texas. We own a 25% equity ownership in EagleHawk Field Services LLC. Petrohawk Energy Corporation, a subsidiary of BHP Billiton operates EagleHawk Field Services LLC and owns the remaining 75% ownership interest. EagleHawk owns two midstream gathering systems in and around Petrohawk's Hawkville and Black Hawk areas of the Eagle Ford shale formation and combined, its assets consist of more than 388 miles of gas gathering pipelines and approximately 266 miles of condensate lines. EagleHawk has a "life of lease" dedication of certain of Petrohawk's Eagle Ford reserves, and to a limited extent, contracts with other Eagle Ford producers to provide natural gas and condensate gathering, treating, condensate stabilization and transportation services.

## Eagle Ford Gathering LLC

KMP owns a 50% equity interest in Eagle Ford Gathering LLC, a joint venture that provides natural gas gathering, transportation and processing services to natural gas producers in the Eagle Ford shale gas formation in South Texas. It is owned 50% by KMP and 50% by Copano. Copano also serves as operator and managing member. Combined, the Eagle Ford Gathering system has approximately 180 miles of pipelines with capacity to gather and process over 700 million cubic feet of natural gas per day. The joint venture has executed long term firm service agreements with multiple producers for the vast majority of its processing capacity, and has also executed interruptible service agreements with multiple producers under which natural gas can flow on a “as capacity is available” basis.

## Red Cedar Gathering Company

KMP owns a 49% equity interest in Red Cedar Gathering Company, a joint venture organized in August 1994 and referred to in this report as Red Cedar. Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado. The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe. Red Cedar’s natural gas gathering system currently consists of approximately 755 miles of gathering pipeline connecting more than 900 producing wells, 133,400 horsepower of compression at 20 field compressor stations and three



## Items 1 and 2. Business and Properties. (continued)

carbon dioxide treating plants. Throughput capacity of the Red Cedar gathering system is approximately 600 million cubic feet per day of natural gas and treating capacity is approximately 800 million cubic feet per day.

## El Paso Midstream Investment Company

KMP and KMI each own a 50% interest in EPMIC. Effective June 1, 2012, KMP acquired its 50% ownership interest in EPMIC, a joint venture that owns (i) the Altamont natural gas gathering, processing and treating assets located in the Unita Basin in Utah and (ii) the Camino Real natural gas and oil gathering systems located in the Eagle Ford shale formation in South Texas. The Altamont system consists of over 1,200 miles of pipeline infrastructure, over 450 well connections with producers, a natural gas processing plant with a design capacity of 60 million cubic feet per day which is being expanded to 80 million cubic feet per day, and a natural gas liquids fractionator with a design capacity of 5,600 barrels per day. The Camino Real gathering system has the capacity to gather 150 million cubic feet per day of natural gas and 110,000 barrels per day of crude oil. KMI, through its EP acquisition, owns the remaining 50%, and as a result we began consolidating EPMIC into our financial statements as of June 1, 2012.

## Endeavor Gathering LLC

KMP owns a 40% equity interest in Endeavor Gathering LLC, which provides natural gas gathering service to GMX Resources and others in the Cotton Valley Sands and Haynesville/Bossier Shale horizontal well developments located in East Texas. GMX Resources, Inc. operates and owns the remaining 60% ownership interest in Endeavor Gathering LLC. Endeavor's gathering system consists of over 100 miles of gathering lines and 25,000 horsepower of compression. The natural gas gathering system has takeaway capacity of approximately 115 million cubic feet per day.

## Pecos Valley Producer Services LLC

KMP owns a 50% equity interest in Pecos Valley Producer Services LLC, a joint venture with Prism Midstream formed to develop natural gas gathering, processing and related opportunities in and around Reeves County, Texas. The joint venture's current activities include moving crude oil and natural gas liquids through a commodity rail terminal in Pecos, Texas that began operations on May 1, 2012. The terminal serves the growing oil and natural gas industries in the Permian Basin and offers a variety of services to producers including crude oil hauling, storage, transloading and marketing. The facility is operated by a subsidiary of Watco Companies, LLC, and is the largest privately held shortline railroad company in the U.S. KMP holds a preferred equity position in Watco.

## KMP Natural Gas Pipelines

## Tennessee Gas Pipeline Company, L.L.C.

KMP’s subsidiary, TGP, owns the approximate 13,900-mile Tennessee Gas natural gas pipeline system. KMP acquired TGP from us in the August 2012 drop-down transaction. The system has a design capacity of approximately 8.0 billion cubic feet per day for natural gas, and during 2012, the average throughput was 7.2 billion cubic feet per day. The multiple-line TGP system begins in the natural gas producing regions of Louisiana, the Gulf of Mexico and South Texas and extends to the northeast section of the U.S., including the metropolitan areas of New York City and Boston.

KMP’s TGP system connects with multiple pipelines (including interconnects at the U.S.-Mexico border and the U.S.-Canada border) that provide customers with access to diverse sources of supply and various natural gas markets. The pipeline system is also connected to four major shale formations: (i) the Haynesville shale formation in northern Louisiana and Texas (ii) the Marcellus shale formation in Pennsylvania; (iii) the Utica shale formation that spans an area from Ohio to Pennsylvania and across the Canadian border; and (iv) the previously discussed Eagle Ford formation located in South Texas. It also includes approximately 93 billion cubic feet of underground working natural gas storage capacity through partially owned facilities or long-term contracts. Of this total storage capacity, 29 billion cubic feet is contracted from Bear Creek Storage Company, L.L.C. (Bear Creek) located in Bienville Parish, Louisiana. Bear Creek is a joint venture equally owned by KMP and EPB. The facility has 58 billion cubic feet of working natural gas storage capacity that is committed equally to KMP and EPB.

KMP’s TGP pipeline system provides natural gas services to a variety of customers, including natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas



## Items 1 and 2. Business and Properties. (continued)

marketing and trading companies. Its existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity, and TGP’s ability to extend its existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Although TGP attempts to recontract or remarket its capacity at the maximum rates allowed under its tariff, it frequently enters into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. As of December 31, 2012, the TGP pipeline system serviced approximately 439 firm and interruptible customers, and was a party to approximately 458 firm transportation contracts.

## Western Interstate Natural Gas Pipeline Group

KMP’s Western interstate natural gas pipeline systems, which operate along the South Central region and the Rocky Mountain region of the Western portion of the U.S., consist of the following two natural gas pipeline systems (i) the combined El Paso Natural Gas and Mojave Pipelines and (ii) the TransColorado Pipeline.

## El Paso Natural Gas Pipeline Company, L.L.C.

KMP and KMI each own a 50% interest in EPNG. EPNG is the sole owner of (i) the 10,200-mile EPNG pipeline system and (ii) Mojave Pipeline Company, LLC, the sole owner of the approximate 500-mile Mojave Pipeline system. KMP acquired its 50% equity interest in EPNG in the August 2012 drop-down transaction. Although the Mojave Pipeline system is a wholly owned entity, it shares common pipeline and compression facilities that are 25% owned by Mojave Pipeline Company, LLC and 75% owned by Kern River Gas Transmission Company.

The EPNG system extends from the San Juan, Permian and Anadarko basins to California, its single largest market, as well as markets in Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico. It has a design capacity of 5.65 billion cubic feet per day for natural gas (reflecting winter-sustainable west-flow capacity of 4.85 billion cubic feet per day and approximately 800 million cubic feet per day of east-end delivery capacity). As of December 31, 2012, the EPNG pipeline system serviced approximately 80 firm and interruptible customers, and was a party to approximately 180 firm transportation contracts that had a weighted average remaining contract term of approximately 2.5 years.

The Mojave system connects with other pipeline systems including (i) the EPNG system near Cadiz, California; (ii) the EPNG and Transwestern Pipeline Company, LLC (Transwestern) systems at Topock, Arizona; and (iii) the Kern River Gas Transmission Company system in California. The Mojave system also extends to customers in the vicinity of Bakersfield, California. It has a design capacity of 400 million cubic feet per day (reflecting east to west flow activity). As of December 31, 2012, the Mojave pipeline system serviced approximately six firm and interruptible customers of which two held firm transportation contracts that had a weighted average remaining contract term of approximately three years.

In addition to its two pipeline systems, EPNG utilizes its Washington Ranch underground natural gas storage facility located in New Mexico to manage its transportation needs and to offer interruptible storage services. This storage facility has up to 44 billion cubic feet of underground working natural gas storage capacity.

The EPNG system provides natural gas services to a variety of customers, including natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing and trading companies. California, Arizona, and Mexico customers account for the majority of transportation on the EPNG system, followed by Texas and New Mexico. The Mojave system is largely contracted to EPNG which utilizes the capacity to provide service to EPNG’s customers. Furthermore, the EPNG system also delivers natural gas to Mexico along the U.S. border serving customers in the Mexican states of Chihuahua, Sonora, and Baja California.

## TransColorado Gas Transmission Company LLC

KMP’s subsidiary, TransColorado Gas Transmission Company LLC, referred to in this report as TransColorado, owns a 300-mile interstate natural gas pipeline that extends from approximately 20 miles southwest of Meeker, Colorado to the Blanco Hub near Bloomfield, New Mexico. It has multiple points of interconnection with various interstate and intrastate pipelines, gathering systems, and local distribution companies. The TransColorado pipeline system is powered by eight compressor stations having an aggregate of approximately 39,000 horsepower. The system is bi-directional to the north and south and has a pipeline capacity of 1.0 billion cubic feet per day of natural gas. In 2012, the TransColorado pipeline system transported an average of approximately 400 million cubic feet per day of natural gas.



## Items 1 and 2. Business and Properties. (continued)

The TransColorado pipeline system receives natural gas from a 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. It 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. TransColorado also 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.

## Central Interstate Natural Gas Pipeline Group

KMP’s Central interstate natural gas pipeline group, which operates primarily in the Mid-Continent region of the U.S., consists of the following three natural gas pipeline systems (i) Kinder Morgan Louisiana Pipeline; (ii) its 50% ownership interest in the Midcontinent Express Pipeline; and (iii) its 50% ownership interest in the Fayetteville Express Pipeline.

## Kinder Morgan Louisiana Pipeline

KMP’s 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, and transports natural gas to various delivery points located in Cameron, Calcasieu, Jefferson Davis, Acadia and Evangeline parishes in Louisiana. The system capacity is fully supported by 20 year take-or-pay customer commitments with Chevron and Total that expire in 2029. The Kinder Morgan Louisiana pipeline system consists of two segments. The first is a 132-mile, 42-inch diameter pipeline with firm capacity of approximately 2.0 billion cubic feet per day of natural gas that extends from the Sabine Pass terminal to a point of interconnection with an existing Columbia Gulf Transmission line in Evangeline Parish, Louisiana (an offshoot consists of approximately 2.3 miles of 24-inch diameter pipeline extending away from the 42-inch diameter line to the Florida Gas Transmission Company compressor station located in Acadia Parish, Louisiana). The second segment is a one-mile, 36-inch diameter pipeline with firm capacity of approximately 1.2 billion cubic feet per day that extends from the Sabine Pass terminal and connects to NGPL’s natural gas pipeline.

## Midcontinent Express Pipeline LLC

KMP owns a 50% interest in Midcontinent Express Pipeline LLC, the sole owner of the approximate 500-mile Midcontinent Express natural gas pipeline system. KMP also operates the Midcontinent Express pipeline system. 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. It interconnects with numerous major pipeline systems and provides an important infrastructure link in the pipeline system moving natural gas supply from newly developed areas in Oklahoma and Texas into the U.S. eastern markets.

The pipeline system is comprised of approximately 30-miles of 30-inch diameter pipe, 275-miles of 42-inch diameter pipe and 197-miles of 36-inch diameter pipe. Midcontinent Express also has four compressor stations and one booster station totaling approximately 144,500 horsepower. It has two rate zones: (i) Zone 1 (which has a capacity of 1.8 billion cubic feet per day) beginning at Bennington and extending to an interconnect with Columbia Gulf Transmission near Delhi, in Madison Parish Louisiana and (ii) Zone 2 (which has a capacity of 1.2 billion cubic feet per day) beginning at Delhi and terminating at an interconnection with Transco Pipeline near the town of Butler in Choctaw County, Alabama. Capacity on the Midcontinent Express system is 99% contracted under long-term firm service agreements that expire between 2014 and 2020. The majority of volume is contracted to producers moving supply from the Barnett shale and Oklahoma supply basins.

## Fayetteville Express Pipeline LLC

KMP owns a 50% interest in Fayetteville Express Pipeline LLC, the sole owner of the Fayetteville Express natural gas pipeline system. The 187-mile Fayetteville Express pipeline system originates in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnect with Trunkline Gas Company's pipeline in Panola County, Mississippi. The system also interconnects with NGPL's pipeline in White County, Arkansas, Texas Gas Transmission's pipeline in Coahoma County, Mississippi, and ANR Pipeline Company's pipeline in Quitman County, Mississippi. Capacity on the Fayetteville Express system is over 90% contracted under long-term firm service agreements.

## EPB

Wyoming Interstate Company, L.L.C. (WIC)



WIC is comprised of a mainline system that extends from western Wyoming to northeast Colorado (the Cheyenne Hub) and several lateral pipeline systems that extend from various interconnections along the WIC mainline into western Colorado, northeast Wyoming and eastern Utah. WIC owns interstate natural gas transportation systems providing takeaway capacity from the mature Overhust, Piceance, Uinta, Powder River and Green River Basins. The WIC system includes approximately 800 miles of pipeline with a capacity of approximately 3,700 Mmcf per day.

## Colorado Interstate Gas Company L.L.C. (CIG)

CIG is comprised of approximately 4,300 miles of pipelines with a capacity of approximately 4,600 Mmcf per day that deliver natural gas from production areas in the Rocky Mountains and the Anadarko Basin directly to customers in Colorado, Wyoming and indirectly to the Midwest, Southwest, California and Pacific Northwest. CIG also owns interests in five storage facilities located in Colorado and Kansas and one natural gas processing plant located in Wyoming.

CIG owns a 50% interest in WYCO, a joint venture with an affiliate of Public Service Company of Colorado (PSCo). WYCO owns Totem and the 164-mile High Plains Pipeline (High Plains) both of which are in northeast Colorado and are operated by CIG under a long-term agreement with WYCO. Totem has a peak withdrawal capacity of 200 MMcf/d and a maximum injection rate of 150 Mmcf/d. Totem services and interconnects with High Plains. WYCO also owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to PSCo's Fort St. Vrain's electric generation plant, which CIG does not operate, and a compressor station in Wyoming leased by WIC.

In total, the CIG system has the capacity to transport 4,611 Mmcf per day and has storage capacity of 37 Bcf. It serves two major markets, an on-system market and an off-system market. The on-system market consists of utilities and other customers located along the front range of the Rocky Mountains in Colorado and Wyoming. The off-system market consists of the transportation of Rocky Mountain natural gas production from multiple supply basins to interconnections with other pipelines in the Midwest, Southwest, California and the Pacific Northwest.

## Southern Natural Gas Company L.L.C. (SNG)

SNG is comprised of approximately 7,200 miles of pipelines extending from natural gas supply basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. SNG owns pipeline facilities serving southeastern markets in Alabama, Georgia and South Carolina. SNG owns 100% of the Muldon storage facility and a 50% interest in Bear Creek. The storage facilities have a combined peak withdrawal capacity of 1.2 Bcf/d. The SNG system is also connected to SLNG's Elba Island LNG terminal and has 3,892 Mmcf per day transportation capacity and 60 bcf storage capacity. The southeastern market served by the SNG system is one of the fastest growing natural gas demand regions in the U.S. Demand for deliveries from the SNG system is characterized by two peak delivery periods, the winter heating season and the summer cooling season.

## Elba Express

Elba Express owns the Elba Express pipeline which transports natural gas supplies from the Elba Island LNG terminal to markets in the southeastern and eastern U.S. Under a firm transportation service agreement, the entire capacity of Elba Express is contracted to Shell NA LNG LLC (Shell LNG) for 30 years at a fixed rate that will be reduced beginning on December 31, 2013 and remains flat thereafter with respect to current facilities. The firm transportation service agreement is supported by a parent guarantee from Shell Oil Company (Shell) that secures the timely performance of the obligations of the agreement. Elba Express was originally designed to transport LNG supplies received by SLNG to markets in the southeast. However, the recent proliferation of gas production from shale formations has shifted the global LNG supply dynamics. With this shift, customers and potential customers of Elba Express have expressed a desire to displace supply from imported LNG with domestically produced natural gas. To that end, Elba Express is currently constructing facilities to effectuate transporting gas from domestic sources to markets in the southeast for a subsidiary of BG Group. These new facilities, which are anticipated to be in-service in the second quarter of 2013, will increase the capacity of Elba Express, which is currently completely subscribed under a long-term contract with a subsidiary of Shell. The new facilities will be subscribed under a long-term contract with a subsidiary of BG. Revenue from both of these contracts is predominantly based on reservation charges. As such, changes in throughput will have relatively little effect on our revenue stream or profitability.

## Cheyenne Plains Gas Company, L.L.C. (CPG)

CPG is a 400-mile pipeline system that extends from Cheyenne Hub in Weld County, Colorado and extends southerly to a variety of delivery locations in the vicinity of the Greensburg Hub in Kiowa County, Kansas. CPG provides pipeline takeaway capacity from the natural gas basins in the Central Rocky Mountain area to the major natural gas markets in the Mid-Continent



## Items 1 and 2. Business and Properties. (continued)

region and has 1,105 Mmcf per day transportation capacity. CPG has high interconnectivity at the Cheyenne Hub. The Cheyenne Hub is connected directly or indirectly to all major pipelines within the Rockies, which gather from all major producing basins in the region. CPG’s interconnects near Greensburg, Kansas continue to benefit customers in the mid-continent by continuing to provide increased reliability (due to pipeline diversity), increased optionality (due to supply basin diversity), and advantageous pricing (due to gas-on-gas competition). CPG’s capacity to move Rockies production from the Cheyenne Hub area remains a vital link and along with sustained growth projections in Rockies production through 2022, CPG is well positioned to accommodate any future increase in Rockies production. In addition, CPG is ideally positioned to accommodate the expected surge in incremental production from associated gas within the high liquid content plays out of the Denver Basin

## Southern LNG Company, L.L.C. (SNLG)

SLNG owns the Elba Island LNG receiving terminal, located near Savannah, Georgia. The Elba Island LNG terminal is one of nine land-based terminal facilities in the U.S. capable of providing domestic storage and vaporization services to international producers of LNG. The Elba Island LNG terminal has approximately 11.5 Bcf equivalent of LNG storage capacity and approximately 1.8 Bcf per day of peak send-out capacity. The capacity of the Elba Island LNG terminal is fully contracted with BG LNG Services, LLC (BG LNG) under a recourse rate contract comprised predominantly of a fixed reservation rate with a small variable rate component and Shell LNG under a long-term step-down fixed reservation rate contract (that will be reduced beginning on December 31, 2013 and remain flat thereafter). The firm SLNG service agreements are supported by parent guarantees from BG Energy Holdings Limited (BG) and Shell that secure the timely performance of the obligations of those agreements. The Elba Island LNG terminal is directly connected to three interstate pipelines, indirectly connected to two others, and also connected by commercial arrangements to a major local distribution company; thus, is readily accessible to the southeast and mid-Atlantic markets. SLNG's terminal capacity is completely subscribed under long-term contracts with subsidiaries of BG and Shell. Revenue from these contracts is predominantly based on reservation charges; therefore, changes in throughput at the terminal driven by domestic or global competition will have relatively little effect on our revenue stream or profitability. Since SLNG's Elba Island LNG terminal is directly connected to three interstate pipelines, and indirectly connected to two others, it is readily accessible to markets in southeast U.S., Florida and the mid-Atlantic as well as supply from the newly developed shale formations. The recent proliferation of gas production from shale formations has shifted the desire of global LNG suppliers from importing LNG to the U.S. to seeking opportunities to export LNG from the U.S. SLNG is well positioned for the LNG export opportunity.

In June 2012, SLNG received authorization from the Department of Energy (DOE) to export domestically produced LNG of up to 4 million tons per year (equivalent to approximately 0.5 Bcf of natural gas per day) to countries with which the U.S. has a free trade agreement. In August 2012, SLNG filed an application with the DOE requesting authorization to export up to 4 million tons per year of LNG from the Elba Island LNG terminal. The authorization would allow the export of LNG from the terminal to any non FTA country.

In January 2013, Southern Liquefaction Company, LLC (SLC), a unit of EPB, and Shell US Gas and Power LLC (SUSGP), a subsidiary of Royal Dutch Shell plc, announced plans to develop a natural gas liquefaction plant in two phases at SLNG. SLC will own 51% of the entity and SUSGP will own the remaining 49%. SLNG will modify its facilities at Elba Island and will operate the facility. Phase I of the project, approximately 210 Mmcfd (1.5 million tons per year), requires no additional DOE approval.

## Other KMI Owned Natural Gas Interests

## Southern Gulf LNG Company, LLC

Southern Gulf LNG Company LLC owns a 50% interest in Gulf LNG Holdings Group LLC which owns an LNG receiving, storage and regasification terminal near Pascagoula, Mississippi. The facility has a peak send out capacity of 1.5 Bcf per day and storage capacity of 6.6 Bcfe. The terminal is fully subscribed under long term contracts and is directly connected by a five mile pipeline to four interstate pipelines and extends to a natural gas processing plant. We expect to sell our interest in Gulf LNG Holdings Group LLC to EPB during 2013.

## Ruby Pipeline (Ruby)

We own a 50% interest in the Ruby Pipeline which is a 680 mile pipeline extending from Wyoming to Oregon that provides natural gas supplies from the major Rocky Mountain basins to consumers in California, Nevada, and the Pacific Northwest.

Citrus Corporation (Citrus)



## Items 1 and 2. Business and Properties. (continued)

We own a 50% interest in Citrus which own Florida Gas Transmission Company LLC (Florida Gas). Florida Gas is a 5,300 mile open access interstate natural gas pipeline extending south from Texas through the Gulf Coast region of the U.S. to south Florida. Florida Gas' pipeline system primarily receives natural gas from producing basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico, and transports it to the Florida market.

## Natural Gas Holdco LLC

We own a 20% interest in and operate Natural Gas Holdco LLC, the owner of Natural Gas Pipeline Company of America (NGPL), which is a 9.220-mile pipeline and storage company.

## Competition

The market for supply of natural gas is highly competitive, and new pipelines are currently being built to serve the growing demand for natural gas in each of the markets served by the pipelines in our Natural Gas Pipelines business segment. These operations compete with interstate and intrastate pipelines, and their shippers, for attachments to new markets and supplies and for transportation, processing and treating services. We believe the principal elements of competition in our various markets are transportation rates, terms of service and flexibility and reliability of service. From time to time, other pipeline projects are proposed that would compete with our pipelines, and some proposed pipelines may deliver natural gas to markets we serve from new supply sources closer to those markets. We do not know whether or when any such projects would be built, or the extent of their impact on our operations or profitability.

Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.

## Products Pipelines—KMP

The Products Pipelines-KMP segment consists of KMP’s refined petroleum products and natural gas liquids pipelines and their associated terminals, Southeast terminals, and its transmix processing facilities.

## West Coast Products Pipelines

KMP’s West Coast Products Pipelines include SFPP, L.P. operations (often referred to in this report as KMP’s Pacific operations), Calnev pipeline operations, and West Coast Terminals operations. The assets include interstate common carrier pipelines rate-regulated by the FERC and intrastate pipelines in the state of California, rate-regulated by the California Public Utilities Commission, and certain non rate-regulated operations and terminal facilities.

KMP’s Pacific operations serve six western states with approximately 2,500 miles of refined petroleum products pipelines and related terminal facilities that provide refined products to major population centers in the U.S., including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. In 2012, the Pacific operations’ mainline pipeline system transported approximately 1,056,600 barrels per day of refined products, approximately 60% gasoline, 23% diesel fuel, and 17% jet fuel.

KMP’s Calnev pipeline system consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from its 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 California. In 2012, the Calnev pipeline system transported approximately 108,300 barrels per day of refined products, approximately 40% gasoline, 30% diesel fuel, and 30% jet fuel.

West Coast Products Pipelines operations include 15 truck-loading terminals (13 on Pacific operations and two on Calnev) with an aggregate usable tankage capacity of approximately 15.3 million barrels. The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.

West Coast Terminals are fee-based terminals located in the Seattle, Portland, San Francisco and Los Angeles areas along the west coast of the U.S. with a combined total capacity of approximately 9.9 million barrels of storage for both petroleum products and chemicals. West Coast Products Pipelines and associated West Coast Terminals together handled 17.4 million barrels of ethanol in 2012.



Combined, West Coast Products Pipelines operations' pipelines transport approximately 1.4 million barrels per day of refined petroleum products, providing pipeline service to approximately 28 customer-owned terminals, 11 commercial airports and 15 military bases. The pipeline systems serve approximately 61 shippers in the refined petroleum products market, the largest customers being major petroleum companies, independent refiners, and the U.S. military. The majority of refined products supplied to the West Coast Product Pipelines come from the major refining centers around Los Angeles, San Francisco, West Texas and Puget Sound, as well as from waterborne terminals and connecting pipelines located near these refining centers.

## Plantation Pipe Line Company

KMP 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 U.S. KMP operates the system pursuant to agreements with Plantation and its wholly-owned subsidiary, Plantation Services LLC. The Plantation pipeline system originates in Louisiana and terminates in the Washington, D.C. area. It connects to approximately 130 shipper delivery terminals throughout eight states and serves as a common carrier of refined petroleum products to various metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area. An affiliate of ExxonMobil Corporation owns the remaining approximately 49% ownership interest, and ExxonMobil has historically been one of the largest shippers on the Plantation system both in terms of volumes and revenues. In 2012, Plantation delivered approximately 512,400 barrels per day of refined petroleum products, approximately 68% gasoline, 19% diesel fuel, and 13% jet fuel.

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, from other products pipeline systems, and via marine facilities located along the Mississippi River. Plantation ships products for approximately 30 companies to terminals throughout the southeastern U.S. Plantation’s principal customers are Gulf Coast refining and marketing companies, and fuel wholesalers.

## Central Florida Pipeline

KMP’s Central Florida pipeline system consists of a 110-mile, 16-inch diameter pipeline that transports gasoline and ethanol, and an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando. The Central Florida pipeline operations include two separate liquids terminals located in Tampa and Taft, Florida, which KMP owns and operates.

In addition to being connected to the Tampa terminal, the Central Florida pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, Buckeye, and Marathon Petroleum. The 10-inch diameter pipeline is connected to the Taft 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 2012, the pipeline system transported approximately 92,600 barrels per day of refined products, approximately 70% gasoline and ethanol, 10% diesel fuel, and 20% jet fuel.

The Tampa terminal contains approximately 1.6 million barrels of refined products storage capacity and is connected to two ship dock facilities in the Port of Tampa and is connected to an ethanol unit train off-load storage facility. The Taft terminal contains approximately 0.8 million barrels of storage capacity, for gasoline, ethanol and diesel fuel for further movement into trucks.

## Cochin Pipeline System

KMP’s 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 70,000 barrels per day. It includes 31 pump stations spaced at 60 mile intervals and five U.S. propane terminals. Underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario through third parties. The pipeline traverses three provinces in Canada and seven states in the U.S. and can transport ethane, propane, butane and natural gas liquids to the midwestern U.S. and eastern Canadian petrochemical and fuel markets. In 2012, the system transported approximately 30,000 barrels per day of propane, and 7,000 barrels per day of ethane-propane mix. In 2014, KMP expect to complete the expansion and reversal of the Cochin pipeline system to transport 95,000 barrels per day of condensate from a new receipt terminal in Kankakee County, Illinois to third party storage in Fort Saskatchewan, Alberta.



## Items 1 and 2. Business and Properties. (continued)

## Cypress Pipeline

KMP owns 50% of Cypress Interstate Pipeline LLC, the sole owner of the Cypress pipeline system. KMP operates the system pursuant to a long-term agreement. 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 U.S. The Cypress pipeline system has a current capacity of approximately 55,000 barrels per day for natural gas liquids. In 2012, the system transported approximately 49,600 barrels per day.

## Southeast Terminals

KMP’s Southeast terminal operations consist of 28 high-quality, liquid petroleum products terminals located along the Plantation/Colonial pipeline corridor in the Southeastern U.S. The marketing activities of the Southeast terminal operations are focused on the Southeastern U.S. from Mississippi through Virginia, including Tennessee. The primary function involves the receipt of petroleum products from common carrier pipelines, short-term storage in terminal tankage, and subsequent loading onto tank trucks. Combined, the Southeast terminals have a total storage capacity of approximately 9.1 million barrels. In 2012, these terminals transferred approximately 383,300 barrels of refined products per day and together handled 12.1 million barrels of ethanol.

## Transmix Operations

KMP’s 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. KMP 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; Indianapolis, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina. Combined, the transmix facilities handled approximately 9.2 million barrels in 2012.

## Kinder Morgan Crude and Condensate Pipeline

The Kinder Morgan Crude and Condensate Pipeline is a Texas intrastate pipeline that transports crude oil and condensate from the Eagle Ford shale field in South Texas to the Houston ship channel refining complex. The 24/30-inch pipeline currently originates in Dewitt County, Texas, and extends 175 miles to third party storage. The pipeline operates on a batch basis and has a capacity of 300,000 barrels per day. Pipeline operations began in the fourth quarter of 2012. Deliveries for the year totaled 1,416,000 barrels.

## Competition

KMP’s Products Pipelines’ pipeline operations 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. The Products Pipelines’ terminal operations compete with proprietary terminals owned and operated by major oil companies and other independent terminal operators, and our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.

##  \( CO_{2} \) —KMP

The  \( CO_{2} \) —KMP business segment consists of Kinder Morgan  \( CO_{2} \)  Company, L.P. and its consolidated affiliates, collectively referred to in this report as  \( KMCO_{2} \) . The  \( CO_{2} \) —KMP business segment produces, transports, and markets carbon dioxide for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields.  \( KMCO_{2} \) 's carbon dioxide pipelines and related assets allow it to market a complete package of carbon dioxide supply, transportation and technical expertise to its customers.  \( KMCO_{2} \)  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 and Gas Producing Activities

Oil Producing Interests



## Items 1 and 2. Business and Properties. (continued)

KMCO \( _{2} \)  holds ownership interests in oil-producing fields located in the Permian Basin of West Texas, 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 99% working interest in the Katz Strawn unit; and (v) lesser interests in the Sharon Ridge unit, the Reinecke unit and the MidCross unit.

The SACROC unit is one of the largest and oldest oil fields in the U.S. using carbon dioxide flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas. KMCO \( _{2} \)  has expanded the development of the carbon dioxide project initiated by the previous owners and increased production and ultimate oil recovery over the last several years. In 2012, the average purchased carbon dioxide injection rate at SACROC was 118 million cubic feet per day. The average oil production rate for 2012 was approximately 29,000 barrels of oil per day (24,100 net barrels to KMCO \( _{2} \)  per day).

The Yates unit is also one of the largest oil fields ever discovered in the U.S. The field is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas. KMCO \( _{2} \) 's plan over the last several years has been to maintain overall production levels and increase ultimate recovery from Yates by combining horizontal drilling with carbon dioxide injection to ensure a relatively steady production profile over the next several years. In 2012, the average purchased carbon dioxide injection rate at the Yates unit was 98 million cubic feet per day, and during 2012, the Yates unit produced approximately 20,800 barrels of oil per day (9,300 net barrels to KMCO \( _{2} \)  per day).

KMCO \( _{2} \)  also operates and owns an approximate 99% working interest in the Katz Strawn unit, located in the Permian Basin area of West Texas. During 2012, the Katz Strawn unit produced approximately 1,700 barrels of oil per day (1,400 net barrels to KMCO \( _{2} \)  per day). In 2012, the average purchased carbon dioxide injection rate at the Katz Strawn unit was 62 million cubic feet per day.

During 2012, KMCO \( _{2} \)  sold its approximate 65% gross working interest in the Claytonville oil field unit located in the Permian Basin area of West Texas to the Scout Energy Group. The Claytonville unit is located nearly 30 miles east of the SACROC unit, in Fisher County, Texas.

The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which KMP owned interests as of December 31, 2012. The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. When used with respect to acres or wells, “gross” refers to the total acres or wells in which KMP has a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by KMP:

<table><tr><td rowspan="2"></td><td colspan="2">Productive Wells (a)</td><td colspan="2">Service Wells (b)</td><td colspan="2">Drilling Wells (c)</td></tr><tr><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>Crude Oil</td><td>2,089</td><td>1,311</td><td>924</td><td>718</td><td>3</td><td>3</td></tr><tr><td>Natural Gas</td><td>5</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total Wells</td><td>2,094</td><td>1,313</td><td>924</td><td>718</td><td>3</td><td>3</td></tr></table>

(a) Includes active wells and wells temporarily shut-in. As of December 31, 2012, KMP 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 and an injection well is a well drilled in a known oil field in order to inject liquids that enhance recovery.

(c) Consists of development wells in the process of being drilled as of December 31, 2012. A development well is a well drilled in an already discovered oil field.

The following table reflects KMP’s net productive and dry wells that were completed in each of the years ended December 31, 2012, 2011 and 2010:



Items 1 and 2. Business and Properties. (continued)

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Productive</td><td></td><td></td><td></td></tr><tr><td>Development</td><td>59</td><td>85</td><td>70</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>59</td><td>85</td><td>70</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. A development well is a well drilled in an already discovered oil field.

The following table reflects the developed and undeveloped oil and gas acreage that KMP held as of December 31, 2012:

<table><tr><td></td><td>Gross</td><td>Net</td></tr><tr><td>Developed Acres</td><td>68,945</td><td>65,811</td></tr><tr><td>Undeveloped Acres</td><td>14,557</td><td>13,971</td></tr><tr><td>Total</td><td>83,502</td><td>79,782</td></tr></table>

Note: As of December 31, 2012, KMP has no material amount of acreage expiring in the next three years.

See “Supplemental Information on Oil and Gas Activities (Unaudited)” included elsewhere in this report for additional information with respect to operating statistics and supplemental information on our oil and gas producing activities.

## Gas and Gasoline Plant Interests

KMCO \( _{2} \)  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 natural gas produced from the SACROC unit and neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell units, all of which are located in the Permian Basin area of West Texas. The Diamond M and the North Snyder plants contract with the Snyder plant to process natural gas. Production of natural gas liquids at the Snyder gasoline plant during 2012 averaged approximately 18,900 gross barrels per day (9,300 net barrels to KMCO \( _{2} \)  per day excluding the value associated to KMCO \( _{2} \) 's 28% net profits interest).

## Sales and Transportation Activities

## Carbon Dioxide

KMCO \( _{2} \)  owns approximately 45% of, and operates, the McElmo Dome unit in Colorado, which contains more than 6.6 trillion cubic feet of recoverable carbon dioxide. It also owns approximately 87% of, and operates, the Doe Canyon Deep unit in Colorado, which contains approximately 871 billion cubic feet of recoverable carbon dioxide. For both units combined, compression capacity exceeds 1.4 billion cubic feet per day of carbon dioxide and during 2012, the two units produced approximately 1.21 billion cubic feet per day of carbon dioxide.

KMCO \( _{2} \)  also owns approximately 11% of the Bravo Dome unit in New Mexico. The Bravo Dome unit contains approximately 801 billion cubic feet of recoverable carbon dioxide and produced approximately 300 million cubic feet of carbon dioxide per day in 2012.

KMCO \( _{2} \) 's 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.



## Items 1 and 2. Business and Properties. (continued)

## Carbon Dioxide Pipelines

As a result of  \( K M C O_{2} \) 's 50% ownership interest in Cortez Pipeline Company,  \( K M C O_{2} \)  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 transports approximately 1.2 billion cubic feet of carbon dioxide per day. The tariffs charged by the Cortez pipeline are not regulated, but are based on a consent decree.

KMCO \( _{2} \) 's Central Basin pipeline consists of approximately 143 miles of mainline pipe and 177 miles of lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas. The pipeline has an ultimate throughput capacity of 700 million cubic feet per day. At its origination point in Denver City, 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 McCamey, where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the Central Basin pipeline are not regulated.

KMCO \( _{2} \) 's Centerline carbon dioxide pipeline consists of approximately 113 miles of pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas. The pipeline has a capacity of 300 million cubic feet per day. The tariffs charged by the Centerline pipeline are not regulated.

KMCO \( _{2} \) 's Eastern Shelf carbon dioxide pipeline, which consists of approximately 91 miles of pipe located in the Permian Basin, begins near Snyder, Texas and ends west of Knox City, Texas. Two 500 horsepower pumps were placed in service in 2012, increasing the capacity of the pipeline from 70 million to 100 million cubic feet per day. The Eastern Shelf Pipeline system is currently flowing 64 million cubic feet per day. The tariffs charged on the Eastern Shelf pipeline are not regulated.

KMCO \( _{2} \)  also 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. Occidental Petroleum (81%) and XTO Energy (6%) hold the remaining ownership interests in the Bravo pipeline.

In addition, KMCO \( _{2} \)  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 McCamey, Texas, to the SACROC unit in the Permian Basin. The pipeline has a capacity of approximately 270 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The Pecos pipeline is a 25-mile pipeline that runs from McCamey to Iraan, Texas. It has a capacity of approximately 120 million cubic feet per day and makes deliveries to the Yates unit. The tariffs charged on the Canyon Reef Carriers and Pecos pipelines are not regulated.

The principal market for transportation on  \( K M C O_{2} \) 's 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.

## Crude Oil Pipeline

KMCO \( _{2} \)  owns the Kinder Morgan Wink Pipeline, a 450-mile Texas intrastate crude oil pipeline system consisting of three mainline sections, two gathering systems and numerous truck delivery stations. The pipeline allows KMCO \( _{2} \)  to better manage crude oil deliveries from its oil field interests in West Texas. KMCO \( _{2} \)  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 located in El Paso, Texas. The throughput agreement expires in 2034. The 20-inch diameter pipeline segment that runs from Wink to El Paso, Texas has a total capacity of 130,000 barrels of crude oil per day with the use of drag reduction agent (DRA), and it transported approximately 119,000 barrels of oil per day in 2012. The Kinder Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad Commission.

## Competition

KMCO \( _{2} \) 's 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 resources, and OxyUSA, Inc, which controls waste carbon dioxide extracted from natural gas production in the Val Verde Basin of West Texas. KMCO \( _{2} \) 's ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines. KMCO \( _{2} \)  also competes with



## Items 1 and 2. Business and Properties. (continued)

other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of carbon dioxide to the Denver City, Texas market area.

## Terminals—KMP

KMP’s Terminals segment includes the operations of its petroleum, chemical and other liquids terminal facilities (other than those included in the Products Pipelines—KMP segment) and all of its coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities, including all transload, engineering, conveying and other in-plant services. Combined, the segment is composed of approximately 113 owned or operated liquids and bulk terminal facilities and approximately 35 rail transloading and materials handling facilities. KMP’s terminals are located throughout the U.S. and in portions of Canada. KMP believes the location of its facilities and its ability to provide flexibility to customers helps keep customers and provides KMP opportunities for expansion. KMP often classifies its terminal operations based on the handling of either liquids or bulk material products.

## Liquids Terminals

KMPs liquids terminals operations primarily store refined petroleum products, petrochemicals, ethanol, 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, KMP’s approximately 27 liquids terminals facilities possess liquids storage capacity of approximately 60.1 million barrels, and in 2012, these terminals handled approximately 630 million barrels of liquids products, including petroleum products, ethanol and chemicals.

## Bulk Terminals

KMPs bulk terminal operations primarily involve dry-bulk material handling services. KMP 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. KMP owns or operates approximately 83 dry-bulk terminals in the U.S. and Canada, and combined, its dry-bulk and material transloading facilities (described below) handled approximately 97 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2012.

## Materials Services (rail transloading)

KMP’s materials services operations include rail or truck transloading shipments from one medium of transportation to another conducted at approximately 35 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 the rest 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. KMP also designs and builds transloading facilities, performs inventory management services, and provides value-added services such as blending, heating and sparging.

Effective March, 31 2013, TRANSFLO, a wholly owned subsidiary of CSX, will terminate their contract with our materials handling wholly-owned subsidiary, Kinder Morgan Materials Services (KMMS). This contract covered 25 terminals located on the CSX Railroad throughout the southeastern section of the U.S. KMMS performed transloading services at the 25 terminals, which included rail-to-truck and truck-to-rail transloading of bulk and liquid products.

## Competition

KMP is one of the largest independent operators of liquids terminals in the U.S. based on barrels of liquids terminaling capacity. Its liquids terminals compete with other publicly or privately held independent liquids terminals, and terminals owned by oil, chemical and pipeline companies. Its bulk terminals compete with numerous independent terminal operators, terminals owned by producers and distributors of bulk commodities, stevedoring companies and other industrial companies opting not to outsource terminal services. In some locations, competitors are smaller, independent operators with lower cost structures. KMP’s rail transloading (material services) operations compete with a variety of single- or multi-site transload, warehouse and terminal operators across the U.S. its ethanol rail transload operations compete with a variety of ethanol handling terminal sites across the U.S., many offering waterborne service, truck loading, and unit train capability serviced by Class 1 rail carriers.



## Kinder Morgan Canada—KMP

KMP’s Kinder Morgan Canada business segment includes Trans Mountain pipeline system, ownership of a one-third interest in the Express pipeline system, and the 25-mile Jet Fuel pipeline system. The weighted average remaining life of the shipping contracts on these pipeline systems was approximately two years as of December 31, 2012.

## Trans Mountain Pipeline System

The Trans Mountain pipeline system originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia. Trans Mountain’s pipeline is 715 miles in length. KMP also owns a connecting pipeline that delivers crude oil to refineries in the state of Washington. The capacity of the line at Edmonton ranges from 300,000 barrels per day when heavy crude represents 20% of the total throughput (which is a historically normal heavy crude percentage), to 400,000 barrels per day with no heavy crude. Trans Mountain is the sole pipeline carrying crude oil and refined petroleum products from Alberta to the west coast. As the recently announced expansion proposal demonstrates, we believe these facilities provide the opportunity to execute on capacity expansions to the west coast, as the market for offshore exports continues to develop.

In 2012, Trans Mountain delivered an average of 291,000 barrels per day. The crude oil and refined petroleum products transported through Trans Mountain’s pipeline system originates in Alberta and British Columbia. The refined and partially refined petroleum products transported to Kamloops, British Columbia and Vancouver originates from oil refineries located in Edmonton. Petroleum products delivered through Trans Mountain’s pipeline system are used in markets in British Columbia, Washington State and elsewhere offshore.

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 our approximate 63-mile, 16-inch to 20-inch diameter Puget Sound pipeline system. The Puget Sound pipeline system in the state of Washington has a sustainable throughput capacity of approximately 135,000 barrels per day when heavy crude represents approximately 25% of throughput, and it connects to four refineries located in northwestern Washington State. The volumes of crude oil shipped to the state of Washington fluctuate in response to the price levels of Canadian crude oil in relation to crude oil produced in Alaska and other offshore sources.

In February 2013, Trans Mountain completed negotiations with the Canadian Association of Petroleum Producers for a new negotiated toll settlement effective for the period beginning January 1, 2013 and ending December 31, 2015. Trans Mountain anticipates NEB approval in the second quarter of 2013.

## Express System

KMP owns a one-third ownership interest in the Express pipeline system. KMP operates the Express pipeline system and accounts for its one-third investment under the equity method of accounting. The Express pipeline system is a batch-mode, common-carrier, crude oil pipeline system comprised of the Express Pipeline and the Platte Pipeline, collectively referred to in this report as the Express pipeline system. The approximate 1,700-mile integrated oil transportation pipeline connects Canadian and U.S. 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 terminal at Hardisty, Alberta and terminates at the Casper, Wyoming facilities of the Platte Pipeline. The Express Pipeline has a design capacity of 280,000 barrels per day. Receipts at Hardisty averaged 191,700 barrels per day in 2012.

The Platte Pipeline is a 926-mile, 20-inch diameter pipeline that runs from the crude oil pipeline terminal at Casper, Wyoming to refineries and interconnecting pipelines in the Wood River, Illinois area. The Platte Pipeline has a current capacity of approximately 150,000 barrels per day downstream of Casper, Wyoming and approximately 140,000 barrels per day downstream of Guernsey, Wyoming. Platte deliveries averaged 148,000 barrels per day in 2012.

On December 11, 2012, KMP announced that it had entered into a definitive agreement to sell its interests in the Express Pipeline system to Spectra. This sale is expected to close in the second quarter of 2013.

## Jet Fuel Pipeline System

KMP also owns and operates the approximate 25-mile aviation 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



## Items 1 and 2. Business and Properties. (continued)

system. In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in Port Metro 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 capacity of 15,000 barrels.

## Competition

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

## Other

During 2012, our other segment activities include those operations that were acquired from EP on May 25, 2012 and are primarily related to several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028. In 2010, this segment primarily consisted of our Power facility which was sold on October 22, 2010. This segment also included an interest in the Bolivia to Brazil Pipeline, which we sold for $88 million on January 18, 2013.

## Major Customers

Our total operating revenues are derived from a wide customer base. For each of the years ended December 31, 2012, 2011 and 2010, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. KMP’s 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 and CO \( _{2} \) -KMP business segments in 2012, 2011 and 2010 accounted for 26%, 42% and 46%, respectively, of our total consolidated revenues. To the extent possible, we attempt 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 also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

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

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



## Items 1 and 2. Business and Properties. (continued)

circumstances to change rates.

## Common Carrier Pipeline Rate Regulation - Canadian Operations

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

Trans Mountain Pipeline. Trans Mountain previously had a one-year toll settlement with shippers that expired on December 31, 2012. In February 2013, Trans Mountain completed negotiations with the Canadian Association of Petroleum Producers for a new negotiated toll settlement to be effective for 2013. Trans Mountain anticipates approval from the NEB in the second quarter of 2013. The toll charged for the portion of Trans Mountain’s pipeline system located in the U.S. falls under the jurisdiction of the FERC. See “-Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations.”

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

## Interstate Natural Gas Transportation and Storage Regulation

Posted tariff rates set the general range of maximum and minimum rates we could 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. 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. There are a variety of rates that different shippers may pay, and while rates may vary by shipper and circumstance, the terms and conditions of pipeline transportation and storage services are not generally negotiable.

The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation services, including storage services, under the Natural Gas Act of 1938. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978. Beginning in the mid-1980's, through the mid-1990's, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were:

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

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

- Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies. Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage).

The FERC standards of conduct address and clarify multiple issues, including (i) the definition of transmission function and transmission function employees; (ii) the definition of marketing function and marketing function employees; (iii) the definition of transmission function information; (iv) independent functioning; (v) transparency; and (vi) the interaction of FERC standards with the North American Energy Standards Board business practice standards. The FERC also promulgates certain 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 employee relationships-using a functional approach-to ensure that natural gas transmission is provided on a nondiscriminatory basis. Pursuant to the FERC’s standards of conduct, a



## Items 1 and 2. Business and Properties. (continued)

natural gas transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. Additionally, no-conduit provisions prohibit a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit.

Rules also require 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.

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

## California Public Utilities Commission Rate Regulation

The intrastate common carrier operations of KMP’s Pacific operations’ pipelines in California are subject to regulation by the California Public Utilities Commission, referred to in this report as the CPUC, under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by KMP 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 KMP’s FERC regulated rates also could 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 to our consolidated financial statements included elsewhere in this report.

## Texas Railroad Commission Rate Regulation

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

## Mexico - Energy Regulating Commission

The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy Regulating Commission (the Commission) on September 30, 2002 and it defines the general and directional conditions for the Company to carry out the activity and provide the natural gas transportation service. This permit has a term of 30 years.

This permit establishes certain restrictive conditions, including without limitations (i) compliance with the general conditions for the provision of natural gas transportation service; (ii) compliance with certain safety measures, contingency plans, maintenance plans and the official Mexican standards regarding safety; (iii) compliance with the technical and economic specifications of the project presented to the Commission; (iv) compliance with certain technical studies established by the Commission; and (v) compliance with a minimum contributed capital not entitled to withdrawal of at least the equivalent of 10% of the investment proposed in the project.

## Safety Regulation

We are also subject to safety regulations imposed by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to as PHMSA, including those requiring us to develop and maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as high consequence areas, or HCAs, where a leak or rupture could potentially do the most harm.

The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs. We plan to



## Items 1 and 2. Business and Properties. (continued)

continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. Department of Transportation rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

The President signed into law new pipeline safety legislation in January 2012, The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. PHMSA is also currently considering changes to its regulations. PHMSA recently issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.

From time to time, our pipelines may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines 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.

We are also subject to the requirements of the Federal Occupational Safety and Health Administration (OSHA) and other comparable federal and state agencies that address employee health and safety. In general, we believe current expenditures are addressing the OSHA requirements and protecting the health and safety of our employees. Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards. However, such increases in our expenditures, and the extent to which they might be offset, cannot be estimated at this time.

## State and Local Regulation

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

## Environmental Matters

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

Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.



## Items 1 and 2. Business and Properties. (continued)

In accordance with U.S. generally accepted accounting principles, we accrue liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency, referred to in this report as the U.S. EPA, or similar state or Canadian agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could increase or mitigate our actual joint and several liability exposures.

We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $397 million as of December 31, 2012. Our reserve estimates range in value from approximately $397 million to approximately $529 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 16 to our consolidated financial statements included elsewhere in this report.

## Hazardous and Non-Hazardous Waste

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

## Superfund

The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the U.S. EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate materials that may fall within the definition of hazardous substance. By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.

## Clean Air Act

Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state and Canadian statutes and regulations. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. The U.S. EPA adopted new regulations under the Clean Air Act that took effect in early 2011 and that establish requirements for the monitoring, reporting, and control of greenhouse gas emissions from stationary sources. See “Climate Change” below.

## 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 U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal, state or Canadian authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release.



## Items 1 and 2. Business and Properties. (continued)

## 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 the burning of natural gas, are examples of greenhouse gases. Various laws and regulations exist or are under development that seek to regulate the emission of such greenhouse gases, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases.

The EPA published in December 2009 its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment. Pursuant to this endangerment finding and other rulemakings and interpretations, EPA concluded that stationary sources would become subject to federal permitting requirements under the Clean Air Act in starting in 2011. In 2010, the EPA issued a final rule, known as the “Tailoring Rule,” that defined regulatory emissions thresholds at which certain new and modified stationary sources would become subject to permitting and other requirements for greenhouse gas emissions under the Clean Air Act. Some of our facilities emit greenhouse gases in excess of the Tailoring Rule’s thresholds and have been required to obtain, and must continue to comply with, a Title V Permit for greenhouse gas emissions. In 2011, the EPA implemented permitting for new and/or modified sources of greenhouse gas emissions through the existing PSD permitting program. The EPA has indicated in rulemakings that it may reduce the current Tailoring Rule regulatory thresholds for greenhouse gases, making additional sources subject to PSD permitting requirements, but has declined to do so at this time. Permitting requirements for greenhouse gas emissions may also trigger permitting requirements for emissions of other regulated air pollutants as well. Additional direct regulation of greenhouse gas emissions in our industry may be implemented under other Clean Air Act programs, including the New Source Performance Standards, or NSPS, program. The EPA has already proposed to regulate greenhouse gas emissions from certain electric generating units under the NSPS program. A final regulation is expected in 2013. While these proposed NSPS regulations for electric generating units would not directly apply to our operations, the EPA may propose a greenhouse gas NSPS for additional source categories.

In addition, in 2009 the EPA published a final rule requiring that specified large greenhouse gas emissions sources annually report the greenhouse gas emissions for the preceding year in the U.S., beginning in 2011 for emissions occurring in 2010. In 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect in December 2010, requires reporting of greenhouse gas emissions by regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with greenhouse gas emissions reporting requirements.

At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. Although many of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that sources such as our gas-fired compressors and processing plants could become subject to related state regulations. Depending on the particular program, we could be required to purchase and surrender emission allowances.

Because our and our subsidiaries operations, including the compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and carbon dioxide, such new legislation or regulation could increase the costs related to operating and maintaining the facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital expenditures for installing new emission controls on the facilities, acquire and surrender allowances for the greenhouse gas emissions, pay taxes related to the 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, as is the case with similarly situated entities in the industry they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries' pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond their control including the outcome of future rate proceedings before the FERC or other regulatory bodies and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations, or prospects.

Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and



## Items 1 and 2. Business and Properties. (continued)

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 cash flows.

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 business segment. However, these positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although the magnitude and direction of these impacts cannot now be predicted, greenhouse gas regulations could have material adverse effects on our business, financial position, results of operations or cash flows.

## EPA Regulation of Internal Combustion Engines

Internal combustion engines used in our operations are also subject to EPA regulation under the Clean Air Act. The EPA published new regulations on emissions of hazardous air pollutants from reciprocating internal combustion engines on August 20, 2010. On June 7, 2012, the EPA proposed amendments to these regulations which are expected to be finalized in the near future. The EPA also revised the New Source Performance Standards for stationary compression ignition and spark ignition internal combustion engines on June 28, 2011 and has proposed minor amendments, included in the June 7, 2012 proposed rule. Compliance with these new regulations may require significant capital expenditures for physical modifications and may require operational changes as well. We are not able to estimate such increased costs, however, as is the case with similarly situated entities in the industry, they could be significant for us.

## Recent EPA Rules Regarding Oil and Natural Gas Air Emissions

In addition, on April 17, 2012, the EPA approved final rules that establish new air emission controls for oil and natural gas production, pipelines and processing operations. These rules were published in the Federal Register on August 16, 2012 and became effective on October 15, 2012. For new or reworked hydraulically fractured gas wells, the rules require the control of emissions through flaring or reduced emission (or “green”) completions until 2015, when the rules require the use of green completions. The rules also establish specific new requirements, effective in 2012, for emissions from compressors, dehydrators, storage tanks, gas processing plants and certain other equipment. These rules may therefore require a number of modifications to our and our customers’ operations, including the installation of new equipment to control emissions. In October 2012, several challenges to EPA’s rules were filed by various parties, including environmental groups and industry associations. Depending on the outcome of such proceedings, the rules may be modified or rescinded or EPA may issue new rules, the costs of compliance with any modified or newly issued rules cannot be predicted.

Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources are appropriate, and, if so, to promulgate performance standards for methane emissions from the oil and gas sector, which was not addressed in the EPA rule that became effective on October 15, 2012. The notice of intent also requested EPA issue emission guidelines for the control of methane emissions from existing oil and gas sources. Depending on whether rules are promulgated and the applicability and restrictions in any promulgated rule, compliance with such rules could result in additional costs, including increased capital expenditures and operating costs. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules may also make it more difficult for us and our customers to operate, thereby reducing the volume of natural gas transported through our pipelines, which may adversely affect our business.

## Department of Homeland Security

In Section 550 of the Homeland Security Appropriations Act of 2007, the U.S. Congress gave the Department of Homeland Security, referred to in this report as the DHS, regulatory authority over security at certain high-risk chemical facilities. Pursuant to its congressional mandate, on April 9, 2007, the DHS promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards. This process includes completing security vulnerability assessments, developing site security plans, and implementing protective measures necessary to meet DHS-defined, risk-based performance standards. The DHS has not provided final notice to all facilities that it determines to be high risk and subject to the rule; therefore, neither the extent to



## Items 1 and 2. Business and Properties. (continued)

which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.

## Other

## Employees

We employed 10,685 full-time people at December 31, 2012, including approximately 818 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2013 and 2016. We consider relations with our employees to be good.

Most of our employees are employed by a limited number of our subsidiaries and provide services to one or more of our business units (subsidiaries or limited partnerships). The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated to our subsidiaries and limited partnerships. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to our subsidiaries and limited partnerships pursuant to existing expense allocation procedures. The effect of these arrangements is that each business unit 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. These processes are in accordance with limited partnership agreements, and the Delegation of Control Agreement among Kinder Morgan G.P., Inc., KMR, KMP and others, and KMR's limited liability company.

## (d) Financial Information about Geographic Areas

For geographic information concerning our assets and operations, see Note 15 to our consolidated financial statements included elsewhere in this report.

## (e) Available Information

We make available free of charge on or through our internet Website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on or connected to our internet Website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

## 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

We are dependent on cash distributions received from KMP and EPB.

For 2012, distributions from KMP and EPB represented approximately 81% of the sum of total cash generated by (i) distributions payable to us by our MLPs (on a declared basis) and (ii) distributable cash generated by assets we own and our share of cash generated by our joint venture investments. A decline in KMP's and/or EPB's revenues or increases in its general and administrative expenses, principal and interest payments under existing and future debt instruments, expenditures for taxes, working capital requirements or other cash needs will limit the amount of cash KMP and EPB can distribute to us, which would reduce the amount of cash available for dividends to our stockholders, which could be material.

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

Our pipelines and storage facilities are subject to regulation and oversight by federal, state and local regulatory authorities. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. Regulation affects almost every part of our business and extends to such matters as (i) rates (which include reservation, commodity, surcharges, fuel and



gas lost and unaccounted for), operating terms and conditions of service; (ii) the types of services we may offer to our customers; (iii) the contracts for service entered into with our customers; (iv) the certification and construction of new facilities; (v) the integrity, safety and security of facilities and operations; (vi) the acquisition of other businesses; (vii) the acquisition, extension, disposition or abandonment of services or facilities; (viii) reporting and information posting requirements; (ix) the maintenance of accounts and records; and (x) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines. Furthermore, new laws or regulations sometimes arise from unexpected sources. For example, the Department of Homeland Security Appropriation Act of 2007 required the issuance of regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to us or our assets could have a material adverse impact on our business, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties-(c) Narrative Description of Business-Regulation.”

The FERC, the CPUC or the NEB may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, the CPUC, the NEB or our customers could file complaints challenging the tariff rates charged by our pipelines, and a successful complaint could have an adverse impact on us.

The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC, the CPUC or the NEB to recover in our rates, or to the extent that there is a lag before we can file and obtain rate increases, such events can have a negative impact upon our operating results can be negatively impacted.

Our existing rates may also be challenged by complaint. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates. Further, the FERC may initiate investigations to determine whether some interstate natural gas pipelines have over-collected on rates charged to shippers. We may face challenges, similar to those described in Note 16 to our consolidated financial statements included elsewhere in this report, to the rates we charge on KMP's, EPB's and our other pipelines. Any successful challenge could materially adversely affect our future earnings, cash flows and financial condition.

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

There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities and refined petroleum products and carbon dioxide transportation activities—such as leaks, explosions and mechanical problems—that could result in substantial financial losses. In addition, these risks may result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and earnings while the affected asset is temporarily out of service. In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.

Increased regulatory requirements relating to the integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.

Primarily, 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. The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of the compliance costs are pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in High Consequence Areas can have a significant impact on integrity testing and repair costs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. DOT rules. The results of these tests could cause us to incur significant and unanticipated



capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

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

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

Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.

We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating, handling, and disposal practices that were consistent with industry practices 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 was not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. 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, transportation of hazardous materials, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities.

Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business,



financial position, results of operations and prospects. For more information about climate change regulation, see Items 1 and 2 “Business Properties-(c) Narrative Description of Business-Environmental Matters-Climate Change.”

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

Methane, a primary component of natural gas, and carbon dioxide, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases. The U.S. EPA began regulating the greenhouse gas emissions in 2011, requiring the reporting of greenhouse gas emissions in the U.S. beginning in 2011 for emissions occurring in 2010 from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, like our MeElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.

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

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

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

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

Any current or future pipeline system or other form of transportation that delivers natural gas, crude oil, or petroleum products into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. To the extent that an excess of supply into these areas is created and persists, our ability to re-contract for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired. We also could experience competition for the supply of petroleum products or natural gas from both existing and proposed pipeline systems. Several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us.

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

KMP, EPB and our other pipelines regularly expand their assets and construct new build projects. They also conduct what are referred to as “open seasons” to evaluate the potential customer interest for new construction projects. A variety of factors outside of their control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction. Significant cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows.



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

We obtain the right to construct and operate pipelines on other owners' land for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be negatively affected. 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 KMP, EPB or our other pipelines have the power of eminent domain for their pipelines, other than interstate natural gas pipelines, varies from state to state depending upon the type of pipeline-petroleum liquids, natural gas or carbon dioxide-and the laws of the particular state. Our interstate natural gas pipelines have federal eminent domain authority. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our subsidiaries' business if they were to lose the right to use or occupy the property on which pipelines are located.

KMP’s and EPB’s acquisition strategies and expansion programs require access to new capital. Limitations on their access to capital would impair our ability to grow.

Consistent with the terms of KMP’s and EPB’s partnership agreements, KMP and EPB distribute most of the cash generated by their operations. As a result, they have relied on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund acquisition and growth capital expenditures. However, to the extent our limited partnerships are unable to continue to finance growth externally; their cash distribution policy will significantly impair their ability to grow. KMP and/or EPB may need new capital to finance these activities. Limitations on access to capital, whether due to tightened capital markets, more expensive capital or otherwise, will impair their ability to execute this strategy.

KMP’s and EPB’s growth strategies may cause difficulties integrating and constructing new operations and they may not be able to achieve the expected benefits from any future acquisitions.

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

Our limited partnerships 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 their ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining and expanding operations, cost savings and other size-related benefits they expected may not be achieved, which could harm their financial condition and results of operations.

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

As of December 31, 2012, we had approximately $32 billion of consolidated debt (including KMP and EPB, but excluding debt fair value adjustments). This level of debt could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions.

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



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

As of December 31, 2012, approximately $11 billion (35%) of our approximately $32 billion consolidated debt (including KMP and EPB, but excluding debt fair value adjustment) was subject to variable interest rates, either as short-term or long-term debt of variable rate debt obligations or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. Should interest rates increase, the amount of cash required to service this debt would increase and our earnings could be adversely affected. For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risk.”

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

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

There is the potential for a change of control of the general partners of KMP and EPB if we default on debt.

We own all of the common equity of the general partners of KMP and EPB. If we default on debt, then the lenders under such debt, in exercising their rights as lenders, could acquire control of the general partners of KMP and EPB through their control of us. A change of control of the general partners of KMP and EPB could materially adversely affect the distributions we receive from KMP and EPB, which could have a material adverse impact on us or our cash available for dividends to our stockholders.

Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.

Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings could cause our cost of doing business to increase by limiting our access to capital, limiting our ability to pursue acquisition opportunities and reducing our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Also, continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect business, financial condition and results of operations.

In addition, any reduction in our credit ratings could negatively impact the credit ratings of our subsidiaries, which could increase their cost of capital and negatively affect their business and operating results. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries' debt instruments, as well as the market value of KMP's and EPB's common units.

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

Some of our customers may experience 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, financial condition and cash flows.

Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business.

The U.S. government has issued public warnings that indicate that pipelines and other assets and systems might be specific targets of terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems or



operating systems and may affect our ability to operate or control our pipeline assets, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations.

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.

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

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

Changes in the business environment, such as a decline in crude oil or natural gas prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from oil and natural gas producing areas. 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 and natural gas. 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 KMP’s and/or EPB’s pipelines also may decline as a result of changes in business conditions. Over the long term, business will depend, in part, on the level of demand for oil, natural gas and refined petroleum products in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand.

The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas, crude oil and refined petroleum products, increase our costs and may have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas, crude oil and refined petroleum products.

The future success of KMP’s 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 and gas producing assets within the CO \( _{2} \) -KMP business segment will decline. KMP 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 KMP does not realize production volumes greater than, or equal to, its hedged volumes, it may suffer financial losses not offset by physical transactions.

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

The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.



The volatility of natural gas and oil prices could have a material adverse effect on the CO \( _{2} \) -KMP segment.

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. For 2013, KMP estimates that every 1 change in the average West Texas Intermediate crude oil price per barrel would impact the CO \( _{2} \) -KMP segment's cash flows by approximately 6 million. Prices for oil, natural gas liquids and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil, natural gas liquids and natural gas, uncertainties within the market and a variety of other factors beyond KMP's control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) the condition of the U.S. economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political stability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources.

A sharp decline in the prices of oil, natural gas liquids or natural gas would result in a commensurate reduction in KMP’s revenues, income and cash flows from the production of oil, natural gas liquids, and natural gas and could have a material adverse effect on the carrying value of KMP’s proved reserves. In the event prices fall substantially, KMP 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 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 engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.

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

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

The Dodd-Frank Act requires the Commodities Futures Trading Commission, referred to as the CFTC, and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. While the CFTC’s rule promulgated pursuant to the Dodd-Frank Act has been vacated by a U.S. District Court and is on appeal, the CFTC has taken the position that the act also requires the CFTC to institute broad new aggregate position limits for over-the-counter swaps and futures and options traded on regulated exchanges. As the law favors exchange trading and clearing, the Dodd-Frank Act also may require us to move certain derivatives transactions to exchanges where no trade credit is provided and also comply with margin requirements in connection with our derivatives activities that are not exchange traded, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act also requires many counterparties to our derivatives instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us. The Dodd-Frank Act and any new regulations could (i) significantly increase the cost of derivative contracts (including those requirements to post collateral, which could adversely affect our available liquidity); (ii) reduce the availability of derivatives to protect against risks we encounter; and (iii) reduce the liquidity of energy related derivatives.



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

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

We are a U.S. dollar reporting company. As a result of the operations of the Kinder Morgan Canada-KMP business segment, a portion of our consolidated assets, liabilities, revenues and expenses are denominated in Canadian dollars. Fluctuations in the exchange rate between U.S. 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 stockholders' equity under applicable accounting rules.

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

Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the U.S. 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 U.S. or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.

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

Some of our pipelines, terminals and other assets are located in areas that are susceptible to hurricanes, earthquakes and other natural disasters. These natural disasters could potentially damage or destroy our pipelines, terminals and other assets and disrupt the supply of the products we transport through our pipelines. Natural disasters can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially.

KMP's and EPB's tax treatment depends on their status as partnerships for U.S. federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states. If KMP and/or EPB were treated as corporations for U.S. federal income tax purposes or if they were to become subject to a material amount of entity-level taxation for state tax purposes, then cash available for distribution to their partners, including us, would be substantially reduced.

We own the general partner interests in both KMP and EPB and approximately 11% and 41% of the limited partner interests of KMP and of EPB, respectively. The anticipated after-tax economic benefit of our investment in KMP and EPB depends largely on their treatment as partnerships for U.S. federal income tax purposes. Neither KMP nor EPB has requested nor plans to request a ruling from the IRS on this or any other tax matter.

Despite the fact that KMP and EPB are organized as limited partnerships under Delaware law, it is possible in certain circumstances for partnerships such as KMP or EPB to be treated as corporations for U.S. federal income tax purposes. Although neither KMP nor EPB believes, based on its current operations, that it is or will be so treated, the IRS could disagree with the positions KMP or EPB takes or a change in KMP's or EPB's business (or a change in current law) could cause them to be treated as corporations for U.S. federal income tax purposes or otherwise subject them to taxation as an entity.

If they were treated as corporations for U.S. federal income tax purposes, they would pay U.S. federal income tax on taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions by KMP and EPB to their partners, including us, would generally be taxed again as corporate dividends (to the extent of their current and accumulated earnings and profits) and no income, gains, losses, deductions or credits would flow through to their partners, including us. Because tax would be imposed on KMP and EPB as corporations, their after-tax cash



available for distribution would be substantially reduced, likely causing a substantial reduction in the dividends we could pay and in the value of our common stock.

The present U.S. federal income tax treatment of publicly traded partnerships, including KMP and EPB, or an investment in them may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Moreover, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that could affect the tax treatment of certain publicly traded partnerships. We are unable to predict whether any of these changes or other proposals will ultimately be enacted.

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. Any state income taxes imposed upon KMP or EPB as entities would reduce their cash available to be distributed to us. Any modification to the U.S. federal income or state tax laws, or interpretations thereof, may be applied retroactively and could negatively impact the value of our investment in KMP and EPB.

KMP's and EPB's partnership agreements provide that if a law is enacted that subjects them to corporate taxation or otherwise subjects them to entity-level taxation for U.S. federal income tax purposes, the minimum quarterly distribution amounts and the target distribution amounts will be adjusted to reflect the impact.

If KMP’s or EPB’s unitholders remove their respective general partner, we would lose our general partner interest in either KMP or EPB, including the right to incentive distributions, and the ability to manage them.

We own the general partners of KMP and EPB and with respect to KMP, all of the voting shares of KMR, to which the general partner has delegated its rights and powers to control the business and affairs of KMP, subject to the approval of the general partner for certain actions. KMP’s and EPB’s partnership agreements, however, give their respective unitholders the right to remove their general partner if (i) the holders of 66 2/3% of the respective partnership’s outstanding units (including the common units, Class B units and i-units, as applicable) voting as a single class vote for such removal; (ii) the holders of KMP’s and EPB’s outstanding units approve the election and succession of a new general partner by the same vote, respectively; and (iii) KMP and/or EPB receives opinion of counsel that the removal and succession of the general partner would not result in the loss of the limited liability of any limited partner or its operating partnership subsidiaries or cause either KMP or EPB or its operating partnership subsidiaries to be taxed as a corporation for federal income tax purposes.

If KMP’s or EPB’s unitholders removed their respective general partner, the general partner would lose its ability to manage KMP or EPB, and with respect to KMP, the delegation of authority to KMR by KMP’s general partner would terminate at the same time. The general partner would receive cash or common units in exchange for its general partner interest. While the cash or common units the general partner would receive are intended under the terms of KMP’s and EPB’s partnership agreements to fully compensate us, as the owner of the general partner, in the event such an exchange is required, the value of the investments we might make with the cash or the common units may not over time be equivalent to the value of the general partner interest and the related incentive distributions had the general partner retained its general partner interest.

If in the future KMR and the general partner cease to manage and control KMP, with respect to KMP and EPB’s general partner ceases to manage and control EPB either limited partnership may be deemed to be an investment company under the Investment Company Act of 1940.

If our subsidiaries, KMR and Kinder Morgan G.P., Inc., which is the general partner of KMP, cease to manage and control KMP, or, El Paso Pipeline GP, L.L.C. ceases to manage and control EPB, either or both KMP and EPB may be deemed to be investment companies under the Investment Company Act of 1940. In that case, KMP and/or EPB would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify their organizational structure or contractual rights so as to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and could adversely affect the price of our common stock.

If we are unable to retain our executive officers, our growth may be hindered.

Our success depends in part on the performance of and our ability to retain our executive officers, particularly our Chairman and Chief Executive Officer, Richard D. Kinder, who is also one of our founders. Along with the other members of our senior



management, Mr. Kinder has been responsible for developing and executing our growth strategy since 1997. If we are not successful in retaining Mr. Kinder or our other executive officers or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.

## Risks Related to the Ownership of Our Common Stock

The price of the common stock may be volatile, and holders of our common stock could lose a significant portion of their investments.

The market price of the common stock could be volatile, and our stockholders may not be able to resell their common stock at or above the price at which they purchased the common stock due to fluctuations in the market price of the common stock, including changes in price caused by factors unrelated to our operating performance or prospects.

Specific factors that may have a significant effect on the market price for the common stock include: (i) changes in stock market analyst recommendations or earnings estimates regarding the common stock, the common units of KMP and EPB, other companies comparable to us or KMP and EPB or companies in the industries we serve; (ii) actual or anticipated fluctuations in our operating results or future prospects; (iii) reaction to our public announcements; (iv) strategic actions taken by us or our competitors, such as acquisitions or restructurings; (v) the recruitment or departure of key personnel; (vi) new laws or regulations or new interpretations of existing laws or regulations applicable to our business and operations; (vii) changes in tax or accounting standards, policies, guidance, interpretations or principles; (viii) adverse conditions in the financial markets or general U.S. or international economic conditions, including those resulting from war, incidents of terrorism and responses to such events; (ix) sales of common stock by us, members of our management team or significant stockholders; and (x) the extent of analysts' interest in following our company.

Non-U.S. holders of our common stock may be subject to U.S. federal income tax with respect to gain on the disposition of our common stock.

If we are or have been a ‘‘U.S. real property holding corporation’’ within the meaning of the Code at any time within the shorter of (i) the five-year period preceding a disposition of our common stock by a non-U.S. holder, or (ii) such holder’s holding period for such common stock, and assuming our common stock is ‘‘regularly traded,’’ as defined by applicable U.S. Treasury regulations, on an established securities market, the non-U.S. holder may be subject to U.S. federal income tax with respect to gain on such disposition if it held more than 5% of our common stock during the shorter of periods (i) and (ii) above. We believe we are, or may become, a U.S. real property holding corporation.

## Risks Related to Our Dividend Policy

Holders of our common stock may not receive the anticipated level of dividends under our dividend policy or any dividends at all.

Our dividend policy provides that, subject to applicable law, we will pay quarterly cash dividends generally representing the cash we receive from our subsidiaries less any cash disbursements and reserves established by a majority vote of our board of directors, including for general and administrative expenses, interest and cash taxes. However, our board of directors, subject to the requirements of our bylaws and other governance documents, may amend, revoke or suspend our dividend policy at any time, and even while the current policy is in place, the actual amount of dividends on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, market opportunities, capital requirements of our subsidiaries, legal, regulatory and contractual constraints, tax laws and other factors. Dividends other than as provided in our dividend policy require supermajority board approval while the Sponsor Investors maintain prescribed ownership thresholds.

Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether we pay dividends and the amount of any dividends we may pay in the future. The terms of any future indebtedness we incur also may restrict us from paying cash dividends on our stock under certain circumstances. A decline in the market price or liquidity, or both, of our common stock could result if our board of directors establishes large reserves that reduce the amount of quarterly dividends paid or if we reduce or eliminate the payment of dividends. This may in turn result in losses by our stockholders, which could be substantial.

The general partners of KMP and EPB, with our consent but without the consent of our stockholders, may take steps to support KMP and EPB that have the effect of reducing cash we have or are entitled to receive, thereby reducing the cash we have available to pay dividends.



We utilize KMP and EPB as our vehicles for growth. We have historically received a significant portion of our cash flows from incentive distributions on the general partner interest. As the owner of the general partner of KMP, and now EPB, we may take steps we judge beneficial to KMP's and EPB's growth that in the short-run reduce the cash we receive and have available to pay dividends. The board of directors of the general partner of KMP or EPB may determine to support a desirable acquisition that may not be immediately accretive to cash available for distribution per the respective Partnership unit. For example, KMP's general partner, with our consent, waived its incentive distributions from the second quarter of 2010 through 2011 on common units issued to finance a portion of KMP's acquisition of the initial 50% interest in the KinderHawk joint venture and has agreed to waive its paid incentive distributions of $27 million and $4 million for 2012 and the first quarter of 2013, respectively, on common units issued to finance a portion of KMP's subsequent acquisition of the remaining 50% interest in the KinderHawk joint venture. In addition, in connection with KMP's proposed acquisition of Copano, KMP's general partner has agreed to waive incentive distributions in 2013 in an amount dependent on the time of closing, $120 million in both 2014 and 2015, $110 million in 2016 and annual amounts thereafter decreasing by $5 million per year from this level.

Our dividend policy may limit our ability to pursue growth opportunities above the limited partnership level or impair our financial flexibility.

If we pay dividends at the level currently anticipated under our dividend policy, we may not retain a sufficient amount of cash to finance growth opportunities above the limited partnership level, meet any large unanticipated liquidity requirements or fund our operations in the event of a significant business downturn. In addition, because of the dividends required under our dividend policy, our ability to pursue any material expansion of our business above the limited partnership level, including through acquisitions, increased capital spending or other increases of our expenditures, will depend more than it otherwise would on our ability to obtain third party financing. We cannot assure our stockholders that such financing will be available to us at all, or at an acceptable cost. If we are unable to take timely advantage of growth opportunities, our future financial condition and competitive position may be harmed, which in turn may adversely affect the market price of our common stock.

If we do not receive sufficient distributions from our subsidiaries, we may be unable to pay dividends.

All of our operations are conducted by our subsidiaries, and our cash flow and our ability to satisfy obligations and to pay dividends to our stockholders are dependent upon cash dividends and distributions or other transfers from our subsidiaries. In addition, our joint ventures and some of our subsidiaries, such as our limited partnerships, are not wholly owned by us. When funds are distributed to us by such joint ventures and subsidiaries, funds also will be distributed to their other owners.

Each of our subsidiaries is a distinct legal entity and has no obligation to transfer funds to us. A number of our subsidiaries are a party to credit facilities and are or may in the future be a party to other borrowing agreements that restrict the payment of dividends to us, and such subsidiaries are likely to continue to be subject to such restrictions and prohibitions for the foreseeable future. In addition, the ability of our subsidiaries to make distributions will depend on their respective operating results and may be subject to further restrictions under, among other things, the laws of their jurisdiction of organization.

The board of directors of KMR, which is the delegate of KMP’s general partner, and EPB’s general partner have broad authority to establish cash reserves for the prudent conduct of their businesses. The establishment of those reserves could result in smaller distributions to us and a corresponding reduction of our cash available for dividends and our anticipated dividend level. Further, the calculation of KMP’s and EPB’s available cash for distribution is discretionary and subject to the approval of the board of directors of KMR or EPB’s general partner, respectively taking into consideration their constituent agreements. Similarly, while the constituent agreements of NGPL provide that it is the intention of NGPL to make distributions of available cash, we own less than a majority of NGPL and do not control it. The same is true for joint ventures in which our limited partnerships own an interest.

The distributions we receive from KMP are largely attributable to the incentive distributions on our general partner interest. The distributions we receive are not as large if KMP distributes cash from interim capital transactions rather than cash from operations, or if KMP’s general partner waives receipt of a portion of those incentive distributions.

As a result of the foregoing, we may be unable to receive cash through distributions or other payments from our subsidiaries in sufficient amounts to pay dividends on our common stock. If we are unable to authorize the payment of dividends due to insufficient cash, a decline in the market price or liquidity, or both, of our common stock could result. This may in turn result in losses by our stockholders, which could be substantial.

Our ability to pay dividends is restricted by Delaware law.



Under the DGCL, our board of directors may not authorize payment of a dividend unless it is either paid out of surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, it is paid out of net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. Our bylaws require the declaration and payment of dividends to comply with the DGCL. If, as a result of these restrictions, we are unable to authorize payment of dividends, a decline in the market price or liquidity, or both, of our common stock could result. This may in turn result in losses by our stockholders.

## Risks Related to Conflicts of Interest

KMP, EPB and their subsidiaries may compete with us.

Neither of KMP, EPB or any of their subsidiaries or entities in which they own an interest is restricted from competing with us. KMR manages KMP (subject to certain decisions requiring the approval of KMP’s general partner) and EPB’s general partner manages EPB, in what they consider to be the best interests of their respective limited partner interests. KMP, EPB and their subsidiaries may acquire, invest in or construct assets that may be in direct competition with us, which could have a material adverse effect on our business, financial condition, results of operations or prospects. Among other things, we and our limited partnerships have a policy that acquisition opportunities of businesses or operating assets will be pursued above the limited partnership level only if KMP and EPB elect not to pursue the opportunity.

Many of our directors and officers also serve as directors or officers of our non-wholly owned subsidiaries, including KMR and EPB, or entities in which we own an interest, such as NGPL, as a result of which conflicts of interest exist and will arise in the future.

Many of our directors and officers are also directors or officers of our non-wholly owned subsidiaries. Any officer or director of our non-wholly owned subsidiaries, who is also a director or officer of ours, in making decisions in such person’s capacity as our officer or director, is required to act in accordance with his or her fiduciary duties to us. However, in making decisions in such person’s capacity as a director or officer of one of our non-wholly owned subsidiaries or such other entities, such person may make a decision that favors the interests of such subsidiary over our interests or the interests of our stockholders and may be to our detriment. Further, the organizational documents of these entities may have provisions reducing or eliminating the duties of their officers or directors to those entities and their owners, including us. In addition, our directors are not required to work full time on our business and affairs and may devote significant time to the affairs of our non-wholly owned subsidiaries. There could be material competition for the time and effort of our directors who provide services to our non-wholly owned subsidiaries.

## Item 1B. Unresolved Staff Comments.

None.

## Item 3. Legal Proceedings.

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

## Item 4. Mine Safety Disclosures.

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95.1 to this annual report.



## PART II

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

On February 16, 2011, we completed an initial public offering of our Class P common stock (see Notes 1 and 10 to our consolidated financial statements included elsewhere in this report) and our Class P common stock is listed for trading on the New York Stock Exchange under the symbol “KMI.” On December 26, 2012, the remaining outstanding shares of our Class A, Class B, and Class C common stock were converted into Class P shares and as of December 31, 2012 only our Class P common stock was outstanding. During the period that our Class A, Class B, and Class C common stock was outstanding, none were traded on a public trading market. The high and low sale prices per Class P share as reported on the New York Stock Exchange and the dividends declared per share by quarter since February 16, 2011, the date we became public, are provided below.

<table><tr><td rowspan="3"></td><td colspan="5">Price Range Per Class P Share</td><td rowspan="3">Declared Cash Dividends (a)</td></tr><tr><td colspan="2">Low</td><td colspan="2">High</td><td></td></tr><tr><td>2012</td><td></td><td></td><td></td><td></td></tr><tr><td>First Quarter</td><td>$</td><td>31.76</td><td>$</td><td>39.25</td><td>$</td><td>0.32</td></tr><tr><td>Second Quarter</td><td>$</td><td>30.51</td><td>$</td><td>40.25</td><td>$</td><td>0.35</td></tr><tr><td>Third Quarter</td><td>$</td><td>32.03</td><td>$</td><td>36.63</td><td>$</td><td>0.36</td></tr><tr><td>Fourth Quarter</td><td>$</td><td>31.93</td><td>$</td><td>36.50</td><td>$</td><td>0.37</td></tr><tr><td>2011</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>First Quarter (beginning February 11, 2011)(b)</td><td>$</td><td>29.50</td><td>$</td><td>32.14</td><td>$</td><td>0.14</td></tr><tr><td>Second Quarter</td><td>$</td><td>26.87</td><td>$</td><td>29.97</td><td>$</td><td>0.30</td></tr><tr><td>Third Quarter</td><td>$</td><td>23.51</td><td>$</td><td>29.45</td><td>$</td><td>0.30</td></tr><tr><td>Fourth Quarter</td><td>$</td><td>24.66</td><td>$</td><td>32.25</td><td>$</td><td>0.31</td></tr></table>

(a) Dividend information is for dividends declared with respect to that quarter. The declared dividends were paid within 45 days after the end of the quarter. We currently expect to declare cash dividends of $1.57 per share for 2013; however, no assurance can be given that we will be able to achieve this level of dividend.

(b) The declared cash dividend was prorated from February 16, 2011, the day we closed our initial public offering. Based on a full quarter, the dividend amounts to $0.29 per share.

As of January 31, 2013, we had 10,262 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank. Other than the warrant repurchase program discussed below, we did not repurchase any shares or sell any unregistered shares in the fourth quarter of 2012.

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 9 “Share-based Compensation and Employee Benefits—Share-based Compensation—Kinder Morgan, Inc.” to our consolidated financial statements included elsewhere in this report.



## Our Purchases of Our Warrants

<table><tr><td>Period</td><td>Total number of warrants repurchased \( ^{(a)} \)</td><td>Average price paid per warrant</td><td>Total number of warrants purchased as part of publicly announced plans \( ^{(a)} \)</td><td>Maximum number (or approximate dollar value) of warrants that may yet be purchased under the plans for programs</td></tr><tr><td>May 1 to May 31, 2012</td><td>10,738,183</td><td>2.01</td><td>10,738,183</td><td>228,303,786</td></tr><tr><td>June 1 to June 30, 2012</td><td>42,395,711</td><td>2.18</td><td>53,133,894</td><td>135,425,212</td></tr><tr><td>July 1 to July 31, 2012</td><td>—</td><td>—</td><td>53,133,894</td><td>135,425,212</td></tr><tr><td>August 1 to August 31, 2012</td><td>3,627,494</td><td>2.95</td><td>56,761,388</td><td>124,687,185</td></tr><tr><td>September 1 to September 30, 2012</td><td>3,833,418</td><td>3.41</td><td>60,594,806</td><td>111,581,803</td></tr><tr><td>October 1 to October 31, 2012</td><td>—</td><td>—</td><td>60,594,806</td><td>111,581,803</td></tr><tr><td>November 1 to November 30, 2012</td><td>2,379,079</td><td>3.45</td><td>62,973,885</td><td>103,344,829</td></tr><tr><td>December 1 to December 31, 2012</td><td>2,637,579</td><td>3.79</td><td>65,611,464</td><td>93,311,980</td></tr><tr><td>Total</td><td>65,611,464</td><td>3.63</td><td>65,611,464</td><td>93,311,980</td></tr></table>

(a) On May 23, 2012, we announced that our board of directors had approved a warrant repurchase program, authorizing us to repurchase in the aggregate up to $250 million of warrants. All purchases during the above periods were made pursuant to this publicly announced repurchase plan.

## Item 6. Selected Financial Data.

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



Five-Year Review
Kinder Morgan, Inc. and Subsidiaries

<table><tr><td rowspan="3"></td><td colspan="7">Year Ended December 31,</td></tr><tr><td>2012(a)</td><td colspan="2">2011</td><td colspan="2">2010</td><td>2009</td><td>2008</td></tr><tr><td colspan="7">(In millions, except per share and ratio data)</td></tr><tr><td>Revenues</td><td>$     9,973</td><td>$     7,943</td><td>$     7,852</td><td>$     6,879</td><td>$     11,716</td><td></td><td></td></tr><tr><td>Operating income (loss)(b)</td><td>$     2,593</td><td>$     1,423</td><td>$     1,133</td><td>$     1,257</td><td>$     2,044</td><td></td><td></td></tr><tr><td>Earnings (loss) from equity investments(c)</td><td>$     153</td><td>$     226</td><td>$     274</td><td>$     123</td><td>$     116</td><td></td><td></td></tr><tr><td>Income (loss) from continuing operations</td><td>$     1,204</td><td>$     449</td><td>$     64</td><td>$     523</td><td>$     2,860</td><td></td><td></td></tr><tr><td>(Loss) income from discontinued operations, net of tax</td><td>$     777</td><td>$     211</td><td>$     236</td><td>$     250</td><td>$     343</td><td></td><td></td></tr><tr><td>Net income (loss)</td><td>$     427</td><td>$     660</td><td>$     300</td><td>$     773</td><td>$     3,203</td><td></td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>$     112</td><td>$     66</td><td>$     341</td><td>$     278</td><td>$     396</td><td></td><td></td></tr><tr><td>Net income (loss) attributable to Kinder Morgan, Inc.</td><td>$     315</td><td>$     594</td><td>$     41</td><td>$     495</td><td>$     3,599</td><td></td><td></td></tr><tr><td>Class P Shares</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Continuing Operations</td><td>$     0.56</td><td>$     0.70</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations</td><td></td><td>(0.21)</td><td>0.04</td><td></td><td></td><td></td><td></td></tr><tr><td>Total Basic and Diluted Earnings Per Common Share</td><td>$     0.35</td><td>$     0.74</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Class A Shares</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Continuing Operations</td><td>$     0.47</td><td>$     0.64</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations</td><td></td><td>(0.21)</td><td>0.04</td><td></td><td></td><td></td><td></td></tr><tr><td>Total Basic and Diluted Earnings Per Common Share</td><td>$     0.26</td><td>$     0.68</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic Weighted Average Number of Shares Outstanding:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Class P shares</td><td></td><td>461</td><td>118</td><td></td><td></td><td></td><td></td></tr><tr><td>Class A shares</td><td></td><td>446</td><td>589</td><td></td><td></td><td></td><td></td></tr><tr><td>Diluted Weighted Average Number of Shares Outstanding:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Class P shares</td><td></td><td>908</td><td>708</td><td></td><td></td><td></td><td></td></tr><tr><td>Class A shares</td><td></td><td>446</td><td>589</td><td></td><td></td><td></td><td></td></tr><tr><td>Dividends per common share declared(d)</td><td>$     1.40</td><td>$     1.05</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures - KMI</td><td>$     148</td><td>$     1</td><td>$     2</td><td>$     12</td><td></td><td></td><td></td></tr><tr><td>Capital expenditures - KMP</td><td>$     1,806</td><td>$     1,199</td><td>$     1,004</td><td>$     12,534</td><td>$     2,533</td><td></td><td></td></tr><tr><td>Capital expenditures - EPB (since May 25, 2012)</td><td>$     68</td><td>$     1.99</td><td>$     1.75</td><td>$     2.14</td><td></td><td></td><td></td></tr><tr><td>Ratio of earnings to fixed charges(e)</td><td>$     2.47</td><td>$     1.99</td><td>$     1.75</td><td>$     2.14</td><td></td><td></td><td></td></tr></table>

<table><tr><td rowspan="3"></td><td colspan="6">December 31,</td></tr><tr><td>2012(a)</td><td colspan="2">2011</td><td colspan="2">2010</td><td>2009</td></tr><tr><td colspan="6">(In millions)</td></tr><tr><td>Net property, plant and equipment</td><td>$     30,996</td><td>$     17,926</td><td>$     17,071</td><td>$     16,804</td><td>$     16,110</td><td></td></tr><tr><td>Total assets</td><td>$     68,185</td><td>$     30,717</td><td>$     28,908</td><td>$     27,581</td><td>$     25,445</td><td></td></tr><tr><td>Long-term debt - KMI(f)</td><td>$     10,441</td><td>$     2,078</td><td>$     2,918</td><td>$     2,925</td><td>$     2,927</td><td></td></tr><tr><td>Long-term debt - KMP(g)</td><td>$     14,714</td><td>$     11,183</td><td>$     10,301</td><td>$     10,022</td><td>$     8,293</td><td></td></tr><tr><td>Long-term debt - EPB(h)</td><td>$     4,254</td><td>$     1.99</td><td>$     1.75</td><td>$     2.14</td><td></td><td></td></tr></table>

(a) Includes amounts of EP subsequent to May 25, 2012 acquisition.



## Item 6. Selected Financial Data. (continued)

(b) Includes a non-cash goodwill impairment charge of $3,451 million in 2008 related to our interest in KMP.

(c) Includes a non-cash impairment charge of $200 million and $430 million, respectively, in 2012 and 2010 to reduce the carrying value of our investment in NGPL Holdco LLC.

(d) Year ended December 31, 2011 dividend per share has been prorated for the portion of the first quarter we were a public company ($0.14 per share). If we had been a public company for the entire year, the year to date declared dividend would have been $1.20 per share ($0.29 per share, $0.30 per share, $0.30 per share and $0.31 per share for the first, second, third and fourth quarter of 2011, respectively).

(e) For the purpose of computing the ratio of earnings to fixed charges, earnings are defined as income from continuing operations before income taxes, and before non-controlling interests in pre-tax income of consolidated subsidiaries with no fixed charges, equity earnings (including amortization of excess cost of equity investments) and unamortized capitalized interest, plus fixed charges and distributed income of equity investees. Fixed charges are defined as the sum of interest on all indebtedness (excluding capitalized interest), amortization of debt issuance costs and that portion of rental expense which we believe to be representative of an interest factor. Also, for the year ended December 31, 2008 fixed charges exceeded earnings by $3,264 million primarily due to non-cash goodwill impairment charge discussed above in footnote (b).

(f) Excludes debt fair value adjustments. Increases (decreases) to long-term debt for debt fair value adjustments for KMI and its subsidiaries (excluding KMP, EPB and their subsidiaries) totaled $1,138 million, $40 million, $12 million, $2 million and $26 million as of December 31, 2012, 2011, 2010, 2009 and 2008, respectively.

(g) Excludes debt fair value adjustments. Increases to long-term debt for debt fair value adjustments totaled $1,461 million, $1,055 million, $582 million, $308 million and $93 million as of December 31, 2012, 2011, 2010, 2009 and 2008, respectively.

(h) Excludes debt fair value adjustments. Decrease to long-term debt for debt fair value adjustments totaled $8 million as of December 31, 2012.



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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this report. Additional sections in our Annual Report on Form 10-K for the year ended December 31, 2012, referred to as the 2012 Form 10-K, 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 2012, 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.”

We prepared our consolidated financial statements in accordance with U.S. generally accepted accounting principles. Accordingly, as discussed in Notes 1, 2, and 3 to our consolidated financial statements included elsewhere in this report, our financial statements reflect:

- Effective May 25, 2012, we completed our previously announced acquisition of all of the outstanding shares of El Paso Corporation, a Delaware corporation referred to as EP in this report. EP owns one of North America’s largest interstate natural gas pipeline systems and an emerging midstream business. EP also owns a 41% limited partner interest and the 2% general partner interest in El Paso Pipeline Partners, L.P., referred to as EPB in this report. Our acquisition of EP created one of the largest energy companies in the U.S.; and

- The reclassifications necessary to reflect the results of KMP’s FTC Natural Gas Pipelines disposal group as discontinued operations. Accordingly, we have excluded the disposal group’s financial results from the Natural Gas Pipelines business segment disclosures for the periods presented in this report.

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

## General

Our business model, through our ownership and operation of energy related assets, is built to support two principal components:

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

• creating long-term value for our shareholders.

To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, natural gas storage, processing and treating facilities, and bulk and liquids terminal facilities. We also produce and sell crude oil. Our reportable business segments are based on the way our management organizes our enterprise, and each of our business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.

Our reportable business segments are:

- Natural Gas Pipelines-For all periods presented in our financial statements this segment consists of approximately 62,000 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 and equity earnings from our 20% interest in NGPL Holdco LLC. Following our May 25, 2012 EP acquisition, this segment also includes the natural gas operations of EP, its subsidiaries (including EPB) and its equity investments;



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

• 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 transmissivity facilities;

- CO2-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 and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;

• Terminals-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 transmissivity facilities;

- Kinder Morgan Canada-KMP-the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the U.S.; and

- Other-In 2010, this segment primarily consisted of our Power facility which was sold on October 22, 2010. Following our May 25, 2012 EP acquisition, this segment primarily includes several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028. This segment also included an interest in the Bolivia to Brazil Pipeline, which we sold for $88 million on January 18, 2013.

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

With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity. Similarly, in KMP's Texas Intrastate Natural Gas Group, it currently derives approximately 75% of its sales and transport margins from long-term transport and sales contracts that include requirements with minimum volume payment obligations. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2012, the remaining average contract life of our combined natural gas transportation contracts (including intrastate pipelines' purchase and sales contracts) was approximately seven years.

The  \( CO_{2} \)  sales and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2012, had a remaining average contract life of approximately 10 years. Carbon dioxide sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries in 2013, and utilizing the average oil price per barrel contained in our 2013 budget, approximately 72% of our contractual volumes are based on a fixed fee or floor price, and 28% fluctuate with the price of oil. In the long-term, our success in this portion of the  \( CO_{2} \) -KMP business segment is driven by the demand for carbon dioxide. However, short-term changes in the demand for carbon dioxide typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In the  \( CO_{2} \) -KMP business segment's oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. In that regard, our production during any period is an important measure. In addition, the revenues we receive from our crude oil, natural gas liquids and carbon dioxide sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging,



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

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. The realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $87.72 per barrel in 2012, $69.73 per barrel in 2011 and $59.96 per barrel in 2010. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $89.91 per barrel in 2012, $92.61 per barrel in 2011 and $76.93 per barrel in 2010.

The factors impacting the Terminals-KMP business segment generally differ depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored. As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. While we handle and store a large variety of products in our bulk terminals, the primary products are coal, petroleum coke, and steel. For the most part, we have contracts for this business that have minimum volume guarantees and are volume based above the minimums. Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions. Our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity. Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts (which on average is approximately four years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.

In our discussions of the operating results of individual businesses that follow (see “-Results of Operations” below), we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods.

Continuing our history of making accretive acquisitions and economically advantageous expansions of existing businesses, in 2012, we completed the acquisition of EP, implemented year-one post acquisition cost savings of more than $400 million, sold EP's Exploration and Production assets immediately prior to the acquisition close date, dropped down the EP acquired assets of TGP and our 50% interest in EPNG to KMP using proceeds from this drop-down to de-lever KMI's outstanding EP acquisition debt, sold the FTC mandated KMP Natural Gas Pipelines disposal group and EP completed its drop down of the Cheyenne Plains Gas Pipeline Company, L.L.C. to EPB on May 24, 2012. Exclusive of the drops downs, during 2012, KMP and EPB (from May 25, 2012 through December 31, 2012) have made business acquisitions and expansions of existing assets of $2.1 billion and $41 million, respectively.

Thus, the amount that we are able to increase dividends to our shareholders will, to some extent, be a function of our and our subsidiaries’ ability to complete successful acquisitions and expansions (including those completed by KMP and EPB). We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $3.1 billion for our combined 2013 capital expansion program (including small acquisitions and investment contributions, but excluding the proposed Copano acquisition discussed under items 1 and 2 “Business and Properties - Recent Developments - Natural Gas Pipelines - KMP”). We and our subsidiaries, KMP and EPB, regularly consider and enter into discussions regarding potential acquisitions, including those from us or our affiliates, and are currently contemplating potential acquisitions including:

- On January 29, 2013, KMP and Copano Energy, L.L.C. announced a definitive agreement whereby KMP will acquire all of Copano’s outstanding units, including convertible preferred units, for a total purchase price of approximately $5 billion, including the assumption of debt. The transaction is subject to customary closing conditions, regulatory approvals, and a vote of the Copano unitholders; however, TPG Advisors VI, Inc., Copano’s largest unitholder, has agreed to support the transaction and we expect the transaction to close in the third quarter of 2013.

- The acquisition of Copano is expected to be accretive to cash available for distribution to KMP’s unitholders, and it is expected to be accretive to our cash available to pay dividends, upon closing. We, as the parent of KMP’s general partner, have agreed to forego a portion of our incremental incentive distributions in 2013 in an amount dependent on the time of closing. Additionally, we intend to forgo incentive distribution amounts of $120 million in 2014, $120 million in 2015, $110 million in 2016 and annual amounts thereafter decreasing by $5 million per year from this level. The



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

transaction is expected to be modestly accretive to KMP in 2013, given the partial year, and about $0.10 per unit accretive for at least the next five years beginning in 2014.

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. Our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates at the right cost, and includes factors over which we have limited or no control. Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates.

Our, or our subsidiaries’ (including EPB and KMP), ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions. As master limited partnerships, KMP and EPB distribute all of their available cash, and they access capital markets to fund acquisitions and asset expansions. Historically, KMP and EPB have succeeded in raising necessary capital in order to fund their acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that KMP’s and EPB’s stable cash flows, credit ratings, and historical records of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required. For a further discussion of our liquidity, including KMP’s and EPB’s public debt and equity offerings in 2012, please see “-Liquidity and Capital Resources” below.

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

## KMI Dividends

Our board of directors has adopted the dividend policy set forth in our shareholders’ agreement, which provides that, subject to applicable law, we will pay quarterly cash dividends on all classes of our capital stock equal to the cash we receive from our subsidiaries and other sources less any cash disbursements and reserves established by a majority vote of our board of directors, including for general and administrative expenses, interest and cash taxes. The division of our dividends among our classes of capital stock is in accordance with our charter. Our board of directors may declare dividends by a majority vote in accordance with our dividend policy pursuant to our bylaws. This policy reflects our judgment that our stockholders would be better served if we distributed to them a substantial portion of our cash. As a result, we may not retain a sufficient amount of cash to fund our operations or to finance unanticipated capital expenditures or growth opportunities, including acquisitions.

<table><tr><td>Three months ended</td><td>Total quarterly dividend per share</td><td>Date of declaration</td><td>Date of record</td><td>Date of dividend</td></tr><tr><td>December 31, 2011</td><td>$ 0.31</td><td>January 18, 2012</td><td>January 31, 2012</td><td>February 15, 2012</td></tr><tr><td>March 31, 2012</td><td>$ 0.32</td><td>April 18, 2012</td><td>April 30, 2012</td><td>May 16, 2012</td></tr><tr><td>June 30, 2012</td><td>$ 0.35</td><td>July 18, 2012</td><td>July 31, 2012</td><td>August 15, 2012</td></tr><tr><td>September 30, 2012</td><td>$ 0.36</td><td>October 17, 2012</td><td>October 31, 2012</td><td>November 15, 2012</td></tr><tr><td>December 31, 2012</td><td>$ 0.37</td><td>January 16, 2013</td><td>January 31, 2013</td><td>February 15, 2013</td></tr></table>

As shown in the table above, we declared dividends of $1.40 per share for 2012, a 17% increase over our 2011 declared dividends of $1.20 per share (the 2011 per share amounts are presented as if we were publicly traded for all of 2011). We expect to declare dividends of $1.57 per share for 2013, a 12% increase over our 2012 declared dividends. Growth in 2013 is expected to be driven by continued strong performance at KMP, along with contributions from EPB and the natural gas assets that KMI acquired in the EP transaction. As presented in the following tables, during the years ended December 31, 2012 and 2011, we generated cash available to pay dividends of $1,411 million (cash available per share of $1.55) and $866 million (cash available per share of $1.22), respectively.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

On December 26, 2012, the remaining outstanding shares of our Class A, Class B, and Class C common stock were converted into Class P shares and as of December 31, 2012 only our Class P common stock was outstanding. Prior to the above common stock conversions, dividends on our Class A, Class B and Class C common stock (investor retain stock) generally were paid at the same time as dividends on our common stock and were based on the aggregate number of shares of common stock into which our investor retained stock was convertible on the record date for the applicable dividend. The portion of our dividends payable on the three classes of our investor retained stock varied among those classes, but the variations did not affect the dividends we paid on our common stock since the total number of shares of common stock into which our investor retained stock could convert in the aggregate was fixed on the closing of our initial public offering.

Our board of directors may amend, revoke or suspend our dividend policy at any time and for any reason. There is nothing in our dividend policy or our governing documents that prohibits us from borrowing to pay dividends. The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, market opportunities, our capital requirements, legal, regulatory and contractual constraints, tax laws and other factors. In particular, distributions received from KMP continue to be the most significant source of our cash available to pay dividends. Our ability to pay and increase dividends to our stockholders is primarily dependent on distributions received from KMP and EPB.

Our dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. We pay our dividends after we receive quarterly distributions from KMP and EPB, which are paid within 45 days after the end of each quarter, generally on or about the 15th day of each February, May, August and November. Therefore, our dividend generally will be paid on or about the 16th day of each February, May, August and November. If the day after we receive KMP’s and EPB’s distributions is not a business day, we expect to pay our dividend on the business day immediately following.

Cash Available to Pay Dividends

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td></tr><tr><td>KMP distributions to us</td><td></td><td></td></tr><tr><td>From ownership of general partner interest (a)</td><td>$ 1,454</td><td>$ 1,217</td></tr><tr><td>On KMP units owned by us (b)</td><td>120</td><td>100</td></tr><tr><td>On KMR shares owned by us (c)</td><td>73</td><td>63</td></tr><tr><td>Total KMP distributions to us (d)</td><td>1,647</td><td>1,380</td></tr><tr><td>EPB distributions to us</td><td></td><td></td></tr><tr><td>From ownership of general partner interest (e)</td><td>118</td><td>—</td></tr><tr><td>On EPB units owned by us (f)</td><td>157</td><td>—</td></tr><tr><td>Total EPB distributions to us</td><td>275</td><td>—</td></tr><tr><td>NGPL cash available for distribution to us (d)</td><td>11</td><td>30</td></tr><tr><td>Total cash generated</td><td>1,933</td><td>1,410</td></tr><tr><td>General and administrative expenses and sustaining capital expenditures</td><td>(18)</td><td>(9)</td></tr><tr><td>Interest expense</td><td>(181)</td><td>(167)</td></tr><tr><td>Cash available to pay dividends before cash taxes</td><td>1,734</td><td>1,234</td></tr><tr><td>Cash taxes(g)</td><td>(419)</td><td>(368)</td></tr><tr><td>Subtotal - Cash available to pay dividends (d)</td><td>1,315</td><td>866</td></tr><tr><td>EP&#x27;s cash available for distribution</td><td></td><td></td></tr><tr><td>EP operations - EBITDA (h)</td><td>518</td><td>—</td></tr><tr><td>Interest expense (i)</td><td>(315)</td><td>—</td></tr><tr><td>EP general and administrative expenses</td><td>(37)</td><td>—</td></tr><tr><td>Sustaining capital expenditures (j)</td><td>(70)</td><td>—</td></tr><tr><td>EP&#x27;s net cash available (k)</td><td>96</td><td>—</td></tr><tr><td>Total - Consolidated cash available to pay dividends (l)</td><td>$ 1,411</td><td>$ 866</td></tr></table>



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

(a) Based on (i) KMP distributions of $4.98 and $4.61 per common unit declared for the years ended December 31, 2012 and 2011, respectively; (ii) 340 million and 319 million aggregate common units, Class B units and i-units (collectively, KMP units) outstanding as of April 30, 2012 and April 29, 2011, respectively; (iii) 347 million and 330 million aggregate KMP units outstanding as of July 31, 2012 and July 29, 2011, respectively; (iv) 365 million and 333 million aggregate KMP units outstanding as of October 31, 2012 and 2011, respectively; (v) 373 million and 336 million aggregate KMP units outstanding as of January 31, 2013 and 2012, respectively, and (vi) waived incentive distributions of $26 million and $29 million for the years ended December 31, 2012 and 2011, respectively. In conjunction with KMP's acquisition of its initial 50% interest in May 2010, and subsequently, the remaining 50% interest in May 2011 of KinderHawk, we as general partner of KMP have agreed to waive receipt of a portion of our incentive distributions related to this investment from the first quarter of 2010 through the first quarter of 2013.

(b) Based on 26 million KMP units owned by us for the six months ended December 31, 2012 and 22 million KMP units owned by us in the prior periods multiplied by the KMP per unit distribution declared, as outlined in footnote (a) above.

(c) Assumes that we sold the KMR shares that we received as distributions for the years ended December 31, 2012 and 2011, respectively. We did not sell any KMR shares in 2012 or 2011. We intend periodically to sell the KMR shares we receive as distributions to generate cash.

(d) 2011 KMP distributions to us have been presented on a declared basis and NGLP amounts have been presented on a cash available basis to be consistent with the current year presentation.

(e) Based on (i) EPB distributions of $1.74 per common unit declared for the nine months ended December 31, 2012 and (ii) 208 million, 216 million and 216 million common units outstanding as of July 31, 2012, October 31, 2012 and January 31, 2013, respectively.

(f) Based on 90 million EPB units owned by us multiplied by the EPB per unit distribution declared, as outlined in footnote (e) above.

(g) Cash taxes were calculated based on the income and expenses included in the table, deductions related to the income included, and $200 million use of our net operating loss carryforwards.

(h) Includes an add back for our share of depreciation expense incurred by our equity investees.

(i) 2012 includes interest associated with our incremental debt issued to finance the cash portion of the EP acquisition purchase price as well as EP consolidated interest expense, excluding EPB. EP interest expense is shown on an accrual basis (rather than a cash basis, as KMI is shown). Due to the timing of the EP cash interest payments, more than 7/12 of the payments occur after May 24.

(j) Includes our share of sustaining capital expenditures incurred by our equity investees.

(k) Represents cash available from EP, exclusive of EPB operations for the period after May 25, 2012 and EP assets dropped down to KMP in the third quarter of 2012.

(l) Excludes $310 million in after-tax expenses associated with the EP acquisition and El Paso Energy (EPE) sale for the year ended December 31, 2012. This includes (i) $101 million in employee severance, retention and bonus costs; (ii) $55 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million write-off associated with the EP acquisition (primarily due to debt repayments) or amortization of capitalized financing fees; (v) $51 million for legal fees and reserves, net of recoveries; and (vi) $19 million benefit associated with pension income.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Reconciliation of Cash Available to Pay Dividends from Income from Continuing Operations (In millions)

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Income from continuing operations (a)</td><td>$ 1,204</td><td>$ 449</td><td></td></tr><tr><td>Income from discontinued operations (a)</td><td>160</td><td>211</td><td></td></tr><tr><td>Income attributable to EPB (b)</td><td>(37)</td><td>—</td><td></td></tr><tr><td>Distributions declared by EPB (b)</td><td>82</td><td>—</td><td></td></tr><tr><td>Depreciation, depletion and amortization (c)</td><td>1,426</td><td>1,092</td><td></td></tr><tr><td>Amortization of excess cost of equity investments (a)</td><td>23</td><td>7</td><td></td></tr><tr><td>Earnings from equity investments (d)</td><td>(223)</td><td>(313)</td><td></td></tr><tr><td>Distributions from equity investments</td><td>381</td><td>287</td><td></td></tr><tr><td>Distributions from equity investments in excess of cumulative earnings</td><td>200</td><td>236</td><td></td></tr><tr><td>KMP certain items (e)</td><td>92</td><td>493</td><td></td></tr><tr><td>EP acquisition related costs (f)</td><td>463</td><td>—</td><td></td></tr><tr><td>EP certain items (g)</td><td>19</td><td>—</td><td></td></tr><tr><td>KMI deferred tax adjustment (h)</td><td>(57)</td><td>—</td><td></td></tr><tr><td>Difference between cash and book taxes</td><td>(264)</td><td>(32)</td><td></td></tr><tr><td>Difference between cash and book interest expense for KMI</td><td>23</td><td>(1)</td><td></td></tr><tr><td>Sustaining capital expenditures (i)</td><td>(393)</td><td>(213)</td><td></td></tr><tr><td>KMP declared distribution on its limited partner units owned by the public (j)</td><td>(1,583)</td><td>(1,357)</td><td></td></tr><tr><td>EPB declared distribution on its limited partner units owned by the public (k)</td><td>(214)</td><td>—</td><td></td></tr><tr><td>Difference between equity investment distributable cash flow and earnings (l)</td><td>160</td><td>4</td><td></td></tr><tr><td>Other (m)</td><td>(51)</td><td>3</td><td></td></tr><tr><td>Cash available to pay dividends (n)</td><td>$ 1,411</td><td>$ 866</td><td></td></tr></table>

(a) Consists of the corresponding line items in our consolidated statements of income included elsewhere in this report.

(b) On May 25, 2012, we began recognizing income from our investment in EPB, and we received in the third quarter the full distribution for the second quarter as we were the holder of record as of July 31, 2012.

(c) Consists of the following:

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Depreciation, depletion and amortization from continuing operations</td><td>$ 1,419</td><td>$ 1,068</td><td></td></tr><tr><td>Depreciation, depletion and amortization from discontinued operations</td><td>$ 7</td><td>$ 24</td><td></td></tr></table>

(d) Consists of the following:

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Earnings from equity investments from continuing operations (1)</td><td>$ (153)</td><td>$ (226)</td><td></td></tr><tr><td>Earnings from equity investments from discontinued operations</td><td>$ (70)</td><td>$ (87)</td><td></td></tr></table>

(1) 2012 includes a $200 million non-cash impairment charge on our NGPL investment, see Note 6 to our consolidated financial statements included elsewhere in this report.

(e) Consists of items such as hedge ineffectiveness, legal and environmental reserves, gain/loss on sale, insurance proceeds from casualty losses, and asset disposition expenses. 2011 includes (i) $167 million non-cash loss on remeasurement of KMP’s previously held equity interest in KinderHawk to fair value; (ii) $234 million increase to KMP’s legal reserve attributable to rate case and other litigation involving KMP’s products pipelines on the West Coast and (iii) KMP’s portion ($87 million) of a $100 million special bonus expense for non-senior employees, which KMP is required to recognize in accordance with GAAP. However, KMP had no obligation,



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

nor did it pay any amounts in respect to such bonuses. The cost of the $100 million special bonus to non-senior employees was not borne by our Class P shareholders. In May of 2011 we paid for the $100 million of special bonuses, which included the amounts allocated to KMP, using $64 million (after-tax) in available earnings and profits reserved for this purpose and not paid in dividends to our Class A shareholders. KMP adds back these certain items in its calculation of distributable cash flow used to determine its distribution.

(f) Includes pre-tax expenses associated with the EP acquisition and EPE sale. 2012 includes (i) $160 million in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $108 million write-off (primarily due to repayments) or amortization of capitalized financing fees; (v) $68 million for legal fees and reserves, net of recoveries and (vi) $29 million benefit associated with pension income.

(g) Legacy marketing contracts and associated interest.

(h) Primarily due to a reduction of FIN 48 income tax reserves.

(i) We define sustaining capital expenditures as capital expenditures that do not expand the capacity of an asset.

(j) Declared distribution multiplied by limited partner units outstanding on the applicable record date less units owned by us. Includes distributions on KMR shares. KMP must generate the cash to cover the distributions on the KMR shares, but those distributions are paid in additional shares and KMP retains the cash. We do not have access to that cash.

(k) Declared distribution multiplied by EPB limited partner units outstanding on the applicable record date less units owned by us.

(l) Consists of the difference between cash available for distributions and earnings from our equity investments primarily related to equity investee depreciation, depletion and amortization expense.

(m) Consists of items such as timing and other differences between earnings and cash, KMP’s and EPB’s cash flow in excess of their distributions, non-cash purchase accounting adjustments related to the EP acquisition and going private transaction primarily associated with non-cash amortization of debt fair value adjustments, and in the year ended 2011 KMP’s crude hedges, and KMI certain items, which includes for the first quarter of 2011, KMI’s portion ($13 million) of the special bonus as described in footnote (e) above.

(n) 2011 KMP distributions to us have been presented on a declared basis and NGPL amounts have been presented on a cash available basis to be consistent with the current year presentation.

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

In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining (i) the economic useful lives of our assets; (ii) the fair values used to assign purchase price from business combinations, determine possible asset impairment charges, and calculate the annual goodwill impairment test; (iii) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (iv) provisions for uncollectible accounts receivables; (v) exposures under contractual indemnifications; and (vi) unbilled revenues.

For a summary of our significant accounting policies, see Note 2 to our consolidated financial statements included elsewhere in this report. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.

## Acquisition Method of Accounting

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values (with limited exceptions) on the date of acquisition. Determining the fair value of these items requires management's judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 to our consolidated financial statements included elsewhere in this report.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## Environmental Matters

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

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

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

## Legal Matters

Many of our operations are regulated by various U.S. and Canadian regulatory bodies and we are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred; accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur, and may 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, 2012, KMP’s most significant ongoing litigation proceedings involved its West Coast Products Pipelines. Transportation rates charged by certain of these pipeline systems are subject to proceedings at the FERC and the CPUC involving shipper challenges to the pipelines’ interstate and intrastate (California) rates, respectively. For more information on regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report.

## Intangible Assets

Intangible assets are those assets which provide future economic benefit but have no physical substance. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate our goodwill for impairment on May 31 of each year. There were no impairment charges resulting from our May 31, 2012 impairment testing, and no event indicating an impairment has occurred subsequent to that date. For more information on our goodwill, see Notes 2 and 7 to our consolidated financial statements included elsewhere in this report.

Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets. For more information on our amortizable intangibles, see Note 7 to our consolidated financial statements included elsewhere in this report.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## 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 and our measures of discounted future net cash flows from oil and gas reserves, please see “Supplemental Information on Oil and Gas Activities (Unaudited)” included elsewhere in this report.

## Hedging Activities

We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives. According to the provisions of U.S. generally accepted accounting principles, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately.

Since it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices—a perfectly effective hedge—we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all. But because the part of such hedging transactions that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations; accordingly, our financial statements may reflect some volatility due to these hedges. For more information on our hedging activities, see Note 13 to our consolidated financial statements included elsewhere in this report.

## Employee Benefit Plans

We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2012, our pension plans were underfunded by $552 million and our other postretirement benefits plans were underfunded by $426 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We select our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. The selection of these assumptions is further discussed in Note 9 to our consolidated financial statements included elsewhere in this report.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. We record these deferred amounts as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations. As of December 31, 2012, we had deferred net losses of approximately $290 million in pretax accumulated other comprehensive income related to our pension and other postretirement benefits.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2012:

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">Other Postretirement Benefits</td></tr><tr><td>Net Benefits Cost</td><td colspan="2">Change in Funded Status and Pretax Accumulated Other Comprehensive Income</td><td>Net Benefits Cost</td><td colspan="2">Change in Funded Status and Pretax Accumulate Other Comprehensive Income</td></tr><tr><td></td><td></td><td></td><td>(1 million)</td><td></td><td></td><td></td></tr><tr><td>One percent increase in:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rates</td><td>$     4</td><td>$     245</td><td>$     1</td><td>$     56</td><td></td><td></td></tr><tr><td>Expected return on plan assets</td><td>$      (14)</td><td>$      —</td><td>$      (1)</td><td>$      —</td><td></td><td></td></tr><tr><td>Rate of compensation increase</td><td>$     1</td><td>$      (6)</td><td>$      —</td><td>$      —</td><td></td><td></td></tr><tr><td>Health care cost trends</td><td>$      —</td><td>$      —</td><td>$     1</td><td>$      (47)</td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>One percent decrease in:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rates</td><td>$      (6)</td><td>$      (291)</td><td>$      (2)</td><td>$      (66)</td><td></td><td></td></tr><tr><td>Expected return on plan assets</td><td>$     14</td><td>$      —</td><td>$     1</td><td>$      —</td><td></td><td></td></tr><tr><td>Rate of compensation increase</td><td>$      (1)</td><td>$     6</td><td>$      —</td><td>$      —</td><td></td><td></td></tr><tr><td>Health care cost trends</td><td>$      —</td><td>$      —</td><td>$      (1)</td><td>$     41</td><td></td><td></td></tr></table>

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 KMP. 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 KMP.

## Going Private Transaction

A Going Private Transaction completed in May 2007 was accounted for as a purchase business combination. Accordingly, our assets and liabilities were 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.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## Results of Operations

Consolidated

<table><tr><td rowspan="3"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td colspan="4">(In millions)</td></tr><tr><td>Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines</td><td>$     2,174</td><td>$     563</td><td>$     169</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td>668</td><td>461</td><td>497</td><td></td></tr><tr><td>CO2—KMP</td><td>1,322</td><td>1,117</td><td>1,018</td><td></td></tr><tr><td>Terminals—KMP</td><td>708</td><td>702</td><td>640</td><td></td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>229</td><td>202</td><td>182</td><td></td></tr><tr><td>Other</td><td>7</td><td>—</td><td>4</td><td></td></tr><tr><td>Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(b)</td><td>5,108</td><td>3,045</td><td>2,510</td><td></td></tr><tr><td>Depreciation, depletion and amortization expense</td><td>(1,419)</td><td>(1,068)</td><td>(1,056)</td><td></td></tr><tr><td>Amortization of excess cost of equity investments</td><td>(23)</td><td>(7)</td><td>(6)</td><td></td></tr><tr><td>Other revenues</td><td>35</td><td>36</td><td>51</td><td></td></tr><tr><td>General and administrative expenses(c)</td><td>(929)</td><td>(515)</td><td>(631)</td><td></td></tr><tr><td>Unallocable interest and other, net(d)</td><td>(1,441)</td><td>(701)</td><td>(652)</td><td></td></tr><tr><td>Income from continuing operations before income taxes</td><td>1,331</td><td>790</td><td>216</td><td></td></tr><tr><td>Unallocable income tax expense</td><td>(127)</td><td>(341)</td><td>(152)</td><td></td></tr><tr><td>Income from continuing operations</td><td>1,204</td><td>449</td><td>64</td><td></td></tr><tr><td>(Loss) income from discontinued operations, net of tax(e)</td><td>(777)</td><td>211</td><td>236</td><td></td></tr><tr><td>Net income</td><td>427</td><td>660</td><td>300</td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>(112)</td><td>(66)</td><td>(341)</td><td></td></tr><tr><td>Net income (loss) attributable to Kinder Morgan, Inc.(f)</td><td>$     315</td><td>$     594</td><td>$      (41)</td><td></td></tr></table>

(a) Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. Allocable income tax expenses included in segment earnings for the years ended December 31, 2012, 2011 and 2010 were $12 million, $20 million and $14 million, respectively.

(b) 2012, 2011 and 2010 amounts include decreases in earnings of $285 million, $374 million and $576 million, respectively, related to the combined effect from the 2012, 2011 and 2010 certain items disclosed below in our management discussion and analysis of segment results.

(c) 2012, 2011 and 2010 amounts include increases in expense of $400 million, $127 million and $268 million, respectively, related to the combined effect from the 2012, 2011 and 2010 certain items related to general and administrative expenses disclosed below in “General and Administrative, Interest, and Noncontrolling Interests”.

(d) 2012 and 2010 amounts include increases in expense of $128 million and $1 million, respectively, related to the combined effect from the 2012 and 2010 certain items related to interest expense disclosed below in “General and Administrative, Interest, and Noncontrolling Interests”. Also, 2010 amount includes a gain of $16 million related to the sale of Triton Power on October 22, 2010.

(e) Represents amounts primarily attributable to KMP’s FTC Natural Gas Pipelines disposal group. 2012 amount includes a combined $937 million loss from the remeasurement of net assets to fair value and the disposal of net assets. 2011 amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011.

(f) 2010 amount includes a reduction of approximately $107 million (after-tax) in the income we recognized from our interest in the general partner due to a KMP interim capital transaction.

Year Ended December 31, 2012 vs. 2011

Our total revenues for 2012 and 2011 were $10.0 billion and $7.9 billion, respectively. Net income attributable to Kinder Morgan, Inc.'s stockholders totaled $315 million for 2012 as compared to net income of $594 million in 2011.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

For 2012, our net income attributable to Kinder Morgan, Inc. was impacted by (i) $310 million in after-tax expenses associated with the EP acquisition and EP Energy sale; (ii) deferred tax adjustments primarily associated with the EP acquisition, which resulted in an incremental benefit of $57 million; (iii) $128 million after-tax non-cash impairment charge associated with our NGPL investment; and (iv) $213 million in after-tax KMP's FTC Natural Gas Pipelines disposal group remeasurement loss and costs to sell.

Total segment earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments (EBDA), increased $2,063 million (68%) in 2012 compared to 2011; however, this overall increase in earnings (i) included a $89 million increase in EBDA from the effect of the certain items described in the footnote (b) to the table above (which combined to decrease total segment EBDA by $285 million and $374 million in 2012 and 2011, respectively) and (ii) excluded $71 million decrease in EBDA from discontinued operations (as described in footnote (e) to the table above and excluding both the combined $937 million loss from the remeasurement of net assets to fair value and disposal costs from the sale of net assets in 2012 and the $10 million increase in expense in 2011 from the write-off of a receivable for fuel under-collected prior to 2011). After adjusting for these two items, the remaining $1,903 million (52%) increase in total segment EBDA in 2012 compared to 2011 resulted from higher earnings from all reportable business segments, driven mainly by increases attributable to the Natural Gas Pipelines primarily due to the contributions from the EP operations, including EPB, the CO \( _{2} \) —KMP and the Terminals—KMP business segments.

## Year Ended December 31, 2011 vs. 2010

Our total revenues for both 2011 and 2010 were $7.9 billion. For 2011, net income attributable to Kinder Morgan, Inc. totaled $594 million as compared to a net loss of $41 million in 2010.

For 2010, our net income attributable to Kinder Morgan, Inc. was negatively impacted by (i) a $128 million (after-tax) Going Private Transaction litigation settlement; (ii) approximately $107 million (after-tax) from a reduction in the income we recognized from our interest in the general partner due to a KMP distribution of cash from interim capital transactions; and (iii) approximately $275 million (after-tax) from an investment impairment charge recorded in the first quarter of 2010.

Total segment EBDA increased $535 million (21%) in 2011 compared to 2010; however, this overall increase in earnings (i) included a $202 million increase in EBDA from the effect of the certain items described in footnote (b) to the table above (which combined to decrease total segment EBDA by $374 million and $576 million in 2011 and 2010, respectively) and (ii) exclude $23 million decrease in EBDA from discontinued operations (as described in footnote (e) to the table above and excluding the $10 million increase in expense in 2011 from the write-off of a receivable for fuel under-collected prior to 2011). The two primary certain items contributing to the $576 million decrease in total segment earnings before depreciation, depletion and amortization for 2010 were (i) a $430 million (pre-tax) impairment of our investment in NGPL Holdco LLC and (ii) a $172 million (pre-tax) expense associated with the Products Pipeline-KMP litigation. After adjusting for these two items, the remaining $310 million (9%) increase in total segment EBDA in 2011 compared to 2010 resulted from better performance from all five of KMP's reportable business segments, primarily due to increases attributable to the CO 2—KMP, Natural Gas Pipelines and Terminals—KMP business segments.

## 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 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 unallocable income taxes. These items are not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. Our general and administrative expenses include such items as employee benefits insurance, rentals,



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

unallocated litigation and environmental expenses, and shared corporate services-including accounting, information technology, human resources and legal services.

We currently evaluate business segment performance primarily based on segment earnings before DD&A in relation to the level of capital employed. Because KMP’s and EPB’s partnership agreements require them to distribute 100% of their available cash to their partners on a quarterly basis (KMP’s and EPB’s 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 KMP. 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.

## Natural Gas Pipelines

<table><tr><td rowspan="3"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td colspan="4">(In millions, except operating statistics)</td></tr><tr><td>Revenues</td><td>$ 5,230</td><td>$ 3,943</td><td>$ 4,078</td><td></td></tr><tr><td>Operating expenses</td><td>(3,111)</td><td>(3,370)</td><td>(3,590)</td><td></td></tr><tr><td>Other expense</td><td>(14)</td><td>(1)</td><td>(1)</td><td></td></tr><tr><td>Earnings (loss) from equity investments</td><td>52</td><td>158</td><td>(317)</td><td></td></tr><tr><td>Interest (expense) income and Other, net</td><td>22</td><td>(164)</td><td>2</td><td></td></tr><tr><td>Income tax expense</td><td>(5)</td><td>(3)</td><td>(3)</td><td></td></tr><tr><td>Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments from continued operations (a)</td><td>2,174</td><td>563</td><td>169</td><td></td></tr><tr><td>Discontinued operations(b)</td><td>(770)</td><td>228</td><td>261</td><td></td></tr><tr><td>Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments including discontinued operations</td><td>$ 1,404</td><td>$ 791</td><td>$ 430</td><td></td></tr><tr><td>Natural gas transport volumes (Bcf)(c)</td><td>9,968.6</td><td>8,866.7</td><td>8,076.2</td><td></td></tr><tr><td>Natural gas sales volumes (Bcf)(c)</td><td>879.1</td><td>804.7</td><td>797.9</td><td></td></tr></table>

(a) 2012, 2011 and 2010 amounts include decreases in earnings of $202 million, $168 million and $437 million, respectively, related to the combined effect from certain items. 2012 and 2010 amounts include $200 million and $430 million, pre-tax, respectively, non-cash equity investment impairment charges related to our 20% ownership interest in NGPL Holdco LLC. 2012 amount also includes a combined $11 million increase in earnings from other certain items. 2011 amount includes a $167 million loss from the remeasurement of KMP's previously held 50% equity interest in KinderHawk Field Services LLC to fair value. 2012, 2011 and 2010 amounts include decreases in earnings of $13 million, $1 million, and $7 million, respectively, related to assets sold, or adjusted, that had been revalued as part of the Going Private Transaction and recorded in the application of the purchase method of accounting.

(b) Represents EBDA attributable to the FTC Natural Gas Pipelines disposal group. 2012 amount includes a combined loss of $937 million from the remeasurement of net assets to fair value and the sale of net assets. 2011 amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011. 2012, 2011 and 2010 amounts include revenues of $227 million, $322 million and $339 million, respectively.

(c) Includes pipeline volumes for TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, Tennessee Gas Pipeline Company, L.L.C., El Paso Natural Gas Pipeline Company, L.L.C., Texas intrastate natural gas pipeline group, El Paso Pipeline Partners, L.P., Florida Gas Transmission Company, Ruby Pipeline L.L.C., and for 2010, 2011 and the first ten months of 2012 only, Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC and Rockies Express Pipeline LLC. Volumes for acquired pipelines are included for all periods.

Combined, the certain items described in the footnotes (a) and (b) to the table above contributed to our Natural Gas Pipelines business segment’s EBDA (including discontinued operations) a $961 million decrease in 2012 and a $259 million increase in 2011, when compared with the respective prior year.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Following is information, including discontinued operations, related to the segment’s remaining (i) $1,574 million (162%) and $102 million (12%) increases in EBDA and (ii) $1,192 million (28%) increase and $152 million (3%) decrease in operating revenues in 2012 and 2011, when compared with the respective prior year:

Year Ended December 31, 2012 versus Year Ended December 31, 2011

<table><tr><td></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td></td><td colspan="4">(In millions, except percentages)</td></tr><tr><td>EP assets(a)</td><td>$     9.6</td><td>n/a</td><td>$     18</td><td>n/a</td></tr><tr><td>EPB</td><td>731</td><td>n/a</td><td>907</td><td>n/a</td></tr><tr><td>EPNG</td><td>222</td><td>n/a</td><td>301</td><td>n/a</td></tr><tr><td>EPMIC</td><td>39</td><td>n/a</td><td>91</td><td>n/a</td></tr><tr><td>Tennessee Gas Pipeline</td><td>436</td><td>n/a</td><td>602</td><td>n/a</td></tr><tr><td>KinderHawk Field Services(b)</td><td>58</td><td>81%</td><td>95</td><td>96%</td></tr><tr><td>Kinder Morgan Treating operations</td><td>33</td><td>70%</td><td>69</td><td>79%</td></tr><tr><td>Fayetteville Express Pipeline(b)</td><td>31</td><td>131%</td><td>—</td><td>n/a</td></tr><tr><td>Eagle Ford Gathering(b)</td><td>23</td><td>203%</td><td>—</td><td>n/a</td></tr><tr><td>Texas Intrastate Natural Gas Pipeline Group</td><td>(6)</td><td>(7)%</td><td>(776)</td><td>(21)%</td></tr><tr><td>NGPL Holdco LLC(b)</td><td>(17)</td><td>(89)%</td><td>n/a</td><td>n/a</td></tr><tr><td>All others (including eliminations)</td><td>(1)</td><td>(1)%</td><td>(20)</td><td>(13)%</td></tr><tr><td>Total Natural Gas Pipelines - continuing operations</td><td>1,645</td><td>225%</td><td>1,287</td><td>33%</td></tr><tr><td>Discontinued operations(c)</td><td>(71)</td><td>(30)%</td><td>(95)</td><td>(29)%</td></tr><tr><td>Total Natural Gas Pipelines - including discontinued operations</td><td>$     1,574</td><td>162%</td><td>$     1,192</td><td>28%</td></tr></table>

n/a – not applicable

(a) Primarily represents EBDA and revenues from the following EP assets and investments: Citrus, GLNG, Ruby, Bear Creek Storage and Young Gas Storage.

(b) For these equity investment we record earnings under the equity method of accounting, but we receive distributions in amounts essentially equal to equity earnings plus depreciation and amortization expenses less sustaining capital expenditures.

(c) Represents amounts attributable to KMP's FTC Natural Gas Pipelines disposal group.

The significant increases and decreases in the Natural Gas Pipelines business segment’s EBDA in the comparable years of 2012 and 2011 included the following:

- incremental earnings of $1,524 million from assets acquired on May 25, 2012 from EP, including earnings from EPB, EPNG and Tennessee Gas Pipeline;

- incremental earnings of $58 million from KMP's now wholly-owned KinderHawk Field Services LLC, due principally to the inclusion of a full year of operations in 2012 (KMP acquired the remaining 50% ownership interest in KinderHawk that it did not already own and began accounting for the investment under the full consolidation method effective July 1, 2011);

- incremental earnings of $33 million due principally to the inclusion of a full year of operations in 2012 from SouthTex Treaters, Inc., which was acquired by Kinder Morgan Treating operations effective November 30, 2011;

- a $31 million (131%) increase in equity earnings from KMP's 50% interest in the Fayetteville Express pipeline system—driven by a ramp-up in firm contract transportation volumes, and to lower interest expense. Higher year-over-year transportation revenues reflected a 15% increase in natural gas transmission volumes, and the decrease in interest expense related to Fayetteville's refinancing of its prior bank credit facility in July 2011;

- incremental equity earnings of $23 million from KMP's 50%-owned Eagle Ford Gathering LLC, which initiated flow on its natural gas gathering system on August 1, 2011; and



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

- a $6 million (2%) decrease from the Texas intrastate natural gas pipeline group—driven by higher operating and maintenance expenses, lower margins on natural gas processing activities, and lower margins on natural gas sales. The increase in expenses was driven by both higher pipeline integrity maintenance and unexpected repairs at the Markham storage facility. The decrease in processing margin was mostly due to lower natural gas liquids prices, and the year-over-year decrease in sales margin was due to lower average natural gas sales prices relative to 2011.

The overall year-to-year decrease in EBDA from discontinued operations was largely due to the loss of income due to the sale of our discontinued operations effective November 1, 2012. EBDA from the Kinder Morgan Interstate Gas Transmission pipeline system, the Trailblazer pipeline system and KMP's investment in the Rockies Express pipeline system decreased $29 million (33%), $20 million (59%) and $17 million (19%) respectively, in 2012 versus 2011. In addition to the loss of income due to our divestiture, earnings from both pipeline systems decreased during the ten months we owned the assets in 2012 compared to the same period in 2011. The decrease was driven by lower operating revenues in 2012, generally related to lower net fuel recoveries, lower margins on operational natural gas sales, and excess natural gas transportation capacity existing out of the Rocky Mountain region, relative to 2011.

Year Ended December 31, 2011 versus Year Ended December 31, 2010

<table><tr><td rowspan="2"></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td colspan="4">(In millions, except percentages)</td></tr><tr><td>KinderHawk Field Services(a)</td><td>$ 92</td><td>n/a</td><td>$ 99</td><td>n/a</td></tr><tr><td>Fayetteville Express Pipeline(b)</td><td>24</td><td>n/a</td><td>n/a</td><td>n/a</td></tr><tr><td>Midcontinent Express Pipeline(b)</td><td>12</td><td>42 %</td><td>n/a</td><td>n/a</td></tr><tr><td>Texas Intrastate Natural Gas Pipeline Group</td><td>6</td><td>2 %</td><td>(252)</td><td>(6)%</td></tr><tr><td>NGPL Holdco LLC(b)</td><td>(12)</td><td>(40)%</td><td>n/a</td><td>n/a</td></tr><tr><td>All others (including eliminations)</td><td>3</td><td>2 %</td><td>18</td><td>9 %</td></tr><tr><td>Total Natural Gas Pipelines - continuing operations</td><td>125</td><td>21 %</td><td>(135)</td><td>(3)%</td></tr><tr><td>Discontinued operations(c)</td><td>(23)</td><td>(9)%</td><td>(17)</td><td>(5)%</td></tr><tr><td>Total Natural Gas Pipelines - including discontinued operations</td><td>$ 102</td><td>12 %</td><td>$ (152)</td><td>(3)%</td></tr></table>

n/a - not applicable

(a) Equity investment until July 1, 2011. See Note (b).

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

(c) Represents amounts attributable to KMP’s FTC Natural Gas Pipelines disposal group.

The primary increases and decreases in the Natural Gas Pipelines business segment’s EBDA from continuing operations in 2011 compared to 2010 were attributable to the following:

• a $92 million increase from incremental earnings from KinderHawk Field Services LLC;

- a $24 million increase from incremental equity earnings from KMP's 50% interest in the Fayetteville Express pipeline system, which began firm contract transportation service on January 1, 2011;

- a $12 million (42%) increase in equity earnings from KMP's 50% interest in the Midcontinent Express pipeline system—driven by higher transportation revenues and by the June 2010 completion of an expansion project that increased the system's Zone 1 transportation capacity from 1.5 billion to 1.8 billion cubic feet per day, and Zone 2 capacity from 1.0 billion to 1.2 billion cubic feet per day; and

- a $6 million (2%) increase from the Texas intrastate natural gas pipeline group—primarily due to higher margins from both natural gas storage and transportation services (due to favorable storage price spreads and a 15% increase in transportation volumes) and incremental equity earnings from KMP's 50% interest in Eagle Ford Gathering LLC. The overall increase in earnings was partly offset by lower natural gas sales margins (mainly attributable to higher costs of natural gas supplies relative to sales price), and higher operating expenses (attributable primarily to higher pipeline integrity and remediation expenses).



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

The primary increases and decreases in the Natural Gas Pipelines business segment’s EBDA from discontinued operations in 2011 compared to 2010 were attributable to the following:

- an $18 million (17%) decrease from the Kinder Morgan Interstate Gas Transmission pipeline system—driven by a $12 million decrease due to lower net fuel recoveries, related to both lower recovery factors resulting from a FERC regulatory settlement reached with shippers that became effective June 1, 2011, and lower average collection prices due to an overall drop in natural gas market prices relative to 2010; and

- an $11 million (25%) decrease from the Trailblazer pipeline system—mainly attributable to both a $5 million increase in expense from the write-off of receivables for under-collected fuel (incremental to the $10 million increase in expense that is described in footnote (b) to the results of operations table above and which relates to periods prior to 2011), and a $3 million decrease in natural gas transmission revenues, due largely to lower transportation base rates implemented in 2011 as a result of a 2010 rate case settlement.

The overall changes in both segment revenues and segment operating expenses (from continuing operations) in both pairs of comparable years primarily relate to the natural gas purchase and sale activities of the Texas intrastate natural gas pipeline group, with the variances from year-to-year in both revenues and operating expenses (which include natural gas costs of sales) mainly due to corresponding changes in the intrastate group’s average prices and volumes for natural gas purchased and sold. The intrastate group both purchases and sells significant volumes of natural gas, which is often stored and/or transported on its pipelines, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases and decreases in its natural gas sales revenues are largely offset by corresponding increases and decreases in its natural gas purchase costs. It realizes earnings by capturing the favorable differences between the changes in its gas sales prices, purchase prices and transportation costs, including fuel. The intrastate group accounted for 54%, 92% and 95%, respectively, of the segment’s revenues in 2012, 2011 and 2010, and 81%, 98% and 99%, respectively, of the segment’s operating expenses in 2012, 2011 and 2010.

## Products Pipelines—KMP

<table><tr><td rowspan="3"></td><td colspan="5">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td colspan="2">2010</td></tr><tr><td colspan="5">(In millions, except operating statistics)</td></tr><tr><td>Revenues</td><td>$ 1,370</td><td>$ 914</td><td>$ 883</td><td></td><td></td></tr><tr><td>Operating expenses</td><td>(759)</td><td>(500)</td><td>(414)</td><td></td><td></td></tr><tr><td>Other income (expense)</td><td>5</td><td>8</td><td>(12)</td><td></td><td></td></tr><tr><td>Earnings from equity investments</td><td>39</td><td>34</td><td>23</td><td></td><td></td></tr><tr><td>Interest income and Other, net</td><td>11</td><td>8</td><td>16</td><td></td><td></td></tr><tr><td>Income tax benefit (expense)</td><td>2</td><td>(3)</td><td>1</td><td></td><td></td></tr><tr><td>Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)</td><td>$ 668</td><td>$ 461</td><td>$ 497</td><td></td><td></td></tr><tr><td>Gasoline (MMBbl) (b)</td><td>395.3</td><td>398.0</td><td>403.5</td><td></td><td></td></tr><tr><td>Diesel fuel (MMBbl)</td><td>141.5</td><td>148.9</td><td>148.3</td><td></td><td></td></tr><tr><td>Jet fuel (MMBbl)</td><td>110.6</td><td>110.5</td><td>106.2</td><td></td><td></td></tr><tr><td>Total refined product volumes (MMBbl)</td><td>647.4</td><td>657.4</td><td>658.0</td><td></td><td></td></tr><tr><td>Natural gas liquids (MMBbl)</td><td>31.7</td><td>26.1</td><td>25.2</td><td></td><td></td></tr><tr><td>Total delivery volumes (MMBbl)(c)</td><td>679.1</td><td>683.5</td><td>683.2</td><td></td><td></td></tr><tr><td>Ethanol (MMBbl)(d)</td><td>33.1</td><td>30.4</td><td>29.9</td><td></td><td></td></tr></table>

(a) 2012, 2011 and 2010 amounts include decreases in earnings of $35 million, $233 million and $191 million, respectively, related to the combined effect from certain items. 2012 amount consists of a $32 million increase in expense associated with environmental liability and environmental recoverable receivable adjustments, and a combined $1 million decrease in earnings from other certain items. 2011 amount consists of a $168 million increase in expense associated with rate case liability adjustments, a $60 million increase in expense associated with rights-of-way lease payment liability adjustments, and a combined $3 million decrease in earnings from other certain items. 2010 amount consists of a $172 million increase in expense associated with rate case liability adjustments, an $18 million decrease in earnings associated with incremental expenses and losses from the disposal of property related to the sale of a portion of KMP’s former Gaffey Street, California terminal land, and a combined $7 million increase in earnings from other certain items. Also,



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

2012, 2011 and 2010 amounts include decreases in earnings of $2 million, $2 million and $8 million, respectively, related to property disposal losses, which had been revalued as part of the Going Private Transaction and recorded in the application of the purchase method of accounting.

(b) Volumes include ethanol pipeline volumes.

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

(d) Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

Combined, the certain items described in the footnotes to the table above accounted for a $198 million increase in segment EBDA in 2012, and a $42 million decrease in EBDA in 2011, when compared with the respective prior year. Following is information related to the segment’s (i) remaining $9 million (1%) and $6 million (1%) increases in EBDA and (ii) $456 million (50%) and $31 million (4%) increases in operating revenues in both 2012 and 2011, when compared with the respective prior year:

Year Ended December 31, 2012 versus Year Ended December 31, 2011

<table><tr><td rowspan="2"></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td colspan="4">(In millions, except percentages)</td></tr><tr><td>Cochin Pipeline</td><td>$ 22</td><td>43%</td><td>$ 4</td><td>5%</td></tr><tr><td>Crude &amp; Condensate Pipeline</td><td>5</td><td>230%</td><td>4</td><td>n/a</td></tr><tr><td>Plantation Pipeline</td><td>4</td><td>7%</td><td>1</td><td>3%</td></tr><tr><td>Southeast Terminals</td><td>4</td><td>5%</td><td>3</td><td>3%</td></tr><tr><td>Transmix operations</td><td>(18)</td><td>(54)%</td><td>447</td><td>928%</td></tr><tr><td>Pacific operations</td><td>(9)</td><td>(3)%</td><td>(10)</td><td>(2)%</td></tr><tr><td>Calnev Pipeline</td><td>(8)</td><td>(16)%</td><td>(6)</td><td>(8)%</td></tr><tr><td>All others (including eliminations)</td><td>9</td><td>7%</td><td>13</td><td>7%</td></tr><tr><td>Total Products Pipelines—KMP</td><td>$ 9</td><td>1%</td><td>$ 456</td><td>50%</td></tr></table>

n/a - not applicable

The primary increases and decreases in the Products Pipelines—KMP business segment’s EBDA in 2012 compared to 2011 were attributable to the following:

- a $22 million (43%) increase from the Cochin natural gas liquids pipeline system-due mainly to a $10 million increase in gross margin, and due partly to both the favorable settlement of a pipeline access dispute and a favorable 2012 income tax adjustment. The increase in gross margin was mainly due to an overall 40% increase in pipeline throughput volumes, which included incremental ethane/propane volumes related primarily to completed expansion projects since the end of 2011;

- incremental earnings of $5 million from the Kinder Morgan Crude & Condensate Pipeline, which began transporting crude oil and condensate volumes in October 2012;

- a $4 million (7%) increase from KMP’s approximate 51% equity interest in the Plantation pipeline system-due largely to higher transportation revenues driven by higher average tariff rates since the end of 2011;

- a $4 million (5%) increase from the Southeast terminal operations—due mainly to higher butane blending revenues and increased throughput volumes of refined products and biofuels;

- an $18 million (54%) decrease from the transmix processing operations—due primarily to a decrease in processing volumes and unfavorable net carrying value adjustments to product inventory. The year-to-year increases in revenues was due mainly to the expiration of certain transmix fee-based processing agreements in March 2012. Due to the expiration of these contracts, KMP now directly purchase incremental volumes of transmix and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

- a $9 million (3%) decrease from the Pacific operations—primarily attributable to a corresponding $9 million drop in mainline transportation revenues, due primarily to lower average FERC tariffs as a result of rate case rulings settlements made since the end of 2011, and due partly to a 2% decrease in mainline delivery volumes; and

- an $8 million (16%) decrease from the Calnev Pipeline—chiefly due to an approximate 9% decrease in pipeline delivery volumes that were due in part to incremental services offered by a competing pipeline.

Year Ended December 31, 2011 versus Year Ended December 31, 2010

<table><tr><td rowspan="2"></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td colspan="4">(In millions, except percentages)</td></tr><tr><td>Cochin Pipeline</td><td>$     18</td><td>53 %</td><td>$     30</td><td>66 %</td></tr><tr><td>Plantation Pipeline</td><td>9</td><td>19 %</td><td>1</td><td>6 %</td></tr><tr><td>West Coast Terminals</td><td>8</td><td>11 %</td><td>10</td><td>10 %</td></tr><tr><td>Pacific operations</td><td>(18)</td><td>(6)%</td><td>(11)</td><td>(3)%</td></tr><tr><td>Calnev Pipeline</td><td>(5)</td><td>(8)%</td><td>(4)</td><td>(5)%</td></tr><tr><td>Transmix operations</td><td>(4)</td><td>(9)%</td><td>3</td><td>6 %</td></tr><tr><td>All others (including eliminations)</td><td>(2)</td><td>(2)%</td><td>2</td><td>1 %</td></tr><tr><td>Total Products Pipelines—KMP</td><td>$     6</td><td>1 %</td><td>$     31</td><td>4 %</td></tr></table>

The primary increases and decreases in the Products Pipelines—KMP business segment’s EBDA in 2011 compared to 2010 were attributable to the following:

- an $18 million (53%) increase from the Cochin pipeline system—largely related to a 33% increase in system-wide throughput volumes, partially offset by increased income tax expense due to the year-over-year increase in pre-tax income;

- a $9 million (19%) increase from KMP’s equity interest in Plantation. The increase in Plantation’s earnings was primarily due to higher oil loss allowance revenues, a 4% increase in transport volumes, and the absence of an expense from the write-off of an uncollectible receivable in the first quarter of 2010;

- an $8 million (11%) increase from the West Coast terminal operations—due mainly to the completion of various terminal expansion projects that increased liquids tank capacity, and partly to higher rates on existing storage;

- an $18 million (6%) decrease from the Pacific operations—due largely to an $11 million decrease in revenues and a $6 million increase in combined operating expenses. The decrease in revenues was primarily due to lower average tariffs, due both to lower rates on the system’s East Line deliveries as a result of rate case settlements since the end of 2010 and to lower military tenders. The increase in operating expenses was associated mainly with liability adjustments made pursuant to an adverse tentative court decision on the amount of 2011 rights-of-way lease payment obligations;

- a $5 million (8%) decrease from the Calnev Pipeline—due largely to a 21% drop in ethanol handling volumes that related to both lower deliveries to the Las Vegas market and incremental ethanol blending services offered by a competing terminal; and

- a $4 million (9%) decrease from the transmix processing operations—due mainly to lower product gains relative to 2010.



## CO₂—KMP

<table><tr><td rowspan="3"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td colspan="4">(In millions, except operating statistics)</td></tr><tr><td>Revenues(a)</td><td>$     1,677</td><td>$     1,434</td><td>$     1,299</td><td></td></tr><tr><td>Operating expenses</td><td>(381)</td><td>(342)</td><td>(309)</td><td></td></tr><tr><td>Other income</td><td>7</td><td>—</td><td>—</td><td></td></tr><tr><td>Earnings from equity investments</td><td>25</td><td>24</td><td>23</td><td></td></tr><tr><td>Interest (expense) income and Other, net</td><td>(1)</td><td>5</td><td>4</td><td></td></tr><tr><td>Income tax (expense) benefit</td><td>(5)</td><td>(4)</td><td>1</td><td></td></tr><tr><td>Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)(b)</td><td>$     1,322</td><td>$     1,117</td><td>$     1,018</td><td></td></tr><tr><td>Southwest Colorado carbon dioxide production (gross) (Bcf/d)(c)</td><td>1.2</td><td>1.3</td><td>1.3</td><td></td></tr><tr><td>Southwest Colorado carbon dioxide production (net) (Bcf/d)(c)</td><td>0.5</td><td>0.5</td><td>0.5</td><td></td></tr><tr><td>SACROC oil production (gross)(MBbl/d)(d)</td><td>29.0</td><td>28.6</td><td>29.2</td><td></td></tr><tr><td>SACROC oil production (net)(MBbl/d)(e)</td><td>24.1</td><td>23.8</td><td>24.3</td><td></td></tr><tr><td>Yates oil production (gross)(MBbl/d)(d)</td><td>20.8</td><td>21.7</td><td>24.0</td><td></td></tr><tr><td>Yates oil production (net)(MBbl/d)(e)</td><td>9.3</td><td>9.6</td><td>10.7</td><td></td></tr><tr><td>Katz oil production (gross)(MBbl/d)(d)</td><td>1.7</td><td>0.5</td><td>0.3</td><td></td></tr><tr><td>Katz oil production (net)(MBbl/d)(e)</td><td>1.4</td><td>0.4</td><td>0.2</td><td></td></tr><tr><td>Natural gas liquids sales volumes (net)(MBbl/d)(e)</td><td>9.5</td><td>8.5</td><td>10.0</td><td></td></tr><tr><td>Realized weighted average oil price per Bbl(f)</td><td>$     87.72</td><td>$     69.73</td><td>$     59.96</td><td></td></tr><tr><td>Realized weighted average natural gas liquids price per Bbl(g)</td><td>$     50.95</td><td>$     65.61</td><td>$     51.03</td><td></td></tr></table>

(a) 2012, 2011 and 2010 amounts include unrealized losses of $11 million, unrealized gains of $5 million and unrealized gains of $5 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales. Also, amounts include increases in segment earnings resulting from valuation adjustments of $18 million and $53 million for the years ended 2011 and 2010, 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) 2012 amount also includes a $7 million gain from the sale of KMP’s ownership interest in the Claytonville oil field unit.

(c) Includes MeElmo Dome and Doe Canyon sales volumes.

(d) Represents 100% of the production from the field. KMP owns an approximately 97% working interest in the SACROC unit and an approximately 50% working interest in the Yates unit, and an approximately 99% working interest in the Katz Strawn unit.

(e) Net to KMP, after royalties and outside working interests.

(f) Includes all of KMP’s crude oil production properties.

(g) Includes production attributable to leasehold ownership and production attributable to KMP’s 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. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and Sales and Transportation Activities.

Combined, the certain items described in footnotes (a) and (b) to the table above (i) decreased EBDA by $27 million and $35 million, respectively, in 2012 and 2011 when compared with the respective prior year and (ii) decreased revenues by $34 million and $35 million, respectively, in 2012 and 2011 when compared with the respective prior year. For each of the segment’s two primary businesses, following is information related to the remaining (i) $232 million (21%) and $134 million



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

(14%) increases in EBDA; and (ii) $277 million (20%) and $170 million (14%) increases in operating revenues in both 2012 and 2011, when compared with the respective prior year:

Year Ended December 31, 2012 versus Year Ended December 31, 2011

<table><tr><td rowspan="2"></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="3">Revenues increase/(decrease)</td></tr><tr><td colspan="5">(In millions, except percentages)</td></tr><tr><td>Oil and Gas Producing Activities</td><td>$     180</td><td>23%</td><td>$     228</td><td>20%</td><td></td></tr><tr><td>Sales and Transportation Activities</td><td>52</td><td>17%</td><td>46</td><td>13%</td><td></td></tr><tr><td>Intrasegment Eliminations</td><td>—</td><td>—%</td><td>3</td><td>5%</td><td></td></tr><tr><td>Total CO2—KMP</td><td>$     232</td><td>21%</td><td>$     277</td><td>20%</td><td></td></tr></table>

The segment’s oil and gas producing activities include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants. When compared to 2011, the increase in earnings from the segment’s oil and gas producing activities in 2012 was mainly due to the following:

- a $256 million (29%) increase due to higher crude oil sales revenues—driven by higher average realizations for U.S. crude oil, increased oil production at the Katz field unit, and increased oil production at the SACROC field unit. When compared to 2011, KMP’s realized weighted average price per barrel of crude oil increased 26% in 2012 (from $69.73 per barrel in 2011 to $87.72 per barrel in 2012);

- a $46 million (14%) decrease due to higher combined operating expenses—driven primarily by higher well workover expenses (due to increased drilling activity) and higher severance and property tax expenses; and

- a $26 million (13%) decrease due to lower plant product sales revenues—due to a 22% year-over-year decrease in the realized weighted average price per barrel of natural gas liquids (from $65.61 per barrel in 2011 to $50.95 per barrel in 2012). The decrease in revenues from lower prices more than offset an increase in revenues related to an overall 12% increase in plant products sales volumes.

The increase in EBDA from the segment’s sales and transportation activities in 2012 compared to 2011 was primarily revenue related, attributable to the following:

- a $24 million (10%) increase due to higher carbon dioxide sales revenues—driven by a 17% increase in average sales prices, due primarily to two factors: (i) a change in the mix of contracts resulting in more carbon dioxide being delivered under higher price contracts and (ii) heavier weighting of new carbon dioxide contract prices to the price of crude oil; and

- a $22 million (22%) increase in all other operating revenues—due largely to both higher non-consent revenues and higher reimbursable project revenues. The increase in non-consent revenues related to sharing arrangements pertaining to certain expansion projects completed at the McElmo Dome unit in Colorado since the end of 2011. The increase in reimbursable revenues related to the completion of prior expansion projects on the Central Basin pipeline system.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## Year Ended December 31, 2011 versus Year Ended December 31, 2010

<table><tr><td></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td></td><td colspan="4">(In millions, except percentages)</td></tr><tr><td>Oil and Gas Producing Activities</td><td>$     9 6</td><td>14%</td><td>$     127</td><td>13%</td></tr><tr><td>Sales and Transportation Activities</td><td>38</td><td>14%</td><td>5 5</td><td>19%</td></tr><tr><td>Intrasegment Eliminations</td><td>—</td><td>—%</td><td>(12)</td><td>(23)%</td></tr><tr><td>Total CO2—KMP</td><td>$     134</td><td>14%</td><td>$     170</td><td>14%</td></tr></table>

When compared to 2010, the increase in earnings from the segment’s oil and gas producing activities in 2011 was mainly due to the following:

- a $92 million (12%) increase due to higher crude oil sales revenues—due to higher average realized sales prices for U.S. crude oil. KMP’s realized weighted average price per barrel of crude oil increased 16% in 2011 versus 2010. The overall increase in crude oil sales revenues was partially offset, however, by a 4% decrease in oil production volumes (volumes presented in the results of operations table above), due primarily to a general year-over-year decline in production at both the SACROC and Yates field units;

- a $19 million (133%) increase due to higher net profits interest revenues from KMP’s 28% net profits interest in the Snyder, Texas natural gas processing plant—driven by higher natural gas liquids prices, increased producing volumes in the last half of 2011, and the favorable impact from the restructuring of certain liquids processing contracts that became effective at the beginning of 2011. The contractual changes increased liquids processing production allocated to the plant, and decreased liquids production allocated to the SACROC field unit;

- a $17 million (9%) increase due to higher natural gas plant products sales revenues—due to a 29% increase in KMP’s realized weighted average price per barrel of natural gas liquids. The increase in revenues from higher realized sales prices was partially offset, however, by a 15% decrease in liquids sales volumes, mainly related to the contractual reduction in KMP’s net interest in liquids production from the SACROC field (described above); and

- a $30 million (10%) decrease due to higher combined operating expenses—driven primarily by higher carbon dioxide supply expenses that related to both initiating carbon dioxide injections into the Katz field and higher carbon dioxide prices.

The increase in EBDA from the segment’s sales and transportation activities in 2011 compared to 2010 was attributable to the following:

- a $43 million (21%) increase due to higher carbon dioxide sales revenues—primarily due to higher average sales prices. The segment’s average price received for all carbon dioxide sales in 2011 increased 19% compared to 2010, due largely to the fact that a portion of its carbon dioxide sales contracts were indexed to higher oil prices. In addition, overall carbon dioxide sales volumes increased slightly (1%) in 2011 versus 2010;

- an $8 million (10%) increase due to higher carbon dioxide and crude oil pipeline transportation revenues—due mainly to incremental transportation service on the Eastern Shelf carbon dioxide pipeline. KMP completed construction of the pipeline in December 2010; and

- a $16 million (30%) decrease due to higher combined operating expenses—driven by higher severance tax expenses and higher carbon dioxide supply expenses, both related to higher commodity prices in 2011.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Terminals—KMP

<table><tr><td rowspan="3"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td colspan="4">(In millions, except operating statistics)</td></tr><tr><td>Revenues</td><td>$     1,359</td><td>$     1,315</td><td>$     1,265</td><td></td></tr><tr><td>Operating expenses</td><td>(685)</td><td>(634)</td><td>(629)</td><td></td></tr><tr><td>Other income (expense)</td><td>14</td><td>(1)</td><td>3</td><td></td></tr><tr><td>Earnings from equity investments</td><td>21</td><td>11</td><td>1</td><td></td></tr><tr><td>Interest income and Other, net</td><td>2</td><td>6</td><td>5</td><td></td></tr><tr><td>Income tax (expense) benefit</td><td>(3)</td><td>5</td><td>(5)</td><td></td></tr><tr><td>Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)</td><td>$     708</td><td>$     702</td><td>$     640</td><td></td></tr><tr><td>Bulk transload tonnage (MMtons)(b)</td><td>96.6</td><td>99.8</td><td>92.5</td><td></td></tr><tr><td>Ethanol (MMBbl)</td><td>65.3</td><td>61.0</td><td>57.9</td><td></td></tr><tr><td>Liquids leasable capacity (MMBbl)</td><td>60.1</td><td>60.2</td><td>58.2</td><td></td></tr><tr><td>Liquids utilization %</td><td>93.20%</td><td>94.50%</td><td>96.20%</td><td></td></tr></table>

(a) 2012, 2011 and 2010 amounts include a decrease of $44 million, an increase of $1 million, and a decrease of $6 million, respectively, related to the combined effect from certain items. 2012 amount consists of a $51 million increase in expense related to hurricanes Sandy and Isaac clean-up and repair activities and the associated write-off of damaged assets, a $4 million increase in expense associated with environmental liability adjustments, and a $12 million casualty indemnification gain related to a 2010 casualty at the Myrtle Grove, Louisiana, International Marine Terminal facility. 2011 amount consists of a $5 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to KMP from us and a combined $2 million decrease from other certain items. 2010 amount consists of a $7 million decrease in earnings from casualty insurance deductibles and the repair of assets related to casualty losses, and a combined $2 million increase from other certain items. Also, 2012, 2011 and 2010 amounts include decreases of earnings of $1 million, $2 million, and $1 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.

(b) 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. KMP groups its bulk and liquids terminal operations into regions based on geographic location and/or primary operating function. This structure allows the management to organize and evaluate segment performance and to help make operating decisions and allocate resources.

Combined, the certain items described in the footnote to the table above decreased segment EBDA by $45 million in 2012 and increased EBDA by $7 million in 2011, when compared with the respective prior year. Following is information related to the segment’s (i) remaining $51 million (7%) and $55 million (9%) increases in EBDA and (ii) $44 million (3%) and $50 million (4%) increases in operating revenues in both 2012 and 2011, when compared with the respective prior year:



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## Year Ended December 31, 2012 versus Year Ended December 31, 2011

<table><tr><td></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td></td><td colspan="4">(In millions, except percentages)</td></tr><tr><td>Gulf Liquids</td><td>$     19</td><td>11 %</td><td>$     17</td><td>7 %</td></tr><tr><td>Mid-Atlantic</td><td>15</td><td>25 %</td><td>19</td><td>16 %</td></tr><tr><td>Northeast</td><td>15</td><td>19 %</td><td>18</td><td>13 %</td></tr><tr><td>Acquired assets and businesses</td><td>10</td><td>n/a</td><td>4</td><td>n/a</td></tr><tr><td>All others (including intragement eliminations and unallocated income tax expenses)</td><td>(8)</td><td>(2)%</td><td>(14)</td><td>(2)%</td></tr><tr><td>Total Terminals—KMP</td><td>$     51</td><td>7 %</td><td>$     44</td><td>3 %</td></tr></table>

The overall increases in EBDA from the Terminals -KMP segment were driven by higher contributions from the terminal facilities included in the Gulf Liquids, Mid-Atlantic and Northeast regions. The increase from the Gulf Liquids facilities were driven by higher warehousing revenues (as a result of new and renewed customer agreements at higher rates) at the Galena Park and Pasadena, Texas facilities, higher ethanol volumes through the Deer Park, Texas rail terminal, and higher overall gasoline throughput volumes. KMP also benefited from both higher capitalized overhead associated with the ongoing construction of KMP’s majority-owned Battleground Texas oil terminal located on the Houston Ship Channel, and higher earnings from its crude oil storage operations located in Cushing, Oklahoma.

The year-to-year earnings increase from the Mid-Atlantic region resulted primarily from higher export coal shipments from the Pier IX terminal, located in Newport News, Virginia, and higher import steel and iron ore imports from the Fairless Hills, Pennsylvania bulk terminal. Economic expansion in developing countries has generated a growth cycle in the coal export market. Due both to this growth in demand and to completed infrastructure expansions since the end of 2011, KMP’s total export coal volumes (for all terminals combined) increased by 5.7 million tons (38%) in 2012, when compared to the prior year.

The increase in earnings from the Northeast terminal operations was driven by higher contributions from the Staten Island terminal due to new and favorable contract changes. Despite being affected heavily by hurricane Sandy in 2012, the liquid terminal in Carteret, New Jersey increased earnings primarily due to higher transfer and storage rates, and to new and renegotiated contracts. KMP also benefited from incremental earnings from the Philadelphia liquids terminal, due largely to new and restructured customer contracts at higher rates, and from the Perth Amboy, New Jersey liquids terminal, due primarily to higher gasoline throughput volumes and favorable contract changes.

The incremental earnings and revenues from acquired assets and businesses primarily represent contributions from KMP’s additional equity investment in the short-line railroad operations of Watco Companies, LLC (acquired in December 2011) and its bulk terminal that handles petroleum coke for the Total refinery in Port Arthur, Texas (acquired in June 2011). The incremental amounts represent earnings and revenues from acquired terminals’ operations during the additional months of ownership in 2012, and do not include increases or decreases during the same months KMP owned the assets in 2011.

The remaining increases and decreases in the Terminals—KMP segment’s earnings and revenues—reported in the “All others” line in the table above—represent increases and decreases in terminal results at various locations; however the overall decreases were driven by lower results from the combined terminal operations included in the Rivers region. The decreases were mainly due to lower domestic coal transload volumes, largely the result of a drop in domestic demand relative to 2011.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## Year Ended December 31, 2011 versus Year Ended December 31, 2010

<table><tr><td></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td></td><td colspan="4">(In millions, except percentages)</td></tr><tr><td>Mid-Atlantic</td><td>$     20</td><td>53 %</td><td>$     28</td><td>30 %</td></tr><tr><td>Acquired assets and businesses</td><td>15</td><td>n/a</td><td>12</td><td>n/a</td></tr><tr><td>Northeast</td><td>9</td><td>12 %</td><td>13</td><td>10 %</td></tr><tr><td>Gulf Liquids</td><td>9</td><td>5 %</td><td>20</td><td>10 %</td></tr><tr><td>Midwest</td><td>5</td><td>12 %</td><td>7</td><td>7 %</td></tr><tr><td>Southeast</td><td>3</td><td>6 %</td><td>3</td><td>2 %</td></tr><tr><td>Ohio Valley</td><td>(4)</td><td>(12)%</td><td>(1)</td><td>(2)%</td></tr><tr><td>West</td><td>(4)</td><td>(6)%</td><td>(6)</td><td>(5)%</td></tr><tr><td>All others (including intragement eliminations and unallocated income tax expenses)</td><td>2</td><td>1 %</td><td>(26)</td><td>(6)%</td></tr><tr><td>Total Terminals—KMP</td><td>$     55</td><td>9 %</td><td>$     50</td><td>4 %</td></tr></table>

The increase in earnings from the terminals included in the Mid-Atlantic region was driven by an $18 million increase from the Pier IX terminal, located in Newport News, Virginia. Pier IX benefitted from a $21 million increase in operating revenues that related chiefly to a 5.2 million ton (74%) increase in coal transload volumes. The increase in volumes was due to the ongoing domestic economic recovery, growth in the export market (due to greater foreign demand for both U.S. metallurgical and steam coal), and completed terminal expansions since the end of 2010. Including all terminals, coal volumes handled increased by 20% in 2011 compared to 2010.

The incremental earnings and revenues from acquired assets and businesses primarily represent contributions from (i) KMP’s initial equity investment in Watco Companies, LLC (acquired in January 2011); (ii) the Port Arthur petroleum coke bulk terminal (acquired in June 2011 and discussed above); and (iii) the bulk and liquids terminal assets it acquired from Slay Industries in March 2010. For more information on KMP’s 2011 terminal acquisitions, see Note 3 to our consolidated financial statements included elsewhere in this report.

The increase in earnings from the Northeast terminals was primarily due to a $7 million increase from the Carteret, New Jersey liquids terminal, driven by both completed liquids tank expansion projects since the end of 2010 (which increased liquids storage capacity by approximately one million barrels), and higher transfer and storage rates. Including all terminals, KMP increased its liquids terminals' leasable capacity by 2.0 million barrels (3.4%) during 2011, via both terminal acquisitions and completed terminal expansion projects and, at the same time, its overall liquids utilization capacity rate (the ratio of KMP's actual leased capacity to its estimated potential capacity) at the end of 2011 decreased by only 1.7% since the end of 2010.

The increase in earnings from the Gulf Liquids terminals primarily related to higher operating results from KMP’s Galena Park and Pasadena liquids facilities driven by higher ethanol volumes, higher distillate warehousing revenues, and new and renewed customer agreements at higher rates. KMP also benefitted from the March 2011 completion of its Deer Park Rail Terminal and its related ethanol handling assets at the Pasadena terminal. For all of the Gulf Liquids terminals combined, total ethanol handling volumes increased by 86% in 2011 compared to 2010.

The overall increase in earnings from the Midwest terminals was mainly due to higher earnings from the combined operations of the Argo and Chicago, Illinois liquids terminals, due to increased ethanol throughput and incremental liquids storage and handling business, and to higher contributions from the Dakota Bulk terminal located in St. Paul, Minnesota, due to higher sand and salt transload volumes.

The increase in earnings from the Southeast terminals was due mainly to higher chemical revenues, increased salt handling, and higher storage fees at the Shipyard River Terminal, located in Charleston, South Carolina, and from higher margins from tank blending services involving various agricultural products at the liquids terminal facility located in Wilmington, North Carolina.

Higher overall earnings from the Terminals—KMP segment in 2011 versus 2010 were partially offset by lower earnings from terminal operations included in the segment’s Ohio Valley and West regions, due mainly to both lower revenues earned



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

from steel handling and iron ore stevedoring services, and lower agricultural exports due to higher soybean meal exports during 2010 as a result of drought conditions in South America.

The remaining increases and decreases in the Terminals—KMP segment’s earnings and revenues—reported in the “All others” line in the table above—represent increases and decreases in terminal results at various locations; however the decrease in revenues relate largely to terminal assets KMP sold (or contributed to joint ventures) and no longer consolidate since the end of 2010.

Kinder Morgan Canada—KMP

<table><tr><td rowspan="3"></td><td colspan="5">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td colspan="2">2010</td></tr><tr><td colspan="5">(In millions, except operating statistics)</td></tr><tr><td>Revenues</td><td>$ 311</td><td>$ 302</td><td>$ 268</td><td></td><td></td></tr><tr><td>Operating expenses</td><td>(103)</td><td>(97)</td><td>(91)</td><td></td><td></td></tr><tr><td>Earnings from equity investments</td><td>5</td><td>(2)</td><td>(3)</td><td></td><td></td></tr><tr><td>Interest income and Other, net</td><td>17</td><td>14</td><td>16</td><td></td><td></td></tr><tr><td>Income tax expense</td><td>(1)</td><td>(15)</td><td>(8)</td><td></td><td></td></tr><tr><td>Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)</td><td>$ 229</td><td>$ 202</td><td>$ 182</td><td></td><td></td></tr><tr><td>Transport volumes (MMBbl)(b)</td><td>106.1</td><td>99.9</td><td>108.4</td><td></td><td></td></tr></table>

(a) 2011 amount includes a $3 million increase in earnings associated with an income tax benefit (reflecting tax savings) related to non-cash compensation expense allocated to KMP from us.

(b) Represents Trans Mountain pipeline system volumes.

The Kinder Morgan Canada—KMP business segment includes the operations of the Trans Mountain and Jet Fuel pipeline systems and KMP’s one-third ownership interest in the Express crude oil pipeline system. The certain items relating to income tax savings described in footnote (a) to the table above accounted for both a $3 million decrease in segment EBDA in 2012, and a $3 million increase in EBDA in 2011, when compared with the respective prior year.

Following is information related to the segment’s (i) remaining $30 million (15%) and $17 million (9%) increases in EBDA and (ii) $9 million (3%) and $34 million (13%) increases in operating revenues in both 2012 and 2011, when compared with the respective prior year:

Year Ended December 31, 2012 versus Year Ended December 31, 2011

<table><tr><td rowspan="2"></td><td colspan="2">EBDA increase/(decrease)</td><td colspan="2">Revenues increase/(decrease)</td></tr><tr><td colspan="4">(In millions, except percentages)</td></tr><tr><td>Trans Mountain Pipeline</td><td>$ 23</td><td>12%</td><td>$ 9</td><td>3%</td></tr><tr><td>Express Pipeline</td><td>7</td><td>61%</td><td>—</td><td>—%</td></tr><tr><td>Total Kinder Morgan Canada—KMP</td><td>$ 30</td><td>15%</td><td>$ 9</td><td>3%</td></tr></table>

The year-to-year increase in Trans Mountain’s EBDA was driven by a $17 million decrease in income tax expenses, associated primarily with favorable tax adjustments, recorded in 2012, related to lower taxable income relative to 2011. Trans Mountain also benefited from higher non-operating income, related primarily to incremental management incentive fees earned from its operation of the Express pipeline system. The year-over-year increase in earnings from the equity investment in the Express pipeline system was mainly due to volumes moving at higher transportation rates on the Express (Canadian) portion of the system, and to higher domestic volumes on the Platte (domestic) portion of the segment.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## Year Ended December 31, 2011 versus Year Ended December 31, 2010

<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>Trans Mountain Pipeline</td><td>$     21</td><td>13 %</td><td>$     34</td><td>13%</td></tr><tr><td>Express Pipeline</td><td>(4)</td><td>(26)%</td><td>—</td><td>—%</td></tr><tr><td>Total Kinder Morgan Canada—KMP</td><td>$     17</td><td>9 %</td><td>$     34</td><td>13%</td></tr></table>

The overall increase in Trans Mountain’s EBDA in 2011 compared to 2010 included an increase of $5 million due to favorable currency impacts, primarily related to favorable changes from the translation of earnings.

Trans Mountain’s remaining $16 million year-over-year increase in EBDA was driven by higher operating revenues, primarily due to favorable impacts from a negotiated pipeline toll settlement agreement which became effective on January 1, 2011. The one-year negotiated toll agreement was formally approved by the National Energy Board (Canada) on April 29, 2011, and replaced the previous mainline toll settlement agreement that expired on December 31, 2010.

The decrease in earnings from KMP’s investment in the Express pipeline system was driven by a $5 million increase in income tax expenses, due to a drop in income tax expense in 2010 related to a valuation allowance release on previously established deferred tax balances. The overall decrease in earnings was partially offset by a $1 million increase in equity earnings, primarily due to higher domestic transportation volumes on the Platte Pipeline segment.

## Other

During 2012, our other segment activities include those operations that were acquired from EP on May 25, 2012 and are primarily related to several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028. In 2010, this segment primarily consisted of our Power facility which was sold on October 22, 2010. This segment also included an interest in the Bolivia to Brazil Pipeline, which we sold for $88 million on January 18, 2013. There were earnings contributions of $7 million and $4 million, respectively, from this segment for the years ended 2012 and 2010.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

## General and Administrative, Interest, and Noncontrolling Interests

<table><tr><td rowspan="3"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td colspan="4">(In millions)</td></tr><tr><td>KMI general and administrative expense(a)(b)</td><td>$     341</td><td>$     42</td><td>$     256</td><td></td></tr><tr><td>KMP general and administrative expense(c)</td><td>493</td><td>473</td><td>375</td><td></td></tr><tr><td>EPB general and administrative expense(d)</td><td>95</td><td>—</td><td>—</td><td></td></tr><tr><td>Consolidated general and administrative expense</td><td>$     929</td><td>$     515</td><td>$     631</td><td></td></tr><tr><td>KMI interest expense, net of allocable interest income(e)</td><td>$     602</td><td>$     169</td><td>$     160</td><td></td></tr><tr><td>KMP interest expense, net of allocable interest income(f)</td><td>652</td><td>531</td><td>507</td><td></td></tr><tr><td>EPB interest expense, net of allocable interest income(g)</td><td>182</td><td>—</td><td>—</td><td></td></tr><tr><td>Other, net(h)</td><td>5</td><td>1</td><td>(15)</td><td></td></tr><tr><td>Unallocable interest expense net of interest income and other, net</td><td>$     1,441</td><td>$     701</td><td>$     652</td><td></td></tr><tr><td>KMR noncontrolling interests</td><td>$     15</td><td>$     14</td><td>$     67</td><td></td></tr><tr><td>KMP noncontrolling interests(i)</td><td>(51)</td><td>52</td><td>274</td><td></td></tr><tr><td>EPB noncontrolling interests</td><td>178</td><td>—</td><td>—</td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>$     112</td><td>$     66</td><td>$     341</td><td></td></tr></table>

(a) 2012 and 2010 amounts include increases in expense of $261 million, $211 million, and the 2011 amount a decrease in expense of $2 million, related to the combined effect from certain items. 2012 amount includes $261 million increase of pre-tax expenses associated with the EP acquisition and EP Energy sale, which includes (i) $84 million (also see footnotes (c) and (d) below for KMP and EPB portion, respectively) in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million for legal fees and reserves, net of recoveries; and less (v) $29 million benefit associated with pension income. 2011 amount includes (i) $46 million reduction to expense for a Going Private transaction litigation insurance reimbursement; (ii) KMI's portion ($13 million) of a $100 million special bonus to non-senior management employees; (iii) $11 million of expense associated with our initial public offering; (iv) a $9 million increase in expense related to the EP acquisition; (v) $10 million increase in Going Private transaction litigation expense; and (vi) a combined $1 million increase in other expense related primarily to non-cash compensation expense. The cost of the $100 million special bonus was not borne by our Class P shareholders. In May of 2011, we paid for the $100 million of special bonuses, which included the amounts allocated to KMP, using $64 million (after-tax) in available earnings and profits reserved for this purpose and not paid in dividends to our Class A shareholders. See also footnote (c) below. 2010 amount includes (i) increase in expense of $200 million associated with Going Private transaction litigation settlement; (ii) increase in legal expense of $7 million associated with our initial public offering; and (iii) combined increase of $4 million related primarily to Going Private transaction legal expense.

(b) 2012, 2011 and 2010 amounts include NGPL Holdco LLC general and administrative reimbursements of $35 million, $35 million, and $47 million, respectively. These amounts were recorded to the “Product sales and other” caption in our accompanying consolidated statements of income with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income. Also, see Note 11 to our consolidated financial statements included elsewhere in this report.

(c) 2012, 2011 and 2010 amounts include increases in expense of $70 million, $94 million and $10 million, respectively, related to the combined effect from certain items. 2012 amount consists of a $56 million increase in expense (including $42 million in severance, retention and bonus costs) attributable to our drop-down asset group for the period prior to our acquisition date of August 1, 2012, and a combined $14 million increase in expense from other certain items. 2011 amount consists of a combined $90 million increase in non-cash compensation expense (including $87 million related to a special non-cash bonus expense to non-senior management employees) allocated to us from KMI; however, we do not have any obligation, nor did we pay any amounts related to this expense, and a combined $4 million increase in expense from other certain items. 2010 amount consists of $5 million increase in non-cash compensation expense allocated to us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this expense), and a combined $5 million increase in expense from other certain items.

(d) 2012 amount includes $34 million for severance cost. This expense is attributable to non-cash severance costs allocated to EPB from us as a result of KMI’s and EP’s merger; however, EPB does not have any obligation, nor did EPB pay any amounts related to this expense.

(e) 2012 amount includes a $108 million write off of capitalized financing fees, almost all of which was associated with the EP acquisition financing that was written-off (due primarily due to debt repayment) or amortized.

(f) 2012 and 2010 amounts include increases in expense of $20 million and $1 million, respectively, related to the combined effect from certain items. 2012 amount consists of a $21 million increase in expense attributable to our drop-down asset group for the period prior to our acquisition date of August 1, 2012, and a combined $1 million decrease in expense from other certain items. 2010 amount consists of a $1 million increase in imputed interest expense, related to our January 1, 2007 Cochin Pipeline acquisition.

(g) Includes expenses and transactions for the periods after the May 25, 2012 EP acquisition date.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

(h) Other, net primarily represents miscellaneous expenses, net of incomes that were not allocable to operating segments. 2010 amount primarily related to gain on sale of the Power facility.

(i) 2012, 2011 and 2010 amounts include decreases of $5 million, $7 million and $5 million, respectively, in net income attributable to KMP's noncontrolling interests, related to the combined effect from all of the 2012, 2011 and 2010 items previously disclosed in the footnotes to the tables included in "Results of Operations."

Combined, the certain items described in footnotes (a) and (b) to the table above affected KMI’s general and administrative expenses by a $263 million increase in 2012, when compared with 2011. The remaining changes in KMI’s general and administrative expense in 2012 were primarily related to EP’s (excluding EPB and the drop-down asset group) general and administrative expense.

Combined, the certain items described in footnote (a) and (b) to the table above decreased KMI’s general and administrative expenses by $225 million in 2011 when compared with 2010. KMI’s remaining general and administrative expenses in 2011 was approximately flat when compared with 2010.

Combined, the certain items described in footnote (c) to the table above decreased KMP’s general and administrative expenses by $24 million in 2012, and increased KMP’s general and administrative expenses by $84 million in 2011, when compared with the respective prior year. The remaining $44 million (12%) increase in general and administrative expenses in 2012 versus 2011 was driven by KMP’s acquisition of additional business, associated primarily with the Tennessee Gas and El Paso Natural Gas (50% interest) pipeline systems it acquired from us effective August 1, 2012. KMP also realized higher benefit and payroll tax expenses, and higher employee labor expenses, which were impacted by cost inflation increases on work-based health and insurance benefits, higher wage rates and a larger year-over-year labor force. The remaining $14 million (4%) increase in general and administrative expenses in 2011 compared to 2010 was driven by (i) a combined $11 million increase due to higher employee benefits and payroll tax expenses (due mainly to both cost inflation increases on work-based health and insurance benefits and higher wage rates); (ii) higher overall salary and labor expenses; and (iii) higher environmental and pension expenses related to KMP’s Canadian pipeline operations.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Combined, the certain items described in footnotes (e) and (f) to the table above affected KMI’s interest expense by a $128 million increase in 2012, when compared with 2011. Our remaining combined interest expense, net of interest income, increased $608 million (87%) in 2012 when compared with 2011. The combined interest expense, net of interest income and the item described in footnote (f), increased by $34 million (5%) in 2011 compared to 2010, which was primarily attributable to higher average KMP borrowings.

The increase in KMI’s interest expense in 2012 compared to 2011 was primarily due to interest expense incurred from (i) EP acquisition debt and (ii) debt assumed in the EP acquisition, see Notes 3 “Acquisition and Divestitures—KMI Acquisition of El Paso Corporation” and Note 8 “Debt” to our consolidated financial statements included elsewhere in this report. The increase in KMI interest expense in 2011 was primarily due to a 7% increase in average borrowings between 2011 and 2010, primarily due to the $200 million Going Private litigation settlement in the fourth quarter of 2010.

For both pairs of comparable years, the increase in KMP’s interest expense was attributable to higher average borrowings. KMP’s average debt balances increased 18% in 2012 and 10% in 2011, when compared to the respective prior year. The increases in average borrowings were largely due to the capital expenditures, external business acquisitions (including debt assumed from the drop-down transaction), and investment contributions KMP has made since the beginning of 2010.

The weighted average interest rate on all of KMP’s borrowings-including both short-term and long-term amounts-was essentially flat across both 2012 and 2011, but decreased by 2% in 2011 versus 2010 (the weighted average interest rate on all of KMP’s borrowings was 4.24% during 2012, 4.26% during 2011 and 4.35% during 2010). The lower average rate in 2011 was due primarily to a decrease in the variable interest rate KMP paid on the borrowings made under its commercial paper program as compared to borrowing under its revolving bank credit facility in 2010.

We and KMP use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt, and as of December 31, 2012, approximately 42% of KMI’s and 39% of KMP’s debt balances (excluding debt fair value adjustments) were subject to variable interest rates-either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. EPB did not have variable rate debt obligations as of December 31, 2012. As of December 31, 2011, approximately 35% of KMI’s and 47% of KMP’s debt balances (excluding debt fair value adjustments) were subject to variable interest rates. For more information on our interest rate swaps, see Note 13 “Risk Management-Interest Rate Risk Management” to our consolidated financial statements included elsewhere in this report.



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Net (income) loss attributable to noncontrolling interests, which represents the allocation of our consolidated net income (or loss) attributable to all outstanding ownership interests in our consolidated subsidiaries (primarily KMP and EPB) that are not held by us, increased $46 million (70%) for 2012 as compared to 2011. The increase for 2012 is primarily due to the additional income from acquisitions, partially offset by non-cash loss of $937 million from both the costs to sell and a remeasurement of the FTC Natural Gas Pipeline disposal group net assets to fair value. The decrease of $275 million (81%) for 2011 compared to 2010 is primarily attributable to a $168 million increase in expense associated with KMP rate case liability adjustments, a $60 million increase in expense associated with KMP rights-of-way lease payment liability adjustments as well as a $167 million non-cash loss from the remeasurement of KMP’s previously held 50% equity interest in KinderHawk Field Services LLC to fair value, partially offset by KMP’s $172 million increase in expense associated with rate case liability adjustments in 2010.

## Income Taxes—Continuing Operations

## Year Ended December 31, 2012 versus Year Ended December 31, 2011

Our income tax expense for income from continuing operations for the year ended December 31, 2012 was $139 million, as compared with 2011 income tax expense of $361 million. The $222 million decrease in tax expense is due primarily to (i) lower income attributable to KMI as a result of costs incurred in 2012 to facilitate the EP acquisition and a $200 million impairment of our NGPL investment and (ii) a 2012 adjustment to decrease our income tax reserve for uncertain tax positions. These decreases are partially offset by (i) a 2012 adjustment to increase the deferred tax liability for a change in non tax-deductible goodwill related to our investment in KMP and (ii) the tax impact of an increase in the deferred state tax rate in 2012 as a result of the EP acquisition.

## Year Ended December 31, 2011 versus Year Ended December 31, 2010

Our tax expense from income from continuing operations for the year ended December 31, 2011 was $361 million, as compared with 2010 tax expense of $166 million. The $195 million increase is primarily due to (i) the tax impact of significantly higher pretax earnings attributable to KMI in 2011 as compared to 2010; (ii) the impact of non-deductible costs incurred to facilitate our initial public offering and the pending EP acquisition; (iii) a 2010 adjustment recorded to decrease our deferred tax liability related to our investment in NGPL; and (iv) a 2011 adjustment to increase the deferred tax liability related to our investment in KMP. These increases are partially offset by (i) adjustments to decrease our income tax reserve in 2011 for uncertain tax positions; (ii) an increase to deferred taxes related to an increase in our state tax rate in 2010; and (iii) a 2010 adjustment to increase the deferred tax liability related to our investment in KMR.

As explained in the KMI Dividends section discussion above, after our initial public offering we intend periodically to sell the KMR shares we receive as distributions from KMR. Since we no longer expect to recover our investment in KMR in a tax-free manner, a deferred tax liability was recorded resulting in a $80 million increase to income tax expense in 2010.

See Note 4 to our consolidated financial statements included elsewhere in this report for additional information on income taxes.

## Liquidity and Capital Resources

## General

Our acquisition of EP on May 25, 2012 resulted in significant changes in our consolidated financial position and our future cash requirements. As of December 31, 2012, we had a combined $714 million of “Cash and cash equivalents” on our consolidated balance sheet (included elsewhere in this report), an increase of $303 million (74%) from December 31, 2011. As of December 31, 2012, KMI also had $638 million of borrowing capacity available under its $1.75 billion senior secured revolving credit facility, KMP had approximately $1.4 billion of borrowing capacity available under its $2.2 billion senior unsecured revolving credit facility (discussed below in “—Short-term Liquidity”) and EPB (through its wholly-owned subsidiary, El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC)) had approximately $992 million of borrowing capacity available under its $1.0 billion senior unsecured revolving credit facility (discussed below in “—Liquidity”). We believe that our cash position and remaining borrowing capacity allow us to manage our day to day cash requirements and any anticipated obligations, and currently, we believe our liquidity to be adequate.

We have relied primarily on cash provided from operations to fund our operations as well as our debt interest payments, sustaining capital expenditures, quarterly dividend payments and our subsidiaries' quarterly distributions.

Expansion capital expenditures, and debt principal payments, as such debt principal payments become due, have historically been funded by us and our subsidiaries through (i) additional borrowings (including commercial paper issuances by KMP); (ii)



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

the issuance of additional common stock by us; (iii) issuance of shares by KMR with proceeds used for its purchase of additional KMP i-units; and (iv) issuance of common units by KMP or EPB.

In addition, KMP has funded a portion of its historical expansion capital expenditures with retained cash, which results primarily from including i-units owned by KMR in the determination of KMP’s cash distributions per unit, but paying quarterly distributions on i-units in additional i-units rather than cash.

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

## Credit Ratings and Capital Market Liquidity

Our and our subsidiaries’ credit ratings affect our ability to access the public and private debt markets (including the commercial paper market by KMP), as well as the terms and pricing of our debt (see Part II, Item 1A “Risk Factors”). Based on our and our subsidiaries’ credit ratings as discussed below, we and our subsidiaries expect that our respective short-term liquidity needs will be met primarily through short-term borrowings. Nevertheless, our and our subsidiaries’ ability to satisfy financing requirements or fund planned capital expenditures (including planned expenditures of our joint ventures) will depend upon future operating performance, which will be affected by prevailing economic conditions in the energy pipeline and terminals industries and other financial and business factors, some of which are beyond our control.

On July 17, 2012, Moody’s Investors Service (Moody’s) downgraded our senior secured debt ratings to Ba2 from Ba1 with a negative outlook. This action concludes the review that was initiated on October 18, 2011 after KMI agreed to purchase 100% of the stock of EP. Other actions taken by Moody’s included placing EP’s ratings on review for upgrade, and the affirmation of the senior unsecured ratings for KMP at Baa2 and EPB at Ba1. On August 17th, 2012, Moody’s upgraded EP’s rating to Ba2 after KMI finalized the guarantee of EP’s debt. On February 27, 2013, Moody’s modified its rating on our senior secured debt ratings from a negative to a positive outlook.

As a result of the July 17, 2012 downgrade on our senior secured debt ratings, the interest rate on our $1.75 billion senior secured revolving credit facility, 364-day bridge credit facility and $5.0 billion 3-year term loan facility, increased by 50 basis points, effective July 17, 2012. The 364-day bridge facility was paid off and terminated and the $5.0 billion 3-year term loan facility was paid down by $2.3 billion in August 2012, see Note 3 “Acquisitions and Divestitures—Drop-Down of EP Assets to KMP” included elsewhere in this report. In November 2012, the terms of KMI’s $1.75 billion senior secured revolving credit facility were amended to decrease the fixed spread component of our floating interest rate by 100 basis points and to extend the maturity of the credit facility to December 31, 2014.

A number of affiliated companies had their ratings changed, the most notable being the upgrade in EPB’s ratings from BB to BBB- (stable) by Standards & Poor’s Ratings Services (S&P) as a result of the EP acquisition and an upgrade for Tennessee Gas Pipeline Company (TGP) and El Paso Natural Gas Company (EPNG) associated with the August 13, 2012 drop-down transaction of 100% of TGP and 50% of EPNG from us to KMP. Subsequent to that transaction, TGP’s rating was upgraded to BBB (stable) by S&P and Baa1 (stable) by Moody’s. EPNG’s rating was upgraded by Moody’s to Baa1 (stable).

Currently, KMP’s long-term corporate debt credit rating is BBB (stable), Baa2 (stable) and BBB (stable), at S&P, Moody’s and Fitch, Inc., respectively. Its short-term corporate debt credit rating is A-2 (susceptible to adverse economic conditions, however, capacity to meet financial commitments is satisfactory), Prime-2 (strong ability to repay short-term debt obligations) and F2 (good quality grade with satisfactory capacity to meet financial commitments), at S&P, Moody’s and Fitch, Inc., respectively. Currently, EPB’s long-term corporate debt rating is BBB- (stable), Ba1 (positive), and BBB- (stable), at S&P, Moody’s and Fitch, Inc., respectively.

## Short-term Liquidity

As of December 31, 2012, our principal sources of short-term liquidity were (i) KMI’s $1.75 billion senior secured revolving credit facility; (ii) KMP’s $2.2 billion senior unsecured revolving credit facility with a diverse syndicate of banks; (iii) KMP’s $2.2 billion short-term commercial paper program (which was supported by its credit facilities described that matures July 1, 2016, with the amount available for borrowing under its credit facility being reduced by its outstanding commercial paper borrowings and letters of credit); (iv) EPB’s $1.0 billion senior unsecured revolving credit facility; and (v) cash from operations. The facilities can be used for the respective entity’s general corporate or partnership purposes, and KMP’s facility can be used as a backup for its short-term commercial paper program. In addition, KMP’s $2.2 billion long-term senior unsecured revolving credit facility can be amended to allow for borrowings of up to $2.5 billion and EPB’s credit facility is expandable to $1.5 billion for certain expansion projects and acquisitions. We provide for additional liquidity by maintaining



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

a sizable amount of excess borrowing capacity related to our credit facilities (discussed following). Additionally, we have consistently generated strong cash flow from operations, providing a source of funds of $2,795 million in 2012 and $2,366 million in 2011, respectively (the year-to-year increase is discussed below in “—Operating Activities”).

The following represents our primary revolving credit facilities that were available to KMI and its subsidiaries, (KMP and EPB), debt outstanding under the credit facilities, including commercial paper borrowings, and available borrowing capacity under the facilities after deducting (i) outstanding letters of credit and (ii) outstanding borrowings under KMI and EPB’s credit facilities, and KMP’s commercial paper program (supported by its credit facility).

<table><tr><td rowspan="2"></td><td colspan="3">At December 31, 2012</td></tr><tr><td>Debt outstanding</td><td>Available borrowing capacity</td><td></td></tr><tr><td></td><td colspan="3">(In millions)</td></tr><tr><td>Credit Facilities</td><td></td><td></td><td></td></tr><tr><td>KMI</td><td></td><td></td><td></td></tr><tr><td>$1.75 billion, six-year secured revolver, due December 2014</td><td>$</td><td>1,035</td><td>$</td></tr><tr><td>KMP</td><td></td><td></td><td></td></tr><tr><td>$2.2 billion, five-year unsecured revolver, due July 2016(a)</td><td>$</td><td>621</td><td>$</td></tr><tr><td>EPB</td><td></td><td></td><td></td></tr><tr><td>$1.0 billion, five-year secured revolver, due May 2016</td><td>$</td><td>—</td><td>$</td></tr></table>

Our combined balance of short-term debt as of December 31, 2012 was $2,401 million, primarily consisting of (i) $1,656 million combined outstanding borrowings under KMI’s $1.75 billion credit facility and KMP’s $2.2 billion commercial paper program; and (ii) $500 million in principal amount of KMP’s 5.0% senior notes that mature on December 15, 2013. KMP’s outstanding short-term debt will be refinanced by the combination of long-term debt, equity, and/or the issuance of additional commercial paper borrowings or credit facility borrowings. KMI intends to refinance its short-term debt through additional credit facility borrowings to replace maturing credit facility borrowings, issuing new long-term debt, or with proceeds from asset sales.

Our combined balance of short-term debt as of December 31, 2011 was $2,899 million, primarily consisting of (i) $421 million in outstanding borrowings under KMI’s senior secured credit facility; (ii) $839 million remaining principal amount of KMI’s 6.50% senior notes that matured on September 1, 2012; (iii) $645 million of KMP’s commercial paper borrowings; (iv) $450 million in principal amount of KMP’s 7.125% senior notes that matured March 15, 2012; and (v) $500 million in principal amount of KMP’s 5.85% senior notes that matured September 15, 2012.

We had working capital deficits of $1,535 million and $2,866 million as of December 31, 2012 and 2011, respectively. The overall $1,331 million (46%) favorable change from year-end 2011 was primarily due to the $498 million decrease in short-term debt discussed above and the favorable working capital impact of the EP acquisition.

Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts and changes in cash and cash equivalent balances as a result of debt or equity issuances (discussed below in “—Long-term Financing”).

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



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

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

## Long-term Financing

From time to time, KMI, KMP or EPB issue long-term debt securities, often referred to as senior notes. All of the senior notes of KMI, KMP or EPB issued to date, other than those issued by KMP and EPB subsidiaries and its operating partnerships, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. KMI and its subsidiaries' (other than KMP and its subsidiaries and EPB and its subsidiaries) senior notes are secured equally and ratably with KMI's $1.75 billion senior secured revolving credit facility. All of KMP and EPB's outstanding senior notes are unsecured obligations that rank equally with all of its other senior debt obligations. A modest amount of secured debt has been incurred by some of KMP's operating partnerships and subsidiaries. All of the fixed rate senior notes of KMI, KMP or EPB provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.

As of December 31, 2012 and December 31, 2011, the balances of long-term debt, including the current portion and the preferred interest in the general partner of KMP, but excluding debt fair value adjustments was $30,154 million and $15,094 million, respectively. To date, our and our subsidiaries' debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness.

Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives. We and our subsidiaries, including KMP and EPB, are subject, however, to conditions in the equity and debt markets and there can be no assurance we will be able or willing to access the public or private markets for equity and/or long-term senior notes in the future. If we were unable or unwilling to access the equity markets, we would be required to either restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our or our subsidiaries' credit ratings. Furthermore, our subsidiaries' ability to access the public and private debt markets is affected by their respective credit ratings.

KMI and some of its direct and indirect subsidiaries (referred to as the Combined Other Guarantor Subsidiaries), guarantee the payment of certain of El Paso LLC’s (formerly known as El Paso Corporation) outstanding debt. As of the successor date of August 13, 2012, each series of El Paso LLC outstanding notes totaling approximately $4.1 billion in aggregate principal amount is guaranteed on a senior unsecured basis by KMI and the Combined Other Guarantor Subsidiaries. See Note 20 “Guarantee of Securities of Subsidiaries” to our consolidated financial statements included elsewhere in this report.

For additional information about our debt-related transactions in 2012, see Note 8 “Debt” to our consolidated financial statements included elsewhere in this report.

## Capital Expenditures

We define sustaining capital expenditures as capital expenditures which do not increase the capacity of an asset. Generally, we fund our sustaining capital expenditures with existing cash or from cash flows from operations. In addition to utilizing cash generated from their own operations, certain of our subsidiaries can each fund their own cash requirements for expansion capital expenditures with proceeds from issuing their own long-term notes or with proceeds from contributions received from us or their other member owners.

All of our, and our subsidiaries', capital expenditures, with the exception of sustaining capital expenditures, are classified as discretionary. Generally, we initially fund our discretionary capital expenditures through borrowings under our credit facilities (or commercial paper program for KMP) until the amount borrowed is of a sufficient size to cost effectively issue either debt, or equity, or both.

Our capital expenditures for the year ended December 31, 2012 and 2011, and the amount we forecast to spend for 2013 to sustain and grow our business are as follows:



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

<table><tr><td rowspan="2"></td><td colspan="2">Actual Year Ended</td><td colspan="2">Forecasted Year Ended</td></tr><tr><td>2012</td><td>2011</td><td>2013</td><td></td></tr><tr><td></td><td colspan="4">(In millions)</td></tr><tr><td>Sustaining capital expenditures</td><td></td><td></td><td></td><td></td></tr><tr><td>KMP</td><td>$     285</td><td>$     212</td><td>$     339</td><td></td></tr><tr><td>EPB (a)</td><td>34</td><td>—</td><td>40</td><td></td></tr><tr><td>KMI</td><td>74</td><td>1</td><td>67</td><td></td></tr><tr><td>Total sustaining capital expenditures (b)</td><td>$     393</td><td>$     213</td><td>$     446</td><td></td></tr><tr><td>Discretionary capital expenditures (c)</td><td>$     1,680</td><td>$     997</td><td>$     2,638</td><td></td></tr></table>

(a) EPB 2012 sustaining capital expenditures are for the period from May 25, 2012 through December 31, 2012.

(b) Actuals for 2012 and 2011, and forecasted for 2013 include $51 million, $10 million, and $68 million, respectively, for our proportionate share of sustaining capital expenditures of unconsolidated joint ventures.

(c) Actuals for 2012 and 2011, and forecasted for 2013 exclude our proportionate share of discretionary capital expenditures of significant unconsolidated joint ventures.

## Off Balance Sheet Arrangements

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

## Contractual Obligations and Commercial Commitments

<table><tr><td rowspan="3"></td><td colspan="7">Payments due by period</td></tr><tr><td rowspan="2">Total</td><td colspan="2">Less than 1 year</td><td colspan="2">1-3 years</td><td colspan="2">More than 5 years</td></tr><tr><td colspan="5">(In millions)</td></tr><tr><td>Contractual obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Debt borrowings-principal payments</td><td>$     31,810</td><td>241</td><td>$     2,401</td><td>$     5,014</td><td>$     4,292</td><td>$     20,103</td><td></td></tr><tr><td>Interest payments(a)</td><td>23,290</td><td></td><td>1,857</td><td>3,463</td><td>2,826</td><td>15,144</td><td></td></tr><tr><td>Lease obligations(b)</td><td>377</td><td></td><td>69</td><td>109</td><td>80</td><td>119</td><td></td></tr><tr><td>Pension and postretirement welfare plans(c)</td><td>2,360</td><td></td><td>269</td><td>474</td><td>475</td><td>1,142</td><td></td></tr><tr><td>Other obligations(d)</td><td>1,149</td><td></td><td>200</td><td>312</td><td>158</td><td>479</td><td></td></tr><tr><td>Total</td><td>$     58,986</td><td></td><td>$     4,796</td><td>$     9,372</td><td>$     7,831</td><td>$     36,987</td><td></td></tr><tr><td>Other commercial commitments:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Standby letters of credit(e)</td><td>$     714</td><td></td><td>$     710</td><td>$      —</td><td>$     4</td><td>$      —</td><td></td></tr><tr><td>Capital expenditures(f)</td><td>$     670</td><td></td><td>$     670</td><td>$      —</td><td>$      —</td><td>$      —</td><td></td></tr></table>

(a) Interest payment obligations exclude adjustments for interest rate swap agreements and assumes no change in variable interest rates from those in effect at December 31, 2012.

(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, 2012.

(d) Primarily represents EPB and KMI transportation and storage agreements for capacity on third party pipeline systems and storage capacity from an affiliate of $281 million and $134 million, respectively, and $258 million for right of way liabilities.

(e) The $714 million in letters of credit outstanding as of December 31, 2012 consisted of the following: (i) $293 million under eleven letters of credit related to power and marketing purposes; (ii) $105 million under twelve letters of credit for insurance purposes; (iii) 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 KMP's Pacific operations' pipelines in the state of California; (iv) KMP's $30 million guarantee under letters of credit totaling $46 million supporting KMP's International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a $45 million letter of credit supporting KMP's pipeline and



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

terminal operations in Canada; (vi) a $25 million letter of credit supporting KMP’s Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $24 million letter of credit supporting KMP’s Kinder Morgan Operating L.P. “B” tax-exempt bonds; (viii) a $15 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; (ix) a $12 million letter of credit supporting debt securities issued by the Express pipeline system; and (x) a combined $49 million in twenty seven letters of credit supporting environmental and other obligations of us and our subsidiaries.

(f) Represents commitments for expansions and the purchase of plant, property and equipment as of December 31, 2012.

## Cash Flows

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

<table><tr><td rowspan="3"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td colspan="4">(In millions)</td></tr><tr><td>Net Cash Provided by (Used in)</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating activities</td><td>$     2,795</td><td>$     2,366</td><td>$     1,913</td><td></td></tr><tr><td>Investing activities</td><td>(5,084)</td><td>(2,392)</td><td>(2,288)</td><td></td></tr><tr><td>Financing activities</td><td>2,584</td><td>(57)</td><td>710</td><td></td></tr><tr><td>Effect of Exchange Rate Changes on Cash</td><td>8</td><td>(8)</td><td>2</td><td></td></tr><tr><td>Net Increase (Decrease) in Cash and Cash Equivalents</td><td>$     303</td><td>$      (91)</td><td>$     337</td><td></td></tr></table>

## Operating Activities

The net increase of $429 (18%) million in cash provided by operating activities in the year ended December 31, 2012 compared to the respective 2011 period was primarily attributable to:

- a $865 million increase in cash from overall higher net income after adjusting our year-to-year $233 million decrease in net income for non-cash items primarily consisting of the remeasurement of net assets to fair value, depreciation, depletion and amortization, deferred income taxes, earnings from equity investments, and litigation reserve adjustments;

- a $290 million decrease associated with net changes in working capital, primarily driven by timing differences that resulted in lower net cash inflows from the collection and payment of trade and related party receivables and payables, including cash outflows of $112 million due to the termination of the accounts receivable sales program in the second quarter of 2012; and

- a $176 million decrease associated with net changes in both non-current assets and liabilities, including, among other things, lower net dock premiums and toll collections received from KMP's Trans Mountain pipeline customers.

## Investing Activities

The $2.7 billion net increase in cash expended for investing activities in the year ended December 31, 2012 compared to the respective 2011 period was primarily attributable to:

- a $5.0 billion cash outlay due to our acquisition of EP in May 2012, net of cash acquired of $6.6 billion (as discussed in Note 3 “Acquisitions and Divestiture—Acquisition of El Paso Corporation” to our consolidated financial statements included elsewhere in this report);

• an $822 million decrease in cash due to higher capital expenditures, as described above in “—Capital Expenditures;”

• a $1.8 billion increase in cash from the proceeds received from the disposal of KMP’s FTC Natural Gas Pipelines disposal group; and

- a $1.1 billion increase in cash due to lower expenditures for the acquisitions of assets and investments from unrelated parties (excluding the EP acquisition). In 2012, KMP paid a combined $83 million for asset acquisitions including a combined $58 million for assets from Enhanced Oil Resources, and from Lincoln Oil Co. Inc. In 2011, KMP spent an



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

aggregate amount of $1.2 billion for asset and investment acquisitions including $835 million for both KMP’s remaining 50% ownership interest in KinderHawk Field Services LLC and 25% equity interest in EagleHawk Field Services LLC.

## Financing Activities

The net increase of $2.6 billion in cash provided by financing activities in the year ended December 31, 2012 compared to the respective 2011 period was primarily attributable to:

- a $2.6 billion net increase in cash from overall debt financing activities primarily related to the May 2012 EP acquisition consisting of: (i) the issuance of $5.3 billion in debt (net of $87 million of debt issuance costs) used to finance a portion of the cash consideration and related fees and expenses paid in connection with the EP acquisition and (ii) a $2.7 billion decrease due to repayments made on the acquisition debt primarily funded by the cash portion of the TGP and 50% of EPNG drop-down transaction. Further information regarding the acquisition and acquisition debt is discussed in Note 3 “Acquisitions and Divestiture—KMI Acquisition of El Paso Corporation” and Note 8 “Debt—KMI,” respectively, to our consolidated financial statements included elsewhere in this report.

Apart from the aforementioned changes in our debt financing activities resulting from the EP acquisition, the year-to-year changes in our and our subsidiaries other debt repayments were largely offset by our debt issuances as summarized below (in millions).

<table><tr><td></td><td>KMI</td><td>KMP</td><td>EPB (a)</td><td>Total</td></tr><tr><td>Debt issuances</td><td>$     773</td><td>$     1,768</td><td>$     660</td><td>$     3,201</td></tr><tr><td>Debt repayments</td><td>(650)</td><td>(1,617)</td><td>(1,034)</td><td>(3,301)</td></tr><tr><td>Net cash increase (decrease)</td><td>$     123</td><td>$     151</td><td>$      (374)</td><td>$      (100)</td></tr></table>

(a) EPB debt issuances and repayments are for the period from May 25, 2012 through December 31, 2012.

Additional information regarding our and our subsidiaries' debt activities is discussed in Note 8 "Debt" to our consolidated financial statements included elsewhere in this report;

- a $969 million increase in contributions provided by non-controlling interests, primarily reflecting the $1.6 billion proceeds KMP received, after commissions and underwriting expenses, from the sales of additional KMP common units and sale of KMR shares in 2012 (discussed in Note 10 "Stockholders' Equity—Noncontrolling Interests—Contributions" to our consolidated financial statements included elsewhere in this report), versus the $955 million it received from the sales of additional KMP common units in the comparable 2011 period, and the $272 million of proceeds EPB received from its issuance of common units in 2012;

• a $414 million decrease in cash due to higher dividend payments;

- a $263 million decrease in cash associated with distributions to non-controlling interests, primarily reflecting the increased distributions to common unit owners by KMP and EPB. Further information regarding KMP and EPB's distributions are included in Note 10 “Stockholders' Equity—Noncontrolling Interests—Distributions” in our consolidated financial statements included elsewhere in this report; and

• a $157 million decrease in cash due to the warrant repurchases in 2012.

## Recent Accounting Pronouncements

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

## Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions,



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

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 which could cause actual results to differ from those in the forward-looking statements include:

• KMP’s ability to complete the proposed merger with Copano;

- failure to obtain, delays in obtaining or adverse conditions contained in, any required regulatory approvals or clearances for KMP’s proposed merger with Copano;

- the potential impact of the announcement or consummation of KMP’s proposed merger with Copano on relationships, including with employees, suppliers, customers and competitors;

• KMP’s ability to successfully integrate Copano’s operations and to realize synergies from the proposed merger;

• the terms and timing of proposed drop-downs of assets to KMP and EPB;

- the timing and extent of changes in 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 and certain agricultural products in North America;

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

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

- our ability to acquire new businesses and assets and integrate those operations into our existing operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as the ability to expand our facilities;

• our ability to access or construct new pipeline, gas processing and NGL fractionation capacity;

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

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

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

- changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in Oklahoma, Pennsylvania and Texas, the U.S. Rocky Mountains and the Alberta, Canada oil sands;

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

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

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

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

• the timing and success of our business development efforts;

- 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;

• changes in tax law, particularly as it relates to partnerships or other “pass-through” entities;

- our ability to offer and sell debt securities, and KMP’s and EPB’s ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our respective 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;

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

- acts of nature, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage greater than our insurance coverage limits;

• possible changes in credit ratings;

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

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

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

• our ability to achieve cost savings and revenue growth;

• foreign exchange fluctuations;

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



## Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

- the extent of KMP’s success in developing and producing oil and gas reserves, including the risks inherent in development drilling, well completion and other development activities;

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

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

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

See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in Item 1A “Risk Factors.” The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. 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 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 that we or KMP 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.

As part of the EP acquisition (see Note 3 “Acquisitions and Divestiture—KMI Acquisition of El Paso Corporation”), we acquired long-term natural gas and power forward and swap contracts. Prior to the acquisition, EP had entered into offsetting positions that eliminated the price risks associated with its power contracts and substantially offset the fixed price exposure related to its natural gas supply contracts. None of these derivatives are designated as accounting hedges.

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, KMP often enters into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of its crude oil or the margin from the sale and purchase of its 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 derivative contracts are only entered into 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 it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.

The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Ratings Services):

<table><tr><td></td><td>Credit Rating</td></tr><tr><td>J. Aron &amp; Company / Goldman Sachs</td><td>A-</td></tr><tr><td>Bank of America / Merrill Lynch</td><td>A-</td></tr><tr><td>Deutsche Bank</td><td>A+</td></tr><tr><td>Morgan Stanley</td><td>A-</td></tr><tr><td>J.P. Morgan</td><td>A</td></tr></table>

As discussed above, the 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 increased certainty with regard to operating cash flows which helps us and our subsidiaries to undertake further capital improvement projects, attain budget results and meet distribution targets. 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 which value is uncertain. Cash flow hedges are defined as hedges made with the intention of decreasing the variability in cash flows related to future transactions, as opposed to the value of an asset, liability or firm commitment, and we are allowed special hedge accounting treatment for such derivative contracts.



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

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

We measure the risk of price changes in the natural gas, crude oil and power derivative instruments portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. As of both December 31, 2012 and 2011, a hypothetical 10% movement in underlying commodity natural gas prices would affect the estimated fair value of natural gas derivatives, held by us and KMP, by $7 million and $4 million, respectively. As of both December 31, 2012 and 2011, a hypothetical 10% movement in underlying commodity crude oil prices would affect the estimated fair value of crude oil derivatives, held by KMP, by $196 million and $194 million, respectively. As of December 31, 2012, a hypothetical 10% movement in underlying commodity electricity prices would affect the estimated fair value of our power derivatives by $2 million. As discussed above, we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts portfolio is offset largely by changes in the value of the underlying physical transactions.

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the natural gas, crude oil and power portfolios of derivative contracts (including commodity futures and options contracts, fixed price swaps and basis swaps) 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. For more information on our energy commodity risk management activities, see Note 13 to our consolidated statements included elsewhere in this report.

## Interest Rate Risk

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

For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not 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 the fixed rate debt until such debt is required to be refinanced.

As of December 31, 2012 and 2011, the carrying values of the fixed rate debt (including the debt fair value adjustments) included in our accompanying consolidated balance sheets were $29,554 million and $16,100 million, respectively. These



amounts compare to, as of December 31, 2012 and 2011, fair values of $31,882 million and $16,462 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2012 and 2011, would result in changes of approximately $1,048 million and $575 million, respectively, in the fair values of these instruments.

The carrying value of the variable rate debt (which approximates the fair value), excluding the value of interest rate swap agreements (discussed following), was $4,847 million and $1,155 million as of December 31, 2012 and 2011, respectively. As of December 31, 2012, KMI and KMP were party to interest rate swap agreements with notional principal amounts of $725.0 million and $5,525 million, respectively. As of December 31, 2011, KMI and KMP were party to interest rate swap agreements with notional principal amounts of $725.0 million and $5,325 million, respectively. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal. A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 49 basis points in 2012 and approximately 44 basis points in 2011) when applied to our outstanding balance of variable rate debt as of December 31, 2012 and 2011, including adjustments for the notional swap amounts described above, would result in changes of approximately $55 million and $32 million, respectively, in our 2012 and 2011 annual pre-tax earnings.

As of December 31, 2012, EPB had no interest rate swap agreements outstanding. In September 2012, EPB terminated its existing variable-to-fixed interest rate swap agreements having a notional principal amount of $137 million and paid $14 million for the early termination of these swap agreements.

Interest rate swap agreements are entered into for the purpose of transforming a portion of the underlying cash flows related to 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 fixed rate debt varies with changes in the market rate of interest, swap agreements are entered into 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 the fixed rate debt due to market rate changes.

We monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time through our subsidiaries, may alter that mix by, for example, refinancing outstanding balances of 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, KMP attempts to maintain an overall target mix of approximately 50% fixed rate debt and 50% of variable rate debt, and typically KMI, excluding KMP, targets well below that level for variable rate debt. As of December 31, 2012, approximately 42% of KMI's debt, excluding that of KMP and EPB, is variable rate debt.

For more information on our interest rate risk management and on our interest rate swap agreements, see Note 13 to our consolidated financial statements included elsewhere in this report.

## Item 8. Financial Statements and Supplementary Data.

The information required in this Item 8 is included in this report as set forth in the “Index to Financial Statements” on page 120.

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, 2012, 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, 2012.

The effectiveness of our internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.

We acquired EP in a purchase business combination on May 25, 2012. EP is a wholly-owned subsidiary and we excluded this business from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012. EP total assets and total revenues represent 56% and 19%, respectively, of our related consolidated financial statement amounts as of and for the year ended December 31, 2012.

## Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2012 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.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.

## Item 11. Executive Compensation.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.

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

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.

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

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.

## Item 14. Principal Accounting Fees and Services.

The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.



## PART IV

## Item 15. Exhibits, Financial Statement Schedules.

## (a) Financial Statements

See “Index to Financial Statements” set forth on Page 120.

## (2) Financial Statement Schedules

The financial statements, including the notes thereto, of KMP and EPB, consolidated subsidiaries of Kinder Morgan, Inc., are incorporated herein by reference to pages 109 through 185 of Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2012 and pages 64 through 102 of El Paso Pipeline Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2012.

## (3) Exhibits

## Exhibit

## Number

## Description

2.1* — Agreement and Plan of Merger, dated as of October 16, 2011, among Kinder Morgan, Inc., Sherpa Merger Sub, Inc., Sherpa Acquisition, LLC, Sirius Holdings Merger Corporation, Sirius Merger Corporation and El Paso Corporation (included as Annex A to the information statement/proxy statement/prospectus forming a part of Kinder Morgan, Inc.'s Registration Statement on Form S-4 (File No. 333-177895) filed on November 10, 2011)

2.2* — Agreement and Plan of Merger, dated as of October 16, 2011, by and among El Paso Corporation, Sirius Holdings Merger Corporation and Sirius Merger Corporation (included as Annex B to the information statement/proxy statement/prospectus forming a part of Kinder Morgan, Inc.'s Registration Statement on Form S-4 (File No. 333-177895) filed on November 10, 2011)

3.1* — Certificate of Incorporation of Kinder Morgan, Inc. (filed as Exhibit 3.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 1-35081) (the "KMI 10-Q"))

3.2* — Amended and Restated Bylaws of Kinder Morgan, Inc. (filed as Exhibit 3.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 1-35081))

4.1* — Form of certificate representing Class P common shares of Kinder Morgan, Inc. (filed as Exhibit 4.1 to Kinder Morgan, Inc.'s Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))

4.2* — Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.2 to the KMI 10-Q)

4.3* — Amendment No. 1 to the Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.3 Kinder Morgan, Inc.'s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))

4.4* — Warrant Agreement, dated as of May 25, 2012, among Kinder Morgan, Inc., Computershare Trust Company, N.A. and Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to Kinder Morgan Inc.'s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))

10.1* — Kinder Morgan, Inc. 2011 Stock Incentive Plan (filed as Exhibit 10.1 to the KMI 10-Q)

10.2* — Form of Restricted Stock Agreement (filed as Exhibit 10.2 to the KMI 10-Q)

10.3* — Kinder Morgan, Inc. Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.4 to the KMI 10-Q)

10.4* — Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to the KMI 10-Q)

10.5* — Kinder Morgan, Inc. Employees Stock Purchase Plan (filed as Exhibit 10.5 to the KMI 10-Q)

10.6* — Kinder Morgan, Inc. Annual Incentive Plan (filed as Exhibit 10.6 to the KMI 10-Q)

10.7* — Employment Agreement dated October 7, 1999, between K N Energy, Inc. and Richard D. Kinder (filed as Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November 16, 1999 (File No. 5-06259))

10.8* — Form of Purchase Provisions between Kinder Morgan Management, LLC and Kinder Morgan Kansas, 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 (File No. 1-16459))

10.9* — Credit Agreement, dated as of May 30, 2007, among Kinder Morgan Kansas, 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 10.10 to Kinder Morgan, Inc.'s Registration Statement on Form S-1 filed on December 30, 2010 (File No. 333-170773))



10.10 \( ^{*} \)  — 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 Kansas, Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 (File No. 1-06446))

10.11 \( ^{*} \)  — 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 of K N Energy, Inc. filed on January 17, 1992 (File No. 33-45091))

10.12 \( ^{*} \)  — 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 Kansas, Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 filed on May 23, 2000 (File No. 1-06446))

10.13 \( ^{*} \)  — 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 of K N Energy, Inc. filed on November 19, 1993 (File No. 33-51115))

10.14 \( ^{*} \)  — Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Kansas, Inc. dated May 18, 2001 (filed as Exhibit 4.7 to Kinder Morgan Kansas, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-06446))

10.15 \( ^{*} \)  — Form of Indenture dated as of August 27, 2002 between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.'s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))

10.16 \( ^{*} \)  — Form of First Supplemental Indenture dated as of December 6, 2002 between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.'s Registration Statement on Form S-4 filed on January 31, 2003 (File No. 333-102873))

10.17 \( ^{*} \)  — Form of 6.50% Note due 2012 (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))

10.18 \( ^{*} \)  — Form of Senior Indenture between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.'s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))

10.19 \( ^{*} \)  — Form of Senior Note of Kinder Morgan Kansas, Inc. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.'s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))

10.20 \( ^{*} \)  — Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.'s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))

10.21 \( ^{*} \)  — Forms of Kinder Morgan Finance Company LLC notes (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))

10.22 \( ^{*} \)  — Form of Indemnification Agreement between Kinder Morgan Kansas, Inc. and each member of the Special Committee of the Board of Directors formed in connection with the Going Private Transaction (filed as Exhibit 10.1 to Kinder Morgan Kansas, Inc.'s Current Report on Form 8-K filed on June 16, 2006 (File No. 1-06446))

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

10.24 \( ^{*} \)  — Amendment No. 1 to Delegation of Control Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form 8-K on July 20, 2007 (File No. 1-11234))

10.25 \( ^{*} \)  — Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234))

10.26 \( ^{*} \)  — Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed November 22, 2004 (File No. 1-11234))

10.27 \( ^{*} \)  — Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed May 5, 2005 (File No. 1-11234))

10.28 \( ^{*} \)  — Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed April 21, 2008 (File No. 1-11234))



10.29* — Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.5 to Kinder Morgan Energy Partners, L.P. Form 10-K filed February 19, 2013 (File No. 1-11234))

10.30* — Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005 (File No. 1-11234))

10.31* — Form of Common Unit Compensation Agreement entered into with Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005 (File No. 1-11234))

10.32* — Credit Agreement dated as of June 23, 2010 among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. "B", the lenders party thereto, Wells Fargo Bank, National Association as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A., and DnB NOR Bank ASA (filed as exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed June 24, 2010 (File No. 1-11234))

10.33* — First Amendment to Credit Agreement, dated as of July 1, 2011, among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. "B", the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 1-11234))

10.34* — Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form 8-K filed February 16, 1999 (File No. 1-11234))

10.35* — Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-11234))

10.36* — Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234))

10.37* — Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))

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

10.39* — Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))

10.40* — Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))

10.41* — Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))

10.42* — First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))

10.43* — Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))

10.44* — Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))

10.45* — Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))

10.46* — Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.00% Notes due December 15, 2013 (filed as Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 1-11234))



10.47* — Certificate of Executive Vice President and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.125% Notes due November 15, 2014 (filed as Exhibit 4.27 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 3, 2004 (File No. 1-11234))

10.48* — Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234))

10.49* — Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))

10.50* — 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. Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))

10.51* — 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. Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (File No. 1-11234))

10.52* — 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. Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234))

10.53* — 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. Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234))

10.54* — Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.625% Senior Notes due 2015, and the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-11234))

10.55* — Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234))

10.56* — Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-11234))

10.57* — Indenture, dated December 20, 2010, among Kinder Morgan Finance Company LLC, Kinder Morgan Kansas, Inc. and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.'s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))

10.58* — Officers’ Certificate establishing the terms of the 6.000% senior notes due 2018 of Kinder Morgan Finance Company LLC (with the form of note attached thereto) (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))

10.59* — Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due 2016, and the 6.375% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.'s Quarterly Report on Form 10-K for the quarter ended March 31, 2011)

10.60* — Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.150% Senior Notes due 2022, and the 5.625% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.'s Quarterly Report on Form 10-K for the quarter ended September 30, 2011)

10.61* — Severance Agreement with C. Park Shaper (filed as Exhibit 10.7 to the KMI 10-Q)



10.62* — Severance Agreement with Steven J. Kean (filed as Exhibit 10.8 to the KMI 10-Q)

10.63* — Severance Agreement with Kimberly A. Dang (filed as Exhibit 10.9 to the KMI 10-Q)

10.64* — Severance Agreement with Joseph Listengart (filed as Exhibit 10.10 to the KMI 10-Q)

10.65* — Class B Share Plan (filed as Exhibit 10.65 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on January 26, 2011 (File No. 333-170773))

10.66* — Class B Trust Agreement (filed as Exhibit 10.66 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on January 26, 2011 (File No. 333-170773))

10.67* — Debt Commitment Letter between Kinder Morgan, Inc. and Barclays Capital PLC, dated as of October 16, 2011 (filed as Exhibit 10.71 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 filed on December 14, 2011 (File No. 333-177895))

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

21.1 — Subsidiaries of Kinder Morgan, Inc.

23.1 — Consent of PricewaterhouseCoopers LLP.

23.2 — Consent of Netherland, Sewell & Associates, Inc.

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.

95.1 — Mine Safety Disclosures.

99.1* — The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries (incorporated by reference to pages 109 through 185 of the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2012, filed on February 19, 2013).

99.2* — The financial statements of El Paso Pipeline Partners, L.P. and subsidiaries (incorporated by reference to pages 64 through 102 of the Annual Report on Form 10-K of El Paso Pipeline Partners, L.P. for the year ended December 31, 2012, filed on February 26, 2013).

99.3 — Estimates of the net reserves and future net revenues as of December 31, 2012 to Kinder Morgan CO2 Company, L.P.'s interests in certain oil and gas properties located in the state of Texas.

101 — Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2011; (iii) our Consolidated Balance Sheets as of December 31, 2012 and 2011; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; (v) our Consolidated Statement of Stockholders' Equity for the years ended December 31, 2012, 2011 and 2010 and (vi) the notes to our Consolidated Financial Statements.

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



## INDEX TO FINANCIAL STATEMENTS

<table><tr><td>KINDER MORGAN, INC. AND SUBSIDIARIES</td><td>Page Number</td></tr><tr><td>Report of Independent Registered Public Accounting Firm</td><td>102</td></tr><tr><td>Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010</td><td>103</td></tr><tr><td>Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010</td><td>105</td></tr><tr><td>Consolidated Balance Sheets as of December 31, 2012 and 2011</td><td>106</td></tr><tr><td>Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010</td><td>108</td></tr><tr><td>Consolidated Statement of Stockholders&#x27; Equity for the years ended December 31, 2012, 2011 and 2010</td><td>110</td></tr><tr><td>Notes to Consolidated Financial Statements</td><td>111</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 income, 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, 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 appearing in Item 9A of the Company's 2012 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 appearing in Item 9A of the Company's 2012 Annual Report on Form 10-K, management has excluded El Paso Corporation from its assessment of internal control over financial reporting as of December 31, 2012 because it was acquired in a purchase business combination by Kinder Morgan, Inc. on May 25, 2012. We have also excluded El Paso Corporation from our audit of internal control over financial reporting. El Paso Corporation is a wholly-owned subsidiary whose total assets and total revenues represent 56% and 19%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2012.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2013



## KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions, Except Per Share Amounts)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas sales</td><td>$ 2,511</td><td>$ 3,305</td><td>$ 3,571</td><td></td></tr><tr><td>Services</td><td>4,855</td><td>2,942</td><td>2,837</td><td></td></tr><tr><td>Product sales and other</td><td>2,607</td><td>1,696</td><td>1,444</td><td></td></tr><tr><td>Total Revenues</td><td>9,973</td><td>7,943</td><td>7,852</td><td></td></tr><tr><td>Operating Costs, Expenses and Other</td><td></td><td></td><td></td><td></td></tr><tr><td>Gas purchases and other costs of sales</td><td>3,057</td><td>3,278</td><td>3,505</td><td></td></tr><tr><td>Operations and maintenance</td><td>1,702</td><td>1,491</td><td>1,373</td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>1,419</td><td>1,068</td><td>1,056</td><td></td></tr><tr><td>General and administrative</td><td>929</td><td>515</td><td>631</td><td></td></tr><tr><td>Taxes, other than income taxes</td><td>286</td><td>174</td><td>160</td><td></td></tr><tr><td>Other expense</td><td>(13)</td><td>(6)</td><td>(6)</td><td></td></tr><tr><td>Total Operating Costs, Expenses and Other</td><td>7,380</td><td>6,520</td><td>6,719</td><td></td></tr><tr><td>Operating Income</td><td>2,593</td><td>1,423</td><td>1,133</td><td></td></tr><tr><td>Other Income (Expense)</td><td></td><td></td><td></td><td></td></tr><tr><td>Earnings (loss) from equity investments</td><td>153</td><td>226</td><td>(274)</td><td></td></tr><tr><td>Amortization of excess cost of equity investments</td><td>(23)</td><td>(7)</td><td>(6)</td><td></td></tr><tr><td>Interest expense</td><td>(1,427)</td><td>(703)</td><td>(668)</td><td></td></tr><tr><td>Interest income</td><td>28</td><td>21</td><td>21</td><td></td></tr><tr><td>Loss on remeasurement of previously held equity interest in KinderHawk to fair value (Note 3)</td><td>—</td><td>(167)</td><td>—</td><td></td></tr><tr><td>Other, net</td><td>19</td><td>17</td><td>24</td><td></td></tr><tr><td>Total Other Expense</td><td>(1,250)</td><td>(613)</td><td>(903)</td><td></td></tr><tr><td>Income from Continuing Operations Before Income Taxes</td><td>1,343</td><td>810</td><td>230</td><td></td></tr><tr><td>Income Tax Expense</td><td>(139)</td><td>(361)</td><td>(166)</td><td></td></tr><tr><td>Income from Continuing Operations</td><td>1,204</td><td>449</td><td>64</td><td></td></tr><tr><td>Discontinued Operations (Note 3)</td><td></td><td></td><td></td><td></td></tr><tr><td>Income from operations of KMP&#x27;s FTC Natural Gas Pipelines disposal group and other, net of tax</td><td>160</td><td>211</td><td>236</td><td></td></tr><tr><td>Loss on remeasurement to fair value and sale of KMP&#x27;s FTC Natural Gas Pipelines disposal group, net of tax</td><td>(937)</td><td>—</td><td>—</td><td></td></tr><tr><td>(Loss) Income from Discontinued Operations, Net of Tax</td><td>(777)</td><td>211</td><td>236</td><td></td></tr><tr><td>Net Income</td><td>427</td><td>660</td><td>300</td><td></td></tr><tr><td>Net Income Attributable to Noncontrolling Interests</td><td>(112)</td><td>(66)</td><td>(341)</td><td></td></tr><tr><td>Net Income (Loss) Attributable to Kinder Morgan, Inc.</td><td>$ 315</td><td>$ 594</td><td>$ (41)</td><td></td></tr></table>



## KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Continued)
(In Millions, Except Per Share Amounts)

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Class P Shares</td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Continuing Operations</td><td>$ 0.56</td><td>$ 0.70</td><td></td></tr><tr><td>Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations</td><td>(0.21)</td><td>0.04</td><td></td></tr><tr><td>Total Basic and Diluted Earnings Per Common Share</td><td>$ 0.35</td><td>$ 0.74</td><td></td></tr><tr><td>Class A Shares</td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Continuing Operations</td><td>$ 0.47</td><td>$ 0.64</td><td></td></tr><tr><td>Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations</td><td>(0.21)</td><td>0.04</td><td></td></tr><tr><td>Total Basic and Diluted Earnings Per Common Share</td><td>$ 0.26</td><td>$ 0.68</td><td></td></tr><tr><td>Basic Weighted-Average Number of Shares Outstanding</td><td></td><td></td><td></td></tr><tr><td>Class P Shares</td><td>461</td><td>118</td><td></td></tr><tr><td>Class A Shares</td><td>446</td><td>589</td><td></td></tr><tr><td>Diluted Weighted-Average Number of Shares Outstanding</td><td></td><td></td><td></td></tr><tr><td>Class P Shares</td><td>908</td><td>708</td><td></td></tr><tr><td>Class A Shares</td><td>446</td><td>589</td><td></td></tr><tr><td>Dividends Per Common Share Declared</td><td>$ 1.40</td><td>$ 1.05</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
(In Millions)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td>Kinder Morgan, Inc.</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss)</td><td>$     315</td><td>$     594</td><td>$     594</td><td>(41)</td></tr><tr><td>Other comprehensive income (loss), net of tax</td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes (net of tax benefit (expense) of $ (19), $ (5) and $ 9, respectively)</td><td>32</td><td>6</td><td>(19)</td><td></td></tr><tr><td>Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $3, $ (36) and $ (11), respectively)</td><td>(5)</td><td>67</td><td>22</td><td></td></tr><tr><td>Foreign currency translation adjustments (net of tax (expense) benefit of $ (8), $8, and $ (21), respectively)</td><td>14</td><td>(14)</td><td>38</td><td></td></tr><tr><td>Benefit plan adjustments (net of tax benefit of $33, $25 and $9, respectively)</td><td>(54)</td><td>(45)</td><td>(16)</td><td></td></tr><tr><td>Benefit plan amortization (net of tax (expense) benefit of $ (4), $ (4) and $ (4), respectively)</td><td>9</td><td>7</td><td>7</td><td></td></tr><tr><td>Total other comprehensive (loss) income</td><td>(4)</td><td>21</td><td>32</td><td></td></tr><tr><td>Total comprehensive income (loss)</td><td>311</td><td>615</td><td>(9)</td><td></td></tr><tr><td>Noncontrolling Interests</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>112</td><td>66</td><td>341</td><td></td></tr><tr><td>Other comprehensive income (loss), net of tax</td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $ (7), $ (1) and $4, respectively)</td><td>50</td><td>7</td><td>(35)</td><td></td></tr><tr><td>Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of \)-, $ (13) and $ (9), respectively)</td><td>(3)</td><td>117</td><td>86</td><td></td></tr><tr><td>Foreign currency translation adjustments (net of tax (expense) benefit of $ (2), $2 and $ (5), respectively)</td><td>18</td><td>(21)</td><td>45</td><td></td></tr><tr><td>Benefit plan adjustments (net of tax (expense) benefit of \)-, $2 and \(-, respectively)</td><td>13</td><td>(16)</td><td>(1)</td><td></td></tr><tr><td>Benefit plan amortization (net of tax benefit (expense) of \)-, \(- and \)-, respectively)</td><td>(4)</td><td>—</td><td>—</td><td></td></tr><tr><td>Total other comprehensive income (loss)</td><td>74</td><td>87</td><td>95</td><td></td></tr><tr><td>Total comprehensive income</td><td>186</td><td>153</td><td>436</td><td></td></tr><tr><td>Total</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>427</td><td>660</td><td>300</td><td></td></tr><tr><td>Other comprehensive income (loss), net of tax</td><td></td><td></td><td></td><td></td></tr><tr><td>Change in fair value of derivatives utilized for hedging purposes (net of tax (expense) benefit of $ (26), $ (6) and $13, respectively)</td><td>82</td><td>13</td><td>(54)</td><td></td></tr><tr><td>Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $3, $ (49) and $ (20), respectively)</td><td>(8)</td><td>184</td><td>108</td><td></td></tr><tr><td>Foreign currency translation adjustments (net of tax (expense) benefit of $ (10), $10 and $ (26), respectively)</td><td>32</td><td>(35)</td><td>83</td><td></td></tr><tr><td>Benefit plan adjustments (net of tax benefit of $33, $27 and $9, respectively)</td><td>(41)</td><td>(61)</td><td>(17)</td><td></td></tr><tr><td>Benefit plan amortization (net of tax (expense) benefit of $ (4), $ (4) and $ (4), respectively)</td><td>5</td><td>7</td><td>7</td><td></td></tr><tr><td>Total other comprehensive income</td><td>70</td><td>108</td><td>127</td><td></td></tr><tr><td>Total comprehensive income</td><td>$     497</td><td>$     768</td><td>$     427</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
(In Millions, Except Share and Per Share Amounts)

<table><tr><td rowspan="2">ASSETS</td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011</td></tr><tr><td>Current assets</td><td></td><td></td></tr><tr><td>Cash and cash equivalents - KMI (Note 19)</td><td>$ 82</td><td>$ 2</td></tr><tr><td>Cash and cash equivalents - KMP and EPB (Note 19)</td><td>632</td><td>409</td></tr><tr><td>Accounts, notes and interest receivable, net</td><td>1,404</td><td>914</td></tr><tr><td>Inventories</td><td>374</td><td>172</td></tr><tr><td>Fair value of derivative contracts</td><td>63</td><td>72</td></tr><tr><td>Assets held for sale</td><td>298</td><td>—</td></tr><tr><td>Other current assets</td><td>821</td><td>94</td></tr><tr><td>Total current assets</td><td>3,674</td><td>1,663</td></tr><tr><td>Property, plant and equipment, net (Note 19)</td><td>30,996</td><td>17,926</td></tr><tr><td>Investments</td><td>5,804</td><td>3,744</td></tr><tr><td>Notes receivable</td><td>76</td><td>165</td></tr><tr><td>Goodwill (Note 19)</td><td>23,572</td><td>5,074</td></tr><tr><td>Other intangibles, net</td><td>1,171</td><td>1,185</td></tr><tr><td>Fair value of derivative contracts</td><td>709</td><td>698</td></tr><tr><td>Deferred charges and other assets</td><td>2,183</td><td>262</td></tr><tr><td>Total Assets</td><td>$ 68,185</td><td>$ 30,717</td></tr><tr><td colspan="3">LIABILITIES AND STOCKHOLDERS&#x27; EQUITY</td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Current portion of debt - KMI (Note 19)</td><td>$ 1,153</td><td>$ 1,261</td></tr><tr><td>Current portion of debt - KMP and EPB (Note 19)</td><td>1,248</td><td>1,638</td></tr><tr><td>Cash book overdrafts</td><td>48</td><td>23</td></tr><tr><td>Accounts payable</td><td>1,200</td><td>728</td></tr><tr><td>Accrued interest</td><td>513</td><td>330</td></tr><tr><td>Fair value of derivative contracts</td><td>80</td><td>121</td></tr><tr><td>Accrued other current liabilities</td><td>967</td><td>428</td></tr><tr><td>Total current liabilities</td><td>5,209</td><td>4,529</td></tr><tr><td>Long-term liabilities and deferred credits</td><td></td><td></td></tr><tr><td>Long-term debt</td><td></td><td></td></tr><tr><td>Outstanding - KMI (Note 19)</td><td>10,341</td><td>1,978</td></tr><tr><td>Outstanding - KMP and EPB (Note 19)</td><td>18,968</td><td>11,183</td></tr><tr><td>Preferred interest in general partner of KMP</td><td>100</td><td>100</td></tr><tr><td>Debt fair value adjustments</td><td>2,591</td><td>1,095</td></tr><tr><td>Total long-term debt</td><td>32,000</td><td>14,356</td></tr><tr><td>Deferred income taxes</td><td>4,033</td><td>2,199</td></tr><tr><td>Fair value of derivative contracts</td><td>133</td><td>39</td></tr><tr><td>Other long-term liabilities and deferred credits</td><td>2,711</td><td>1,026</td></tr><tr><td>Total long-term liabilities and deferred credits</td><td>38,877</td><td>17,620</td></tr><tr><td>Total Liabilities</td><td>$ 44,086</td><td>$ 22,149</td></tr></table>



## KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)
(In Millions, Except Share and Per Share Amounts)

<table><tr><td colspan="4">Commitments and contingencies (Notes 8, 12 and 16)</td></tr><tr><td colspan="4">Stockholders&#x27; Equity</td></tr><tr><td>Class P shares, $0.01 par value, 2,000,000,000 shares authorized, 1,035,668,596, and 170,921,140 shares, respectively, issued and outstanding</td><td>$</td><td>10</td><td>$ 2</td></tr><tr><td>Class A shares, $0.01 par value, 707,000,000 shares authorized, no shares and 535,972,387 shares, respectively, issued and outstanding</td><td></td><td>—</td><td>5</td></tr><tr><td>Class B shares, $0.01 par value, 100,000,000 shares authorized, no shares and 94,132,596 shares, respectively, issued and outstanding</td><td></td><td>—</td><td>1</td></tr><tr><td>Class C shares, $0.01 par value, 2,462,927 shares authorized, no shares and 2,318,258 shares, respectively, issued and outstanding</td><td></td><td>—</td><td>—</td></tr><tr><td>Preferred stock, $0.01 par value, 10,000,000 shares authorized, none outstanding</td><td></td><td>—</td><td>—</td></tr><tr><td>Additional paid-in capital</td><td></td><td>14,917</td><td>3,431</td></tr><tr><td>Retained deficit</td><td></td><td>(943)</td><td>(3)</td></tr><tr><td>Accumulated other comprehensive loss</td><td></td><td>(119)</td><td>(115)</td></tr><tr><td>Total Kinder Morgan, Inc.&#x27;s stockholders&#x27; equity</td><td></td><td>13,865</td><td>3,321</td></tr><tr><td>Noncontrolling interests</td><td></td><td>10,234</td><td>5,247</td></tr><tr><td>Total Stockholders&#x27; Equity</td><td></td><td>24,099</td><td>8,568</td></tr><tr><td>Total Liabilities and Stockholders&#x27; Equity</td><td></td><td>$ 68,185</td><td>$ 30,717</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
(In Millions)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Cash Flows From Operating Activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     427</td><td>$     660</td><td>$     300</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash provided by operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>1,426</td><td>1,092</td><td>1,079</td><td></td></tr><tr><td>Deferred income taxes</td><td>47</td><td>84</td><td>(8)</td><td></td></tr><tr><td>Amortization of excess cost of equity investments</td><td>23</td><td>7</td><td>6</td><td></td></tr><tr><td>Loss from the remeasurement of net assets to fair value and the sale of discontinued operations (net of cash selling expenses) (Note 3)</td><td>859</td><td>167</td><td>—</td><td></td></tr><tr><td>Loss on early extinguishment of debt</td><td>82</td><td>—</td><td>—</td><td></td></tr><tr><td>Non-cash compensation expense on settlement of EP stock awards</td><td>87</td><td>—</td><td>—</td><td></td></tr><tr><td>(Earnings) loss from equity investments</td><td>(223)</td><td>(313)</td><td>186</td><td></td></tr><tr><td>Distributions from equity investments</td><td>381</td><td>287</td><td>220</td><td></td></tr><tr><td>Proceeds from termination of interest rate swap agreements</td><td>53</td><td>73</td><td>157</td><td></td></tr><tr><td>Changes in components of working capital</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(231)</td><td>8</td><td>18</td><td></td></tr><tr><td>Inventories</td><td>(92)</td><td>(36)</td><td>19</td><td></td></tr><tr><td>Other current assets</td><td>32</td><td>(10)</td><td>—</td><td></td></tr><tr><td>Accounts payable</td><td>44</td><td>41</td><td>(1)</td><td></td></tr><tr><td>Cash book overdrafts</td><td>26</td><td>(12)</td><td>(2)</td><td></td></tr><tr><td>Accrued interest</td><td>(26)</td><td>19</td><td>18</td><td></td></tr><tr><td>Accrued liabilities</td><td>(68)</td><td>(35)</td><td>(49)</td><td></td></tr><tr><td>Rate reparations, refunds and other litigation reserve adjustments</td><td>(39)</td><td>171</td><td>(34)</td><td></td></tr><tr><td>Other, net</td><td>(13)</td><td>163</td><td>4</td><td></td></tr><tr><td>Net Cash Provided by Operating Activities</td><td>2,795</td><td>2,366</td><td>1,913</td><td></td></tr><tr><td>Cash Flows From Investing Activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Acquisition of El Paso (net of $6,581 cash acquired)</td><td>(4,970)</td><td>—</td><td>—</td><td></td></tr><tr><td>Acquisitions of investments</td><td>—</td><td>(971)</td><td>(926)</td><td></td></tr><tr><td>Acquisitions of assets</td><td>(83)</td><td>(208)</td><td>(288)</td><td></td></tr><tr><td>Proceeds from disposal of discontinued operations</td><td>1,791</td><td>—</td><td>—</td><td></td></tr><tr><td>Repayments from related party</td><td>76</td><td>31</td><td>3</td><td></td></tr><tr><td>Capital expenditures</td><td>(2,022)</td><td>(1,200)</td><td>(1,006)</td><td></td></tr><tr><td>Sale or casualty of property, plant and equipment and other net assets, net of removal costs</td><td>154</td><td>23</td><td>49</td><td></td></tr><tr><td>Contributions to investments</td><td>(192)</td><td>(371)</td><td>(299)</td><td></td></tr><tr><td>Distributions from equity investments in excess of cumulative earnings</td><td>200</td><td>236</td><td>225</td><td></td></tr><tr><td>Other, net</td><td>(38)</td><td>68</td><td>(46)</td><td></td></tr><tr><td>Net Cash Used in Investing Activities</td><td>(5,084)</td><td>(2,392)</td><td>(2,288)</td><td></td></tr><tr><td>Cash Flows From Financing Activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Issuance of debt - KMI</td><td>8,218</td><td>2,070</td><td>2,233</td><td></td></tr><tr><td>Payment of debt - KMI</td><td>(5,710)</td><td>(2,399)</td><td>(1,655)</td><td></td></tr><tr><td>Issuance of debt - KMP and EPB</td><td>9,930</td><td>7,502</td><td>7,140</td><td></td></tr><tr><td>Payment of debt - KMP and EPB</td><td>(9,045)</td><td>(6,394)</td><td>(6,186)</td><td></td></tr><tr><td>Debt issue costs</td><td>(111)</td><td>(76)</td><td>(31)</td><td></td></tr><tr><td>Cash dividends/distributions (Note 10)</td><td>(1,184)</td><td>(770)</td><td>(700)</td><td></td></tr><tr><td>Repurchase of warrants</td><td>(157)</td><td>—</td><td>—</td><td></td></tr><tr><td>Contributions from noncontrolling interests</td><td>1,939</td><td>970</td><td>759</td><td></td></tr><tr><td>Distributions to noncontrolling interests</td><td>(1,219)</td><td>(956)</td><td>(849)</td><td></td></tr><tr><td>Other, net</td><td>(77)</td><td>(4)</td><td>(1)</td><td></td></tr><tr><td>Net Cash Provided by (Used in) Financing Activities</td><td>2,584</td><td>(57)</td><td>710</td><td></td></tr><tr><td>Effect of Exchange Rate Changes on Cash and Cash Equivalents</td><td>8</td><td>(8)</td><td>2</td><td></td></tr></table>



<table><tr><td>Net increase (decrease) in Cash and Cash Equivalents</td><td>303</td><td>(91)</td><td>337</td></tr><tr><td>Cash and Cash Equivalents, beginning of period</td><td>411</td><td>502</td><td>165</td></tr><tr><td>Cash and Cash Equivalents, end of period</td><td>$ 714</td><td>$ 411</td><td>$ 502</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 (continued)
(In Millions)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Noncash Investing and Financing Activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net assets and liabilities acquired by the issuance of shares and warrants</td><td>$     11,454</td><td>$      —</td><td>$      —</td><td></td></tr><tr><td>Liabilities settled by the issuance of shares and warrants</td><td>$     15</td><td>$      —</td><td>$      —</td><td></td></tr><tr><td>Assets acquired by the assumption or incurrence of liabilities</td><td>$      —</td><td>$     207</td><td>$     14</td><td></td></tr><tr><td>Assets acquired by contributions from noncontrolling interests</td><td>$     306</td><td>$     24</td><td>$     82</td><td></td></tr><tr><td>Increase in accrual for construction costs</td><td>$     83</td><td>$     35</td><td>$     28</td><td></td></tr><tr><td>Supplemental Disclosures of Cash Flow Information</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>$     1,349</td><td>$     681</td><td>$     628</td><td></td></tr><tr><td>Cash paid during the period for income taxes (net of refunds)</td><td>$     182</td><td>$     277</td><td>$     147</td><td></td></tr></table>

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



## KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In Millions)

<table><tr><td></td><td>KMI Members</td><td>Common Shares</td><td>Additional paid-in capital</td><td>Retained deficit</td><td>Accumulated other comprehensive loss</td><td>Stockholders&#x27; equity attributable to KMI</td><td>Non-controlling interests</td><td>Total</td></tr><tr><td>Balance at December 31, 2009</td><td>$ 4,338</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ (168)</td><td>$ 4,170</td><td>$ 4,675</td><td>$ 8,845</td></tr><tr><td>Impact from equity transactions of KMP</td><td>(28)</td><td></td><td></td><td></td><td></td><td>(28)</td><td>43</td><td>15</td></tr><tr><td>A-1 and B unit amortization</td><td>6</td><td></td><td></td><td></td><td></td><td>6</td><td></td><td>6</td></tr><tr><td>Net (loss) income</td><td>(41)</td><td></td><td></td><td></td><td></td><td>(41)</td><td>341</td><td>300</td></tr><tr><td>Distributions</td><td></td><td></td><td></td><td></td><td></td><td>—</td><td>(849)</td><td>(849)</td></tr><tr><td>Contributions</td><td></td><td></td><td></td><td></td><td></td><td>—</td><td>841</td><td>841</td></tr><tr><td>Deconsolidation of variable interest entity</td><td></td><td></td><td></td><td></td><td></td><td>—</td><td>(46)</td><td>(46)</td></tr><tr><td>Cash distributions</td><td>(700)</td><td></td><td></td><td></td><td></td><td>(700)</td><td></td><td>(700)</td></tr><tr><td>Other comprehensive income</td><td></td><td></td><td></td><td></td><td>32</td><td>32</td><td>95</td><td>127</td></tr><tr><td>Balance at December 31, 2010</td><td>3,575</td><td>—</td><td>—</td><td>—</td><td>(136)</td><td>3,439</td><td>5,100</td><td>8,539</td></tr><tr><td>Reclassification of equity upon the offering</td><td>(3,404)</td><td>8</td><td>3,396</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of restricted shares</td><td></td><td></td><td>7</td><td></td><td></td><td>7</td><td></td><td>7</td></tr><tr><td>Impact from equity transactions of KMP</td><td></td><td></td><td>28</td><td></td><td></td><td>28</td><td>(44)</td><td>(16)</td></tr><tr><td>A-1 and B unit amortization</td><td>4</td><td></td><td></td><td></td><td></td><td>4</td><td></td><td>4</td></tr><tr><td>Net income</td><td>71</td><td></td><td></td><td>523</td><td></td><td>594</td><td>66</td><td>660</td></tr><tr><td>Distributions</td><td></td><td></td><td></td><td></td><td></td><td>—</td><td>(956)</td><td>(956)</td></tr><tr><td>Contributions</td><td></td><td></td><td></td><td></td><td></td><td>—</td><td>994</td><td>994</td></tr><tr><td>Cash distributions/dividends</td><td>(246)</td><td></td><td></td><td>(524)</td><td></td><td>(770)</td><td></td><td>(770)</td></tr><tr><td>Class A, Class B and Class C share conversions</td><td></td><td></td><td></td><td>(2)</td><td></td><td>(2)</td><td></td><td>(2)</td></tr><tr><td>Other comprehensive income</td><td></td><td></td><td></td><td></td><td>21</td><td>21</td><td>87</td><td>108</td></tr><tr><td>Balance at December 31, 2011</td><td>—</td><td>8</td><td>3,431</td><td>(3)</td><td>(115)</td><td>3,321</td><td>5,247</td><td>8,568</td></tr><tr><td>EP acquisition (Note 3)</td><td></td><td>3</td><td>11,461</td><td></td><td></td><td>11,464</td><td>3,797</td><td>15,261</td></tr><tr><td>Warrants repurchased</td><td></td><td></td><td>(157)</td><td></td><td></td><td>(157)</td><td>—</td><td>(157)</td></tr><tr><td>Conversion of EP Trust I Preferred Securities</td><td></td><td></td><td>14</td><td></td><td></td><td>14</td><td>—</td><td>14</td></tr><tr><td>Class A, Class B and Class C share conversions</td><td></td><td>(1)</td><td>1</td><td>(71)</td><td></td><td>(71)</td><td>—</td><td>(71)</td></tr><tr><td>Amortization of restricted shares</td><td></td><td></td><td>14</td><td></td><td></td><td>14</td><td>—</td><td>14</td></tr><tr><td>Impact from equity transactions of KMP, KMR and EPB</td><td></td><td></td><td>64</td><td></td><td></td><td>64</td><td>(102)</td><td>(38)</td></tr><tr><td>Tax impact on stock based compensation</td><td></td><td></td><td>90</td><td></td><td></td><td>90</td><td>—</td><td>90</td></tr><tr><td>Net income</td><td></td><td></td><td></td><td>315</td><td></td><td>315</td><td>112</td><td>427</td></tr><tr><td>Distributions</td><td></td><td></td><td></td><td></td><td></td><td>—</td><td>(1,219)</td><td>(1,219)</td></tr><tr><td>Contributions</td><td></td><td></td><td></td><td></td><td></td><td>—</td><td>2,329</td><td>2,329</td></tr><tr><td>Cash dividends</td><td></td><td></td><td></td><td>(1,184)</td><td></td><td>(1,184)</td><td>—</td><td>(1,184)</td></tr><tr><td>Other</td><td></td><td></td><td>(1)</td><td></td><td></td><td>(1)</td><td>(4)</td><td>(5)</td></tr><tr><td>Other comprehensive (loss) income</td><td></td><td></td><td></td><td></td><td>(4)</td><td>(4)</td><td>74</td><td>70</td></tr><tr><td>Balance at December 31, 2012</td><td>$ —</td><td>$ 10</td><td>$ 14,917</td><td>$ (943)</td><td>$ (119)</td><td>$ 13,865</td><td>$ 10,234</td><td>$ 24,099</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

Kinder Morgan, Inc. is the largest midstream and the third largest energy company in North America with a combined enterprise value, including its two publicly traded master limited partnership subsidiaries, of approximately $100 billion and unless the context requires otherwise, references to “we,” “us,” “our,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, gasoline, crude oil, CO \( _2 \)  and other products, and our terminals store petroleum products and chemicals and handle such products as ethanol, coal, petroleum coke and steel.

Effective on May 25, 2012, we completed the acquisition of all of the outstanding shares of El Paso Corporation, referred to as “EP.” As a result, we own a 41% limited partner interest and the 2% general partner interest in El Paso Pipeline Partners, L.P., referred to as “EPB,” as well as certain natural gas pipeline assets (see Notes 3 and 10).

We also own the general partner and approximately 11% of the limited partner interests of Kinder Morgan Energy Partners, L.P. (KMP), one of the largest publicly-traded pipeline limited partnerships in America. KMP’s limited partner units are traded on the New York Stock Exchange under the ticker symbol “KMP.”

On February 16, 2011, we completed the initial public offering of our common stock (the offering). All of the common stock that was sold in the offering was sold by our existing investors consisting of funds advised by or affiliated with Goldman Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC. No members of management sold shares in the offering, and we did not receive any proceeds from the offering. During 2012, the funds advised by or affiliated with Goldman Sachs & Co., The Carlyle Group and Riverstone Holdings LLC, sold their remaining interests in KMI and representatives of these funds are no longer on our board. For additional information on the offering, see Note 10 “Shareholders’ Equity—Kinder Morgan, Inc.—Equity Interests—Initial Public Offering.”

Kinder Morgan Management, LLC (KMR), is a publicly traded Delaware limited liability company. Kinder Morgan G.P., Inc., the general partner of KMP and a wholly owned subsidiary of ours, owns all of KMR’s voting shares. KMR, 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 KMP, 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$.

Our accompanying consolidated financial statements have been prepared under the rules and regulations of the United States Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation. 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 our accounts and those of our majority-owned subsidiaries as well as the accounts of KMP, EPB and KMR. Investments in jointly owned operations in which we hold a 50% or less interest (other than KMP, EPB and KMR, because we have the ability to exercise significant control over their operating and financial policies) are accounted for under the equity method. All significant intercompany transactions and balances have been eliminated.

Notwithstanding the consolidation of KMP and EPB and their respective subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of KMP and EPB and/or their respective subsidiaries and vice versa, except as discussed in the following paragraph. Responsibility for payments of obligations reflected in our, KMP’s or EPB’s financial statements is a legal determination based on the entity that incurs the liability.



In conjunction with KMP’s acquisition of certain natural gas pipelines from us, we agreed to indemnify KMP with respect to approximately $4.3 billion of its debt. This includes $3.6 billion associated with KMP’s August 2012 purchase of Tennessee Gas Pipeline L.L.C. and 50% of El Paso Natural Gas Company, L.L.C. In conjunction with our EP acquisition, we have agreed to indemnify EPB with respect to $470 million of its debt. We would be obligated to perform under these indemnities only if KMP’s or EPB’s assets, as applicable, were unable to satisfy its obligations.

Effective November 1, 2012, we sold KMP’s FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, L.P. for approximately $1.8 billion (before selling costs), or $3.3 billion including our share of joint venture debt, to satisfy terms of a March 15, 2012 agreement with the U.S. Federal Trade Commission (FTC) to divest certain of its assets in order to receive regulatory approval for its EP acquisition. KMP’s FTC Natural Gas Pipelines disposal group’s assets included (i) Kinder Morgan Interstate Gas Transmission natural gas pipeline system; (ii) Trailblazer natural gas pipeline system; (iii) Casper and Douglas natural gas processing operations; and (iv) 50% equity investment in the Rockies Express natural gas pipeline system. Accordingly, we (i) reclassified and excluded KMP’s FTC Natural Gas Pipelines disposal group’s results of operations from our results of continuing operations and reported the disposal group’s results of operations separately as “Income from operations of KMP’s FTC Natural Gas Pipelines disposal group and other, net of tax” within the discontinued operations section of our accompanying consolidated statements of income for all periods presented and (ii) separately reported a “(Loss) on remeasurement to fair value and sale of KMP’s FTC Natural Gas Pipelines disposal group, net of tax” within the discontinued operations section of our accompanying consolidated statements of income for the year ended December 31, 2012. In addition, we did not elect to present separately the operating, investing and financing cash flows related to the disposal group in our accompanying consolidated statements of cash flows.

For more information about the divestiture of KMP’s FTC Natural Gas Pipelines disposal group, see Note 3 “Acquisitions and Divestitures—FTC Natural Gas Pipelines Disposal Group - Discontinued Operations.”

## Acquisition Method of Accounting

We account for acquired businesses that we control by the acquisition method of accounting. Under this method, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values (with limited exceptions) on the date of acquisition. We recognize the sum of (i) the value of consideration transferred, (ii) the value of any noncontrolling interest in the acquiree, and (iii) the fair value of any previously held equity interest in the acquiree as goodwill to the extent it exceeds the estimated fair value and as a bargain purchase gain to the extent it is below the estimated fair value. Additionally, we classify or designate the identifiable assets acquired and liabilities assumed as necessary to subsequently apply other GAAP based on their contractual terms, economic conditions, our operating or accounting policies, and other pertinent conditions as they exist on the date of acquisition. See Note 3 for more information on our acquisitions and application of the acquisition method.

## Going Private Transaction

On May 30, 2007 we went through a going private transaction (the Going Private Transaction). The Going Private Transaction 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 based on an allocation of the aggregate purchase price paid in the Going Private Transaction, resulting in a new basis of accounting effective with the closing of the Going Private Transaction. To the extent that we consolidated less than wholly owned subsidiaries (such as KMP and KMR), the reported assets and liabilities for these entities were 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 our purchase of our economic interest in these entities (approximately 50% in the case of KMP and 14% in the case of KMR). The remaining percentage of these assets and liabilities, reflecting the continuing noncontrolling ownership interest, is included at its historical accounting basis.

## 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 and Restricted Deposits

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

As of December 31, 2012 and 2011, our restricted deposits totaled $52 million and $35 million, respectively. As of December 31, 2012 restricted deposits consisted primarily of (i) $45 million associated with KM Insurance, Ltd., a Bermuda insurance company and wholly-owned subsidiary of KMI; (ii) KMP's restricted cash of $2 million deposited into a third-party escrow account to comply with certain contractual stipulations related to its Canadian terminal operations; and (iii) $5 million consisting of cash margin deposits associated with KMP's energy commodity contract positions and over-the-counter swap partners. As of December 31, 2011, restricted deposits consisted of $35 million associated with KM Insurance, Ltd., a Bermuda insurance company. We report restricted deposits within "Other current assets" on our accompanying consolidated balance sheets.

## Accounts Receivable

The amounts reported as “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheets as of December 31, 2012 and 2011 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.

## Inventories

Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas and carbon dioxide. We report these assets at the lower of weighted-average cost or market. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

## 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 both December 31, 2012 and 2011, our gas imbalance receivables—including both trade and related party receivables—totaled $18 million and $19 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2012 and 2011, our gas imbalance payables—including both trade and related party payables—totaled $150 million and $10 million, respectively, and we included these amounts within “Accrued other current liabilities” on our accompanying consolidated balance sheets.

## Property, Plant and Equipment

## Capitalization, Depreciation and Depletion and Disposals

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



are recorded to the appropriate accumulated depreciation reserve. Generally, gains and losses for operating unit sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines. In those instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount.

We generally compute depreciation using the straight-line method based on estimated economic lives; however, for certain depreciable assets, we employ the composite depreciation method, applying a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.9% to 23.0% 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 our accompanying consolidated balance sheets), and this unrecoverable portion is depreciated over the facility’s estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

## Impairments

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



We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. For the purpose of impairment testing, adjustments for the inclusion of risk-adjusted probable and possible reserves, as well as forward curve pricing, will cause impairment calculation cash flows to differ from the amounts presented in “Supplemental Information on Oil and Gas Activities (Unaudited)” included elsewhere in this report.

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.

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

## Goodwill

Goodwill represents the excess of the cost of an acquisition price over the fair value of the acquired net assets, and such amounts are reported separately as “Goodwill” on our accompanying consolidated balance sheets. Our total goodwill was $23,572 million and $5,074 million as of December 31, 2012 and 2011, respectively. Goodwill cannot be amortized, but instead must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We perform our goodwill impairment test on May 31 of each year. There were no impairment charges resulting from our May 31, 2012, 2011 or 2010 impairment testing, and no event indicating an impairment has occurred subsequent to May 31, 2012.

If a significant portion of one of our business segments is disposed of (that also constitutes a business), we would allocate goodwill based on the relative fair values of the portion of the segment being disposed of and the portion of the segment remaining. 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, generally based on Houston Ship Channel index posted prices. In some cases, we sell natural gas under short-term agreements at prevailing market prices. In all cases, we recognize natural gas sales revenues when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies. We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and generally, our natural gas marketing revenues are recorded gross, not net of cost of gas sold.

In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers. The natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes



## Item 15. Exhibits, Financial Statement Schedules. (continued)

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.

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, carbon dioxide 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 generally 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 record at fair value, where appropriate, environmental liabilities assumed in a business combination.

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, is reasonably possible to occur, and may 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.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## Pensions and Other Postretirement Benefits

We fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and other 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 or as a regulatory asset or liability for certain of our regulated operations, until they are amortized to be recognized as a component of benefit 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. In our accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests represents the ownership interests in our consolidated subsidiaries’ net assets held by parties other than us. It is presented separately as “Noncontrolling interests” within “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 us, we have applied an accounting policy that looks through its investments including its investment in KMP. 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 KMP.

## Foreign Currency Transactions and Translation

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

Foreign currency translation is the process of expressing, in U.S. dollars, amounts denominated or measured in a different local functional currency, for example the Canadian dollar for a Canadian subsidiary. We translate the assets and liabilities of each of our consolidating foreign subsidiaries that have a local functional currency to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and 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 our accompanying consolidated balance sheets.

## Comprehensive Income

For each of the years ended December 31, 2012, 2011 and 2010, the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts utilized for hedging our exposure to fluctuating expected future cash flows produced by both energy commodity price risk and interest rate risk; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 13.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Cumulative revenues, expenses, gains and losses that under U.S. generally accepted accounting principles are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. The following table summarizes changes in the amount of our “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets for each of the years ended December 31, 2012 and 2011 (in millions):

<table><tr><td></td><td>Net unrealized gains/(losses) on cash flow hedge derivatives</td><td>Foreign currency translation adjustments</td><td>Pension and other postretirement liability adj.</td><td>Total accumulated other comprehensive loss</td></tr><tr><td>December 31, 2010</td><td>$ (93)</td><td>$ 51</td><td>$ (94)</td><td>$ (136)</td></tr><tr><td>Change for period</td><td>73</td><td>(14)</td><td>(38)</td><td>21</td></tr><tr><td>December 31, 2011</td><td>(20)</td><td>37</td><td>(132)</td><td>(115)</td></tr><tr><td>Change for period</td><td>27</td><td>14</td><td>(45)</td><td>(4)</td></tr><tr><td>December 31, 2012</td><td>$ 7</td><td>$ 51</td><td>$ (177)</td><td>$ (119)</td></tr></table>

## Risk Management Activities

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

Furthermore, changes in our derivative contracts’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative contract meets those criteria, the contract’s gains and losses 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 our regulatory assets and liabilities totaled $464 million and $120 million, respectively, as of December 31, 2012, and totaled $15 million and $12 million respectively, as of December 31, 2011. We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Accrued other current liabilities” and “Other long-term liabilities and deferred credits,” in our accompanying consolidated balance sheets as of December 31, 2012 and 2011. These assets are expected to be recovered in tariff rates over a period of approximately one year to forty-three years.

## 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.



## Earnings per Share

On December 26, 2012, the remaining outstanding shares of our Class A, Class B, and Class C common stock were converted into Class P shares and as of December 31, 2012 only our Class P common stock was outstanding, see Note 10.

Earnings per share was calculated using the two-class method. Earnings were allocated to each class of common stock based on the amount of dividends declared in the current period for each class of stock plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security shares in earnings or excess distributions over earnings. For the investor retained stock, the allocation of undistributed earnings or excess distributions over earnings was in direct proportion to the maximum number of Class P shares into which it could convert.

For the Class P diluted per share computations, total net income attributable to Kinder Morgan, Inc. was divided by the adjusted weighted-average shares outstanding during the period, including all dilutive potential shares. This included the Class P shares into which the investor retained stock was convertible. The number of Class P shares on a fully-converted basis was the same before and after any conversion of our investor retained stock. Each time one Class P share was issued upon conversion of investor retained stock, the number of Class P shares went up by one, and the number of Class P shares into which the investor retained stock was convertible went down by one. Accordingly, there was no difference between Class P basic and diluted earnings per share because the conversion of Class A, Class B, and Class C shares into Class P shares did not impact the number of Class P shares on a fully-converted basis. Commencing with the acquisition of EP, dilutive potential shares also included the Class P shares issuable in connection with the warrants (see Note 10) and the trust preferred securities (see Note 3). For 2012, our warrants and convertible trust preferred securities were antidilutive and, accordingly, were excluded from the determination of diluted earnings per share.

As no securities were convertible into Class A shares, the basic and diluted earnings per share computations for Class A shares were the same.

The following tables set forth the computation of basic and diluted earnings per share from continuing operations for the year ending December 31, 2012 and the period ending February 11, 2011 (the date of our initial public offering) through December 31, 2011 (in millions, except per share amounts):

<table><tr><td rowspan="3"></td><td colspan="6">Year ended December 31, 2012</td></tr><tr><td colspan="5">Income from Continuing Operations Available to Shareholders</td><td rowspan="2">Total</td></tr><tr><td>Class P</td><td colspan="2">Class A</td><td colspan="2">Participating Securities (a)</td></tr><tr><td>Income from continuing operations</td><td></td><td></td><td></td><td></td><td></td><td>$ 1,204</td></tr><tr><td>Less: income from continuing operations attributable to noncontrolling interests</td><td></td><td></td><td></td><td></td><td></td><td>(696)</td></tr><tr><td>Income from continuing operations attributable to KMI</td><td></td><td></td><td></td><td></td><td></td><td>508</td></tr><tr><td>Dividends declared during the period</td><td>$ 601</td><td>$ 542</td><td>$ 41</td><td></td><td></td><td>(1,184)</td></tr><tr><td>Excess distributions over earnings</td><td>(344)</td><td>(331)</td><td></td><td>(1)</td><td>$ (676)</td><td></td></tr><tr><td>Income from continuing operations attributable to shareholders</td><td>$ 257</td><td>$ 211</td><td>$ 40</td><td></td><td></td><td>508</td></tr><tr><td>Basic earnings per share from continuing operations</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic weighted-average number of shares outstanding</td><td>461</td><td></td><td>446</td><td>N/A</td><td></td><td></td></tr><tr><td>Basic earnings per common share from continuing operations(b)</td><td>$ 0.56</td><td>$ 0.47</td><td>—</td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted earnings per share from continuing operations</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income from continuing operations attributable to shareholders and assumed conversions(c)</td><td>$ 508</td><td>$ 211</td><td></td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted weighted-average number of shares</td><td>908</td><td></td><td>446</td><td>—</td><td>N/A</td><td></td></tr><tr><td>Diluted earnings per common share from continuing operations(b)</td><td>$ 0.56</td><td>$ 0.47</td><td></td><td>N/A</td><td></td><td></td></tr></table>



<table><tr><td rowspan="3"></td><td colspan="5">February 11, 2011 through December 31, 2011</td></tr><tr><td colspan="5">Income from Continuing Operations Available to Shareholders</td></tr><tr><td>Class P</td><td>Class A</td><td>Participating Securities (a)</td><td>Total</td><td></td></tr><tr><td>Income from continuing operations for the year ended December 31, 2011</td><td></td><td></td><td></td><td>$</td><td>449</td></tr><tr><td>Plus: loss from continuing operations attributable to noncontrolling interests for the year ended December 31, 2011</td><td></td><td></td><td></td><td></td><td>112</td></tr><tr><td>Income from continuing operations attributable to KMI for the year ended December 31, 2011</td><td></td><td></td><td></td><td></td><td>561</td></tr><tr><td>Less: income from continuing operations attributable to KMI members prior to incorporation</td><td></td><td></td><td></td><td></td><td>(67)</td></tr><tr><td>Total net income from continuing operations attributable to shareholders</td><td></td><td></td><td></td><td></td><td>494</td></tr><tr><td>Dividends declared during the period</td><td>$</td><td>87</td><td>$</td><td>399</td><td>$ 38</td></tr><tr><td>Excess distributions over earnings</td><td></td><td>(5)</td><td></td><td>(25)</td><td>—</td></tr><tr><td>Income from continuing operations attributable to shareholders</td><td>$</td><td>82</td><td>$</td><td>374</td><td>$ 38</td></tr><tr><td>Basic earnings per share from continuing operations</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic weighted-average number of shares outstanding(d)</td><td></td><td>118</td><td></td><td>589</td><td>N/A</td></tr><tr><td>Basic earnings per common share from continuing operations(b)</td><td>$</td><td>0.70</td><td>$</td><td>0.64</td><td>N/A</td></tr><tr><td>Diluted earnings per share from continuing operations</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income from continuing operations attributable to shareholders and assumed conversions(c)</td><td>$</td><td>494</td><td>$</td><td>374</td><td>N/A</td></tr><tr><td>Diluted weighted-average number of shares(d)</td><td></td><td>708</td><td></td><td>589</td><td>N/A</td></tr><tr><td>Diluted earnings per common share from continuing operations(b)</td><td>$</td><td>0.70</td><td>$</td><td>0.64</td><td>N/A</td></tr></table>

The following tables set forth the computation of basic and diluted earnings per share for the year ended December 31, 2012 and for the period February 11, 2011 (the date of our initial public offering) through December 31, 2011 (in millions, except per share amounts):

<table><tr><td rowspan="3"></td><td colspan="5">Year ended December 31, 2012</td></tr><tr><td colspan="5">Net Income Available to Shareholders</td></tr><tr><td>Class P</td><td>Class A</td><td>Participating Securities (a)</td><td>Total</td><td></td></tr><tr><td>Net income attributable to KMI</td><td></td><td></td><td></td><td>$ 315</td><td></td></tr><tr><td>Dividends declared during period</td><td>$ 601</td><td>$ 542</td><td>$ 41</td><td>(1,184)</td><td></td></tr><tr><td>Excess distributions over earnings</td><td>(441)</td><td>(426)</td><td>(2)</td><td>(869)</td><td></td></tr><tr><td>Net income attributable to shareholders</td><td>$ 160</td><td>$ 116</td><td>$ 39</td><td>$ 315</td><td></td></tr><tr><td>Basic earnings per share</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic weighted-average number of shares outstanding</td><td>461</td><td>446</td><td>N/A</td><td></td><td></td></tr><tr><td>Basic earnings per common share(b)</td><td>$ 0.35</td><td>$ 0.26</td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted earnings per share</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income attributable to shareholders and assumed conversions(c)</td><td>$ 315</td><td>$ 116</td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted weighted-average number of shares</td><td>908</td><td>446</td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted earnings per common share(b)</td><td>$ 0.35</td><td>$ 0.26</td><td>N/A</td><td></td><td></td></tr></table>



February 11, 2011 through December 31, 2011

<table><tr><td rowspan="3"></td><td colspan="5">Net Income Available to Shareholders</td></tr><tr><td rowspan="2">Class P</td><td rowspan="2">Class A</td><td rowspan="2">Participating Securities (a)</td><td rowspan="2">Total</td><td></td></tr><tr><td></td></tr><tr><td>Net income attributable to KMI for the year ended December 31, 2011</td><td></td><td></td><td></td><td>$ 594</td><td></td></tr><tr><td>Less: net income attributable to KMI members prior to incorporation</td><td></td><td></td><td></td><td></td><td>(70)</td></tr><tr><td>Net income attributable to shareholders</td><td></td><td></td><td></td><td></td><td>524</td></tr><tr><td>Dividends declared during period</td><td>$ 87</td><td>$ 399</td><td>$ 38</td><td></td><td>(524)</td></tr><tr><td>Excess distributions over earnings</td><td>—</td><td>—</td><td>—</td><td>$ —</td><td>—</td></tr><tr><td>Total net income attributable to shareholders</td><td>$ 87</td><td>$ 399</td><td>$ 38</td><td>$ 524</td><td></td></tr><tr><td>Basic earnings per share</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic weighted-average number of shares outstanding(d)</td><td>118</td><td>589</td><td>N/A</td><td></td><td></td></tr><tr><td>Basic earnings per common share(b)</td><td>$ 0.74</td><td>$ 0.68</td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted earnings per share</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income attributable to shareholders and assumed conversions(c)</td><td>$ 524</td><td>$ 399</td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted weighted-average number of shares(d)</td><td>708</td><td>589</td><td>N/A</td><td></td><td></td></tr><tr><td>Diluted earnings per common share(b)</td><td>$ 0.74</td><td>$ 0.68</td><td>N/A</td><td></td><td></td></tr></table>

(a) Participating securities include Class B shares, Class C shares, and unvested restricted stock awards issued to non-senior management employees that contained rights to dividends. Our Class B and Class C shares were entitled to participate in our earnings, only to the extent of cash distributions made to them. As a result, no earnings in excess of dividends received were allocated to the Class B and Class C shares in our determination of basic and diluted earnings per share. There were 2,154,022 restricted stock awards outstanding as of December 31, 2012.

(b) The Class A shares earnings per share as compared to the Class P shares earnings per share has been reduced due to the sharing of economic benefits (including dividends) amongst the Class A, B, and C shares. Class A, B and C shares owned by Richard Kinder, the sponsor investors, the original shareholders, and other management are referred to as “investor retained stock,” and were convertible into a fixed number of Class P shares. In the aggregate, our investor retained stock was entitled to receive a dividend per share on a fully converted basis equal to the dividend per share on our common stock. The conversion of shares of investor retained stock into Class P shares did not increase our total fully-converted shares outstanding, impact the aggregate dividends we paid or the dividends we paid per share on our Class P common stock.

(c) For the diluted earnings per share calculation, total net income attributable to each class of common stock was divided by the adjusted weighted-average shares outstanding during the period, including all dilutive potential shares.

(d) The weighted-average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from February 11, 2011 to December 31, 2011.

## 3. Acquisitions and Divestitures

## KMI Acquisition of El Paso Corporation

Effective on May 25, 2012, we acquired all of the outstanding shares of EP for an aggregate consideration of approximately $23.0 billion. In total, EP shareholders received $11.6 billion in cash, 330 million KMI Class P shares with a fair value of $10.6 billion as of May 24, 2012 and 505 million KMI warrants with a fair value of $863 million as of May 24, 2012. The warrants have an exercise price of $40 per share and a 5-year term.

Together EP, and its subsidiary EPB, offered natural gas transmission services to a range of customers, including natural gas producers, marketers and end-users, as well as other natural gas transmission, distribution and electric generation companies. The pipelines group of EP and EPB were the nation's largest interstate natural gas pipeline franchise, transporting natural gas through interstate natural gas pipelines that connect the nation's principal supply regions to its major consuming regions (the Gulf Coast, California, the northeast, the southwest and the southeast). The pipelines business also included storage and liquefied natural gas terminating facilities.

We accounted for the EP Merger using the acquisition method of accounting. The acquisition method of accounting requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair



values as of the acquisition date. Our consolidated balance sheet presented as of December 31, 2012 reflects preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming results to determine the final purchase price allocation, which is expected to be completed in second quarter of 2013. On May 24, 2012, EP sold its subsidiary, EP Energy LLC, which consisted of EP's exploration and production business for $7.2 billion. Accordingly, the assets and liabilities of EP Energy LLC are not included in the purchase price allocation table below and the net sale proceeds were used to pay off the holders of EP Energy LLC's $961 million long-term debt, and the remaining $6.2 billion (included in "Current assets" in the table below) was used to pay for a portion of the $11.6 billion cash portion of the purchase price. EP's net operating loss carryforwards are expected to significantly offset the cash taxes associated with the sale of EP Energy LLC.

The following is the purchase price for EP (in millions, except per share and per warrant amounts):

<table><tr><td>Cash portion of purchase price</td><td>$ 11,551</td></tr><tr><td>Total KMI Class P shares issued</td><td>330</td></tr><tr><td>KMI Class P share price as of May 24, 2012</td><td>$ 32.11</td></tr><tr><td>Fair value of KMI Class P shares portion of purchase price</td><td>$ 10,601</td></tr><tr><td>Total KMI warrants issued</td><td>505</td></tr><tr><td>KMI warrant fair value per warrant as of May 24, 2012</td><td>$ 1.71</td></tr><tr><td>Fair value of KMI warrants portion of purchase price</td><td>$ 863</td></tr><tr><td>Total consideration paid (excluding debt assumed)</td><td>$ 23,015</td></tr><tr><td>Less: EP share based awards expensed in the post-combination period</td><td>(87)</td></tr><tr><td>Total Purchase Price</td><td>$ 22,928</td></tr></table>

The preliminary allocation of the purchase price is as follows (in millions):

<table><tr><td colspan="2">Preliminary Purchase Price Allocation:</td></tr><tr><td>Current assets</td><td>$ 7,175</td></tr><tr><td>Goodwill (a)</td><td>18,495</td></tr><tr><td>Investments (b)</td><td>4,211</td></tr><tr><td>Property, plant and equipment (c)</td><td>12,922</td></tr><tr><td>Deferred charges and other assets (d)</td><td>1,507</td></tr><tr><td>Current liabilities</td><td>(1,441)</td></tr><tr><td>Deferred income taxes (e)</td><td>(889)</td></tr><tr><td>Other deferred credits</td><td>(1,838)</td></tr><tr><td>Long-term debt (f)</td><td>(13,417)</td></tr><tr><td>Net assets acquired</td><td>26,725</td></tr><tr><td>Less: Fair value of noncontrolling interests (g)</td><td>(3,797)</td></tr><tr><td>Total Purchase Price</td><td>$ 22,928</td></tr></table>

(a) Goodwill of $18.5 billion, which represents the excess of the consideration transferred over the fair value of the assets acquired and liabilities assumed. Goodwill was recognized in the Natural Gas Pipelines reporting segment. Goodwill is not amortized and is not deductible for tax purposes, but is subject to an impairment test annually and when other impairment conditions arise.

(b) Investments were recorded at their estimated fair market value, which resulted in a purchase price allocation adjustment (increase) of $1.8 billion primarily associated with EP's equity investments in Citrus, El Paso Midstream Investment Company, LLC, Ruby Pipeline Holding Company, LLC and Gulf LNG Holdings Group, LLC.

(c) Property, plant and equipment includes a $2.1 billion reduction to record EP’s regulated businesses at their regulatory value in conformity with our accounting policy.

(d) Deferred charges and other assets include a purchase price allocation adjustment of $1.0 billion to record a regulatory offset to the fair value of debt purchase price allocation adjustment described in footnote (f) below.

(e) Deferred income taxes include a purchase price allocation reduction adjustment of $109 million (net) which primarily consisted of an adjustment to reduce deferred tax liabilities associated with the tax effects of purchase price allocation adjustments described herein, partially offset by adjustments to EP's equity investment in Citrus using our statutory federal and state tax rate of 36.7%.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

(f) EP’s debt assumed in the acquisition was recorded at its fair market value resulting in a $1.6 billion purchase price allocation adjustment (increase).

(g) Represents the fair value of noncontrolling interests associated with EP’s investment in EPB. The amount assigned in the purchase price allocation process was based on the 117 million EPB common units outstanding to the public as of May 24, 2012 and valued at EPB’s May 24, 2012 closing price of $32.37 per common unit.

## Pro Forma Statements of Income

The following unaudited pro forma condensed consolidated statements of income for the year ended December 31, 2012 and 2011 are presented as if the EP acquisition had been completed on January 1, 2011. The pro forma condensed consolidated statements of income are not necessarily indicative of what the actual results of operations or financial position of KMI would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of KMI for any future periods or as of any date. The pro forma condensed consolidated statements of income do not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements.

The following pro forma information is in millions, except per share amounts.

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Revenues</td><td>$ 11,158</td><td>$ 10,909</td><td></td></tr><tr><td>Income from continuing operations</td><td>$ 1,059</td><td>$ 553</td><td></td></tr><tr><td>Income from discontinued operations</td><td>$ 1,291</td><td>$ 493</td><td></td></tr><tr><td>Net income attributable to Kinder Morgan, Inc.</td><td>$ 2,139</td><td>$ 699</td><td></td></tr><tr><td>Class P shares</td><td></td><td></td><td></td></tr><tr><td>Basic earnings per common share</td><td>$ 2.06</td><td>$ 0.61</td><td></td></tr><tr><td>Diluted earnings per common share</td><td>$ 1.97</td><td>$ 0.54</td><td></td></tr><tr><td>Class A shares</td><td></td><td></td><td></td></tr><tr><td>Basic earnings per common share</td><td>$ 2.06</td><td>$ 0.61</td><td></td></tr><tr><td>Diluted earnings per common share</td><td>$ 1.97</td><td>$ 0.54</td><td></td></tr></table>

The pro forma condensed statements of income include adjustments to:

• include the results of EP for all periods presented;

- include the results of discontinued operations from (i) EP Energy and (ii) KMP’s FTC Natural Gas Pipelines disposal group (see below) including (i) a $2.0 billion gain (net of income taxes) on the sale of EP Energy for the year ended December 31, 2012 and (ii) $937 million of losses (net of income taxes) on selling costs and the remeasurement of KMP’s FTC Natural Gas Pipelines disposal group for the year ended December 31, 2012;

• include incremental interest expense related to financing the transactions;

• include incremental depreciation and amortization expense on assets and liabilities that were revalued as part of the purchase price allocation;

• reflect income taxes for the above adjustments at our effective income tax rate; and

• reflect the increase in KMI Class P shares outstanding.

## Expenses Related to the EP Acquisition

During the year 2012, we incurred $463 million, net of legal recoveries of pre-tax expenses associated with the EP acquisition, and EP Energy sale, including (i) $160 million in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million for legal fees and reserves, net of legal recoveries; (v) a $108 million write-off (due to debt repayments) or amortization of capitalized financing fees associated with the EP acquisition financing; and less (vi) a $29 million benefit associated with pension income.



## KMP’s FTC Natural Gas Pipelines Disposal Group – Discontinued Operations

As described above in Note 2, following our March 2012 agreement with the FTC, we began accounting for KMP’s FTC Natural Gas Pipelines disposal group as discontinued operations (prior to KMI’s sale announcement, we included the disposal group in the Natural Gas Pipelines business segment). Additionally, during 2012, we remeasured the disposal group’s net assets to reflect our assessment of fair value as a result of the FTC mandated sale requirement. Effective November 1, 2012, we then sold KMP’s FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, L.P., and KMP received proceeds of $1,791 million (before cash selling expenses). In November 2012, we also paid selling expenses of $78 million (consisting of certain required tax payments to joint venture partners). As a result of our remeasurement of net assets to fair value and the sale of net assets, we recognized a combined $937 million non-cash loss, and we reported this loss amount separately as “Loss on remeasurement to fair value and sales of KMP’s FTC Natural Gas Pipelines disposal group, net of tax” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2012.

Summarized financial information for KMP’s FTC Natural Gas Pipelines disposal group is as follows (in millions):

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Operating revenues</td><td>$ 227</td><td>$ 322</td><td>$ 339</td><td></td></tr><tr><td>Operating expenses</td><td>(131)</td><td>(183)</td><td>(168)</td><td></td></tr><tr><td>Depreciation and amortization</td><td>(7)</td><td>(24)</td><td>(23)</td><td></td></tr><tr><td>Other expense</td><td>(1)</td><td>—</td><td>—</td><td></td></tr><tr><td>Earnings from equity investments</td><td>70</td><td>87</td><td>88</td><td></td></tr><tr><td>Interest income and Other, net</td><td>2</td><td>2</td><td>2</td><td></td></tr><tr><td>Income tax expense</td><td>—</td><td>(2)</td><td>(1)</td><td></td></tr><tr><td>Income from operations of KMP’s FTC Natural Gas Pipelines disposal group</td><td>$ 160</td><td>$ 202</td><td>$ 237</td><td></td></tr></table>

(a) 2012 amounts represent financial information for the ten month period ended October 31, 2012. We sold KMP’s FTC Natural Gas Pipelines disposal group effective November 1, 2012.

## Drop-Down of EP Assets to KMP

Effective August 1, 2012, KMP acquired from us (i) 100% of the outstanding equity interests in the Tennessee Gas natural gas pipeline system (Tennessee Gas Pipeline L.L.C. or TGP), and a 50% ownership interest in the El Paso Natural Gas pipeline system (El Paso Natural Gas Company, L.L.C. or EPNG) for an aggregate consideration (including debt assumed) of $6.2 billion, referred to herein as the drop-down transaction. The drop-down transaction was completed by KMI to allow KMP to replace the cash flows associated with KMP’s FTC Natural Gas Pipelines disposal group discussed above. The drop-down transaction was accounted for as a transfer of net assets between entities under common control. Specifically, KMP recognized the acquired assets and assumed liabilities at our carrying value, including our purchase accounting adjustments, as of May 25, 2012.

The consideration that we received from KMP consisted of (i) $3.5 billion in cash; (ii) 4,667,575 of KMP’s common units (valued at $400 million based on KMP’s $81.52 closing market price of the common units on the New York Stock Exchange on the August 13, 2012 issuance date); and (iii) $2.3 billion in assumed debt (consisting of the combined carrying value of 100% of TGP’s debt borrowings and 50% of EPNG’s debt borrowings as of August 1, 2012, excluding any debt fair value adjustments).

The terms of the drop-down transaction were approved on our behalf by the independent members of our board of directors and on KMP’s behalf by its general partner’s and KMR’s audit committees and the boards of directors of both its general partner and KMR, in its capacity as the delegate of KMP’s general partner, following the receipt by our independent directors and by the audit committees of KMP’s general partner and KMR of separate fairness opinions from different independent financial advisors.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

We used the proceeds from the drop-down transaction to (i) pay down $2.3 billion on our 3-year term loan facility; (ii) pay off and terminate our 364-day bridge facility; and (iii) pay off an $839 million senior note which matured on September 1, 2012. Also, see Note 8.

## KMP Investment in El Paso Midstream Investment Company, LLC

Effective June 1, 2012, KMP acquired from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, referred to as KKR) a 50% ownership interest in El Paso Midstream Investment Company, LLC (EP Midstream), a joint venture that owns (i) the Altamont natural gas gathering, processing and treating assets located in the Unita Basin in Utah and (ii) the Camino Real natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas. KMP acquired its equity interest for an aggregate consideration of $289 million in common units (KMP issued 3,792,461 common units and determined each unit's value based on KMP's $76.23 closing market price of the common units on the New York Stock Exchange on the June 4, 2012 issuance date).

We, through our EP acquisition, own the remaining 50%, and as a result we consolidate EP Midstream in the accompanying unaudited consolidated balance sheet effective June 1, 2012. No gain or loss on the previously held equity investment was recognized as the fair value of the equity investment acquired through our EP acquisition was determined to equal the $289 million purchase price paid by KMP for their 50% interest. As such, the fair value of 100% of EP Midstream was determined to be $578 million. EP Midstream's operating results are included in the Natural Gas Pipelines business segment.

We measured the identifiable intangible assets acquired at fair value on the acquisition date, and as a result, we recognized $50 million in “Deferred charges and other assets,” representing the fair value of separate and identifiable relationships with existing customers. We estimate the remaining useful life of these existing customer relationships to be approximately ten years. After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $248 million of “Goodwill,” an intangible asset representing the future economic benefits expected to be derived from this acquisition that are not assigned to other identifiable, separately recognizable assets acquired. We believe the primary item that generated the goodwill is our ability to grow the business by leveraging our pre-existing natural gas operations, and we believe that this value contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities. This goodwill is not deductible for tax purposes.

## Income Tax Impact on the Drop-Down of EP Assets to KMP and KMP Investment in EP Midstream

As discussed above, we accounted for the acquisition of EP as a business combination and for the subsequent drop-down transaction as a transfer of net assets between entities under common control. For income tax purposes, the drop-down transaction was treated as a partial sale and partial contribution.

Our accounting policy is to apply the look-through method of recording deferred taxes on the outside book tax basis differences in our investments without regard to non tax deductible goodwill. As a result of the drop-down transaction, a deferred tax liability arose related to the portion of the outside basis difference associated with the underlying goodwill that was contributed to KMP by us. However, since the drop-down was a transaction between entities under common control, we recognized an offsetting deferred charge of $448 million, which will be amortized to income tax expense over the remaining useful lives of the transferred assets of approximately 25 years. Similar to the impact described above, KMP’s acquisition of a 50% ownership interest in the EP Midstream joint venture, also generated the recognition of a deferred charge and corresponding deferred tax liability and is included in the amount above.

The amortization of the deferred charge will result in incremental income tax expense of approximately $18 million per year. For the year ended December 31, 2012, total income tax expense related to the amortization of the deferred charge was approximately $7 million.

## Additional KMP Acquisitions

During 2012, 2011 and 2010, KMP completed the following significant acquisitions, and except for its acquisition of equity interests in Watco Companies, LLC (noted in the table and discussion below), KMP accounted for these acquisitions in accordance with the “Business Combinations” Topic of the Codification. Accordingly, KMP (i) recorded all the acquired assets and assumed liabilities at their estimated fair market values as of the acquisition date; (ii) included the results of operations from these acquisitions in our consolidated financial statements from the acquisition date; and (iii) recognized “Goodwill” where applicable. After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, goodwill is an intangible asset representing the future economic benefits.



expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated KMP’s goodwill are both the value of the synergies created between the acquired assets and its pre-existing assets, and its expected ability to grow the business KMP acquired by leveraging its pre-existing business experience. Furthermore, we expect that the entire amount of the recorded goodwill will be deductible for tax purposes.

Assignment of Purchase Price

<table><tr><td>Date</td><td>Acquisition</td><td colspan="2">Purchase Price</td><td>Current Assets</td><td colspan="2">(in millions) Property Plant &amp; Equipment</td><td colspan="2">Deferred Charges &amp; Other</td><td>Goodwill</td></tr><tr><td>1/10</td><td>USD Terminal Acquisition</td><td>$</td><td>201</td><td>$</td><td>5</td><td>$</td><td>43</td><td>$</td><td>95</td></tr><tr><td>3/10</td><td>Slay Industries Terminal Acquisition</td><td>$</td><td>102</td><td>$</td><td>—</td><td>$</td><td>68</td><td>$</td><td>33</td></tr><tr><td>5/10</td><td>KinderHawk Field Services LLC (1 of 2)</td><td>$</td><td>917</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>917</td></tr><tr><td>1/11</td><td>Watco Companies, LLC (1 of 2)</td><td>$</td><td>50</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>50</td></tr><tr><td>6/11</td><td>TGS Development, L.P. Terminal Acquisition</td><td>$</td><td>74</td><td>$</td><td>—</td><td>$</td><td>43</td><td>$</td><td>31</td></tr><tr><td>7/11</td><td>KinderHawk Field Services LLC and EagleHawk Field Services LLC (2 of 2)</td><td>$</td><td>912</td><td>$</td><td>36</td><td>$</td><td>642</td><td>$</td><td>140</td></tr><tr><td>11/11</td><td>SouthTex Treaters, Inc. Natural Gas Treating Assets</td><td>$</td><td>179</td><td>$</td><td>27</td><td>$</td><td>9</td><td>$</td><td>17</td></tr><tr><td>12/11</td><td>Watco Companies, LLC (2 of 2)</td><td>$</td><td>50</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>50</td></tr></table>

USD Terminal Acquisition

On January 15, 2010, KMP acquired three ethanol handling train terminals from US Development Group LLC for an aggregate consideration of $201 million, consisting of $114 million in cash, $82 million in common units, and $5 million in assumed liabilities. The three train terminals are located in Linden, New Jersey; Baltimore, Maryland and Euless, Texas. As part of the transaction, KMP announced the formation of a joint venture with US Development Group LLC to optimize and coordinate customer access to the three acquired terminals, other ethanol terminal assets it 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 KMP previously owned, and all of the acquired assets are included in the Terminals—KMP business segment.

## Slay Industries Terminal Acquisition

On March 5, 2010, KMP acquired certain bulk and liquids terminal assets from Slay Industries for an aggregate consideration of $102 million, consisting of $97 million in cash, assumed liabilities of $2 million, and an obligation to pay additional cash consideration of $3 million in years 2013 through 2019, contingent upon the purchased assets providing KMP an agreed-upon amount of earnings during the three years following the acquisition. Including accrued interest, KMP expects to pay total contingent consideration of $2 million, including $1 million of this contingent consideration in the first half of 2013.

The acquired assets included (i) a marine terminal located in Sauget, Illinois; (ii) a transload liquid operation located in Muscatine, Iowa; (iii) a liquid bulk terminal located in St. Louis, Missouri; and (iv) a warehousing distribution center located in St. Louis. All of the acquired terminals have long-term contracts with large creditworthy shippers. As part of the transaction, KMP 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 Cahoika terminal, located in Sauget and which has approximately 175 acres of land ready for development. All of the assets located in Sauget have access to the Mississippi River and are served by five rail carriers. The acquisition complemented and expanded KMP’s 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.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## KinderHawk Field Services LLC (1 of 2)

On May 21, 2010, KMP purchased a 50% ownership interest in Petrohawk Energy Corporation’s natural gas gathering and treating business in the Haynesville shale gas formation located in northwest Louisiana. KMP paid an aggregate consideration of $917 million in cash. During a short transition period, Petrohawk continued to operate the business, and effective October 1, 2010, a newly formed company named KinderHawk Field Services LLC, owned 50% by KMP and 50% by Petrohawk, assumed the joint venture operations. The acquisition complemented and expanded KMP’s existing natural gas gathering and treating businesses, and KMP assigned its entire purchase price to “Investments” (including $145 million of equity method goodwill, representing the excess of KMP’s investment cost over its proportionate share of the fair value of the joint venture’s identifiable net assets).

On July 1, 2011, KMP acquired from Petrohawk Energy Corporation both the remaining 50% equity ownership interest in KinderHawk Field Services LLC and a 25% equity ownership interest in Petrohawk's natural gas gathering and treating business located in the Eagle Ford shale formation in South Texas. For more information about this acquisition, see “—KinderHawk Field Services LLC and EagleHawk Field Services LLC” below.

## Watco Companies, LLC (1 of 2)

On January 3, 2011, KMP purchased 50,000 Class A preferred shares of Watco Companies, LLC for $50 million in cash in a private transaction. In connection with its purchase of these preferred shares, the most senior equity security of Watco, KMP entered into a limited liability company agreement with Watco that provides KMP certain priority and participating cash distribution and liquidation rights. Pursuant to the agreement, KMP receives priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter (13% annually), and it participates partially in additional profit distributions at a rate equal to 0.5%. The preferred shares have no conversion features and hold no voting powers, but do provide KMP certain approval rights, including the right to appoint one of the members to Watco's Board of Managers. On December 28, 2011, KMP made an additional $50 million investment in Watco, as described below in “—Watco Companies, LLC (2 of 2)”.

## TGS Development, L.P. Terminal Acquisition

On June 10, 2011, KMP acquired a newly constructed petroleum coke terminal located in Port Arthur, Texas from TGS Development, L.P. (TGSD) for an aggregate consideration of $74 million, consisting of $43 million in cash, $24 million in common units, and an obligation to pay additional consideration of $7 million. In March 2012, KMP settled the $7 million

liability by issuing additional common units to TGSD (they issued 87,162 common units and determined each unit’s value based on the $83.87 closing market price of the common units on the New York Stock Exchange on the March 14, 2012 issuance date).

All of the acquired assets are located in Port Arthur, Texas, and include long-term contracts to provide petroleum coke handling and cutting services to improve the refining of heavy crude oil at Total Petrochemicals USA Inc.'s Port Arthur refinery. The acquisition complemented KMP's existing Gulf Coast bulk terminal facilities and expanded its pre-existing petroleum coke handling operations. All of the acquired assets are included as part of the Terminals —KMP business segment.

## KinderHawk Field Services LLC and EagleHawk Field Services LLC

Effective July 1, 2011, KMP acquired from Petrohawk Energy Corporation both the remaining 50% equity ownership interest in KinderHawk Field Services LLC that it did not already own and a 25% equity ownership interest in Petrohawk's natural gas gathering and treating business located in the Eagle Ford shale formation in South Texas for an aggregate consideration of $912 million, consisting of $835 million in cash and assumed debt of $77 million (representing 50% of KinderHawk's borrowings under its bank credit facility as of July 1, 2011). KMP then repaid the outstanding $154 million of borrowings and following this repayment, KinderHawk had no outstanding debt. The revolving bank credit facility was terminated at the time of such repayment.

Following KMP’s acquisition of the remaining ownership interest on July 1, 2011, KMP changed its method of accounting from the equity method to full consolidation, and due to the fact that KMP acquired a controlling financial interest in KinderHawk, KMP remeasured its previous 50% equity investment in KinderHawk to its fair value. KMP recognized a $167 million non-cash loss as a result of this remeasurement. The loss amount represents the excess of the carrying value of the investment ($910 million as of July 1, 2011) over its fair value ($743 million), and we reported this loss separately within



## Item 15. Exhibits, Financial Statement Schedules. (continued)

the “Other Income (Expense)” section in our accompanying consolidated statements of income for the year ended December 31, 2011.

KinderHawk Field Services LLC gathers and treats natural gas in the Haynesville shale gas formation located in northwest Louisiana. Its assets currently consist of approximately 479 miles of natural gas gathering pipeline currently in service and natural gas treating plants having a current capacity of approximately 2,600 gallons per minute. The system is designed to have approximately 2 billion cubic feet per day of pipeline capacity. Currently, it gathers approximately 1 billion cubic feet of natural gas per day. The Eagle Ford natural gas gathering joint venture is named EagleHawk Field Services LLC, and the 25% investment is accounted for under the equity method of accounting. A subsidiary of BHP Billiton (described below) operates EagleHawk Field Services LLC and owns the remaining 75% ownership interest. The joint venture owns two midstream gathering systems in and around Petrohawk's Hawkville and Black Hawk areas of Eagle Ford and combined, the joint venture's assets as of December 31, 2012 consist of more than 388 miles of gas gathering pipelines and approximately 266 miles of condensate gathering lines. It also has a life of lease dedication of Petrohawk's Eagle Ford reserves that provides Petrohawk and other Eagle Ford producers with gas and condensate gathering, treating and condensate stabilization services.

All of the acquired assets are included in the Natural Gas Pipelines business segment.

Additionally, on August 25, 2011, mining and oil company BHP Billiton completed its previously announced acquisition of Petrohawk Energy Corporation through a short-form merger under Delaware law. The merger was closed with Petrohawk being the surviving corporation as a wholly owned subsidiary of BHP Billiton. The acquisition did not affect the terms of KMP’s contracts with Petrohawk.

## SouthTex Tractors, Inc. Natural Gas Treating Assets

On November 30, 2011, KMP acquired a manufacturing complex and certain natural gas treating assets from SouthTex Tractors, Inc. for an aggregate consideration of $179 million, consisting of $152 million in cash and assumed liabilities of $27 million. SouthTex Tractors, Inc. is a leading manufacturer, designer and fabricator of natural gas treating plants that are used to remove impurities (carbon dioxide and hydrogen sulfide) from natural gas before it is delivered into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications. The acquisition complemented and expanded KMP’s existing natural gas treating business, and all of the acquired operations are included in the Natural Gas Pipelines business segment.

## Watco Companies, LLC (2 of 2)

On December 28, 2011, KMP purchased an additional 50,000 Class A preferred shares of Watco Companies, LLC for $50 million in cash in a private transaction. The priority and participating cash distribution and liquidation rights associated with these shares are similar to the rights associated with the 50,000 Class A preferred shares KMP acquired on January 3, 2011. KMP receives priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter (13% annually), and participates partially in additional profit distributions at a rate equal to 0.5%.

Watco Companies, LLC is the largest privately held short line railroad company in the U.S., operating 22 short line railroads on approximately 3,500 miles of leased and owned track. KMP’s investment provided capital to Watco for further expansion of specific projects and complemented KMP’s existing terminal network. It also provides KMP’s customers more transportation services for many of the commodities that it currently handles, and offers it the opportunity to share in additional growth opportunities through new projects. As of December 31, 2012, KMP’s net equity investment in Watco totaled $103 million and is included within “Investments” on our accompanying consolidated balance sheet. KMP accounts for its investment under the equity method of accounting, and it is included in the Terminals—KMP business segment.

## Pro Forma Information

Other than the EP acquisition discussed above, the pro forma consolidated income statement information that gives effect to all of the other acquisitions we have made and accounted for as business combinations since January 1, 2011 as if they had occurred as of January 1, 2011 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

## Acquisitions Subsequent to December 31, 2012

On January 29, 2013, KMP and Copano Energy, L.L.C. (Copano) announced a definitive agreement whereby KMP will



## Item 15. Exhibits, Financial Statement Schedules. (continued)

acquire all of Copano’s outstanding units, including convertible preferred units, for a total purchase price of approximately $5 billion, including the assumption of debt. The transaction, which has been approved by the board of directors of both KMP’s general partner and Copano, will be a 100% unit for unit transaction with an exchange ratio of 0.4563 of our common unit for each Copano unit. The transaction is subject to customary closing conditions, regulatory approvals, and a vote of the Copano unitholders; however, TPG Advisors VI, Inc., Copano’s largest unitholder, has agreed to support the transaction and we expect the transaction to close in the third quarter of 2013.

Copano is a midstream natural gas company that provides comprehensive services to natural gas producers, including natural gas gathering, processing, treating and natural gas liquids fractionation. Copano owns an interest in or operates approximately 6,900 miles of pipelines with 2.7 billion cubic feet per day of natural gas transportation capacity, and also owns nine natural gas processing plants with more than 1.0 billion cubic feet per day of natural gas processing capacity and 315 million cubic feet per day of natural gas treating capacity. Its operations are located primarily in Texas, Oklahoma and Wyoming. All of the acquired assets will be included in the Natural Gas Pipelines business segment.

## Additional KMP Divestitures

## Express Pipeline System

On December 11, 2012, KMP announced that it had entered into a definitive agreement to sell both its one-third equity ownership interest in the Express pipeline system and its subordinated debenture investment in Express to Spectra Energy Corp. for approximately $380 million (before tax). KMP acquired its equity ownership interest in the Express pipeline system from us effective August 28, 2008. The Express pipeline system is a 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 system connects Canadian and U.S. producers to refineries located in the U.S. Rocky Mountain and Midwest regions. The transaction is subject to customary consents and regulatory approvals and is expected to close in the second quarter of 2013. On this date, Spectra also announced that it will acquire the remaining ownership interests in Express, and following its acquisitions, will fully own the Express pipeline system.

We account for our equity investment in Express under the equity method of accounting and include its financial results within the Kinder Morgan Canada-KMP business segment. As of December 31, 2012, our (i) equity investment in the Express pipeline system totaled $65 million and our note receivable due from Express totaled $114 million. We included the combined $179 million amount within “Assets held for Sale” on our accompanying consolidated balance sheet.

## Battleground Oil Specialty Terminal Company LLC

Effective December 1, 2012, TransMontaigne exercised its previously announced option to acquire up to 50% of KMP's Class A member interest in Battleground Oil Specialty Terminal Company LLC (BOSTCO), KMP's previously announced oil terminal joint venture located on the Houston Ship Channel. On this date, TransMontaigne acquired a 42.5% Class A member interest in BOSTCO from KMP for an aggregate consideration of $79 million, and following this acquisition, KMP now owns a 55% Class A member interest in BOSTCO (KMP sold a 2.5% Class A member interest in BOSTCO to a third party on January 1, 2012 for an aggregate consideration of $1 million). Because KMP retained a controlling financial interest in BOSTCO, we accounted for this change in KMP's ownership interest as an equity transaction. We continue to account for KMP's investment under the full consolidation method and as of December 31, 2012, construction continues on the approximately $430 million oil terminal joint venture.

## Divestitures subsequent to December 31, 2012

As of December 31, 2012, we owned a 33 1/3% interest in BBPH Holdings Ltda which we acquired as a part of the EP acquisition. The remaining interest is owned 33 1/3% by British Gas International Holdings B.V. and 33 1/3% by Total. BBPH Holdings Ltda owns a 29% interest in Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. which is referred to as the Bolivia to Brazil Pipeline. On January 18, 2013, we completed the sale of our equity interests in the Bolivia to Brazil Pipeline for $88 million. As of December 31, 2012, our $88 million equity interests in the Bolivia to Brazil Pipeline was included within "Assets held for sale" on our accompanying consolidated balance sheet.

## 4. Income Taxes

The components of “Income from Continuing Operations Before Income Taxes are as follows (in millions):



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td>United States</td><td>$ 1,246</td><td>$ 731</td><td>$ 157</td><td></td></tr><tr><td>Foreign</td><td>97</td><td>79</td><td>73</td><td></td></tr><tr><td>Total Income from Continuing Operations Before Income Taxes</td><td>$ 1,343</td><td>$ 810</td><td>$ 230</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="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td>Current tax provision</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$ 48</td><td>$ 241</td><td>$ 151</td><td></td></tr><tr><td>State</td><td>34</td><td>33</td><td>20</td><td></td></tr><tr><td>Foreign</td><td>10</td><td>3</td><td>3</td><td></td></tr><tr><td></td><td>92</td><td>277</td><td>174</td><td></td></tr><tr><td>Deferred tax provision</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>49</td><td>64</td><td>(38)</td><td></td></tr><tr><td>State</td><td>4</td><td>(1)</td><td>19</td><td></td></tr><tr><td>Foreign</td><td>(6)</td><td>21</td><td>11</td><td></td></tr><tr><td></td><td>47</td><td>84</td><td>(8)</td><td></td></tr><tr><td>Total tax provision</td><td>$ 139</td><td>$ 361</td><td>$ 166</td><td></td></tr></table>

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

<table><tr><td rowspan="2"></td><td colspan="6">Year Ended December 31,</td></tr><tr><td colspan="2">2012</td><td colspan="2">2011</td><td colspan="2">2010</td></tr><tr><td>Federal income tax</td><td>$ 470</td><td>35.0%</td><td>$ 284</td><td>35.0%</td><td>$ 80</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></tr><tr><td>Deferred tax liability on KMI Investment in KMR</td><td>(5)</td><td>(0.4)%</td><td>(1)</td><td>(0.1)%</td><td>80</td><td>34.6%</td></tr><tr><td>State deferred tax rate change</td><td>20</td><td>1.5%</td><td>(1)</td><td>(0.1)%</td><td>17</td><td>7.6%</td></tr><tr><td>Taxes on foreign earnings</td><td>(6)</td><td>(0.5)%</td><td>24</td><td>3.0%</td><td>14</td><td>6.1%</td></tr><tr><td>Net effects of consolidating KMP&#x27;s U.S. income tax provision</td><td>(288)</td><td>(21.5)%</td><td>34</td><td>4.2%</td><td>(23)</td><td>(10.0)%</td></tr><tr><td>State income tax, net of federal benefit</td><td>21</td><td>1.6%</td><td>26</td><td>3.2%</td><td>16</td><td>6.8%</td></tr><tr><td>Adjustment to KMI&#x27;s investment in NGPL</td><td>—</td><td>—%</td><td>—</td><td>—%</td><td>(8)</td><td>(3.5)%</td></tr><tr><td>Adjustment to employee benefit plan</td><td>—</td><td>—%</td><td>—</td><td>—%</td><td>(5)</td><td>(2.1)%</td></tr><tr><td>Dividend received deduction</td><td>(32)</td><td>(2.4)%</td><td>(10)</td><td>(1.2)%</td><td>(11)</td><td>(4.8)%</td></tr><tr><td>Adjustments to uncertain tax positions</td><td>(72)</td><td>(5.3)%</td><td>(9)</td><td>(1.1)%</td><td>4</td><td>1.8%</td></tr><tr><td>Acquisition costs</td><td>18</td><td>1.3%</td><td>—</td><td>—%</td><td>—</td><td>—%</td></tr><tr><td>Other</td><td>13</td><td>1.0%</td><td>14</td><td>1.7%</td><td>2</td><td>0.9%</td></tr><tr><td>Total</td><td>$ 139</td><td>10.3%</td><td>$ 361</td><td>44.6%</td><td>$ 166</td><td>72.4%</td></tr></table>



## Item 15. Exhibits, Financial Statement Schedules. (continued)

As part of our dividend policy, after our initial public offering (See Note 10 “Stockholders’ Equity—Kinder Morgan, Inc. – Equity Interests—Initial Public Offering) we intend periodically to sell the KMR shares we receive as distributions from KMR. Since we no longer expect to recover our investment in KMR in a tax-free manner, a deferred tax liability was recorded resulting in a $80 million increase to income tax expense in 2010.

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

<table><tr><td rowspan="2"></td><td colspan="3">December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Deferred tax assets</td><td></td><td></td><td></td></tr><tr><td>Employee benefits</td><td>$     357</td><td>$     43</td><td></td></tr><tr><td>Book accruals</td><td>86</td><td>16</td><td></td></tr><tr><td>Net operating loss carryforwards/tax credits (net of valuation allowance)</td><td>1,058</td><td>32</td><td></td></tr><tr><td>Derivative instruments</td><td>89</td><td>—</td><td></td></tr><tr><td>Interest rate and currency swaps</td><td>36</td><td>19</td><td></td></tr><tr><td>Debt fair value adjustment</td><td>155</td><td>—</td><td></td></tr><tr><td>Other</td><td>89</td><td>11</td><td></td></tr><tr><td>Total deferred tax assets</td><td>1,870</td><td>121</td><td></td></tr><tr><td>Deferred tax liabilities</td><td></td><td></td><td></td></tr><tr><td>Property, plant and equipment</td><td>283</td><td>279</td><td></td></tr><tr><td>Investments</td><td>5,040</td><td>1,997</td><td></td></tr><tr><td>Book accruals</td><td>21</td><td>17</td><td></td></tr><tr><td>Derivative instruments</td><td>—</td><td>13</td><td></td></tr><tr><td>Debt fair value adjustment</td><td>—</td><td>14</td><td></td></tr><tr><td>Other</td><td>20</td><td>6</td><td></td></tr><tr><td>Total deferred tax liabilities</td><td>5,364</td><td>2,326</td><td></td></tr><tr><td>Net deferred tax liabilities</td><td>$     3,494</td><td>$     2,205</td><td></td></tr><tr><td>Current deferred tax (asset) liability</td><td>$      (539)</td><td>$     6</td><td></td></tr><tr><td>Non-current deferred tax liability</td><td>4,033</td><td>2,199</td><td></td></tr><tr><td>Net deferred tax liabilities</td><td>$     3,494</td><td>$     2,205</td><td></td></tr></table>

In 2010, we sold certain assets that generated a capital loss of approximately $116 million. The capital loss was carried back and a current deferred tax asset of approximately $41 million was realized as a result of the carryback. A refund of $41 million was received in 2011.

Deferred Tax Assets and Valuation Allowances: As a result of our acquisition of EP, our deferred tax assets related to net operating loss carryovers has increased to a balance at December 31, 2012 of $864 million. Our deferred tax assets related to alternative minimum, general business, and foreign tax credits has increased by approximately $292 million to a balance at December 31, 2012 of $298 million. Valuation allowances related to the deferred tax assets have increased by $104 million to a balance of $104 million at December 31, 2012.

Expiration Periods for Deferred Tax Assets: As of December 31, 2012, we have U.S. federal net operating loss carryforwards of $1.9 billion, which will expire from 2017 - 2031; state losses of $3.1 billion which will expire from 2012 - 2032; and foreign losses of $211 million, of which approximately $159 million carries over indefinitely and $52 million expires from 2028 - 2032. We also have $291 million of federal alternative minimum tax credits which do not expire; and approximately $7 million of general business and foreign tax credits, the majority of which will expire from 2015 - 2021. Use of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations.

Unrecognized Tax Benefits: 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



## Item 15. Exhibits, Financial Statement Schedules. (continued)

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 is as follows (in millions):

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Balance at beginning of period</td><td>$     57</td><td>$     53</td><td>$     52</td><td></td></tr><tr><td>Uncertain tax positions of EP</td><td>289</td><td>—</td><td>—</td><td></td></tr><tr><td>Subtotal</td><td>346</td><td>53</td><td>52</td><td></td></tr><tr><td>Additions based on current year tax positions</td><td>11</td><td>11</td><td>12</td><td></td></tr><tr><td>Additions based on prior year tax positions</td><td>1</td><td>2</td><td>—</td><td></td></tr><tr><td>Uncertain tax positions related to entities sold</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Settlements with taxing authority</td><td>(55)</td><td>—</td><td>(2)</td><td></td></tr><tr><td>Changes due to lapse in statute of limitations</td><td>(34)</td><td>(9)</td><td>1</td><td></td></tr><tr><td>Reduction for tax positions related to prior year</td><td>—</td><td>—</td><td>(10)</td><td></td></tr><tr><td>Balance at end of period</td><td>$     269</td><td>$     57</td><td>$     53</td><td></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, 2012, we had $28 million of accrued interest and $2 million in accrued penalties. As of December 31, 2011, we had $5 million of accrued interest and $1 million in accrued penalties. As of December 31, 2010, we had $4 million of accrued interest and $1 million of accrued penalties. All of the $269 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $90 million during the next year to approximately $179 million.

We are subject to taxation, and have tax years open to examination for the periods 2008-2012 in the U.S., 1999-2012 in various states and 2007-2012 in various foreign jurisdictions.

## 5. Property, Plant and Equipment

## Classes and Depreciation

As of December 31, 2012 and 2011, our property, plant and equipment consisted of the following (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011</td></tr><tr><td>Natural gas, liquids, crude oil and carbon dioxide pipelines</td><td>$     14,513</td><td>$     7,371</td></tr><tr><td>Natural gas, liquids, carbon dioxide, and terminals station equipment</td><td>15,309</td><td>10,699</td></tr><tr><td>Natural gas, liquids (including linefill), and transmix processing</td><td>336</td><td>226</td></tr><tr><td>Other</td><td>3,477</td><td>2,053</td></tr><tr><td>Accumulated depreciation, depletion and amortization</td><td>(5,278)</td><td>(3,912)</td></tr><tr><td></td><td>28,357</td><td>16,437</td></tr><tr><td>Land and land right-of-way</td><td>1,143</td><td>691</td></tr><tr><td>Construction work in process</td><td>1,496</td><td>798</td></tr><tr><td>Property, plant and equipment, net</td><td>$     30,996</td><td>$     17,926</td></tr></table>

As of December 31, 2012 and 2011, we included regulated property, plant and equipment amounts of $13,563 million and $2,114 million, respectively, within “Property, plant and equipment, net” on our accompanying consolidated balance sheets. These regulated amounts constituted 44% and 12%, respectively, of our total property, plant and equipment amounts at each reporting date. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $1,324 million, $1,022 million, and $1,026 million, for the year ended December 31, 2012, 2011, and 2010, respectively.



## Asset Retirement Obligations

As of December 31, 2012 and 2011, we recognized asset retirement obligations in the aggregate amount of $175 million and $125 million, respectively. The majority of our asset retirement obligations are associated with the CO 2—KMP business segment, where KMP 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 included $11 million of asset retirement obligations as of both December 31, 2012 and 2011 within “Accrued other current liabilities” in our accompanying consolidated balance sheets. The remaining amounts are included within “Other long-term liabilities and deferred credits” at each reporting date.

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

## 6. Investments

Our investments primarily consist of equity investments where we hold significant influence over investee actions and which we account for under the equity method of accounting. As of December 31, 2012 and 2011 our investments consisted of the following (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011</td></tr><tr><td>Citrus Corporation</td><td>$ 1,966</td><td>$ —</td></tr><tr><td>Ruby Pipeline Holding Company LLC</td><td>1,185</td><td>—</td></tr><tr><td>Midcontinent Express Pipeline LLC</td><td>633</td><td>667</td></tr><tr><td>Gulf LNG Holdings Group LLC</td><td>596</td><td>—</td></tr><tr><td>Plantation Pipe Line Company</td><td>313</td><td>320</td></tr><tr><td>Red Cedar Gathering Company</td><td>172</td><td>168</td></tr><tr><td>Fayetteville Express Pipeline LLC</td><td>159</td><td>173</td></tr><tr><td>EagleHawk Field Services LLC</td><td>208</td><td>141</td></tr><tr><td>Eagle Ford Gathering LLC</td><td>151</td><td>117</td></tr><tr><td>Watco Companies, LLC</td><td>103</td><td>102</td></tr><tr><td>NGPL Holdco LLC</td><td>68</td><td>263</td></tr><tr><td>Express pipeline system</td><td>—</td><td>65</td></tr><tr><td>Cortez Pipeline Company</td><td>11</td><td>10</td></tr><tr><td>Rockies Express Pipeline LLC</td><td>—</td><td>1,595</td></tr><tr><td>All others</td><td>231</td><td>115</td></tr><tr><td>Total equity investments</td><td>5,796</td><td>3,736</td></tr><tr><td>Bond investments</td><td>8</td><td>8</td></tr><tr><td>Total investments</td><td>$ 5,804</td><td>$ 3,744</td></tr></table>

The overall change in the carrying amount of our equity investments, including those of KMP, since December 31, 2011, primarily consisted of (i) increases due to our EP acquisition of 50% interest in Citrus Corporation, Ruby Pipeline Holding Company LLC, and Gulf LNG Holdings Group LLC, respectively. The remaining interest in Citrus Corporation is owned by Energy Transfer Partners L.P. (50%); the remaining interest in Ruby Pipeline Holding Company LLC is owned by Global Infrastructure Partners as convertible preferred interest (50%); and the remaining interests in Gulf LNG Holdings Group LLC are owned by GE Financial Services (46%), and by various other investors (4%); (ii) a decrease from KMP's November 1, 2012 divestiture of a 50% interest in Rockies Express Pipeline LLC; (iii) a decrease from KMP's December 11, 2012 announcement to sell its 33 1/3% interest in the Express pipeline system (as of December 31, 2012, KMP's equity investment in Express totaled $65 million and we have included this amount within "Assets held for Sale" on our accompanying consolidated balance sheet); and (iv) a decrease of $200 million pre-tax, non-cash equity investment impairment charge related



to our 20% interest in NGPL Holdco LLC in 2012 (see below for further discussion). For further information pertaining to these acquisitions and these divestitures, see Note 3 “Acquisition and Divestitures”.

As shown in the table above, our significant equity investments, including those of KMP (excluding the first five investments described above and in Note 3), as of December 31, 2012 consisted of the following:

- Midcontinent Express Pipeline LLC—KMP operates and owns a 50% interest in Midcontinent Express Pipeline LLC. It is the sole owner of the Midcontinent Express natural gas pipeline system. The remaining interest in Midcontinent Express Pipeline LLC is owned by subsidiaries of Regency Energy Partners L.P. (50%);

- Plantation Pipe Line Company—KMP operates and owns a 51.17% interest in Plantation Pipe Line Company, the sole owner of the Plantation refined petroleum products pipeline system. A subsidiary of Exxon Mobil Corporation 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, KMP does not control Plantation Pipe Line Company, and it accounts for its investment under the equity method;

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

- Fayetteville Express Pipeline LLC—KMP owns a 50% interest in Fayetteville Express Pipeline LLC, the sole owner of the Fayetteville Express natural gas pipeline system. Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of Fayetteville Express Pipeline LLC;

- EagleHawk Field Services LLC—KMP owns a 25% interest in EagleHawk Field Services LLC. A subsidiary of BHP Billiton operates Eagle Hawk Field Services LLC and owns the remaining 75% ownership interest;

- Eagle Ford Gathering LLC—KMP owns a 50% member interest in Eagle Ford Gathering LLC. Copano Energy, L.L.C. owns the remaining 50% interest and serves as operator and managing member of Eagle Ford Gathering LLC. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for discussion regarding KMP’s proposed merger with Copano Energy, L.L.C.;

- Watoo Companies, LLC—KMP holds a preferred equity investment in Watoo Companies, LLC, the largest privately held short line railroad company in the United States. KMP owns 100,000 Class A preferred shares and pursuant to the terms of its investment, it receives priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and participates partially in additional profit distributions at a rate equal to 0.5%. The preferred shares have no conversion features and hold no voting powers, but do provide KMP certain approval rights, including the right to appoint one of the members to Watoo’s Board of Managers;

- NGPL Holdco LLC—KMI operates and owns a 20% interest in NGPL Holdco LLC, the owner of Natural Gas Pipeline Company of America LLC and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system. In 2010, we remeasured the fair value of our NGPL investment upon the April 2010 settlement with the FERC associated with the FERC’s Section 5 of the Natural Gas Act investigation into the justness and reasonableness of the transportation and storage rates as well as the fuel and natural gas lost percentages of NGPL.

Beginning in February 2013 (subsequent to KMI’s fourth quarter earnings release), we evaluated multiple financial projections for NGPL and concluded that continued natural gas market conditions, characterized by excess gas supply, low commodity prices, reduced basis spreads and low volatility that had negatively impacted NGPL’s operating results and its cash flows in 2012, with a more pronounced impact in the fourth quarter, were not expected to significantly improve in the foreseeable future. Due to these developments, we again reconsidered the fair value of our NGPL investment as of December 31, 2012.

A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. The fair value represents the price that would be received to sell the investment in an orderly transaction between market participants. For both 2012 and 2010, we determined the fair value of the investment in NGPL Holdco LLC by taking the total fair value of NGPL Holdco LLC (calculated as discussed below), deducting the fair value of NLPL’s debt and multiplying by our 20% interest. We calculated the total fair value of NGPL Holdco LLC from the present value of the expected future after-tax cash flows of the reporting unit, inclusive of a terminal value, consistent with our valuation of similar assets. The result of our analysis showed that the fair value of our investment in NGPL Holdco LLC was less than its carrying value in both years. Therefore, in 2012 and 2010, we recognized $200 million and $430 million, respectively, of pre-tax, non-cash impairment charges.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Both the 2010 and 2012 non-cash impairment charges are included in the caption “Earnings (loss) from equity investments” in our accompanying consolidated statements of income.

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

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

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Citrus Corporation</td><td>$ 53</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Midcontinent Express Pipeline LLC</td><td>42</td><td>43</td><td>30</td><td></td></tr><tr><td>Red Cedar Gathering Company</td><td>32</td><td>32</td><td>29</td><td></td></tr><tr><td>Plantation Pipe Line Company</td><td>32</td><td>28</td><td>20</td><td></td></tr><tr><td>Cortez Pipeline Company</td><td>25</td><td>24</td><td>23</td><td></td></tr><tr><td>Favetteville Express Pipeline LLC</td><td>5</td><td>24</td><td>—</td><td></td></tr><tr><td>Gulf LNG Holdings Group LLC</td><td>22</td><td>—</td><td>—</td><td></td></tr><tr><td>KinderHawk Field Services LLC</td><td>—</td><td>22</td><td>19</td><td></td></tr><tr><td>Eagle Ford Gathering LLC</td><td>34</td><td>11</td><td>—</td><td></td></tr><tr><td>Watco Companies, LLC</td><td>13</td><td>6</td><td>—</td><td></td></tr><tr><td>EagleHawk Field Services LLC</td><td>11</td><td>3</td><td>—</td><td></td></tr><tr><td>Express pipeline system</td><td>5</td><td>(2)</td><td>(3)</td><td></td></tr><tr><td>Ruby Pipeline Holding Company LLC</td><td>(5)</td><td>—</td><td>—</td><td></td></tr><tr><td>NGPL Holdco LLC (a)</td><td>(198)</td><td>19</td><td>(399)</td><td></td></tr><tr><td>All others</td><td>32</td><td>16</td><td>7</td><td></td></tr><tr><td>Total</td><td>$ 153</td><td>$ 226</td><td>$ (274)</td><td></td></tr><tr><td>Amortization of excess costs</td><td>$ (23)</td><td>$ (7)</td><td>$ (6)</td><td></td></tr></table>

(a) 2012 and 2010 amounts include non-cash investment impairment charges, which we recorded in the amount of $200 million and $430 million (pre-tax), respectively, as discussed above.

Summarized combined 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 rowspan="2">Income Statement</td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Revenues</td><td>$ 3,931</td><td>$ 3,145</td><td>$ 2,641</td></tr><tr><td>Costs and expenses</td><td>3,106</td><td>3,287</td><td>2,860</td></tr><tr><td>Earnings before extraordinary items and cumulative effect of a change in accounting principle</td><td>825</td><td>(142)</td><td>(219)</td></tr><tr><td>Net income</td><td>$ 825</td><td>$ (142)</td><td>$ (219)</td></tr></table>



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2">Balance Sheet</td><td colspan="3">December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Current assets</td><td>$ 917</td><td>$ 717</td><td></td></tr><tr><td>Non-current assets</td><td>$ 21,308</td><td>$ 16,629</td><td></td></tr><tr><td>Current liabilities</td><td>$ 1,538</td><td>$ 1,906</td><td></td></tr><tr><td>Non-current liabilities</td><td>$ 11,401</td><td>$ 7,471</td><td></td></tr><tr><td>Partners’/owners’ equity</td><td>$ 9,286</td><td>$ 7,969</td><td></td></tr></table>

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

## 7. Goodwill and Other Intangibles

## Goodwill and Excess Investment Cost

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

We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Natural Gas Pipelines; (ii) Products Pipelines-KMP (excluding associated terminals); (iii) Products Pipelines Terminals-KMP (evaluated separately from Products Pipelines-KMP for goodwill purposes, but combined with Products Pipelines-KMP for presentation in the table below); (iv) CO \( _{2} \) -KMP; (v) Terminals-KMP; and (vi) Kinder Morgan Canada-KMP. There were no impairment charges resulting from our May 31, 2012 impairment testing, and no event indicating an impairment has occurred subsequent to that date.

The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using market multiples between six and ten times cash flows) discounted at a rate of 8.0%. The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date.

Changes in the gross amounts of our goodwill and accumulated impairment losses for the years ended December 31, 2012 and 2011 are summarized as follows (in millions):

<table><tr><td></td><td>Natural Gas Pipelines</td><td>Products Pipelines-KMP</td><td>CO2-KMP</td><td>Terminals-KMP</td><td>Kinder Morgan Canada-KMP</td><td>Total</td></tr><tr><td>Historical Goodwill - includes accumulated activities except impairments</td><td>$ 3,488</td><td>$ 2,117</td><td>$ 1,522</td><td>$ 1,489</td><td>$ 626</td><td>$ 9,242</td></tr><tr><td>Accumulated impairment losses</td><td>(2,090)</td><td>(1,267)</td><td>—</td><td>(677)</td><td>(377)</td><td>(4,411)</td></tr><tr><td>Balance as of December 31, 2010</td><td>1,398</td><td>850</td><td>1,522</td><td>812</td><td>249</td><td>4,831</td></tr><tr><td>Other adjustments(a)</td><td>15</td><td>12</td><td>6</td><td>7</td><td>—</td><td>40</td></tr><tr><td>Acquisitions(b)</td><td>220</td><td>—</td><td>—</td><td>—</td><td>—</td><td>220</td></tr><tr><td>Disposals(c)</td><td>—</td><td>—</td><td>—</td><td>(12)</td><td>—</td><td>(12)</td></tr><tr><td>Currency translation adjustments</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(5)</td><td>(5)</td></tr><tr><td>Balance as of December 31, 2011</td><td>1,633</td><td>862</td><td>1,528</td><td>807</td><td>244</td><td>5,074</td></tr><tr><td>Acquisitions(d)</td><td>18,743</td><td>—</td><td>—</td><td>—</td><td>—</td><td>18,743</td></tr><tr><td>Disposals(e)</td><td>(250)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(250)</td></tr><tr><td>Currency translation adjustments</td><td>—</td><td>—</td><td>—</td><td>—</td><td>5</td><td>5</td></tr><tr><td>Balance as of December 31, 2012</td><td>$ 20,126</td><td>$ 862</td><td>$ 1,528</td><td>$ 807</td><td>$ 249</td><td>$ 23,572</td></tr></table>



## Item 15. Exhibits, Financial Statement Schedules. (continued)

(a) Tax adjustments related to our investment in KMP.

(b) 2011 acquisition amount consists of (i) $126 million relating to KMP’s acquisition of natural gas treating assets from SouthTex Treaters, Inc. and (ii) $94 million relating to KMP’s purchase of the remaining 50% ownership interest in KinderHawk Field Services LLC that it did not already own (both discussed further in Note 3).

(c) 2011 disposal amount consists of (i) $11 million related to the sale of KMP’s ownership interest in the boat fleeting business it acquired from Megafleet Towing Co., Inc. in April 2009; and (ii) $1 million related to the sale of KMP’s subsidiary Arrow Terminals B.V. (both discussed further in Note 3).

(d) 2012 acquisition amount consists of the EP and EP Midstream acquisitions as discussed in Note 3.

(e) 2012 disposal amount relates to the sale of KMP’s FTC Natural Gas Pipelines disposal group as discussed in Note 3. Since the FTC Natural Gas Pipelines disposal group represented a significant portion of the Natural Gas Pipelines business segment, we allocated the goodwill of the segment based on the relative fair value of the portion being disposed of and the portion of the segment remaining.

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

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

The first differential, representing the excess of the fair market value of our investees' plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $186 million and $193 million as of December 31, 2012 and 2011, 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, 2012, this excess investment cost is being amortized over a weighted average life of approximately 26 years.

The second differential, representing total unamortized excess cost over underlying fair value of net assets acquired (equity method goodwill) totaled $138 million as of both December 31, 2012 and 2011. 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, 2012, 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 contracts, relationships and agreements, lease value, and technology-based assets. These intangible assets have definite lives, are subject to amortization, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets. As of December 31, 2012 and 2011, these intangible assets totaled $1,171 million and $1,185 million, respectively, and primarily consisted of customer contracts, relationships and agreements associated with the Natural Gas Pipelines and Terminals-KMP business segments.

Primarily, these contracts, relationships and agreements related to the gathering of natural gas, and the 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. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (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. 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



## Item 15. Exhibits, Financial Statement Schedules. (continued)

relationship. Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new technology, and competition.

For each of the years ended December 31, 2012, 2011 and 2010, the amortization expense on our intangibles totaled $86 million, $65 million and $50 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2013 – 2017) is approximately $86 million, $83 million, $79 million, $75 million and $74 million, respectively. As of December 31, 2012, the weighted average amortization period for our intangible assets was approximately 16 years.

## 8. Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term and then amortize these costs as interest expense in our consolidated statements of income. The following table summarizes the carrying value of our outstanding debt including the preferred interest in the general partner of KMP and excluding our debt fair value adjustments (in millions):

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011</td></tr><tr><td>Current portion of debt(a)</td><td>$ 2,401</td><td>$ 2,899</td></tr><tr><td>Long-term portion of debt</td><td>29,409</td><td>13,261</td></tr><tr><td>Net carrying value of debt(b)</td><td>$ 31,810</td><td>$ 16,160</td></tr></table>

(a) As of December 31, 2012 and 2011, balances include (i) KMI’s credit facility borrowings of $1,035 million and $421 million, respectively; (ii) KMP’s commercial paper borrowings of $621 million and $645 million, respectively; and (iii) $288 million of letter of credit facilities as of December 31, 2012.

(b) Excludes debt fair value adjustments. As of December 31, 2012 and 2011, our “Debt fair value adjustments” increased our debt balances by $2,591 million and $1,095 million, respectively. In addition to normal adjustments associated with valuing our debt obligations equal to the present value of amounts to be paid determined at appropriate current interest rates, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt, all unamortized debt discount/premium amounts, purchase accounting on our debt balances, and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see Note 13 “Risk Management — Fair Value of Derivative Contracts.”

## Long-Term Debt

As of December 31, 2012 and 2011, KMI and its subsidiaries were in compliance with its respective debt related covenants. The following provides additional detail on our debt instruments, excluding debt fair value adjustments, as of December 31, 2012 and 2011 (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>KMI</td><td></td><td></td><td></td></tr><tr><td>Senior notes and debentures, 5.15% through 7.45%(a)</td><td>$     315</td><td>$     1,155</td><td></td></tr><tr><td>Senior secured term loan facility, variable, due May 24, 2015</td><td>2,714</td><td>—</td><td></td></tr><tr><td>Deferrable interest debentures issued to subsidiary trusts, 7.63% and 8.56%, due 2027 and 2028(b)</td><td>27</td><td>27</td><td></td></tr><tr><td>KMI credit facility borrowings</td><td>1,035</td><td>421</td><td></td></tr><tr><td>Subsidiary borrowings(as obligor)</td><td></td><td></td><td></td></tr><tr><td>Kinder Morgan Finance Company, LLC</td><td></td><td></td><td></td></tr><tr><td>5.70% through 6.40% series, due 2016 through 2036(a)(c)</td><td>1,636</td><td>1,636</td><td></td></tr><tr><td>EPC Building LLC promissory note 3.967%, due 2035(d)</td><td>217</td><td>—</td><td></td></tr><tr><td>Colorado Interstate Gas Services Company(CIG Services)</td><td></td><td></td><td></td></tr><tr><td>7.76% Totem note payable due 2018</td><td>1</td><td>—</td><td></td></tr><tr><td>El Paso Natural Gas Company(EPNG)</td><td></td><td></td><td></td></tr><tr><td>5.95% through 8.625%, due 2017 through 2032(a)</td><td>1,115</td><td>—</td><td></td></tr><tr><td>El Paso LLC</td><td></td><td></td><td></td></tr></table>



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td>Senior notes and debentures, 6.50% through 12.00%, due 2013 through 2037(a)</td><td>3,860</td><td>—</td></tr><tr><td>Credit facilities borrowings(see below credit facilities)</td><td>210</td><td>—</td></tr><tr><td>Capital Trust I, 4.75%, due 2028(e)</td><td>286</td><td>—</td></tr><tr><td>EP Midstream Investment Company, LLC credit facility</td><td>78</td><td>—</td></tr><tr><td>Kinder Morgan G.P., Inc.</td><td></td><td></td></tr><tr><td>$1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(f)</td><td>100</td><td>100</td></tr><tr><td>Less: Current portion of debt</td><td>(1,153)</td><td>(1,261)</td></tr><tr><td>Total long-term debt - KMI</td><td>$ 10,441</td><td>$ 2,078</td></tr><tr><td>KMP</td><td></td><td></td></tr><tr><td>Senior notes, 3.45% through 9.00%, due 2013 through 2042(a)</td><td>$ 13,350</td><td>$ 12,050</td></tr><tr><td>Commercial paper borrowings</td><td>621</td><td>645</td></tr><tr><td>Subsidiary borrowings(as obligor)</td><td></td><td></td></tr><tr><td>Tennessee Gas Pipeline Company, L.L.C.-senior notes, 7.00% through 8.375%, due 2016 through 2037(g)</td><td>1,790</td><td>—</td></tr><tr><td>International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025(h)</td><td>40</td><td>40</td></tr><tr><td>Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due January 15, 2018(i)</td><td>25</td><td>25</td></tr><tr><td>Kinder Morgan Operating L.P. “B”-Jackson-Union Cos. II. Revenue Bonds due April 1, 2024(j)</td><td>24</td><td>24</td></tr><tr><td>Other miscellaneous subsidiary debt</td><td>19</td><td>37</td></tr><tr><td>Less: Current portion of debt</td><td>(1,155)</td><td>(1,638)</td></tr><tr><td>Total long-term debt - KMP</td><td>$ 14,714</td><td>$ 11,183</td></tr><tr><td>EPB</td><td></td><td></td></tr><tr><td>El Paso Pipeline Partners Operating Company, L.L.C.(EPPOC)</td><td></td><td></td></tr><tr><td>Senior notes, 4.10% through 8.00%, due 2013 through 2042(k)</td><td>$ 2,348</td><td>$ —</td></tr><tr><td>Subsidiary borrowings(as obligor)</td><td></td><td></td></tr><tr><td>Colorado Interstate Gas Company, L.L.C.(CIG)</td><td></td><td></td></tr><tr><td>Senior notes and debentures, 5.95% through 6.85%, due 2015 and 2037(l)</td><td>475</td><td>—</td></tr><tr><td>Southern LNG Company, L.L.C.(SLNG)</td><td></td><td></td></tr><tr><td>Senior notes, 9.50% and 9.75%, due 2014 and 2016(m)</td><td>135</td><td>—</td></tr><tr><td>Southern Natural Gas Company, L.L.C.(SNG)</td><td></td><td></td></tr><tr><td>Notes, 4.40% through 8.00%, due 2017 through 2032(n)</td><td>1,211</td><td>—</td></tr><tr><td>Other financing obligations(o)</td><td>178</td><td>—</td></tr><tr><td>Less: Current portion of debt</td><td>(93)</td><td>—</td></tr><tr><td>Total long-term debt - EPB</td><td>$ 4,254</td><td>$ —</td></tr></table>

(a) Notes provide for redemption 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.

(b) KMI’s business trusts, K N Capital Trust I and K N Capital Trust III, are obligated for $13 million of 8.56% Capital Trust Securities maturing on April 15, 2027 and $14 million of 7.63% Capital Trust Securities maturing on April 15, 2028, respectively, which it guarantees. The 2028 Securities are redeemable in whole or in part, at KMI’s option at any time, at redemption prices as defined in the associated prospectus. The 2027 Securities are redeemable in whole or in part at KMI’s option and at any time in certain limited circumstances upon the occurrence of certain events and at prices all defined in the associated prospectus supplements. Upon redemption by KMI or at maturity of the Junior Subordinated Deferrable Interest Debentures, the proceeds must be used to make redemptions of the Capital Trust Securities on a pro rata basis.

(c) Each series of these notes is fully and unconditionally guaranteed by KMI on a senior secured basis as to principal, interest and any additional amounts required to be paid as a result of any withholding or deduction for Canadian taxes.

(d) In December 2012, our subsidiary, EPC Building, LLC issued a $217 million, 3.967% amortizing promissory note due between 2013 and December 10, 2035. EPC Building, LLC, as the landlord, leases the property to Kinder Morgan, Inc. as a tenant. Proceeds from the issuance of the note were used to reduce KMI's credit facility borrowings.

(e) Capital Trust I (Trust I), is a 100%-owned business trust that issued 6.5 million of 4.75% trust convertible preferred securities for $325 million (referred to as the EP Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I's sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. EP provides a full and unconditional



guarantee of the EP Trust I Preferred Securities. There are no significant restrictions on EP’s ability to obtain funds from its subsidiaries by distribution, dividend or loan. The EP Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75%, carry a liquidation value of $50 per security plus accrued and unpaid distributions and, subsequent to the acquisition of EP, are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of KMI Class P common stock; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of KMI Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the EP Trust I Preferred Securities into debt ( $283 million) and equity ( $42 million) components, resulting in a fair value of $325 million, and included in the total debt assumed as of the EP acquisition date. Subsequent to the EP acquisition and through December 31, 2012, a total of 781,633 EP Trust I Preferred Securities had been converted into (i) 562,521 shares of KMI Class P common stock; (ii) $20 million in cash; and (iii) 859,796 in warrants.

(f) As of December 31, 2012, 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 accumulated, commencing on the issue date, at a fixed rate of 8.33% per annum and were 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 accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and are 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 KMP or its SFPP, L.P. or Calnew Pipe Line LLC subsidiaries. During 2012, $7.3 million in cash dividends, was paid on Kinder Morgan G.P. Inc.'s Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock. On January 16, 2013, 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 $10.638 per share paid on February 19, 2013 to shareholders of record as of January 31, 2013.

<table><tr><td>Three months ended</td><td>Total quarterly dividend per share</td><td>Date of declaration</td><td>Date of record</td><td>Date of dividend</td></tr><tr><td>December 31, 2011</td><td>$ 20.825</td><td>January 18, 2012</td><td>January 31, 2012</td><td>February 20, 2012</td></tr><tr><td>March 31, 2012</td><td>$ 20.825</td><td>April 18, 2012</td><td>April 30, 2012</td><td>May 18, 2012</td></tr><tr><td>June 30, 2012</td><td>$ 20.825</td><td>July 18, 2012</td><td>July 31, 2012</td><td>August 20, 2012</td></tr><tr><td>September 30, 2012</td><td>$ 10.9478</td><td>October 17, 2012</td><td>October 31, 2012</td><td>November 19, 2012</td></tr></table>

(g) Consists of six separate series of fixed-rate unsecured senior notes that KMP had assumed as part of the drop-down transaction.

(h) KMP owns a 66 2/3% interest in the International Marine Terminals (IMT) partnership. The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40 million Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. As of December 31, 2012, the interest rate on these bonds was 1.08%. The bonds are backed by two letters of credit issued by Wells Fargo. KMP’s obligation according to its ownership interests is approximately $30 million for principal, plus interest and other fees.

(i) Consists of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. As of December 31, 2012, the interest rate on these bonds was 0.15%. KMP has an outstanding letter of credit issued by Citibank in the amount of $25 million that backs-up the $25 million principal amount of the bonds.

(j) The tax exempt bonds issued by the Jackson-Union Counties Regional Port District, a political subdivision embracing the territories of Jackson County and Union County in the state of Illinois. These variable rate demand bonds bear interest at a weekly floating market rate and are backed-up by a letter of credit issued by Wells Fargo. The bond indenture also contains certain standby purchase agreement provisions which allow investors to put (sell) back their bonds at par plus accrued interest. As of December 31, 2012, the interest rate on these bonds was 0.15%. KMP’s outstanding letter of credit issued by Wells Fargo totaled $24 million, which backs-up the principal amount of the bonds.

(k) EPB’s only operating asset is its investment in EPPOC, and EPPOC’s only operating assets are its investments in WIC, CIG, SLNG, Elba Express, SNG and Cheyenne Plains Gas Pipeline Company, L.L.C. (CPG), (collectively, the non-guarantor operating companies). EPB’s and EPPOC’s independent assets and operations, other than those related to these investments and EPPOC’s debt are less than 3% of the total assets and operations of EPB, and thus substantially all of the operations and assets exist within these non-guarantor operating companies. Furthermore, there are no significant restrictions on EPPOC’s or EPB’s ability to access the net assets or cash flows related to its controlling interests in the operating companies either through dividend or loan. The restrictive covenants under these debt obligations are no more restrictive than the restrictive covenants under EPB’s credit facility.

(l) CIG is subject to a number of restrictions and covenants under its debt obligation. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.

(m) The SLNG senior notes impose certain limitations on the ability of SLNG to, among other things, incur additional indebtedness, make certain restricted payments, enter into transactions with affiliates, and merge or consolidate with any other person, sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its assets. SLNG is required to comply with certain financial covenants, including a leverage ratio of no more than 5.0 to 1.0 and an interest coverage ratio of no less than 2.0 to 1.0. The SLNG notes are subject to a change of control prepayment offer in the event of a ratings downgrade within a 120-day period from and including the date on which a change of control with respect to SLNG occurs (as defined in the note purchase agreement). If a sufficient number of the rating agencies downgrade the ratings of the SLNG notes below investment grade within the 120-day period from and including the date of any such change of control, then SLNG is required to offer to prepay the entire unpaid principal amount of the notes held by each holder at



101% of the principal amount of such SLNG notes (without any make-whole amount or other penalty), together with interest accrued thereon to the date for such prepayment.

(n) SNG and Southern Natural Issuing Corporation (SNIC) issued these notes subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. SNIC is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG's outstanding debt securities. SNIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of the debt securities. Accordingly, it has no ability to service obligations on the debt securities.

(o) In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG's joint venture partner in WYCO Development L.L.C. (WYCO) funded 50% of the construction costs. EPB reflected the payments made by their joint venture partner as other long-term liabilities on the balance sheet during construction and upon project completion, the advances were converted into a financing obligation to WYCO. Upon placing these projects in service, EPB transferred its title in the projects to WYCO and leased the assets back. Although EPB transferred the title in these projects to WYCO, the transfer did not qualify for sale leaseback accounting because of the continuing involvement through EPB's equity investment in WYCO. As such, the costs of the facilities remain on our balance sheet and the advanced payments received from EPB's 50% joint venture partner are reflected as a financing obligation due to WYCO. As of December 31, 2012, the principal amounts of the Totem and High Plains financing obligations were $75 million and $97 million, respectively, which will be paid in monthly installments through 2039, and extended for the term of related firm service agreements until 2060 and 2043, respectively. Interest payments on these obligations are based on 50% of the operating results of the facilities and are estimated at a 15.5% interest rate as of December 31, 2012.

## 2012 Changes in Debt

Changes in our and our subsidiaries outstanding debt, excluding debt fair value adjustments, during the year ended December 31, 2012 are summarized as follows (in millions):

<table><tr><td>Debt borrowings</td><td>Interest rate</td><td>Increase/ (decrease)</td><td>Cash received/(paid)</td></tr><tr><td>Issuances and assumptions</td><td></td><td></td><td></td></tr><tr><td>KMI</td><td></td><td></td><td></td></tr><tr><td>EP acquisition debt(a)</td><td></td><td></td><td></td></tr><tr><td>Senior secured term loan credit facility, due May 24, 2015</td><td>variable</td><td>$ 5,000</td><td>$ 5,000</td></tr><tr><td>Secured term loan credit facility, due May 24, 2013</td><td>variable</td><td>375</td><td>375</td></tr><tr><td>KMI credit facility</td><td>variable</td><td>2,513</td><td>2,513</td></tr><tr><td>EP Holdco credit facility</td><td>variable</td><td>112</td><td>112</td></tr><tr><td>EP Midstream Investment Company, LLC credit facility</td><td>variable</td><td>95</td><td>—</td></tr><tr><td>Debt assumed as of May 25, 2012(see below)</td><td>various</td><td>12,178</td><td>—</td></tr><tr><td>EPC Building LLC promissory note, due December 10, 2035(b)</td><td>3.967%</td><td>217</td><td>217</td></tr><tr><td>KMP and subsidiaries</td><td></td><td></td><td></td></tr><tr><td>Senior notes due September 1, 2022(c)</td><td>3.95%</td><td>1,000</td><td>998</td></tr><tr><td>Senior notes due February 15, 2023(d)</td><td>3.45%</td><td>625</td><td>622</td></tr><tr><td>Senior notes due February 15, 2023(d)</td><td>5.00%</td><td>625</td><td>621</td></tr><tr><td>Commercial paper</td><td>variable</td><td>6,453</td><td>6,453</td></tr><tr><td>Bridge loan credit facility due February 6, 2013(e)</td><td>variable</td><td>576</td><td>576</td></tr><tr><td>Tennessee Gas Pipeline Company, L.L.C.-senior notes, 7.00% through 8.375%, due 2016 through 2037(f)</td><td>various</td><td>1,790</td><td>—</td></tr><tr><td>EPB and subsidiaries</td><td></td><td></td><td></td></tr><tr><td>Senior notes, due 2042(g)</td><td>4.70%</td><td>475</td><td>475</td></tr><tr><td>EPB credit facility</td><td>various</td><td>105</td><td>105</td></tr><tr><td>EPB revolving credit</td><td>variable</td><td>80</td><td>80</td></tr><tr><td>Other</td><td></td><td>5</td><td>1</td></tr><tr><td>Total increase in debt</td><td></td><td>$ 32,224</td><td>$ 18,148</td></tr><tr><td>Repayments and other</td><td></td><td></td><td></td></tr><tr><td>KMI</td><td></td><td></td><td></td></tr><tr><td>EP acquisition debt(a)</td><td></td><td></td><td></td></tr></table>



## Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td>Senior secured term loan credit facility, due May 24, 2015</td><td>variable</td><td>$ (2,286)</td><td>$ (2,286)</td></tr><tr><td>Secured term loan credit facility, due May 24, 2013</td><td>variable</td><td>(375)</td><td>(375)</td></tr><tr><td>Senior notes due September 1, 2012(a)</td><td>6.50%</td><td>(839)</td><td>(839)</td></tr><tr><td>KMI credit facility</td><td>variable</td><td>(1,899)</td><td>(1,899)</td></tr><tr><td>EP senior notes due 2012</td><td>various</td><td>(176)</td><td>(176)</td></tr><tr><td>EP preferred securities, due March 31, 2028</td><td>4.75%</td><td>(39)</td><td>(20)</td></tr><tr><td>EP senior notes, due December 31, 2012</td><td>7.375%</td><td>(98)</td><td>(98)</td></tr><tr><td>EP Midstream Investment Company, LLC credit facility</td><td>variable</td><td>(17)</td><td>(17)</td></tr><tr><td>TGP unsecured senior notes (f)</td><td>various</td><td>(1,790)</td><td>—</td></tr><tr><td>KMP and subsidiaries</td><td></td><td></td><td></td></tr><tr><td>Senior notes due March 15, 2012(c)</td><td>7.125%</td><td>(450)</td><td>(450)</td></tr><tr><td>Senior notes due September 15, 2012(h)</td><td>5.85%</td><td>(500)</td><td>(500)</td></tr><tr><td>Commercial paper</td><td>variable</td><td>(6,476)</td><td>(6,476)</td></tr><tr><td>Bridge loan credit facility due February 6, 2013(e)</td><td>variable</td><td>(576)</td><td>(576)</td></tr><tr><td>Kinder Morgan Texas Pipeline, L.P. - senior notes due January 2, 2014</td><td>5.23%</td><td>(8)</td><td>(8)</td></tr><tr><td>Kinder Morgan Arrow Terminals L.P. - note due April 4, 2014</td><td>6.00%</td><td>(1)</td><td>(1)</td></tr><tr><td>Kinder Morgan Operating L.P. “A” - BP note due March 31, 2012</td><td>5.40%</td><td>(5)</td><td>—</td></tr><tr><td>Kinder Morgan Canada Company - BP note due March 31, 2012</td><td>5.40%</td><td>(5)</td><td>—</td></tr><tr><td>EPB and subsidiaries (since May 25, 2012)</td><td></td><td></td><td></td></tr><tr><td>EPB credit facility</td><td>variable</td><td>(805)</td><td>(805)</td></tr><tr><td>Cheyenne Plains Gas Pipeline Company, LLC term loan due 2015</td><td>variable</td><td>(176)</td><td>(176)</td></tr><tr><td>EPPOC senior notes</td><td>various</td><td>(50)</td><td>(50)</td></tr><tr><td>Other</td><td>various</td><td>(3)</td><td>(3)</td></tr><tr><td>Total decrease in debt</td><td></td><td>$ (16,574)</td><td>$ (14,755)</td></tr></table>

(a) We used proceeds from the drop-down transaction to (i) pay down $2.3 billion on our 3-year term loan facility; (ii) pay off and terminate our 364-day bridge facility; and (iii) pay off the senior notes which matured on September 1, 2012.

(b) In December 2012, our subsidiary, EPC Building, LLC, issued a $217 million, 3.967% amortizing promissory note due between 2013 and December 10, 2035. EPC Building, LLC, as the landlord, leased the property to Kinder Morgan, Inc. as a tenant. Proceeds from the issuance of the note were used to reduce KMI's credit facility borrowings.

(c) Represents KMP senior notes issued in a public offering completed on March 14, 2012. KMP received proceeds from the issuance of the notes, after deducting the underwriting discount, of $994 million, and used the proceeds both to repay its $450 million, 7.125% senior notes that matured on March 15, 2012 and to reduce the borrowings under its commercial paper program.

(d) Represents senior notes issued in a public offering completed on August 13, 2012. KMP received proceeds from the issuance of the notes, after deducting the underwriting discount, of $1,236 million, and used the proceeds to pay a portion of the purchase price for the drop-down transaction.

(e) On August 6, 2012, KMP entered into a second credit agreement with KMP as borrower; Wells Fargo Bank, National Association, as administrative agent; Barclays Bank PLC, as syndication agent; and a syndicate of other lenders. This credit agreement provided for borrowings up to $2.0 billion pursuant to a short-term bridge loan credit facility with a term of six months. The covenants of this facility were substantially similar to the covenants of KMP's existing senior unsecured revolving credit facility that is due July 1, 2016, and similar to KMP's existing credit facility, borrowings under this bridge loan credit facility could be used to back its commercial paper issuances and for other general partnership purposes (including to pay a portion of the purchase price for the drop-down transaction). In August 2012, KMP made borrowings of $576 million under its short-term bridge loan credit facility to pay a portion of the purchase price for the drop-down transaction. KMP then repaid these credit facility borrowings in August 2012 with incremental borrowings under its commercial paper program, and terminated its bridge loan credit facility on November 16, 2012. (KMP subsequently repaid the incremental commercial paper borrowings in November 2012 from the net proceeds it received from the disposal of the FTC Natural Gas Pipelines disposal group).

(f) KMP's subsidiary, TGP is the obligor of six separate series of fixed-rate unsecured senior notes having a combined principal amount of $1,790 million. KMP assumed these debt borrowings during the third quarter 2012 as part of the drop-down transaction.

(g) Represents senior notes issued on November 8, 2012. After deducting the underwriters' discount and offering costs, EPB received approximately $469 million of net proceeds from the debt offering. The net proceeds were used to repay borrowings under EPB's revolving credit facility.

(h) On September 15, 2012, KMP paid $500 million to retire the principal amount of its 5.85% senior notes that matured on that date. KMP borrowed the necessary funds under the commercial paper program. Also, on March 15, 2011, KMP paid $700 million to retire the



## Item 15. Exhibits, Financial Statement Schedules. (continued)

principal amount of the 6.75% senior notes that matured on that date. KMP used both cash on hand and borrowings under the commercial paper program to repay the maturing senior notes.

## 2011 Debt Issuances and Retirements

During 2011, KMP completed two separate public offerings of senior notes. With regard to these offerings, KMP received proceeds, net of underwriter discounts, as follows: (i) $1,093 million from a March 14, 2011 public offering of a total of $1.1 billion in principal amount of senior notes, consisting of $500 million of 3.50% notes due March 1, 2016 and $600 million of 6.375% notes due March 1, 2041 and (ii) $743 million from an August 17, 2011 public offering of a total of $750 million in principal amount of senior notes, consisting of $375 million of 4.15% notes due March 1, 2022 and $375 million of 5.625% notes due September 1, 2041. KMP used the proceeds from all of its 2011 debt offerings to reduce the borrowings under its commercial paper program.

## Subsequent Event

On February 28, 2013, KMP issued a combined $1.0 billion of senior notes in separate transactions consisting of: (i) $600 million 3.50% senior notes due September 1, 2023; and (ii) $400 million 5.00% senior notes due March 1, 2043. KMP received total net proceeds of $991 million from the issuance of these senior notes.

## El Paso Debt Assumed on May 25, 2012 (in millions):

<table><tr><td>EP</td><td></td><td></td></tr><tr><td>Notes, 6.50% through 12.00%, due 2012 through 2037</td><td>$</td><td>4,134</td></tr><tr><td>Revolving credit facility, variable, due 2014</td><td></td><td>98</td></tr><tr><td>El Paso Natural Gas Company</td><td></td><td></td></tr><tr><td>Notes, 5.95% through 8.625%, due 2017 through 2032</td><td></td><td>1,115</td></tr><tr><td>Tennessee Gas Pipeline Company</td><td></td><td></td></tr><tr><td>Notes, 7.00% through 8.375%, due 2016 through 2037</td><td></td><td>1,790</td></tr><tr><td>Other financing obligations</td><td></td><td></td></tr><tr><td>Capital Trust I, due 2028</td><td></td><td>325</td></tr><tr><td>Other</td><td></td><td>3</td></tr><tr><td>Total EP</td><td></td><td>7,465</td></tr><tr><td>EPB</td><td></td><td></td></tr><tr><td>EPB credit facility, variable due 2016</td><td></td><td>620</td></tr><tr><td>Notes, 4.10% through 8.00%, due 2012 through 2040</td><td></td><td>1,916</td></tr><tr><td>Colorado Interstate Gas</td><td></td><td></td></tr><tr><td>Notes, 5.95% through 6.85%, due 2015 through 2037</td><td></td><td>475</td></tr><tr><td>Southern Natural Gas Company</td><td></td><td></td></tr><tr><td>Notes, 4.40% through 8.00%, due 2017 through 2032</td><td></td><td>1,211</td></tr><tr><td>Cheyenne Plains Investment Company</td><td></td><td></td></tr><tr><td>Term loan, variable, due 2015</td><td></td><td>176</td></tr><tr><td>Other</td><td></td><td>315</td></tr><tr><td>Total EPB</td><td></td><td>4,713</td></tr><tr><td>Total financing obligations assumed</td><td></td><td>$ 12,178</td></tr></table>

## Credit Facilities and Restrictive Covenants

## KMI

On February 10, 2012, KMI entered into the following agreements which were effective with the May 25, 2012 acquisition of EP: (i) an amendment to its existing $1 billion revolving credit facility to, among other things, permit the EP acquisition, to fund, in part, the transactions and related costs and expenses, and to provide for ongoing working capital and for other general corporate purposes; (ii) an incremental joinder agreement which provides for $750 million in additional commitments under the



existing revolving credit facility; and (iii) an acquisition debt facilities credit agreement (Acquisition Credit Facility) containing a 364-day bridge facility and a $5 billion 3-year term loan facility, the proceeds of which were used to finance a portion of the cash consideration and related fees and expenses paid in connection with the EP acquisition.

The amended and restated credit facility provides that the $1.75 billion revolver will bear interest, at KMI’s option, at either (i) the adjusted London Interbank Offered Rate (LIBOR) plus an applicable margin per annum varying from 2.50% per annum to 4.25% per annum depending on the publicly announced debt ratings for senior secured non-credit enhanced long-term indebtedness for borrowed money of KMI or (ii) an alternate base rate plus an applicable margin varying from 1.50% per annum to 3.25% per annum depending on debt ratings of KMI. In November 2012, the terms of KMI’s $1.75 billion senior secured revolving credit facility were amended to decrease the fixed spread component of our floating interest rate by 100 basis points and to extend the maturity of the revolver to December 31, 2014. As of December 31, 2012 and 2011, the average interest rates on KMI’s credit facility borrowings were 2.72% and 1.51%, respectively.

KMI’s credit facility included the following restrictive covenants as of December 31, 2012:

• total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed 6.00: 1.00;

• 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.

The Acquisition Credit Facility provides that:

- the bridge loans under the bridge facility will bear interest, at KMI’s option, at either (i) adjusted LIBOR plus an applicable margin varying from 2.50% per annum to 4.25% per annum depending on certain debt ratings of KMI or (ii) an alternate base rate plus an applicable margin varying from 1.50% per annum to 3.25% per annum depending on certain debt ratings of KMI; and

- the term loans under the term loan facility will bear interest, at KMI’s option, at either (i) adjusted LIBOR plus an applicable margin varying from 3.00% per annum to 4.75% per annum depending on certain debt ratings of KMI or (ii) an alternate base rate plus an applicable margin varying from 2.00% per annum to 3.75% per annum depending on certain debt ratings of KMI.

As of December 31, 2012, the amount available for borrowing under KMI’s $1.75 billion senior secured credit facility was reduced by a combined amount of $1,112 million consisting of (i) $1,035 million in borrowings outstanding under its credit facility and (ii) $77 million in fifteen letters of credit required under provisions of our property and casualty, workers’ compensation and general liability insurance policies.

Credit facilities associated with three of our other subsidiaries (that were acquired through the EP acquisition) having a combined capacity of $670 million were reduced at December 31, 2012 by a combined $636 million consisting of: (i) $288 million in borrowings outstanding under the credit facilities with average interest rates ranging from 1.619% to 2.673% and (ii) $348 million in 24 letters of credit.

## KMP

On July 1, 2011, KMP amended its $2.0 billion, three-year senior unsecured revolving credit facility to, among other things, (i) allow for borrowings of up to $2.2 billion; (ii) extend the maturity of the credit facility from June 23, 2013 to July 1, 2016; (iii) permit an amendment to allow for borrowings of up to $2.5 billion; and (iv) decrease the interest rates and commitment fees for borrowings under this facility. The credit facility is with a syndicate of financial institutions, and the facility permits KMP to obtain bids for fixed rate loans from members of the lending syndicate. Wells Fargo Bank, National Association is the administrative agent, and borrowings under the credit facility can be used for general partnership purposes and as a backup for KMP’s commercial paper program. There were no borrowings under the credit facility as of December 31, 2012 or as of December 31, 2011.

As of December 31, 2012, KMP’s commercial paper program provides for the issuance of up to $2.2 billion of commercial paper. KMP’s unsecured revolving credit facility supports its commercial paper program, and borrowings under its commercial paper program reduce the borrowings allowed under KMP’s credit facility. As of December 31, 2012 and 2011, the average interest rates on KMP’s outstanding commercial paper borrowings were 0.45% and 0.53%, respectively. The borrowings under



KMP’s commercial paper program were used principally to finance the acquisitions and capital expansions made during 2012 and 2011, and in the near term, KMP expects that its short-term liquidity and financing needs will be met primarily through borrowings made under its commercial paper program.

As of December 31, 2012, the amount available for borrowing under KMP’s credit facility was reduced by a combined amount of $841 million, consisting of $621 million of commercial paper borrowings and $220 million of letters of credit, consisting of (i) a $100 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of the Pacific operations’ pipelines in the state of California; (ii) a combined $85 million in three letters of credit that support tax-exempt bonds; (iii) a $12 million letter of credit that supports debt securities issued by the Express pipeline system; and (iv) a combined $23 million in other letters of credit supporting other obligations of KMP and its subsidiaries.

Interest on KMP’s 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 0.05%) or (ii) LIBOR, plus a margin, which varies depending upon the credit rating of its long-term senior unsecured debt. Additionally, KMP’s credit facility included the following restrictive covenants as of December 31, 2012:

• 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 KMP makes any Specified Acquisition (as defined in the credit facility) or (ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or

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

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

• limitations on granting liens; and

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

In addition to normal repayment covenants, under the terms of KMP’s credit facility, the occurrence at any time of any of the following would constitute an event of default: (i) KMP’s 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) KMP’s 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 KMP 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 KMP’s liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.

Also, KMP’s credit facility does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin KMP 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 credit rating. None of KMP’s debt is subject to payment acceleration as a result of any change to its credit ratings.

## EPB

In May 2011, EPPOC and WIC entered into an unsecured 5-year credit facility with an initial aggregate borrowing capacity of $1 billion, expandable to $1.5 billion for certain expansion projects and acquisitions. EPPOC is a wholly owned subsidiary of EPB. In May 2012, EPB borrowed from the revolving credit facility to fund the acquisition of CPG and the remaining interest in CIG. On May 24, 2012, Standard & Poor's Rating Service raised EPB's credit rating, triggering a pricing level change. EPB's interest rate for borrowings under the credit facility has decreased from the LIBOR plus 2% to LIBOR plus 1.75% and the commitment fee paid for unutilized commitments decreased from 0.4% to 0.3% and these rates remained effective at December 31, 2012. As of December 31, 2012, EPB had no outstanding balance under its revolving credit facility and $8 million outstanding in letters of credit. EPB's remaining availability under this facility was $992 million. Borrowings under the credit facility are guaranteed by EPB.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

The credit facility contains covenants and provisions that affect EPB, the borrowers and EPB’s other restricted subsidiaries, including, without limitation, customary covenants and provisions:

• total debt divided by earnings before interest, income taxes, depreciation and amortization as of the end of each quarter may not exceed:

• 5.0 to 1.0 for any trailing four consecutive quarter period; and

- 5.5 to 1.0 for any such four quarter period during the three full fiscal quarters subsequent to the consummation of specified permitted acquisitions having a value greater than $25 million.

EPB also has additional flexibility to the covenants for growth projects. In case of a capital construction or expansion project in excess of $20 million, pro forma adjustments to consolidated EBITDA, approved by the lenders, may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments shall be limited to 25% of actual consolidated EBITDA.

• 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.

The credit facility contains certain customary events of default that affect EPB, the borrowers and EPB’s other restricted subsidiaries, including, without limitation, (i) nonpayment of principal when due or nonpayment of interest or other amounts within 5 business days when due; (ii) bankruptcy or insolvency with respect to EPB, the general partner, the borrowers or any of EPB’s other restricted subsidiaries; (iii) judgment defaults against EPB, the general partner, the borrowers or any of EPB’s other restricted subsidiaries in excess of $50 million; or (iv) the failure of El Paso to directly or indirectly own a majority of the voting equity of EPB’s general partner and a failure by EPB to directly or indirectly own 100% of the equity of EPPOC.

## Maturities of Debt

The scheduled maturities of the outstanding debt balances, excluding purchase accounting adjustments and value of interest rate swaps, as of December 31, 2012, are summarized as follows (in millions):

<table><tr><td>Year</td><td></td><td>KMI</td><td>KMP</td><td>EPB</td></tr><tr><td>2013</td><td>$</td><td>1,153</td><td>$</td><td>93</td></tr><tr><td>2014</td><td></td><td>414</td><td>501</td><td>76</td></tr><tr><td>2015</td><td></td><td>2,968</td><td>300</td><td>755</td></tr><tr><td>2016</td><td></td><td>922</td><td>750</td><td>69</td></tr><tr><td>2017</td><td></td><td>1,146</td><td>900</td><td>505</td></tr><tr><td>Thereafter</td><td></td><td>4,991</td><td>12,263</td><td>2,849</td></tr><tr><td>Total</td><td>$</td><td>11,594</td><td>$</td><td>4,347</td></tr></table>

## Interest Rates, Interest Rate Swaps and Contingent Debt

The weighted average interest rate on all of our borrowings was 4.92% during 2012 and 4.38% during 2011. Information on our interest rate swaps is contained in Note 13 “Risk Management—Interest Rate Risk Management.” For information about our contingent debt agreements, see Note 12 “Commitments and Contingent Liabilities—Contingent Debt.”



## 9. Share-based Compensation and Employee Benefits

## Share-based Compensation

Kinder Morgan, Inc.

We completed an initial public offering in February 2011 as discussed further in Note 10 “Stockholders’ Equity-Kinder Morgan, Inc. - Equity Interests-Initial Public Offering.” As a result of our initial public offering, our outstanding Class B units and Class A-1 units were converted to Class B shares and Class C shares, respectively. As of December 26, 2012, all class B and C shares had converted into Class P shares.

Class P Shares

Stock Compensation Plan for Non-Employee Directors

In connection with our initial public offering, we adopted the Stock Compensation Plan for Non-Employee Directors, in which our independent directors will participate. None of the 11 directors nominated by Richard D. Kinder or the Sponsor Investors participate in the plan. The plan recognizes that the compensation paid to each non-employee director is fixed by our board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each non-employee director who was not nominated by Richard D. Kinder or one of the Sponsor Investors, referred to as “eligible directors,” may elect to receive shares of Class P common stock. Each election will be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of shares of Class P common stock authorized under the plan is 250,000. During 2012 and 2011, we made restricted Class P common stock grants to our non-employee directors of 5,520 and 1,570, respectively. These grants were valued at time of issuance at $185,000 and $45,000, respectively. All of the restricted stock grants made to non-employee directors vest during a six-month period.

Restricted Stock and Long-term Incentive Retention Award Plan

Upon our initial public offering, our restricted stock compensation program replaced our Long-term Incentive Retention Award Plan. Our restricted stock compensation program is available to employees eligible under the former Long-term Incentive Retention Award Plan, discussed below. The following table sets forth a summary of activity and related balances of our restricted stock excluding that issued to non-employee directors (in millions, except share amounts):

<table><tr><td rowspan="2"></td><td colspan="2">Year ended December 31, 2012</td><td colspan="2">February 11, 2011 Through December 31, 2011</td></tr><tr><td>Shares</td><td>Weighted Average Grant Date Fair Value (In millions)</td><td>Shares</td><td>Weighted Average Grant Date Fair Value (In millions)</td></tr><tr><td>Outstanding at beginning of period</td><td>1,163,090</td><td>33</td><td>—</td><td>—</td></tr><tr><td>Granted</td><td>1,463,388</td><td>51</td><td>980,851</td><td>28</td></tr><tr><td>Shares issued in exchange for cash awards</td><td>—</td><td>—</td><td>213,040</td><td>6</td></tr><tr><td>Vested</td><td>(102,033)</td><td>(3)</td><td>—</td><td>—</td></tr><tr><td>Forfeited</td><td>(370,423)</td><td>(12)</td><td>(30,801)</td><td>(1)</td></tr><tr><td>Outstanding at end of period</td><td>2,154,022</td><td>69</td><td>1,163,090</td><td>33</td></tr><tr><td>Intrinsic value of restricted stock vested during the period</td><td></td><td>4</td><td></td><td>—</td></tr></table>

Restricted stock grants made to employees have vesting periods ranging from two years with variable vesting dates to seven years. Following is a summary of the future vesting of our outstanding restricted stock grants:



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td>Year</td><td>Vesting of Restricted Shares</td></tr><tr><td>2013</td><td>107,375</td></tr><tr><td>2014</td><td>500,926</td></tr><tr><td>2015</td><td>742,823</td></tr><tr><td>2016</td><td>67,666</td></tr><tr><td>2017</td><td>157,749</td></tr><tr><td>2018</td><td>385,138</td></tr><tr><td>2019</td><td>192,345</td></tr><tr><td>Total Outstanding</td><td>2,154,022</td></tr></table>

The related expense less estimated forfeitures is recognized ratably over the vesting period of the restricted stock grants. Upon vesting, the grants will be paid in our Class P common shares.

During 2012 and 2011, we recorded $14 million and $4 million, respectively, in amortization expense related to restricted stock grants. In addition, in conjunction with the exchange for restricted shares discussed above, we recorded an increase to additional paid-in capital in the amount of $2 million in 2011. At December 31, 2012, unrecognized restricted stock compensation expense, less estimated forfeitures, was approximately $49 million.

From 2006 until our initial public offering, 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 provided cash awards approved by the compensation committees of the Company which are granted in July of each year to recommended key employees. Senior management was 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. The remaining grants outstanding were made in July of 2010. During the years ended December 31, 2012, 2011 and 2010, we expensed $7 million, $13 million and $18 million, respectively, related to these grants.

## Awards of Participation Interests in Going Private Transaction

In connection with our Going Private Transaction, members of management were awarded Kinder Morgan Holdco LLC Class A-1 and Class B units. In accordance with generally accepted accounting principles, we were required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units; however, we do not have any obligation, nor did we pay any amounts related to these compensation expenses as all expenses were borne by the Investors, and since we were not responsible for paying these expenses, we recognized the amounts allocated to us as both an expense on our income statement and a contribution to "Stockholders Equity" on our balance sheet. The awards and terms of the Class B units granted to members of management were determined after extensive negotiations between management and the Sponsor Investors with respect to which management agreed to forego any long-term executive compensation at least until the Sponsor Investors sell their interests in us or convert their Class A shares into Class P shares. The Class B units were converted into Class B shares, and the class A-1 units were converted into Class C shares in connection with our initial public offering. The aggregate amount of our Class P common stock into which the Class A shares, Class B shares and Class C shares could convert was fixed. The conversion of Class B shares into Class P shares reduced the number of Class P shares into which the Class A shares and Class C shares could convert. Therefore, we view the Class B shares, along with the Class A shares and Class C shares, as participation interests in the Going Private Transaction, rather than as awards of stock-based compensation. As of December 26, 2012, all class B and C shares had converted into Class P shares.

## Kinder Morgan Energy Partners, L.P.

KMP 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 KMR’s then three non-employee directors was granted 7,500 common unit appreciation rights. In addition, 10,000 common unit appreciation rights were granted to each of KMR’s then three non-employee



## Item 15. Exhibits, Financial Statement Schedules. (continued)

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, KMP 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. As of December 31, 2010, 17,500 unit appreciation rights had been granted, vested and remained outstanding. In 2011, 17,500 unit appreciation rights were exercised at an aggregate fair value of $81.86 per unit, paid in a cash amount of $671,200. Accordingly, as of December 31, 2011, no unit appreciation rights 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 KMR board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. 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 2,450 common units were issued to non-employee directors in both 2011 and 2010, respectively, as a result of their elections to receive common units in lieu of cash compensation.

## Pension and Other Postretirement Benefit Plans

## Kinder Morgan, Inc.

## Overview of Retirement Benefit Plans

Pension Plans. Our pension plan is a defined benefit plan that covers substantially all of our U.S. employees and provides benefits under a cash balance formula. A participant in the cash balance plan accrues benefits through contribution credits based on a combination of age and years of service times eligible compensation. Interest is also credited to the participant's plan account. A participant becomes fully vested in the plan after three years, and may take a lump sum distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees continue to accrue benefits through a career pay formula.

In connection with the EP acquisition, we assumed El Paso’s defined benefit pension plans including a cash balance plan and a supplemental executive retirement plan (“SERP”). These plans had combined benefit obligations of $2,407 million and assets of $1,949 million as of the May 25, 2012 acquisition date. We merged the El Paso cash balance plan into our cash balance plan on December 31, 2012. We terminated the El Paso SERP and partially settled the plan’s benefit obligation during 2012. The $28 million SERP obligation that remained as of December 31, 2012 was settled in February 2013.

Savings Plan. We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain plan participants' contributions and Company contributions are based on collective bargaining agreements. In connection with the EP acquisition, we assumed El Paso's defined contribution savings plan which was merged into our savings plan during 2012. The total amount charged to expense for our savings plan was approximately $32 million, $24 million, and $21 million for the years ended December 31, 2012, 2011, and 2010.

Other Postretirement Benefit Plans. We provide other postretirement benefits (“OPEB”), including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. Medical benefits for these closed groups of retirees may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits.

In connection with the EP acquisition, we assumed El Paso’s OPEB plans including retiree medical and life insurance benefits. These plans had aggregate benefit obligations of $532 million and assets of $155 million as of the May 25, 2012 acquisition date.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2012 and 2011 (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td>2012</td><td>2011</td><td></td><td>2012</td><td>2011</td><td></td></tr><tr><td>Change in benefit obligation:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Benefit obligation at beginning of period</td><td>$     343</td><td>$     308</td><td>$     91</td><td>$     84</td><td></td><td></td></tr><tr><td>Service cost</td><td>18</td><td>13</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Interest cost</td><td>67</td><td>17</td><td>16</td><td>4</td><td></td><td></td></tr><tr><td>Actuarial loss</td><td>178</td><td>29</td><td>31</td><td>11</td><td></td><td></td></tr><tr><td>Benefits paid</td><td>(58)</td><td>(18)</td><td>(33)</td><td>(13)</td><td></td><td></td></tr><tr><td>Participant contributions</td><td>—</td><td>—</td><td>6</td><td>4</td><td></td><td></td></tr><tr><td>Early retiree reinsurance receipts</td><td>—</td><td>—</td><td>—</td><td>1</td><td></td><td></td></tr><tr><td>Medicare Part D subsidy receipts</td><td>—</td><td>—</td><td>1</td><td>—</td><td></td><td></td></tr><tr><td>Business combination(a)</td><td>2,407</td><td>—</td><td>532</td><td>—</td><td></td><td></td></tr><tr><td>Plan amendments</td><td>(17)</td><td>(6)</td><td>(1)</td><td>—</td><td></td><td></td></tr><tr><td>Curtailments, settlements and special termination benefits(b)</td><td>(146)</td><td>—</td><td>(1)</td><td>—</td><td></td><td></td></tr><tr><td>Benefit obligation at end of period</td><td>2,792</td><td>343</td><td>642</td><td>91</td><td></td><td></td></tr></table>

<table><tr><td>Change in plan assets:</td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at beginning of period</td><td>258</td><td>250</td><td>55</td><td>61</td></tr><tr><td>Actual return on plan assets</td><td>203</td><td>6</td><td>15</td><td>2</td></tr><tr><td>Employer contributions</td><td>32</td><td>20</td><td>18</td><td>—</td></tr><tr><td>Participant contributions</td><td>—</td><td>—</td><td>6</td><td>4</td></tr><tr><td>Benefits paid</td><td>(58)</td><td>(18)</td><td>(33)</td><td>(13)</td></tr><tr><td>Early retiree reinsurance receipts</td><td>—</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Business combination(a)</td><td>1,949</td><td>—</td><td>155</td><td>—</td></tr><tr><td>Settlements(b)</td><td>(144)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Fair value of plan assets at end of period</td><td>2,240</td><td>258</td><td>216</td><td>55</td></tr><tr><td>Funded status - net liability at December 31,</td><td>$ (552)</td><td>$ (85)</td><td>$ (426)</td><td>$ (36)</td></tr></table>

(a) Reflects the acquisition date amount of benefit plan obligations and assets assumed from El Paso.

(b) Reflects the settlement of benefit obligations associated with certain participants in the acquired El Paso plans as a result of the sale of EP Energy, a reduction in force and termination of the SERP.

Components of Funded Status. The following table details the amounts recognized in our balance sheet at December 31, 2012 and 2011 related to our pension and OPEB plans (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="2">OPEB</td></tr><tr><td>2012</td><td>2011</td><td></td><td>2012</td><td>2011</td></tr><tr><td>Non-current benefit asset</td><td>$ —</td><td>$ —</td><td>$ 88</td><td>$ —</td><td></td></tr><tr><td>Current benefit liability</td><td>(28)</td><td>—</td><td></td><td>(33)</td><td>—</td></tr><tr><td>Non-current benefit liability</td><td>(524)</td><td>(85)</td><td></td><td>(481)</td><td>(36)</td></tr><tr><td>Funded status - net liability at December 31,</td><td>$ (552)</td><td>$ (85)</td><td>$ (426)</td><td>$ (36)</td><td></td></tr></table>

Components of Accumulated Other Comprehensive Income (Loss). The following table details the amounts recognized in pre-tax accumulated other comprehensive income (loss) at December 31, 2012 and 2011 related to our pension and OPEB plans (in millions):



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td>2012</td><td>2011</td><td>2012</td><td>2011</td><td>2012</td><td>2011</td></tr><tr><td>Unrecognized net actuarial gain (loss)</td><td>$ (218)</td><td>$ (144)</td><td>$ (72)</td><td>$ (50)</td><td></td><td></td></tr><tr><td>Unrecognized prior service (cost) credit</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>20</td><td>5</td><td>1</td><td>—</td><td></td><td></td></tr><tr><td>Accumulated other comprehensive income (loss)</td><td>$ (198)</td><td>$ (139)</td><td>$ (71)</td><td>$ (50)</td><td></td><td></td></tr></table>

We anticipate that approximately $3 million of our pre-tax accumulated other comprehensive loss will be recognized as part of our net periodic benefit cost in 2013, including $5 million of unrecognized net actuarial loss and $2 million of unrecognized prior service credit.

Our accumulated benefit obligation for our defined benefit pension plans was $2,773 million and $326 million at December 31, 2012 and 2011, respectively. Our accumulated benefit obligation for our defined benefit plans, whose accumulated benefit obligations exceeded the fair value of plan assets, was $2,773 million and $326 million at December 31, 2012 and 2011, respectively. The fair value of these plans' assets was approximately $2,240 million and $258 million at December 31, 2012 and 2011, respectively.

Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $569 million and $91 million at December 31, 2012 and 2011, respectively. The fair value of these plans' assets was approximately $5 million and $55 million at December 31, 2012 and 2011, respectively.

Plan Assets. The investment policies and strategies for the assets of our pension and OPEB 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, 2012, the target asset allocations in effect for the pension plan were 51%, equity, 40% fixed income, 5% alternative investments and 4% cash. As of December 31, 2012, the asset allocations in effect for the retiree medical and retiree life insurance plans were 62% equity, 35% fixed income and 3% cash. In order to achieve enhanced diversification, the equity category is further subdivided into sub-categories with respect to small cap vs. large cap, value vs. growth and international vs. domestic, each with its own target asset allocation. One such sub-category is an investment of 5% in KMI common stock.

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: 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.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Below are the details of our pension and OPEB plan assets classified by level and a description of the valuation methodologies used for assets measured at fair value.

- Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are dollar-denominated money market funds, common stock and preferred stock. Common stock and preferred stock are valued at the closing price reported on the active market on which the individual securities are traded.

- Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are money market funds, common/collective trust funds, mutual funds, fixed income and other securities. Money market funds are valued at amortized cost, which approximates fair value. The common/collective trust funds’ and mutual funds’ fair values are primarily based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market.

- Level 3 assets’ fair values are similar to Level 2 assets and calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable. Included in this level are insurance contracts, mutual funds with significant redemption restrictions, limited partnerships and private equity. Insurance contracts are valued at contract value, which approximates fair value. The mutual funds’ fair values are primarily based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. The limited partnerships’ and private equity investments’ fair values are primarily based on the securities’ value as reported by the issuer, which is determined utilizing discounted present value.

Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value classified in each level at December 31, 2012 and 2011 (in millions):

Pension Assets

<table><tr><td rowspan="2"></td><td colspan="6">2012</td><td colspan="6">2011</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td><td></td></tr><tr><td>Money market funds</td><td>$ 1</td><td>$ 6</td><td>$ —</td><td>$ 7</td><td>$ —</td><td>$ 8</td><td>$ —</td><td>$ 8</td><td></td><td></td><td></td><td></td></tr><tr><td>Common/collective trusts(a)</td><td>—</td><td>765</td><td>—</td><td>765</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Insurance contracts</td><td>—</td><td>—</td><td>14</td><td>14</td><td>—</td><td>—</td><td>14</td><td>14</td><td></td><td></td><td></td><td></td></tr><tr><td>Mutual funds(b)</td><td>—</td><td>266</td><td>40</td><td>306</td><td>—</td><td>82</td><td>—</td><td>82</td><td></td><td></td><td></td><td></td></tr><tr><td>Common and preferred stocks</td><td>812</td><td>—</td><td>—</td><td>812</td><td>86</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>111</td><td>—</td><td>111</td><td>—</td><td>34</td><td>—</td><td>34</td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. government securities</td><td>—</td><td>99</td><td>—</td><td>99</td><td>—</td><td>18</td><td>—</td><td>18</td><td></td><td></td><td></td><td></td></tr><tr><td>Asset backed securities</td><td>—</td><td>25</td><td>—</td><td>25</td><td>—</td><td>3</td><td>—</td><td>3</td><td></td><td></td><td></td><td></td></tr><tr><td>Limited partnerships</td><td>—</td><td>—</td><td>20</td><td>20</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>13</td><td>13</td><td>—</td><td>—</td><td>13</td><td>13</td><td></td><td></td><td></td><td></td></tr><tr><td>Other</td><td>—</td><td>68</td><td>—</td><td>68</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Total asset fair value(c)</td><td>$ 813</td><td>$ 1,340</td><td>$ 87</td><td>$ 2,240</td><td>$ 86</td><td>$ 145</td><td>$ 27</td><td>$ 258</td><td></td><td></td><td></td><td></td></tr></table>

(a) For 2012, this category includes common/collective trusts funds which are invested in approximately 59% fixed income, 36% equity and 5% short term securities.

(b) For 2012, this category includes mutual funds which are invested in approximately 28% fixed income and 72% equity and other investments. For 2011, this category includes mutual funds which are invested in approximately 32% fixed income and 68% equity and other investments.

(c) For 2012, plan assets include $133 million of KMI Class P common stock. For 2011, plan assets include $13 million of KMI Class P common stock.



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="8">OPEB Assets</td></tr><tr><td colspan="4">2012</td><td colspan="4">2011</td></tr><tr><td></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td>Money market funds</td><td>$ 6</td><td>$ 1</td><td>$ —</td><td>$ 7</td><td>$ —</td><td>$ 3</td><td>$ —</td><td>$ 3</td></tr><tr><td>Common/collective trusts(a)</td><td>—</td><td>157</td><td>—</td><td>157</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Insurance contracts</td><td>—</td><td>—</td><td>44</td><td>44</td><td>—</td><td>—</td><td>42</td><td>42</td></tr><tr><td>Mutual funds</td><td>—</td><td>8</td><td>—</td><td>8</td><td>—</td><td>10</td><td>—</td><td>10</td></tr><tr><td>Total asset fair value</td><td>$ 6</td><td>$ 166</td><td>$ 44</td><td>$ 216</td><td>$ —</td><td>$ 13</td><td>$ 42</td><td>$ 55</td></tr></table>

(a) For 2012, this category includes common/collective trusts funds which are invested in approximately 65% equity and 35% fixed income securities.

The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2012 and 2011 (in millions):

<table><tr><td rowspan="2"></td><td colspan="6">Pension Assets</td></tr><tr><td>Balance at Beginning of Period</td><td>Transfers In (Out)</td><td>Realized and Unrealized Gains (Losses), net</td><td>Purchases (Sales), net</td><td>Balance at End of Period</td><td></td></tr><tr><td>December 31, 2012</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Insurance contracts</td><td>$ 14</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>14</td></tr><tr><td>Mutual funds</td><td>—</td><td>38</td><td>2</td><td>—</td><td>40</td><td></td></tr><tr><td>Limited partnerships</td><td>—</td><td>16</td><td>—</td><td>4</td><td>20</td><td></td></tr><tr><td>Private equity</td><td>13</td><td>—</td><td>—</td><td>—</td><td>13</td><td></td></tr><tr><td>Total</td><td>$ 27</td><td>$ 54</td><td>$ 2</td><td>$ 4</td><td>$ 87</td><td></td></tr><tr><td>December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Insurance contracts</td><td>$ 14</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>14</td></tr><tr><td>Private equity</td><td>11</td><td>—</td><td>2</td><td>—</td><td>13</td><td></td></tr><tr><td>Total</td><td>$ 25</td><td>$ —</td><td>$ 2</td><td>$ —</td><td>$ 27</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="6">OPEB Assets</td></tr><tr><td>Balance at Beginning of Period</td><td>Transfers In (Out)</td><td>Realized and Unrealized Gains (Losses), net</td><td>Purchases (Sales), net</td><td>Balance at End of Period</td><td></td></tr><tr><td>December 31, 2012</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Insurance contracts</td><td>$ 42</td><td>$ —</td><td>$ 7</td><td>$ (5)</td><td>$ 44</td><td></td></tr><tr><td>Total</td><td>$ 42</td><td>$ —</td><td>$ 7</td><td>$ (5)</td><td>$ 44</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Insurance contracts</td><td>$ 45</td><td>$ —</td><td>$ (6)</td><td>$ 3</td><td>$ 42</td><td></td></tr><tr><td>Total</td><td>$ 45</td><td>$ —</td><td>$ (6)</td><td>$ 3</td><td>$ 42</td><td></td></tr></table>



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 2012 and 2011.

Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2012, we expect to make the following benefit payments under our plans (in millions):

<table><tr><td>Fiscal year</td><td colspan="2">Pension Benefits</td><td>OPEB(a)</td></tr><tr><td>2013</td><td>$ 221</td><td>$ 48</td><td></td></tr><tr><td>2014</td><td>190</td><td>47</td><td></td></tr><tr><td>2015</td><td>190</td><td>47</td><td></td></tr><tr><td>2016</td><td>192</td><td>46</td><td></td></tr><tr><td>2017</td><td>191</td><td>46</td><td></td></tr><tr><td>2018-2022</td><td>929</td><td>213</td><td></td></tr></table>

(a) Includes a reduction of approximately $7 million in each of the years 2013 - 2017 and approximately $34 million in aggregate for 2018 - 2022 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

In January 2013, we contributed $78 million to our pension plans, including $28 million to settle our remaining SERP obligation. We expect to contribute approximately $35 million to our OPEB plan in 2013.

Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation and net benefit costs of our pension and OPEB plans for 2012, 2011 and 2010:

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Assumptions related to benefit obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>3.40%</td><td>4.50%</td><td>5.50%</td><td>3.33%</td><td>4.25%</td><td>5.00%</td></tr><tr><td>Rate of compensation increase</td><td>3.00%</td><td>3.50%</td><td>3.50%</td><td>n/a</td><td>n/a</td><td>n/a</td></tr><tr><td>Assumptions related to benefit costs:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate(a)</td><td>4.22%</td><td>5.50%</td><td>6.00%</td><td>4.11%</td><td>5.00%</td><td>5.75%</td></tr><tr><td>Expected return on plan assets (b) (c)</td><td>8.44%</td><td>8.90%</td><td>8.90%</td><td>8.29%</td><td>8.90%</td><td>8.90%</td></tr><tr><td>Rate of compensation increase</td><td>3.50%</td><td>3.50%</td><td>3.50%</td><td>n/a</td><td>n/a</td><td>n/a</td></tr></table>

(a) The discount rate related to pension benefit cost was 4.50% for the period from January 1, 2012 to May 24, 2012, and 4.03% for the period from May 25, 2012 to December 31, 2012. The discount rate related to other postretirement benefit cost was 4.25% for the period from January 1, 2012 to May 24, 2012 and 4.00% for the period from May 25, 2012 to December 31, 2012.

(b) The expected return on plan assets related to pension cost was 8.90% for the period from January 1, 2012 to May 24, 2012, and 8.11% for the period from May 25, 2012 to December 31, 2012. The expected return on plan assets related to other postretirement benefit cost was 8.90% for the period from January 1, 2012 to May 24, 2012, and 7.85% for the period from May 25, 2012 to December 31, 2012.

(c) The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the assumed El Paso OPEB plans, we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes at a rate of 22%.

The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans' investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class.

Actuarial estimates for our OPEB plans assumed a weighted-average annual rate of increase in the per capita cost of covered health care benefits of 6.37%, gradually decreasing to 4.69% by the year 2019. Assumed health care cost



trends have a significant effect on the amounts reported for OPEB plans. A one-percentage point change in assumed health care cost trends would have the following effects as of December 31, 2012 and 2011 (in millions):

<table><tr><td></td><td>2012</td><td>2011(a)</td></tr><tr><td>One-percentage point increase:</td><td></td><td></td></tr><tr><td>Aggregate of service cost and interest cost</td><td>$ 1</td><td>—</td></tr><tr><td>Accumulated postretirement benefit obligation</td><td>47</td><td>—</td></tr><tr><td>One-percentage point decrease:</td><td></td><td></td></tr><tr><td>Aggregate of service cost and interest cost</td><td>$ (1)</td><td>—</td></tr><tr><td>Accumulated postretirement benefit obligation</td><td>(41)</td><td>—</td></tr></table>

(a) Includes effects of less than $1 million on benefit costs and obligations.

Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows (in millions):

<table><tr><td rowspan="2"></td><td colspan="4">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Components of net benefit cost:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 18</td><td>$ 13</td><td>$ 12</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Interest cost</td><td>67</td><td>17</td><td>16</td><td>16</td><td>4</td><td>5</td><td></td></tr><tr><td>Expected return on assets</td><td>(110)</td><td>(22) —</td><td>(19)</td><td>(11)</td><td>(5)</td><td>(5)</td><td></td></tr><tr><td>Amortization of prior service (credit) cost</td><td>(1)</td><td>(1) —</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Amortization of net actuarial loss (gain)</td><td>10</td><td>7</td><td>6</td><td>5</td><td>4</td><td>3</td><td></td></tr><tr><td>Curtailment and settlement (gain) loss</td><td>(2)</td><td>—</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td></td></tr><tr><td>Net benefit (credit) cost</td><td>(18)</td><td>14</td><td>15</td><td>9</td><td>3</td><td>3</td><td></td></tr><tr><td>Other changes in plan assets and benefit obligations recognized in other comprehensive income:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net loss (gain) arising during period</td><td>85</td><td>46</td><td>15</td><td>27</td><td>13</td><td>9</td><td></td></tr><tr><td>Prior service (credit) cost arising during period</td><td>(17)</td><td>(6)</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td></td></tr><tr><td>Amortization of net actuarial (loss) gain</td><td>(10)</td><td>(7)</td><td>(6)</td><td>(5)</td><td>(4)</td><td>(3)</td><td></td></tr><tr><td>Amortization of prior service (cost) credit</td><td>1</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total recognized in other comprehensive income</td><td>59</td><td>34</td><td>9</td><td>21</td><td>9</td><td>6</td><td></td></tr><tr><td>Total recognized in net benefit cost and other comprehensive income</td><td>$ 41</td><td>$ 48</td><td>$ 24</td><td>$ 30</td><td>$ 12</td><td>$ 9</td><td></td></tr></table>

Kinder Morgan Energy Partners, L.P.

Pension and Other Postretirement Benefit Plans

Two of KMP’s 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 pipeline system 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. KMP also provides postretirement benefits other than pensions for retired employees.

KMP’s combined net periodic benefit costs for these Trans Mountain pension and other postretirement benefit plans for 2012, 2011 and 2010 were approximately $11 million, $7 million and $4 million, respectively, recognized ratably over each year. As of December 31, 2012, KMP estimates its overall net periodic pension and other postretirement benefit costs for these plans for the year 2013 will be approximately $12 million, although this estimate could change if



## Item 15. Exhibits, Financial Statement Schedules. (continued)

there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. KMP expects to contribute approximately $12 million to these benefit plans in 2013.

KMP’s subsidiary, TGP, also provides postretirement benefits other than pensions for certain retired employees. The costs for this plan are prefunded to the extent such costs are recoverable through natural gas pipeline transportation rates. KMP’s combined net periodic benefit costs for the TGP other postretirement benefit plan for 2012 was a credit (increase to net income) of $2 million, recognized ratably over the seven months KMP included TGP in its consolidated results. As of December 31, 2012, KMP estimates its overall net periodic other postretirement benefit cost for this plan for the year 2013 will be a credit of approximately $3 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. Furthermore, KMP expects to make no contributions to this benefit plan in 2013.

Additionally, KMP’s subsidiary SFPP, L.P. has incurred certain liabilities for postretirement benefits to certain current and former employees, their covered dependents, and their beneficiaries. However, the net periodic benefit costs, contributions and liability amounts associated the SFPP, L.P. postretirement benefit plan are not material to our consolidated income statements or balance sheets.

As of December 31, 2012 and 2011, the recorded value of KMP’s pension and other postretirement benefit obligations for all of these plans was a combined $74 million and $70 million, respectively. As of December 31, 2012, the TGP other postretirement benefit plan was overfunded by $32 million. KMP considers its pension and other 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 KMP’s acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, KMP participates in several multi-employer pension plans for the benefit of employees who are union members. KMP does not administer these plans and contributes 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 $11 million, $12 million and $10 million for the years ended December 31, 2012, 2011 and 2010, respectively. KMP considers its overall multi-employer pension plan liability exposure to be minimal in relation to the value of its total consolidated assets and net income.

## El Paso Pipeline Partners, L.P.

## Other Postretirement Benefit Plans

Two of EPB’s subsidiaries, CIG and SNG, provide postretirement benefits other than pensions for certain retired employees. The costs for these plans are prefunded to the extent these costs are recoverable through natural gas pipeline transportation rates. EPB’s combined net periodic benefit costs for the CIG and SNG other postretirement benefit plans for 2012 was a credit (increase to income) of $1 million, recognized ratably over the seven months we included CIG and SNG in our consolidated results. As of December 31, 2012, we estimate EPB’s overall net periodic other postretirement benefit cost for these plans for 2013 will be a credit of approximately $3 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. Furthermore, EPB expects to make contributions of approximately $1 million to the SNG other postretirement benefit plan in 2013.

As of December 31, 2012, the CIG and SNG other postretirement benefit plans were overfunded by a combined $15 million. EPB considers its overall other postretirement benefit liability exposure and the fair value of its other postretirement plan assets to be minimal in relation to the value of its total consolidated assets and net income.



## 10. Stockholders' Equity

## Kinder Morgan, Inc. – Equity Interests

Common Equity

The following tables set forth the changes in our outstanding shares during 2012 and during 2011 since becoming public (see “—Initial Public Offering” following):

<table><tr><td rowspan="2"></td><td colspan="4">Shares Outstanding</td></tr><tr><td>Class P</td><td>Class A</td><td>Class B</td><td>Class C</td></tr><tr><td>Balance at December 31, 2011</td><td>170,921,140</td><td>535,972,387</td><td>94,132,596</td><td>2,318,258</td></tr><tr><td>Shares issued for EP acquisition (see note 3)</td><td>330,154,610</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Shares issued with conversions of EP Trust I Preferred Securities</td><td>562,521</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Shares converted</td><td>535,972,387</td><td>(535,972,387)</td><td>(94,132,596)</td><td>(2,318,258)</td></tr><tr><td>Shares canceled</td><td>(2,049,615)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Restricted shares vested</td><td>107,553</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Balance at December 31, 2012</td><td>1,035,668,596</td><td>—</td><td>—</td><td>—</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Shares Outstanding</td></tr><tr><td>Class P</td><td>Class A</td><td>Class B</td><td>Class C</td></tr><tr><td>Balance at February 16, 2011</td><td>109,786,590</td><td>597,213,410</td><td>100,000,000</td><td>2,462,927</td></tr><tr><td>Shares converted</td><td>61,241,023</td><td>(61,241,023)</td><td>(5,867,404)</td><td>(144,669)</td></tr><tr><td>Shares canceled</td><td>(108,043)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Restricted shares vested</td><td>1,570</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Balance at December 31, 2011</td><td>170,921,140</td><td>535,972,387</td><td>94,132,596</td><td>2,318,258</td></tr></table>

For accounting purposes, both our Class P and our Class A shares are considered common stock, and our Class B and Class C shares are considered participating securities.

## Initial Public Offering

On February 10, 2011, we converted from a Delaware limited liability company named Kinder Morgan Holdco LLC to a Delaware corporation named Kinder Morgan, Inc. and our outstanding units were converted into classes of our capital stock. These transactions are referred to herein as the “Conversion Transaction.” On February 16, 2011, we completed the initial public offering of our Class P common stock, which is sometimes referred to herein as our “common stock.” All of the common stock that was sold in the offering was sold by our existing investors consisting of funds advised by or affiliated with Goldman Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC, referred to herein as the “Sponsor Investors.” No members of management sold shares in the offering, and we did not receive any proceeds from the offering.

Upon the completion of our initial public offering of Class P common stock we were owned by the public, and by individuals and entities that were the owners of Kinder Morgan Holdco LLC, which are referred to collectively in this report as the “Investors.” The Investors were Richard D. Kinder, our Chairman and Chief Executive Officer; the Sponsor Investors; Fayez Sarofim, one of our directors, and investment entities affiliated with him, and an investment entity affiliated with Michael C. Morgan, another of our directors, and William V. Morgan, one of our founders, whom we refer to collectively as the “Original Stockholders”; and a number of other members of our management, who are referred to collectively as “Other Management.”

The Investors owned all of our outstanding Class A shares, Class B shares and Class C shares, which are sometimes referred to in this report as the “investor retained stock.” Our Class A shares represented the total capital contributed by the Investors (and a notional amount of capital allocated to the contribution of the holders of the Class C shares) at the time of the Going



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Private Transaction. The Class B shares and Class C shares represented incentive compensation that were held by members of our management, including Mr. Kinder only in the case of the Class B shares.

During the year ended December 31, 2012, certain of the Sponsor Investors (the Selling Stockholders) completed underwritten public offerings (the Offerings) of an aggregate of 198,996,921 shares of our Class P common stock (including 8,700,000 shares that were the subject of an underwriters' option to purchase additional shares). Neither we nor our management sold any shares of common stock in the Offerings, and we did not receive any of the proceeds from the Offerings of shares by the Selling Stockholders. As a result of these offerings, the Sponsor Investors advised by or affiliated with Goldman Sachs & Co., The Carlyle Group, and Riverstone Holdings LLC no longer own any of our shares, and representatives of these Sponsor Investors are no longer on our board.

On December 26, 2012, the remaining series of the Class A, Class B and Class C shares held by the Investors automatically converted into shares of Class P common stock upon the election of the holders of at least two-thirds of the shares of each such series of Class A common stock and the holders of at least two-thirds of the shares of each such series of Class B common stock. Subsequent to these conversions, all our Class A, Class B and Class C shares were fully converted and as a result, only our Class P common stock was outstanding as of December 31, 2012. Additionally, as Class A, Class B and Class C shares converted, certain holders of Class P shares were paid out in cash and their Class P shares were immediately canceled. During the years ended December 31, 2012 and 2011, approximately 2 million and less than 1 million, respectively, Class P shares were canceled resulting in payments totaling approximately $71 million and $2 million, respectively, to the holders of those shares.

## Dividends

Holders of our common stock share equally in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011(a)</td><td></td></tr><tr><td>Per common share cash dividend declared</td><td>$ 1.40</td><td>$ 1.05</td><td></td></tr><tr><td>Per common share cash dividend paid(b)</td><td>$ 1.34</td><td>$ 0.74</td><td></td></tr></table>

(a) Represent dividends subsequent to the initial public offering.

(b) Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year.

On February 11, 2011, our board of directors declared and paid a dividend to our then existing investors of $246 million with respect to the period for which we were not public. This consisted of $205 million for the fourth quarter of 2010 and $105 million for the first 46 days of 2011, representing the portion of the first quarter of 2011 that we were not public, less a one-time adjustment of $64 million in available earnings and profits reserved for the after tax cost of special cash bonuses (and premium pay) in an aggregate amount of approximately $100 million that was paid in May of 2011 to certain of our non-senior management employees. No holders of our Class B shares or Class C shares received such bonuses. During the year ended December 31, 2010, we paid distributions on our Class A units totaling $700 million.

## Dividends Subsequent to December 31, 2012

On January 16, 2013, our board of directors declared a cash dividend of $0.37 per share for the quarterly period ended December 31, 2012. This dividend was paid on February 15, 2013 to shareholders of record as of January 31, 2013. Since this dividend was declared after the end of the quarter, no amount is shown in our accompanying December 31, 2012 consolidated balance sheet as a dividend payable.

## Warrants

As part of the consideration paid for the EP acquisition, we issued 505 million warrants that were valued at approximately $863 million as of May 24, 2012 (see Note 3 “Acquisitions and Divestiture—KMI Acquisition of El Paso Corporation”). Each warrant entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017. On May 23, 2012, we announced that our board of directors had approved a warrant repurchase program, authorizing us to repurchase in the aggregate up to $250 million of the warrants. Subsequent to the EP acquisition and through December 31, 2012, we paid approximately $157 million to repurchase approximately 66



## Item 15. Exhibits, Financial Statement Schedules. (continued)

million warrants that were then canceled. Additionally we issued less than 1 million in warrants in conjunction with conversion of the EP Trust I Preferred Securities (see Note 8, "Debt").

## Noncontrolling Interests

Noncontrolling interests represent the economic interests in subsidiaries that we do not own. The caption “Noncontrolling interests” in our 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>2012</td><td>2011</td></tr><tr><td>KMP</td><td>$ 3,270</td><td>$ 3,239</td></tr><tr><td>EPB</td><td>4,111</td><td>—</td></tr><tr><td>KMR</td><td>2,716</td><td>1,988</td></tr><tr><td>Other</td><td>137</td><td>20</td></tr><tr><td></td><td>$ 10,234</td><td>$ 5,247</td></tr></table>

At December 31, 2012, we owned, directly, and indirectly in the form of i- units corresponding to the number of shares of KMR we owned, approximately 41 million limited partner units of KMP. These units, which consist of 21 million common units, 5 million Class B units and 15 million i-units, represent approximately 11.1% of the total outstanding limited partner interests of KMP. In addition, we indirectly own all the common equity of the general partner of KMP, which holds an effective 2% interest in KMP and its operating partnerships. Together, at December 31, 2012, our limited partner and general partner interests represented approximately 12.8% of KMP's total equity interests and represented an approximate 50% economic interest in KMP. This difference results from the existence of incentive distribution rights (IDRs) held by Kinder Morgan G.P., Inc., the general partner of KMP.

As part of the EP acquisition (see Note 3, “Acquisitions and Divestitures—KMI Acquisition of El Paso Corporation”), we acquired $3,797 million of noncontrolling interests related to EPB. As of December 31, 2012, we owned approximately 90 million limited partner units of EPB, representing approximately 41% of the total equity interests of EPB. In addition, we are the sole owner of the general partner of EPB, which holds an effective 2% interest in EPB, including all of EPB’s IDRs.

At December 31, 2012, we owned approximately 15 million KMR shares representing approximately 13.0% of KMR’s outstanding shares.

## Contributions

Contributions from our noncontrolling interests consist primarily of KMP and EPB’s issuance of its common units that we did not purchase or obtain. The table below shows significant issuances of common units, the net proceeds from the issuances and the ultimate use of the proceeds during the years ended December 31, 2012 and 2011 for KMP and KMR, and for EPB, from the May 2012 acquisition date through December 31, 2012 (dollars in millions and shares in thousands).



## Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td>Issuance date</td><td>Common units/shares (in thousands)</td><td>Net proceeds (in millions)</td><td>Use of proceeds</td></tr><tr><td colspan="4">KMP</td></tr><tr><td colspan="4">Issued under UBS Equity Distribution Agreement (a)</td></tr><tr><td>2012</td><td>6,933</td><td>$ 560</td><td>Reduced borrowings under KMP&#x27;s commercial paper program</td></tr><tr><td>2011</td><td>5,765</td><td>$ 421</td><td>Reduced borrowings under KMP&#x27;s commercial paper program</td></tr><tr><td colspan="4">Other issuances</td></tr><tr><td>June 2012</td><td>3,792</td><td>$ — (b)</td><td>Issued as KMP&#x27;s purchase price for the 50% equity ownership interest in El Paso Midstream Investment Company, LLC it acquired from KKR</td></tr><tr><td>December 2012(c)</td><td>4,485</td><td>$ 349</td><td>Reduced borrowings under KMP&#x27;s commercial paper program</td></tr><tr><td>June 2011(c)</td><td>7,705</td><td>$ 534</td><td>Reduced borrowings under KMP&#x27;s commercial paper program</td></tr><tr><td colspan="4">EPB</td></tr><tr><td>September 2012(c)</td><td>8,165</td><td>$ 278</td><td>Repayment of CPG debt, certain EPB short-term debt and general partnership purposes</td></tr><tr><td colspan="4">KMR</td></tr><tr><td>September 2012</td><td>10,120</td><td>$ 727</td><td>Purchased additional KMP i-units; KMP then used proceeds for a portion of the purchase price of the drop-down transaction</td></tr></table>

(a) On February 27, 2012, KMP entered into a third amended and restated equity distribution agreement with UBS Securities LLC (UBS) which increased the aggregate offering price of its common units to up to $1.9 billion (up from $1.2 billion). Sales of KMP's common units pursuant to its equity distribution agreement are made by means of ordinary brokers' transactions on the New York Stock Exchange at market prices, in block transactions or as otherwise agreed between KMP and UBS. Under the terms of this agreement, KMP also may sell its 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 KMP and UBS.

KMP’s equity distribution agreement provides it the right, but not the obligation, to sell common units in the future, at prices it deems appropriate. KMP 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 KMP and UBS agree. UBS will then use its reasonable efforts to sell, as KMP’s sales agent and on KMP’s behalf, all of the designated common units. KMP may instruct UBS not to sell common units if the sales cannot be effected at or above the price designated by KMP in any such instruction. Either KMP or UBS may suspend the offering of common units pursuant to the agreement by notifying the other party.

(c) Includes the underwriters' exercise of the overallotment option.

(b) See Note 3 "Acquisitions and Divestitures—KMP Investment in El Paso Midstream Investment Company, LLC."

(c) Includes the underwriters' exercise of the overallotment option.

The above equity issuances by KMP, EPB and KMR during the years ended December 31, 2012 and 2011 had the associated effects of increasing our (i) noncontrolling interests by $2,112 million and $935 million, respectively; (ii) accumulated deferred income taxes by $38 million and $16 million, respectively; and (iii) additional paid-in capital by $64 million and $28 million, respectively.

KMP Contributions Subsequent to December 31, 2012

On February 26, 2013, KMP issued in a public offering, 4,600,000 of its common units at a price of $86.35 per unit, less commissions and underwriting expenses and received net proceeds of $385 million for the issuance of these units.

## Distributions

Distributions to our noncontrolling interests consist primarily of distributions by KMP and EPB to its respective common unit holders. The following table provides information about distributions from our noncontrolling interests (in millions except per unit and i-unit distribution amounts):



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>KMP</td><td></td><td></td><td></td><td></td></tr><tr><td>Per unit cash distribution declared</td><td>$     4.98</td><td>$     4.61</td><td>$     4.40</td><td></td></tr><tr><td>Per unit cash distribution paid(a)</td><td>$     4.85</td><td>$     4.58</td><td>$     4.32</td><td></td></tr><tr><td>Cash distributions paid to the public</td><td>$     1,081</td><td>$     955</td><td>$     848</td><td></td></tr><tr><td>EPB(b)</td><td></td><td></td><td></td><td></td></tr><tr><td>Per unit cash distribution declared</td><td>$     1.74</td><td>n/a</td><td>n/a</td><td></td></tr><tr><td>Per unit cash distribution paid(a)</td><td>$     1.13</td><td>n/a</td><td>n/a</td><td></td></tr><tr><td>Cash distributions paid to the public</td><td>$     137</td><td>n/a</td><td>n/a</td><td></td></tr><tr><td>KMR(c)</td><td></td><td></td><td></td><td></td></tr><tr><td>Share distributions paid</td><td>6,488,946</td><td>6,601,402</td><td>6,369,724</td><td></td></tr></table>

(a) Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.

(b) Represents distribution information since the May 2012 EP acquisition.

(c) KMR’s distributions are paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. On February 14, 2013, KMR made a share distribution of 0.015676 shares per outstanding share (1,804,595 total shares) to shareholders of record as of January 31, 2013, based on the $1.29 per common unit distribution declared by KMP.

## KMP Distributions

KMP’s 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. Available Cash consists generally of all of KMP’s 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 its noncontrolling interests.

KMR, 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 KMP, 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 KMP's business, which might include reserves for matters such as future operating expenses, debt service, sustaining capital expenditures and rate refunds, and for distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines KMP's 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 KMP’s 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 common units, Class B units and i-units relative to the distributions retained by Kinder Morgan G.P., Inc. as KMP’s general partner.

Cash from Operations. Cash from operations generally refers to KMP’s 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 distributions that are funded from borrowings, sales of debt and equity securities and sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets and assets disposed of in the ordinary course of business.

Rule for Characterizing Distributions. Generally, all available cash distributed by KMP 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 KMP commenced operations through the end of the calendar quarter prior to that distribution. Any distribution of available cash which, when added to the sum of all prior distributions, is in excess of the cumulative amount of cash from operations, will be considered a distribution of cash from interim capital transactions until the initial common unit price is fully recovered as described below under “—Allocation of Distributions from Interim Capital Transactions.” For purposes of calculating the sum of all distributions of available cash, the total equivalent cash amount of all



## Item 15. Exhibits, Financial Statement Schedules. (continued)

distributions of i-units to KMR, as the holder of all i-units, will be treated as distributions of available cash, even though the distributions to KMR are made in additional i-units rather than cash. KMP retains this cash and uses it in its business. To date, all of KMP’s available cash distributions, other than a $177 million distribution of cash from interim capital transactions for the second quarter of 2010 (paid in the third quarter of 2010), have been treated as distributions of cash from operations.

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

<table><tr><td rowspan="2"></td><td colspan="3">Marginal percentage interest in distribution</td></tr><tr><td colspan="2">Total quarterly distribution per unit target amount</td><td>Unitholders</td></tr><tr><td>First target distribution</td><td>$0.15125</td><td>98%</td><td>2%</td></tr><tr><td>Second target distribution</td><td>above $0.15125 up to $0.17875</td><td>85%</td><td>15%</td></tr><tr><td>Third target distribution</td><td>above $0.17875 up to $0.23375</td><td>75%</td><td>25%</td></tr><tr><td>Thereafter</td><td>above $0.23375</td><td>50%</td><td>50%</td></tr></table>

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

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

• 2% to Kinder Morgan G.P., Inc. as KMP’s general partner, until KMP has distributed cash from this source in respect of a common unit outstanding since KMP’s original public offering in an aggregate amount per unit equal to the initial common unit price of $5.75, as adjusted for splits.

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

Beginning with KMP’s distribution payments for the quarterly period ended June 30, 2010, and ending with its distribution payments for the quarterly period ended March 31, 2013, Kinder Morgan G.P., Inc., as KMP’s general partner, has agreed not to take certain incentive distributions related to KMP’s acquisition of KinderHawk Field Services LLC. Accordingly, distributions paid by KMP to Kinder Morgan G.P., Inc. during 2012, 2011 and 2010 were reduced by waived incentive amounts equal to $27 million, $28 million and $11 million, respectively. For more information about this acquisition, see Note 3 “Acquisitions and Divestitures—Additional KMP Acquisitions—KinderHawk Field Services LLC (1 of 2)” and “—KinderHawk Field Services LLC and EagleHawk Field Services LLC (2 of 2).”

## KMP Distributions Subsequent to December 31, 2012

On January 16, 2013, KMP declared a cash distribution of $1.29 per common unit for the quarterly period ended December 31, 2012. This distribution was paid on February 14, 2013 to unitholders of record as of January 31, 2013, of which $299 million was paid to the public holders (represented in noncontrolling interests). Related to this February 14, 2013 distribution, Kinder Morgan G.P., Inc., waived an incentive distribution amount equal to $7 million to support KMP’s July 2011 KinderHawk acquisition.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## EPB Distributions

Incentive Distribution Rights. El Paso Pipeline GP Company, L.L.C., as the general partner of EPB and the holder of EPB's IDRs, has the right under EPB's partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and (upon satisfaction of certain conditions) to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to El Paso Pipeline GP Company, L.L.C., as EPB's general partner, would be set. In connection with this election, El Paso Pipeline GP Company, L.L.C., as EPB's general partner, will be entitled to receive a number of newly issued Class B common units and general partner units based on a predetermined formula. Although the conditions have been met to entitle El Paso Pipeline GP Company, L.L.C. to elect to reset the minimum quarterly distribution amount and the target distribution levels, no such election has been made.

El Paso Pipeline GP Company, L.L.C. currently holds all of EPB’s IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in EPB’s partnership agreement.

Income Allocation and Declared Distributions. For the purposes of maintaining partner capital accounts, EPB’s partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to El Paso Pipeline GP Company, L.L.C., as the holder of EPB’s IDRs. Incentive distributions are generally defined as all cash distributions paid to El Paso Pipeline GP Company, L.L.C., as EPB’s general partner, that are in excess of 2% of the aggregate value of cash distributions made to all partners.

EPB’s partnership agreement requires that it distribute all of its available cash from operating surplus each quarter. EPB determines the allocation of incentive distributions to El Paso Pipeline GP Company, L.L.C., as EPB’s general partner, by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of EPB’s partnership agreement summarized in the table below. The percentage interests set forth below for El Paso Pipeline GP Company, L.L.C., as EPB’s general partner, include its 2% general partner interest and assume El Paso Pipeline GP Company, L.L.C. has contributed any additional capital necessary to maintain its 2% general partner interest and has not transferred its incentive distribution rights.

Marginal percentage interest in distributions

<table><tr><td rowspan="2"></td><td rowspan="2">Total quarterly distribution per unit target amount</td><td colspan="2">Marginal percentage interest in distributions</td></tr><tr><td>Unitholders</td><td>General partner</td></tr><tr><td>Minimum quarterly distribution</td><td>$0.2875</td><td>98%</td><td>2%</td></tr><tr><td>First target distribution</td><td>above $0.2875 up to $0.33063</td><td>98%</td><td>2%</td></tr><tr><td>Second target distribution</td><td>above $0.33063 up to $0.35938</td><td>85%</td><td>15%</td></tr><tr><td>Third target distribution</td><td>above $0.35938 up to $0.43125</td><td>75%</td><td>25%</td></tr><tr><td>Thereafter</td><td>above $0.43125</td><td>50%</td><td>50%</td></tr></table>

Distributions Subsequent to December 31, 2012

On January 16, 2013, EPB declared a cash distribution of $0.61 per common unit for the quarterly period ended December 31, 2012. This distribution was paid on February 14, 2013 to unitholders of record as of January 31, 2013, of which $77 million was paid to the public holders (represented in noncontrolling interests).

## 11. Related Party Transactions

## Kinder Morgan, Inc. Common Stock

On November 22, 2011, Richard D. Kinder, our Chief Executive Officer and Chairman of our Board of Directors, entered into an agreement to purchase with his personal funds an aggregate of 19,723,865 of Kinder Morgan, Inc. Class P shares for an aggregate net sale amount of approximately $500 million ($25.35 per share) from several Sponsor Investors (Sellers) pursuant to the terms of a Stock Purchase Agreement, dated as of November 22, 2011, by and among Richard D. Kinder and certain Sponsor Investors (Share Purchase Transaction). In connection with the Share Purchase Transaction, the Sellers converted



## Item 15. Exhibits, Financial Statement Schedules. (continued)

19,723,865 of Kinder Morgan, Inc. Class A shares that they owned into an equal number of Class P shares. This Share Purchase Transaction was completed on December 9, 2011.

## Asset Sales

Mr. C. Berdon Lawrence, a non-management director on the boards of Kinder Morgan G.P., Inc. and KMR until July 20, 2011, is also Chairman Emeritus of the Board of Kirby Corporation. On February 9, 2011, KMP sold a marine vessel to Kirby Corporation’s subsidiary Kirby Inland Marine, L.P., and additionally, KMP and Kirby Inland Marine L.P. formed a joint venture named Greens Bayou Fleeting, LLC. Pursuant to the joint venture agreement, KMP sold the ownership interest in the boat fleeting business KMP acquired from Megafeet Towing Co., Inc. in April 2009 to the joint venture for $4 million in cash and a 49% ownership interest in the joint venture. Kirby then made cash contributions to the joint venture in exchange for the remaining 51% ownership interest. In the first quarter of 2011, after final reconciliation and measurement of all of the net assets sold, KMP recognized a combined $2 million increase in income from the sale of these net assets, and additionally, the sale of the ownership interest resulted in an $11 million non-cash reduction in KMP’s goodwill (see Note 7).

For services in the ordinary course of Kirby Corporation’s and the Terminalis-KMP segment’s businesses, Kirby Corporation received payments from our subsidiaries totaling $38,729 in 2011 and $39,828 in 2010. In turn, Kirby made payments of $44,615 to our subsidiaries in 2011.

## Affiliated Balances

The following table summarizes our balance sheet affiliate balances (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Balance sheet location</td><td></td><td></td><td></td></tr><tr><td>Accounts, notes, and interest receivable, net</td><td>$ 36</td><td>$ 34</td><td></td></tr><tr><td>Assets held for sale</td><td>114</td><td>—</td><td></td></tr><tr><td>Other current assets</td><td>3</td><td>11</td><td></td></tr><tr><td>Notes receivable</td><td>48</td><td>161</td><td></td></tr><tr><td></td><td>$ 201</td><td>$ 206</td><td></td></tr><tr><td>Accounts payable</td><td>$ 11</td><td>$ 1</td><td></td></tr></table>

## Notes Receivable

## Plantation Pipe Line Company

KMP and ExxonMobil have a term loan agreement covering a note receivable due from Plantation Pipe Line Company (Plantation). KMP owns a 51.17% equity interest in Plantation and KMP’s proportionate share of the outstanding principal amount of the note receivable was $49 million as of December 31, 2012 and $50 million as of December 31, 2011. The note bears interest at the rate of 4.25% per annum and provides for semiannual payments of principal and interest on December 31 and June 30 each year, with a final principal payment of $45 million (for KMP’s portion of the note) due on July 20, 2016. We included $1 million of the note receivable balance within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheets as of both December 31, 2012 and December 31, 2011, and we included the remaining outstanding balance within “Notes receivable.”

## Express US Holdings LP

KMP owns a 33 1/3% equity ownership interest in the Express pipeline system. KMP also holds a long-term investment in a C$114 million debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system. The debenture (i) is denominated in Canadian dollars; (ii) is due in full on January 9, 2023; (iii) bears interest at the rate of 12.0% per annum; and (iv) provides for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year. As of December 31, 2012 and December 31, 2011, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $114 million and $112 million, respectively. We included the December 31, 2012 note balance within “Assets held for sale” (because KMP had entered into a definitive agreement to sell its debt investment in



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Express as discussed in Note 3 “Acquisitions and Divestitures--Divestitures--Express Pipeline System”). We included the December 31, 2011 note balance within “Notes receivable” on our accompanying consolidated balance sheets.

## Southern Gulf LNG Company, LLC

In conjunction with the acquisition of EP, KMI acquired a long-term note receivable due from Southern Gulf LNG Company, LLC a 50% equity investee with a remaining principal amount of $85 million. Subsequent to the EP acquisition and through the end of 2012, we received payments on this note totaling $75 million. The outstanding principle balance as of December 31, 2012 of $10 million bears interest at 12% per annum, requires quarterly payments of principal and interest, and since we expect the note to be paid in full March 2013, we have included this amount within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet.

## 12. Commitments and Contingent Liabilities

## Leases

The table below depicts future gross minimum rental commitments under our operating leases as of December 31, 2012 (in millions):

<table><tr><td>Year</td><td>Commitment</td></tr><tr><td>2013</td><td>$ 69</td></tr><tr><td>2014</td><td>59</td></tr><tr><td>2015</td><td>50</td></tr><tr><td>2016</td><td>42</td></tr><tr><td>2017</td><td>38</td></tr><tr><td>Thereafter</td><td>119</td></tr><tr><td>Total minimum payments</td><td>$ 377</td></tr></table>

The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to forty-one years. Total lease and rental expenses were $94 million, $146 million and $69 million for the years ended December 31, 2012, 2011 and 2010, respectively. The increase in our lease and rental expenses in 2011 compared to 2012 and 2010 was driven by a $70 million increase in expense associated with adjustments to KMP's Pacific operations' rights-of-way liabilities. For more information about this expense, see Note 16 "Litigation, Environmental and Other Contingencies—Commercial Litigation Matters—Union Pacific Railroad Company Easements." The amount of capital leases included within "Property, Plant and Equipment, net" in our accompanying consolidated balance sheets as of December 31, 2012 and 2011 are not material to our consolidated balance sheets.

## Contingent Debt

KMP’s contingent debt disclosures pertain to certain types of guarantees or indemnifications KMP has made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring KMP’s performance under such guarantee is remote. As of December 31, 2012, KMP’s contingent debt obligations, as well as KMP’s obligations with respect to related letters of credit, totaled $86 million. This amount is primarily related to the debt obligations of KMP’s 50%-owned investee, Cortez Pipeline Company (it is severally liable for its percentage ownership share (50%) of the Cortez Pipeline Company debt).

## Contingent Lease Liabilities

KMP has agreed to guarantee certain lease payments from 2013 through 2035 made by us to EPC Building, LLC, a wholly owned subsidiary, related to Kinder Morgan’s principal executive offices located at 1001 Louisiana Street in Houston, Texas. KMP would be required to perform under this guarantee only if we were unable to perform. During the term of this lease, the payments KMP guarantees increase from $26 million in 2013 to $38 million in 2035.

## KMI Guarantee of KMP and EPB Debt

In conjunction with KMP’s acquisition of certain natural gas pipelines from us, we agreed to indemnify KMP with respect to approximately $4.3 billion of its debt. This includes $3.6 billion associated with KMP’s August 2012 purchase of Tennessee



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Gas Pipeline L.L.C. and 50% of El Paso Natural Gas Company, L.L.C. in conjunction with our EP acquisition, we have agreed to indemnify EPB with respect to $470 million of its debt. We would be obligated to perform under these indemnities only if KMP’s or EPB’s assets, as applicable, were unable to satisfy its obligations. (For more information on Guarantees of Securities of Subsidiaries, see Note 20).

## Guarantees and Indemnifications

We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.

Our potential exposure under guarantee and indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. Those arrangements with a specified dollar amount have a maximum stated value of approximately $730 million, which primarily represents indemnification agreements that we assumed in the EP acquisition associated with EP's prior discontinued and foreign operations. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

For additional information regarding our, KMP’s and EPB’s debt facilities see Note 8 “Debt.”

## 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.

As part of the EP acquisition (see Note 3 “Acquisitions and Divestiture—KMI Acquisition of El Paso Corporation”), we acquired long-term natural gas and power forward and swap contracts. Prior to the acquisition, EP had entered into offsetting positions that eliminated the price risks associated with its power contracts and substantially offset the fixed price exposure related to its natural gas supply contracts. None of these derivatives are designated as accounting hedges.

## Energy Commodity Price Risk Management

As of December 31, 2012, KMP and KMI had entered into the following outstanding commodity forward contracts to hedge its forecasted energy commodity purchases and sales:

<table><tr><td></td><td>Net open position long/(short)</td></tr><tr><td>Derivatives designated as hedging contracts</td><td></td></tr><tr><td>Crude oil</td><td>(21.7) million barrels</td></tr><tr><td>Natural gas fixed price</td><td>(18.5) billion cubic feet</td></tr><tr><td>Natural gas basis</td><td>(17.9) billion cubic feet</td></tr><tr><td>Derivatives not designated as hedging contracts</td><td></td></tr><tr><td>Natural gas fixed price</td><td>1.7 billion cubic feet</td></tr><tr><td>Natural gas basis</td><td>5.0 billion cubic feet</td></tr></table>

As of December 31, 2012, 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 2016.

## Interest Rate Risk Management

As of December 31, 2012, KMI and KMP each had a combined notional principal amount of $725 million and $5,525 million, respectively, of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated



## Item 15. Exhibits, Financial Statement Schedules. (continued)

with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2012, 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 March 15, 2035.

As of December 31, 2012, EPB had no interest rate swap agreements outstanding. In September 2012, EPB terminated its existing variable-to-fixed interest rate swap agreements having a notional principal amount of $137 million and paid $14 million for the early termination of these swap agreements.

As of December 31, 2011, KMI and KMP each had a combined notional principal amount of $725 million and $5,325 million, respectively, of fixed-to-variable interest rate swap agreements. In March 2012, KMP entered into four additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million, effectively converting a portion of the interest expense associated with KMP's 3.95% senior notes due September 1, 2022 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread; and (ii) two separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $200 million and converting a portion of the interest expense associated with KMP's 7.125% senior notes terminated upon the maturity of the associated notes. In addition, (i) in June 2012 KMP terminated an existing fixed-to-variable interest rate swap agreement having a notional amount of $100 million, and received proceeds of $53 million from the early termination of this swap agreement; (ii) in August 2012, KMP entered into an additional fixed-to-variable interest rate swap agreement having a notional principal amount of $100 million, effectively converting a portion of the interest expense associated with its 3.45% senior notes due February 15, 2023 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread; and (iii) in September 2012, a fixed-to-variable interest rate swap agreement having a notional principal amount of $100 million and effectively converting a portion of the interest expense associated with KMP's 5.85% senior notes terminated upon the maturity of the associated notes.

## 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” in the respective sections of our accompanying consolidated balance sheets. The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of December 31, 2012 and 2011 (in millions):



Fair Value of Derivative Contracts

<table><tr><td rowspan="4"></td><td rowspan="4">Balance sheet location</td><td colspan="3">Asset derivatives</td><td colspan="3">Liability derivatives</td></tr><tr><td colspan="3">December 31,</td><td colspan="3">December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td><td>2012</td><td>2011</td><td></td></tr><tr><td colspan="3">Fair value</td><td colspan="3">Fair value</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 rowspan="2">Natural gas and crude derivative contracts</td><td>Current-Fair value of derivative contracts</td><td>$</td><td>42</td><td>$</td><td>66</td><td>$</td><td>(18)</td></tr><tr><td>Non-current-Fair value of derivative contracts</td><td></td><td>40</td><td></td><td>39</td><td></td><td>(11)</td></tr><tr><td>Subtotal</td><td></td><td></td><td>82</td><td></td><td>105</td><td></td><td>(29)</td></tr><tr><td rowspan="2">Interest rate swap agreements - Fair value hedges</td><td>Current-Fair value of derivative contracts</td><td></td><td>9</td><td></td><td>3</td><td></td><td>—</td></tr><tr><td>Non-current-Fair value of derivative contracts</td><td></td><td>656</td><td></td><td>659</td><td></td><td>(1)</td></tr><tr><td>Subtotal</td><td></td><td></td><td>665</td><td></td><td>662</td><td></td><td>(1)</td></tr><tr><td>Total</td><td></td><td></td><td>747</td><td></td><td>767</td><td></td><td>(30)</td></tr><tr><td>Derivatives not designated as hedging contracts</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td rowspan="2">Natural gas derivative contracts</td><td>Current-Fair value of derivative contracts</td><td>$</td><td>4</td><td>$</td><td>3</td><td>$</td><td>(3)</td></tr><tr><td>Non-current-Fair value of derivative contracts</td><td></td><td>—</td><td></td><td>—</td><td></td><td>(1)</td></tr><tr><td>Subtotal</td><td></td><td></td><td>4</td><td></td><td>3</td><td></td><td>(4)</td></tr><tr><td rowspan="2">Power derivative contracts</td><td>Current-Fair value of derivative contracts</td><td></td><td>8</td><td></td><td>—</td><td></td><td>(59)</td></tr><tr><td>Non-current-Fair value of derivative contracts</td><td></td><td>13</td><td></td><td>—</td><td></td><td>(120)</td></tr><tr><td>Subtotal</td><td></td><td></td><td>21</td><td></td><td>—</td><td></td><td>(179)</td></tr><tr><td>Total</td><td></td><td></td><td>25</td><td></td><td>3</td><td></td><td>(183)</td></tr><tr><td>Total derivatives</td><td></td><td></td><td>$</td><td>772</td><td>$</td><td>770</td><td>$</td></tr></table>

The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. Our “Debt fair value adjustments” also include amounts associated with the offsetting entry for hedged debt, all unamortized debt discount/premium amounts, purchase accounting on our debt balances, and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. These fair value adjustments to our debt balances included (i) increases of $664 million and $662 million at December 31, 2012 and 2011, respectively, associated with the offsetting entry for hedged debt; (ii) decreases of $33 million and $24 million at December 31, 2012 and 2011, respectively, associated with unamortized debt discount amounts; (iii) an increase of $1,470 million and a decrease of $32 million at December 31, 2012 and 2011 respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; and (iv) increases of $490 million and $489 million at December 31, 2012 and 2011, respectively, associated with unamortized premium from the termination of interest rate swap agreements. As of December 31, 2012, the weighted-average amortization period of the unamortized premium from the termination of the interest rate swaps was approximately 18 years.

## Effect of Derivative Contracts on the Income Statement

The following three tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the years ended December 31, 2012 and 2011 (in millions):



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2">Derivatives not designated as hedging contracts</td><td rowspan="2">Location of gain/(loss)recognized in income on derivatives</td><td colspan="2">Amount of gain/(loss) recognized in income on derivatives</td></tr><tr><td colspan="2">Year Ended December 31,</td></tr><tr><td></td><td></td><td>2012</td><td>2011</td></tr><tr><td>Natural gas derivative contracts</td><td>Natural gas sales</td><td>$ 1</td><td>$ —</td></tr><tr><td>Power derivative contracts</td><td>Product sales and other</td><td>(4)</td><td>—</td></tr><tr><td>Total</td><td></td><td>$ (3)</td><td>$ —</td></tr></table>

## Credit Risks

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

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

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

The maximum potential exposure to credit losses on our derivative contracts as of December 31, 2012 was (in millions):

<table><tr><td></td><td>Asset position</td></tr><tr><td>Interest rate swap agreements</td><td>$ 665</td></tr><tr><td>Energy commodity derivative contracts</td><td>107</td></tr><tr><td>Gross exposure</td><td>772</td></tr><tr><td>Netting agreement impact</td><td>(38)</td></tr><tr><td>Cash collateral held</td><td>—</td></tr><tr><td>Net exposure</td><td>$ 734</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, 2012 and 2011, KMP had no outstanding letters of credit supporting its hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil. As of December 31, 2012, KMP had cash margin deposits associated with its energy commodity contract positions and over-the-counter swap partners totaling $5 million, and we reported this amount within “Other current assets” in our accompanying consolidated balance sheet. As of December 31, 2011, KMP’s counterparties associated with its energy commodity contract positions and over-the-counter swap agreements had margin deposits with KMP totaling $10 million and we reported this amount within “Accrued other current liabilities” in our accompanying consolidated balance sheet. As of December 31, 2012, KMI had $300 million of outstanding letters of credit supporting its commodity price risks associated with the sale of natural gas and power. As of December 31, 2012 and 2011, KMI had no margin deposits outstanding with counterparties associated with its energy commodity contract positions and over-the-counter swap agreements.

KMP and KMI also have agreements with certain counterparties to their derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in their credit rating. As of December 31, 2012, we estimate that if KMP’s



## Item 15. Exhibits, Financial Statement Schedules. (continued)

credit rating was downgraded one notch, it would be required to post no additional collateral to its counterparties. If KMP was downgraded two notches (that is below investment grade), KMP would be required to post $7 million of incremental collateral. As of December 31, 2012, we estimate that if KMI’s credit rating was downgraded one or two notches, KMI would be required to post no additional collateral to its counterparties.

## 14. Fair Value

The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. 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 and (ii) interest rate swap agreements as of December 31, 2012 and 2011, based on the three levels established by the Codification. The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” in the respective sections of our accompanying consolidated balance sheets. The fair value measurements in the tables below do not include cash margin deposits made by us or our counterparties, which are reported within “Other current assets” and “Accrued other current liabilities,” respectively, in our accompanying consolidated balance sheets (in millions).

Asset fair value measurements using

<table><tr><td></td><td>Total</td><td>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, 2012</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(a)</td><td>$ 107</td><td>$ 3</td><td>$ 76</td><td>$ 28</td></tr><tr><td>Interest rate swap agreements</td><td>$ 665</td><td>$ —</td><td>$ 665</td><td>$ —</td></tr><tr><td>As of December 31, 2011</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(a)</td><td>$ 108</td><td>$ 34</td><td>$ 47</td><td>$ 27</td></tr><tr><td>Interest rate swap agreements</td><td>$ 662</td><td>$ —</td><td>$ 662</td><td>$ —</td></tr></table>



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="5">Liability fair value measurements using</td></tr><tr><td>Total</td><td>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><td></td></tr><tr><td>As of December 31, 2012</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(a)</td><td>$ (212)</td><td>$ (3)</td><td>$ (26)</td><td>$ (183)</td><td></td></tr><tr><td>Interest rate swap agreements</td><td>$ (1)</td><td>—</td><td>$ (1)</td><td>$ —</td><td></td></tr><tr><td>As of December 31, 2011</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy commodity derivative contracts(a)</td><td>$ (160)</td><td>$ (15)</td><td>$ (125)</td><td>$ (20)</td><td></td></tr><tr><td>Interest rate swap agreements</td><td>$ —</td><td>—</td><td>—</td><td>—</td><td></td></tr></table>

(a) Level 1 consists primarily of New York Mercantile Exchange (NYMEX) natural gas futures. Level 2 consists primarily of over-the-counter (OTC) West Texas Intermediate swaps and OTC natural gas swaps that are settled on NYMEX. Level 3 consists primarily of West Texas Intermediate options and power derivative contracts.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the years ended December 31, 2012 and 2011 (in millions):

Significant unobservable inputs (Level 3)

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td></td></tr><tr><td>Derivatives-net asset (liability)</td><td></td><td></td><td></td></tr><tr><td>Beginning of period</td><td>$     7</td><td>$     19</td><td></td></tr><tr><td>Total gains or (losses):</td><td></td><td></td><td></td></tr><tr><td>Included in earnings</td><td>(4)</td><td>(2)</td><td></td></tr><tr><td>Included in other comprehensive income</td><td>(1)</td><td>(12)</td><td></td></tr><tr><td>Purchases (a)</td><td>(194)</td><td>5</td><td></td></tr><tr><td>Settlements</td><td>37</td><td>(3)</td><td></td></tr><tr><td>End of period</td><td>$ (155)</td><td>$     7</td><td></td></tr><tr><td>The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date</td><td>$ (2)</td><td>$     2</td><td></td></tr></table>

a) 2012 purchases include a net liability of $197 million of Level 3 energy commodity derivative contracts associated with the EP acquisition.

As of December 31, 2012, our West Texas Intermediate options and power-related derivatives were reported at fair value using Level 3 inputs due to such derivatives not having observable market prices. Fair value of West Texas Intermediate options is determined using the Black Scholes option valuation methodology after giving consideration to a range of factors, including the prices at which the options were acquired, local market conditions, implied volatility, and trading values on public exchanges. Power-related derivatives are primarily in the Pennsylvania-New Jersey-Maryland (PJM) markets and value based upon price quotes from third-party service providers.

The significant unobservable input used in the fair value measurement of our West Texas Intermediate options is implied volatility. Implied volatility of our West Texas Intermediate options is obtained from a third-party service provider. As of December 31, 2012, this volatility ranged from 26% - 27% based on both historical market data and future estimates of market fluctuation. The significant unobservable inputs used in the fair value measurement of our power-related derivatives are illiquid pricing points. As the delivery points in our power contracts are in an illiquid market and not actively traded, we adjust the PJM forward curves by the difference between the 12-month rolling average of actual settled prices at delivery points in the PJM East region. As of December 31, 2012, the adjusted prices over the contract term ranged from $28.50 per megawatt-hour (MW/h) to $57.32 per MW/h. However, we have entered into offsetting positions that eliminate the price risks associated with



## Item 15. Exhibits, Financial Statement Schedules. (continued)

our PJM power contracts. Significant increases (decreases) in these inputs in isolation would result in a significantly lower (higher) fair value measurement.

## Fair Value of Financial Instruments

The estimated fair value of our outstanding debt balance as of December 31, 2012 and 2011 (both short-term and long-term and including debt fair value adjustments), is disclosed below (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">December 31, 2012</td><td colspan="2">December 31, 2011</td></tr><tr><td>Carrying value</td><td>Estimated fair value</td><td>Carrying value</td><td>Estimated fair value</td><td></td></tr><tr><td>Total debt</td><td>$     34,401</td><td>$     36,720</td><td>$     17,255</td><td>$     17,616</td><td></td></tr></table>

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2012 and 2011.

## 15. Reportable Segments

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

- Natural Gas Pipelines—for all periods presented in our financial statements this segment includes the sale, transport, processing, treating, storage and gathering of natural gas for KMP and equity earnings from our 20% interest in NGPL Holdco LLC. Following our May 25, 2012 EP acquisition, this segment also includes the natural gas operations of EP, its subsidiaries (including EPB) and its equity investments;

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

- CO2—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 from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States; and

- Other—In 2010, this segment primarily consisted of our Power facility which was sold on 10/22/2010. Following our May 25, 2012 EP acquisition, this segment primarily includes several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028.

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

Because KMP’s and EPB’s partnership agreements require them to distribute 100% of their available cash to their partners on a quarterly basis (available cash consists primarily of all 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. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

During 2012, 2011 and 2010, 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="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>$     5,230</td><td>$     3,943</td><td>$     4,078</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>1,370</td><td>914</td><td>883</td><td></td></tr><tr><td>CO2—KMP</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>1,677</td><td>1,434</td><td>1,299</td><td></td></tr><tr><td>Terminals—KMP</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>1,356</td><td>1,314</td><td>1,264</td><td></td></tr><tr><td>Intersegment revenues</td><td>3</td><td>1</td><td>1</td><td></td></tr><tr><td>Kinder Morgan Canada—KMP</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from external customers</td><td>311</td><td>302</td><td>268</td><td></td></tr><tr><td>Other</td><td>(6)</td><td>—</td><td>9</td><td></td></tr><tr><td>Total segment revenues</td><td>9,941</td><td>7,908</td><td>7,802</td><td></td></tr><tr><td>Other revenues(b)</td><td>35</td><td>36</td><td>51</td><td></td></tr><tr><td>Less: Total intersegment revenues</td><td>(3)</td><td>(1)</td><td>(1)</td><td></td></tr><tr><td>Total consolidated revenues</td><td>$     9,973</td><td>$     7,943</td><td>$     7,852</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Operating expenses(c)</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$     3,111</td><td>$     3,370</td><td>$     3,590</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td>759</td><td>500</td><td>414</td><td></td></tr><tr><td>CO2—KMP</td><td>381</td><td>342</td><td>309</td><td></td></tr><tr><td>Terminals—KMP</td><td>685</td><td>634</td><td>629</td><td></td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>103</td><td>97</td><td>91</td><td></td></tr><tr><td>Other</td><td>5</td><td>—</td><td>5</td><td></td></tr><tr><td>Total segment operating expenses</td><td>5,044</td><td>4,943</td><td>5,038</td><td></td></tr><tr><td>Other operating expenses</td><td>4</td><td>1</td><td>1</td><td></td></tr><tr><td>Less: Total intersegment operating expenses</td><td>(3)</td><td>(1)</td><td>(1)</td><td></td></tr><tr><td>Total consolidated operating expenses</td><td>$     5,045</td><td>$     4,943</td><td>$     5,038</td><td></td></tr></table>



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td>Other expense (income)</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$     14</td><td>$     1</td><td>$     1</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td>(5)</td><td>(8)</td><td></td><td>12</td></tr><tr><td>CO2—KMP</td><td>(7)</td><td>—</td><td></td><td>—</td></tr><tr><td>Terminals—KMP</td><td>(14)</td><td>1</td><td></td><td>(3)</td></tr><tr><td>Other</td><td>(1)</td><td>—</td><td></td><td>(16)</td></tr><tr><td>Total consolidated other expense (income)</td><td>$      (13)</td><td>$      (6)</td><td>$      (6)</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td>Depreciation, depletion and amortization</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$     478</td><td>$     163</td><td>$     127</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td>143</td><td>131</td><td></td><td>127</td></tr><tr><td>CO2—KMP</td><td>494</td><td>492</td><td></td><td>543</td></tr><tr><td>Terminals—KMP</td><td>236</td><td>226</td><td></td><td>216</td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>56</td><td>56</td><td></td><td>43</td></tr><tr><td>Other</td><td>12</td><td></td><td></td><td>—</td></tr><tr><td>Total consolidated depreciation, depletion and amortization</td><td>$     1,419</td><td>$     1,068</td><td>$     1,056</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td>Earnings (loss) from equity investments</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)(d)</td><td>$     52</td><td>$     158</td><td>$      (317)</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td>39</td><td></td><td>34</td><td></td></tr><tr><td>CO2—KMP</td><td>25</td><td></td><td>24</td><td></td></tr><tr><td>Terminals—KMP</td><td>21</td><td></td><td>11</td><td></td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>5</td><td></td><td>(2)</td><td></td></tr><tr><td>Other</td><td>11</td><td></td><td>1</td><td></td></tr><tr><td>Total consolidated equity earnings (loss)</td><td>$     153</td><td>$     226</td><td>$      (274)</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td><td>2010</td></tr><tr><td>Amortization of excess cost of equity investments</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$     17</td><td>$     1</td><td>$      —</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td>4</td><td></td><td>4</td><td></td></tr><tr><td>CO2—KMP</td><td>2</td><td></td><td>2</td><td></td></tr><tr><td>Total consolidated amortization of excess cost of equity investments</td><td>$     23</td><td>$     7</td><td>$     6</td><td></td></tr></table>



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Interest income</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$ 18</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td>2</td><td>3</td><td>4</td><td></td></tr><tr><td>CO2—KMP</td><td>—</td><td>1</td><td>2</td><td></td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>14</td><td>14</td><td>13</td><td></td></tr><tr><td>Other</td><td>3</td><td>—</td><td>—</td><td></td></tr><tr><td>Total segment interest income</td><td>37</td><td>18</td><td>19</td><td></td></tr><tr><td>Unallocated interest income</td><td>(9)</td><td>3</td><td>2</td><td></td></tr><tr><td>Total consolidated interest income</td><td>$ 28</td><td>$ 21</td><td>$ 21</td><td></td></tr></table>

<table><tr><td></td><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Other, net-income (expense)</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)(e)</td><td>$ 4</td><td>$ (164)</td><td>$ 2</td></tr><tr><td>Products Pipelines—KMP</td><td>9</td><td>5</td><td>12</td></tr><tr><td>CO2—KMP</td><td>(1)</td><td>4</td><td>2</td></tr><tr><td>Terminals—KMP</td><td>2</td><td>6</td><td>5</td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>3</td><td>—</td><td>3</td></tr><tr><td>Other</td><td>2</td><td>(1)</td><td>—</td></tr><tr><td>Total consolidated other, net-income (expense)</td><td>$ 19</td><td>$ (150)</td><td>$ 24</td></tr></table>

<table><tr><td></td><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Income tax benefit (expense)</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$ (5)</td><td>$ (3)</td><td>$ (3)</td></tr><tr><td>Products Pipelines—KMP</td><td>2</td><td>(3)</td><td>1</td></tr><tr><td>CO2—KMP</td><td>(5)</td><td>(4)</td><td>1</td></tr><tr><td>Terminals—KMP</td><td>(3)</td><td>5</td><td>(5)</td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>(1)</td><td>(15)</td><td>(8)</td></tr><tr><td>Total segment income tax expense</td><td>(12)</td><td>(20)</td><td>(14)</td></tr><tr><td>Unallocated income tax expense</td><td>(127)</td><td>(341)</td><td>(152)</td></tr><tr><td>Total consolidated income tax expense</td><td>$ (139)</td><td>$ (361)</td><td>$ (166)</td></tr></table>



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(f)</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$ 2,174</td><td>$ 563</td><td>$ 169</td></tr><tr><td>Products Pipelines—KMP</td><td>668</td><td>461</td><td>497</td></tr><tr><td>CO2—KMP</td><td>1,322</td><td>1,117</td><td>1,018</td></tr><tr><td>Terminals—KMP</td><td>708</td><td>702</td><td>640</td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>229</td><td>202</td><td>182</td></tr><tr><td>Other</td><td>7</td><td>—</td><td>4</td></tr><tr><td>Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments</td><td>5,108</td><td>3,045</td><td>2,510</td></tr><tr><td>Total segment depreciation, depletion and amortization</td><td>(1,419)</td><td>(1,068)</td><td>(1,056)</td></tr><tr><td>Total segment amortization of excess cost of equity investments</td><td>(23)</td><td>(7)</td><td>(6)</td></tr><tr><td>Other revenues</td><td>35</td><td>36</td><td>51</td></tr><tr><td>General and administrative expenses(g)</td><td>(929)</td><td>(515)</td><td>(631)</td></tr><tr><td>Interest expense, net of unallocable interest income (h)</td><td>(1,441)</td><td>(701)</td><td>(652)</td></tr><tr><td>Unallocable income tax expense</td><td>(127)</td><td>(341)</td><td>(152)</td></tr><tr><td>Income from discontinued operations, net of tax(i)</td><td>(777)</td><td>211</td><td>236</td></tr><tr><td>Total consolidated net income</td><td>$ 427</td><td>$ 660</td><td>$ 300</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Capital expenditures</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$ 499</td><td>$ 153</td><td>$ 138</td></tr><tr><td>Products Pipelines—KMP</td><td>307</td><td>254</td><td>145</td></tr><tr><td>CO2—KMP</td><td>453</td><td>432</td><td>373</td></tr><tr><td>Terminals—KMP</td><td>707</td><td>332</td><td>326</td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>16</td><td>28</td><td>22</td></tr><tr><td>Other</td><td>40</td><td>1</td><td>2</td></tr><tr><td>Total consolidated capital expenditures</td><td>$ 2,022</td><td>$ 1,200</td><td>$ 1,006</td></tr></table>

<table><tr><td>Investments at December 31</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$ 5,193</td><td>$ 3,150</td><td></td></tr><tr><td>Products Pipelines—KMP</td><td></td><td>400</td><td>354</td></tr><tr><td>CO2—KMP</td><td></td><td>11</td><td>10</td></tr><tr><td>Terminals—KMP</td><td></td><td>179</td><td>164</td></tr><tr><td>Kinder Morgan Canada—KMP</td><td></td><td>1</td><td>66</td></tr><tr><td>Other</td><td></td><td>20</td><td>—</td></tr><tr><td>Total consolidated investments</td><td>$ 5,804</td><td>$ 3,744</td><td></td></tr></table>



## Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td></td><td>2012</td><td>2011</td></tr><tr><td>Assets at December 31</td><td></td><td></td></tr><tr><td>Natural Gas Pipelines(a)</td><td>$ 46,540</td><td>$ 12,359</td></tr><tr><td>Products Pipelines—KMP</td><td>6,089</td><td>5,745</td></tr><tr><td>CO2—KMP</td><td>4,148</td><td>4,015</td></tr><tr><td>Terminals—KMP</td><td>5,931</td><td>5,272</td></tr><tr><td>Kinder Morgan Canada—KMP</td><td>1,724</td><td>1,827</td></tr><tr><td>Other</td><td>601</td><td>—</td></tr><tr><td>Total segment assets</td><td>65,033</td><td>29,218</td></tr><tr><td>Corporate assets(j)</td><td>2,854</td><td>1,499</td></tr><tr><td>Assets held for sale(k)</td><td>298</td><td>—</td></tr><tr><td>Total consolidated assets</td><td>$ 68,185</td><td>$ 30,717</td></tr></table>

(a) The increase in the 2012 amount versus the 2011 amount reflects the acquisition of EP. See Note 3 “Acquisitions and Divestiture—KMI Acquisition of El Paso Corporation.”

(b) Primarily represents a reimbursement of general and administrative costs for services we perform for NGPL Holdco LLC (see Note 11).

(c) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes.

(d) 2012 and 2010 amounts include impairment charges of $200 million and $430 million, respectively, to reduce the carrying value of our investment in NGPL Holdco LLC (see Note 6).

(e) 2011 amount includes a $167 million loss from the remeasurement of KMP’s previously held 50% equity interest in KinderHawk Field Services LLC to fair value (see Note 3).

(f) Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).

(g) 2012, 2011 and 2010 amounts include increases in expense of $400 million, $127 million and $268 million, respectively, related to the combined effect from the 2012, 2011 and 2010 certain items related to general and administrative expenses disclosed in Management’s Discussion and Analysis section “General and Administrative, Interest, and Noncontrolling Interests”.

(h) Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments. 2012 amount includes $108 million of expense for capitalized financing fees associated with the EP acquisition financing that were written-off (due to debt repayments) or amortized.

(i) Represents amounts from KMP’s FTC Natural Gas Pipelines disposal group and other, net of tax (see Note 3).

(j) Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, risk management assets related to debt fair value adjustments and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.

(k) Primarily represents amounts attributable to KMP’s Express pipelines system and our ownership interest in Bolivia to Brazil Pipeline.

We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2012, 2011 and 2010, we reported total consolidated interest expense of $1,427 million, $703 million and $668 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">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Revenues from external customers</td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 9,488</td><td>$ 7,513</td><td>$ 7,476</td><td></td></tr><tr><td>Canada</td><td>407</td><td>411</td><td>356</td><td></td></tr><tr><td>Mexico and other(a)</td><td>78</td><td>19</td><td>20</td><td></td></tr><tr><td>Total consolidated revenues from external customers</td><td>$ 9,973</td><td>$ 7,943</td><td>$ 7,852</td><td></td></tr></table>



## Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td></td><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Long-lived assets at December 31(b)</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 37,651</td><td>$ 20,848</td><td>$ 19,926</td></tr><tr><td>Canada</td><td>2,035</td><td>1,863</td><td>1,929</td></tr><tr><td>Mexico and other(a)</td><td>82</td><td>84</td><td>96</td></tr><tr><td>Total consolidated long-lived assets</td><td>$ 39,768</td><td>$ 22,795</td><td>$ 21,951</td></tr></table>

(a) Includes operations in Mexico and until August 31, 2011, the Netherlands.

(b) Long-lived assets exclude goodwill and 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 2012. This note also contains a description of any material legal proceedings that were initiated against us during the 2012, and a description of any material events occurring subsequent to December 31, 2012, but before the filing of this report.

In this note, we refer to KMP’s subsidiary SFPP, L.P. as SFPP; KMP’s subsidiary Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; BP West Coast Products, LLC as BP; ConocoPhillips Company (now Phillips 66 Company) as Phillips 66; Tesoro Refining and Marketing Company as Tesoro; Western Refining Company, L.P. as Western Refining; Navajo Refining Company, L.L.C. as Navajo; Holly Refining & Marketing Company LLC (now HollyFrontier Refining & Marketing LLC) as HollyFrontier; ExxonMobil Oil Corporation as ExxonMobil; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; Southwest Airlines Co. as Southwest Airlines; Continental Airlines, Inc., Northwest Airlines, Inc. (now Delta Air Lines, Inc.), Southwest Airlines Co. and US Airways, Inc., collectively, as the Airlines; KMP’s subsidiary Tennessee Gas Pipeline, L.L.C. as TGP; KMP’s 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 Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company) as UPRR; the American Railway Engineering and Maintenance-of-Way Association as AREMA; Severstal Sparrows Point, LLC as Severstal; RG Steel Sparrows Point LLC as RG Steel; the Texas Commission of Environmental Quality as the TCEQ; The Premcor Refining Group, Inc. as Premcor; Port Arthur Coker Company as PACC; the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration as the PHMSA; a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order as an NOPV; the federal Comprehensive Environmental Response, Compensation and Liability Act as CERCLA; the Interstate Commerce Act as the ICA; the United States Environmental Protection Agency as the U.S. EPA; the United States Environmental Protection Agency’s Suspension and Debarment Division as the U.S. EPA SDD; the New Jersey Department of Environmental Protection as the NJDEP; KMP’s subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; KMP’s subsidiary Kinder Morgan Liquids Terminals LLC as KMLT; Rockies Express Pipeline LLC as Rockies Express; and Plantation Pipe Line Company as Plantation. “OR” dockets designate FERC complaint proceedings, and “IS” dockets designate FERC protest proceedings.

## Federal Energy Regulatory Commission Proceedings

## SFPP

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

The issues involved in these proceedings include, among others: (i) whether “substantially changed circumstances” have occurred with respect to any “grandfathered” rates under the Energy Policy Act of 1992 such that those rates could be challenged; (ii) whether indexed rate increases are justified; and (iii) the appropriate level of return and income tax allowance KMP may include in its rates.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

The following FERC dockets currently are pending:

- FERC Docket No. IS08-390 (West Line Rates) (Opinion Nos. 511 and 511-A)-Protestants: BP, ExxonMobil, Phillips 66, Valero Marketing, Chevron, the Airlines-Status: FERC order issued on December 16, 2011 (Opinion No. 511-A). While the order made certain findings that were adverse to SFPP, it ruled in favor of SFPP on many significant issues. SFPP made a compliance filing at the end of January 2012, and our rates reflect this filing. SFPP also filed a rehearing request on certain adverse rulings in the FERC order. Petitions for review of Opinion Nos. 511 and 511-A have been filed at the D.C. Circuit and are held in abeyance pending a ruling on SFPP’s request for rehearing. It is not possible to predict the outcome of FERC review of the rehearing request or appellate review;

- FERC Docket No. IS09-437 (East Line Rates)-Protestants: BP, ExxonMobil, Phillips 66, Valero Marketing, Chevron, Western Refining, Navajo, HollyFrontier, and Southwest Airlines-Status: Opinion and Order on Initial Decision, Opinion No. 522, issued on September 20, 2012. The FERC generally made findings favorable to SFPP on significant issues and consistent with FERC's Opinion Nos. 511 and 511-A. SFPP and others filed requests for rehearing of Opinion No. 522 at FERC and petitions for review at the D.C. Circuit. The petitions for review are held in abeyance pending FERC action on the requests for rehearing. It is not possible to predict the outcome of FERC review of any request for rehearing or appellate review of this order. SFPP made a compliance filing in November 2012, and our rates reflect this filing;

- FERC Docket No. IS11-444 (2011 West Line Index Rate Increases)-Protestants: BP, ExxonMobil, Phillips 66, Valero Marketing, Chevron, the Airlines, Tesoro, Western Refining, Navajo, and HollyFrontier-Status: The shippers filed a motion for summary disposition that was granted in the shippers' favor in an initial decision issued on March 16, 2012. SFPP filed a brief with the FERC taking exception to the initial decision. The FERC will review the initial decision, and it is not possible to predict the outcome of FERC or appellate review;

- FERC Docket Nos. IS12-390 (East Line Index Rates)/IS12-388, IS12-500 and IS12-501 (West Line Index Rates)-Protestants: the Airlines, BP, Chevron, HollyFrontier, Phillips 66, Tesoro, Valero Marketing, and Western Refining-Status: Collectively, these shippers protested SFPP's index-based rate increases for its East Line (IS12-390) and West Line (IS12-388, IS12-500 and IS12-501). FERC rejected the protests against SFPP's East Line rate increases (IS12-390) and accepted the protests against SFPP's West Line rate increases (IS12-388). Following FERC acceptance of the West Line protests, SFPP withdrew these rate increases, reinstated the prior rates (IS12-500), and then subsequently increased its West Line rates by a smaller index-based percentage (IS12-501), which FERC accepted notwithstanding shipper protests. Shippers requested rehearing of FERC's acceptance of the East Line and West Line index rate increases in IS12-390 and IS12-501, and those requests are pending before FERC. It is not possible to predict the outcome of FERC review. FERC terminated the IS12-388/IS12-500 proceedings in July 2012;

- FERC Docket Nos. OR12-1, 12-2 and 12-3 (SFPP Index Ceiling Levels)-Complainants: Chevron, Tesoro and Phillips 66-Status: FERC dismissed the complaints on February 16, 2012.

- FERC Docket No. OR11-13 (Base Rates)-Complainant: Phillips 66-Status: SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390. Phillips 66 permitted to amend its complaint based on additional data;

- FERC Docket No. OR11-16 (Base Rates)-Complainant: Chevron-Status: SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390. Chevron permitted to amend its complaint based on additional data; and

- FERC Docket No. OR11-18 (Base Rates)-Complainant: Tesoro-Status: SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390. Tesoro permitted to amend its complaint based on additional data.

With respect to all of the SFPP proceedings above, we estimate that the shippers are seeking approximately $20 million in annual rate reductions and approximately $100 million in refunds. However, applying the principles of Opinion Nos. 511, 511-A, and 522 as applicable, to pending cases would result in substantially lower rate reductions and refunds than those sought by the shippers. We do not expect refunds in these cases to have an impact on KMP’s distributions to its limited partners or our dividends to our shareholders.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## Calnev

On March 17, 2011, the FERC issued an order consolidating and setting for hearing the complaints in Docket Nos. OR07-7, OR07-18, OR07-19, OR07-22, OR09-15, and OR09-20 filed by Tesoro, the Airlines, BP, Chevron, Phillips 66 and Valero Marketing. A settlement agreement resolving these proceedings was filed on February 24, 2012 and was certified to the FERC on March 1, 2012. On April 3, 2012, the FERC approved the settlement, and in May 2012, after the rates reduced by the settlement became effective, KMP made settlement payments of $54 million.

El Paso Natural Gas Company, L.L.C.

Docket No. RP08-426

In April 2010, the FERC approved an offer of settlement which increased EPNG’s base tariff rates, effective January 1, 2009. The settlement resolved all but four issues in the proceeding. In January 2011, the presiding administrative law judge issued a decision that for the most part found against EPNG on those four issues. In May 2012, the FERC upheld the initial decision of the presiding administrative law judge in Opinion No. 517 on three of the issues and found in favor of EPNG on one of the issues. EPNG, along with other parties, has sought rehearing of those decisions to the FERC and may also seek review of any of the FERC’s decisions to the U.S. Court of Appeals. However, in compliance with Opinion No. 517, EPNG filed with the FERC to implement certain aspects of the May 2012 order as they relate to rates under Docket No. RP08-426. Although the final outcome of all issues related to this open docket is not currently determinable, EPNG believes the accruals established for this matter are adequate.

Docket No. RP10-1398

In September 2010, EPNG filed a new rate case with the FERC proposing an increase in base tariff rates which would increase revenues by approximately $100 million annually over previously effective tariff rates. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. Hearings were conducted during the fourth quarter of 2011 and in June 2012, the presiding administrative law judge issued an initial decision which was overall favorable for EPNG. The initial decision is currently being reviewed by the FERC. Participants may appeal this decision to the FERC and ultimately seek review of the FERC’s decision to the U.S. Court of Appeals. Additionally, certain customers have requested that the FERC require EPNG to decrease its currently effective recourse rates based on an order issued in May 2012 for matters in Docket No. RP08-426. The FERC issued an order requiring the implementation of its decisions in Docket No. RP08-426, which included interim reductions to the currently effective rates. Although EPNG requested rehearing on the interim rate decrease, EPNG filed proforma tariff records to comply with the FERC’s order and requested adequate surcharge authority in the event the final rates are above the interim rates. That rehearing request and filing currently are pending before the FERC. EPNG is pursuing settlement with its customers of all issues in both open rate cases. It is uncertain whether the expected increase in revenues will be achieved in the context of any such settlement or following the final determination of the FERC or the courts on the rate matters. Although the final outcome is not currently determinable, EPNG believes the accruals established for this matter are adequate.

## California Public Utilities Commission Proceedings

KMP has previously reported ratemaking and complaint proceedings against SFPP 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.

On May 26, 2011, the CPUC issued a decision in several intrastate rate cases involving SFPP and a number of its shippers, (the "Long" cases). The decision includes determinations on issues, such as SFPP's entitlement to an income tax allowance, allocation of environmental expenses and refund liability, which KMP believes are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines. On March 8, 2012, the CPUC issued another decision related to the Long cases. This decision largely reflected the determinations made on May 26, 2011, including the denial of an income tax allowance for SFPP. The CPUC's order denied SFPP's request for rehearing of the CPUC's income tax allowance treatment, while granting requested rehearing of various, other issues relating to SFPP's refund liability and staying the payment of refunds until resolution of the outstanding issues on rehearing. On March 23, 2012, SFPP filed a petition for writ of review in the California Court of Appeal, seeking a court order vacating the CPUC's determination that SFPP is not entitled to recover an



## Item 15. Exhibits, Financial Statement Schedules. (continued)

income tax allowance in its intrastate rates. The Court has granted review with respect to SFPP’s petition and the matter awaits scheduling of oral argument.

On April 6, 2011, in proceedings unrelated to the above-referenced CPUC dockets, a CPUC administrative law judge issued a proposed decision (Bemesderfer case) substantially reducing SFPP’s authorized cost of service and ordering SFPP to pay refunds from May 24, 2007 to the present of revenues collected in excess of the authorized cost of service. The proposed decision was subsequently withdrawn, and the presiding administrative law judge is expected to reissue a proposed decision at some indeterminate time in the future. On January 30, 2012, SFPP filed an application reducing its intrastate rates by approximately 7%. This matter remains pending before the CPUC.

Based on KMP’s review of these CPUC proceedings and the shipper comments thereon, it estimates that the shippers are requesting approximately $375 million in reparation payments and approximately $30 million in annual rate reductions. The actual amount of reparations will be determined through further proceedings at the CPUC and potentially, the California Court of Appeal. KMP believes that the appropriate application of the income tax allowance and corrections of errors in law and fact should result in a considerably lower amount. We do not expect any reparations that KMP would pay in these matters to have an impact on KMP’s distributions to its limited partners or our dividends to our shareholders.

## Copano Shareholders' Litigation

Five putative class action lawsuits have been filed in connection with KMP’s proposed merger with Copano. Two lawsuits have been filed in the District Court of Harris County, Texas: (i) Schultes v. Copano Energy, L.L.C., et al. (Case No. 06966), filed on February 5, 2013; and (ii) Bruen v. Copano Energy, L.L.C., et al (Case No. 07076), filed on February 5, 2013. Three lawsuits have also been filed in the Court of Chancery of the State of Delaware: Berlin v. Copano Energy L.L.C., et al (Case No. 8284-VCN), filed February 6, 2013; Welzenbach v. William L. Thacker, et al. (Case No. 8317-VCN), filed on February 14, 2013; and Hudson v. Copano Energy L.L.C., et al. (Case No. 8337-VCN), filed February 19, 2013.

Each of the actions names Copano, its board of directors, Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. and Merger Sub as defendants. All three lawsuits are purportedly brought on behalf of a putative class seeking to enjoin the merger and alleging, among other things, that the members of Copano’s board of directors breached their fiduciary duties by agreeing to sell Copano for inadequate and unfair consideration and pursuant to an inadequate and unfair process, and that Copano, Kinder Morgan, Kinder Morgan G.P., Inc. and Merger Sub aided and abetted such alleged breaches.

Kinder Morgan has not yet responded to any of the complaints, but intends to vigorously defend these lawsuits.

## Carbon Dioxide Tax Assessments

## Colorado Severance Tax Assessment

On September 16, 2009, the Colorado Department of Revenue issued three Notices of Deficiency to KMP’s subsidiary 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 6 million, plus interest of 1 million and penalties of 2 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 overstatement of transportation and other expenses used to calculate the net taxable value. Kinder Morgan CO \( ^{2} \)  paid the retroactive tax bills under protest and filed petitions for a refund of the taxes paid under protest. On February 6, 2012, the Montezuma County Board of County Commissioners denied the refund petitions, and KMP appealed to the Colorado Board of Assessment Appeals. A hearing on this matter is presently scheduled to occur in the second quarter of 2013.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## 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 v. 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 September 2011, the judge determined that the annual rent payable as of January 1, 2004 was $15 million, subject to annual consumer price index increases. SFPP intends to appeal the judge's determination, but if that determination is upheld, SFPP would owe approximately $75 million in back rent. Accordingly, during 2011, KMP increased its rights-of-way liability to cover this liability amount. In addition, the judge determined that UPRR is entitled to an estimated $20 million for interest on the outstanding back rent liability. KMP believes the award of interest is without merit and it is pursuing its appellate rights.

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 AREMA 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. A trial occurred in the fourth quarter of 2011, with a verdict having been reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. SFPP is evaluating its post-trial and appellate options.

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, our results of operations, our cash flows, and our distributions to our limited partners. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.

## Several Sparrows Point Crane Collapse

On June 4, 2008, a bridge crane owned by Several and located in Sparrows Point, Maryland collapsed while being operated by KMBT. According to KMP’s 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, Case No. 09CV1668-WMN. Several and its successor in interest, RG Steel, allege 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. RG Steel seeks to recover in excess of $30 million for the alleged value of the crane and lost profits. KMBT denies each of RG Steel’s allegations. On or about June 1, 2012, RG Steel filed for bankruptcy in Case No. 12-11669 in the United States Bankruptcy Court for the District of Delaware; consequently, the trial date has been postponed indefinitely.

## Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al.

In December 2011 (“Brinckerhoff I”) and March 2012, (“Brinckerhoff II”) derivative lawsuits were filed in Delaware Chancery Court against EP, El Paso Pipeline GP Company, L.L.C., the general partner of EPB, and the directors of the general partner. EPB was named in both lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010 and November 2010 drop-down transactions involving EPB’s purchase of Southern LNG Co LLC, Elba Express Co LLC and Southern Natural Gas Co LLC. The lawsuits allege various conflicts of interest and that the consideration paid by EPB was excessive. Defendants’ motion to dismiss in Brinckerhoff I was denied in part. Defendants continue to believe that these actions are without merit and intend to defend against them vigorously.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## Allen v. El Paso Pipeline GP Company, L.L.C., et al.

In May 2012, a unitholder of EPB filed a purported class action in Delaware Chancery Court, alleging both derivative and non-derivative claims, against EPB, and EPB's general partner and its board. EPB was named in the lawsuit as both a "Class Defendant" and a "Derivative Nominal Defendant." The complaint alleges a breach of the duty of good faith and fair dealing in connection with the sale to EPB of a 25% ownership interest in SNG. Defendants' motion to dismiss was denied. Defendants continue to believe that this lawsuit is without merit, and intend to defend against it vigorously.

## Price Reporting Litigation

Beginning in 2003, several lawsuits were filed against El Paso Marketing L.P. (EPM) alleging that EP, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which were pending in Nevada, were dismissed. Appeals have been filed and argued. Although damages in excess of $140 million have been alleged in total against all defendants in one of the remaining lawsuits where a damage number is provided, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us. Therefore, our costs and legal exposure related to the remaining outstanding lawsuits and claims are not currently determinable.

## 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.

## Perth Amboy, New Jersey Tank Release

On October 17, 2012, the PHMSA issued a Final Order to KMLT related to an October 28, 2009 tank release from our Perth Amboy, New Jersey liquids terminal. No product left the company’s property, and additionally, there were no injuries, no impact to the adjacent community or public, and no fire as a result of the release. KMLT paid the penalty of less than $1 million and is in the process of implementing the compliance order requirements in the Final Order.

## Central Florida Pipeline Release, Tampa, Florida

On July 22, 2011, KMP’s subsidiary Central Florida Pipeline LLC reported a refined petroleum products release on a section of its 10-inch diameter pipeline near Tampa, Florida. The pipeline carries jet fuel and diesel to Orlando and was carrying jet fuel at the time of the incident. There was no fire and were no injuries associated with the incident. KMP immediately began clean up operations in coordination with federal, state and local agencies. The cause of the incident is outside force damage. The incident is under investigation by the PHMSA, U.S. EPA and the Florida Department of Environmental Protection.

## Herscher Illinois Compressor Station Incident

On August 16, 2011, at NGPL’s Compressor Station 201 in Herscher, Illinois, a crew was performing work inside a compressor building when a flash fire and explosion occurred. Three workers were injured. NGPL is working with the Department of Transportation Pipeline and Hazardous Materials Safety Administration to investigate the cause of the incident.

## Litigation Regarding KMI’s Acquisition of El Paso Corporation

On October 16, 2011, we and EP announced a definitive agreement whereby KMI would acquire all of the outstanding shares of EP. Beginning on October 17, 2011, the day after the agreement was announced, and in the days following, several putative class action lawsuits were filed in Harris County (Houston), Texas and in the Court of Chancery of the State of Delaware against the Board of Directors of EP alleging that the director-defendants breached their fiduciary duties to EP shareholders in connection with their negotiation of and entry into the merger agreement. The lawsuits also assert that EP and KMI “aided and abetted” the alleged breaches by the EP directors. The actions sought, among other things, to enjoin the proposed merger, disgorgement of any improper profits received by the defendants, and attorneys’ fees.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

On February 9, 2012, the Delaware Chancery Court heard oral argument on a motion by plaintiffs to enjoin the EP shareholder vote on the proposed merger. In a memorandum opinion, dated February 29, 2012, the Delaware Court of Chancery denied plaintiffs' motion for a preliminary injunction to enjoin the shareholder vote.

On March 9, 2012, EP held its special meeting of its stockholders, and the merger was approved. The merger thereafter closed on May 24, 2012 and became effective on May 25, 2012.

Beginning in June 2012, the parties engaged in settlement discussions with the assistance of a mediator. On July 18, 2012, the parties reached an agreement in principle to resolve, settle and release all claims asserted in the consolidated putative class actions for $110 million, subject to the execution of a customary stipulation and agreement of settlement and related papers, and subject also to notice to EP shareholders and approval by the Delaware Court of Chancery. On December 3, 2012, the Delaware Chancery Court entered a Final Order and Judgment which approved the settlement and dismissed the claims against all defendants with prejudice. Thereafter, the Texas cases were dismissed with prejudice on December 6, 2012.

During the second quarter of 2012, we recorded a pre-tax charge of $71 million, net of insurance proceeds, which was the amount that we paid in connection with this settlement.

Hite Hedge LP, et al. v. El Paso Corporation, et al.

In December 2011, unitholders of EPB filed a purported class action complaint in Delaware Chancery Court against EP and its board members, asserting that the defendants breached their purported fiduciary duties to EPB by entering into the sale agreement with KMI. EPB and EPB’s general partner were named in the lawsuit as “Nominal Defendants.” The complaint alleges that the agreement with KMI will result in fewer drop-down transactions into EPB and has resulted in a reduction of the price of EPB common units. In February 2012, the defendants filed a motion to dismiss the complaint. The plaintiffs filed an amended complaint adding a derivative claim, and the defendants responded with a second motion to dismiss in April 2012. Defendants’ motion to dismiss was granted and the dismissal is now a final judgment.

## 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 reasonably 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 and the reserves we have established, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or dividends to shareholders. As of December 31, 2012 and December 31, 2011, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $423 million and $334 million, respectively. The December 31, 2012 reserve is primarily related to various claims from regulatory proceedings arising from KMP’s West Coast products pipeline transportation rates and amounts accrued by us primarily for EP outstanding legal matters. 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

New Jersey Department of Environmental Protection v. Occidental Chemical Corporation, et al. (Defendants), Maxus Energy Corp. and Tierra Solutions, Inc. (Third-Party Plaintiffs) v. 3M Company et al., Superior Court of New Jersey, Law Division – Essex County, Docket No. L-9868-05

The NJDEP sued Occidental Chemical and others under the New Jersey Spill Act for contamination in the Newark Bay Complex including numerous waterways and rivers. Occidental et al. then brought in approximately 300 third-party defendants for contribution. NJDEP claimed damages related to forty years of discharges of TCDD (a form of dioxin), DDT and “other hazardous substances.” GATX Terminals Corporation (n/k/a/KMLT) was brought in as a third-party defendant because of the noted hazardous substances language and because the Carteret, New Jersey facility (a former GATX Terminals facility) is located on the Arthur Kill River, one of the waterways included in the litigation. This case was filed against third-party defendants in 2009. The judge issued his trial plan for this case during the first quarter of 2011. According to the trial plan, the judge allowed the State to file summary judgment motions against Occidental, Maxus and Tierra on liability issues immediately. Numerous third-party defendants, as part of a joint defense group of which KMLT is a member, filed motions to



dismiss, which were denied, and now have filed interim appeals from those motions. The appeals court panel heard oral arguments on these motions to dismiss in March 2012 and issued a ruling denying these motions in June 2012. The appellants have filed appeals to the New Jersey Supreme Court regarding this lower court ruling and denied the appeals. Maxus/Tierra’s claims against the third-party defendants are set to be tried in April 2013 with damages to be tried in September 2013. KMLT, as part of a defense group, has begun settlement negotiations with the NJDEP.

## Portland Harbor Superfund Site, Willamette River, Portland, Oregon

In December 2000, the U.S. EPA sent out General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the Remedial Investigation and Feasibility Study leading to the proposed remedy for cleanup of the Portland Harbor site. Once the U.S. EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision. Currently, KMLT and 90 other parties are involved in an allocation process to determine each party’s respective share of the cleanup costs. This is a non-judicial allocation process. KMP is participating in the allocation process on behalf of both KMLT and KMBT. Each entity has two facilities located in Portland Harbor. KMP expects the allocation to conclude in 2013 or 2014, depending upon when the U.S. EPA issues its Record of Decision.

## Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., U.S. District Court, Arizona

This is a CERCLA case brought against a number of defendants by a water purveyor whose wells have allegedly been contaminated due to the presence of a number of contaminants. The Roosevelt Irrigation District is seeking up to $175 million from approximately 70 defendants. The plume of contaminants has traveled under KMP’s Phoenix Terminal. The plaintiffs have advanced a novel theory that the releases of petroleum from the Phoenix Terminal (which are exempt under the petroleum exclusion under CERCLA) have facilitated the natural degradation of certain hazardous substances and thereby have resulted in a release of hazardous substances regulated under CERCLA. KMP is part of a joint defense group consisting of other terminal operators at the Phoenix Terminal including Chevron, BP, Salt River Project, Shell and a number of others, collectively referred to as the terminal defendants. Together, KMP filed a motion to dismiss all claims based on the petroleum exclusion under CERCLA. This case was assigned to a new judge, who has deemed all previous motions withdrawn and will grant leave to re-file such motions at a later date. KMP plans to re-file the motion to dismiss as well as numerous summary judgment motions as the judge allows.

## Casper and Douglas, U.S. EPA Notice of Violation

In March 2011, the U.S. EPA conducted inspections of several environmental programs at the Douglas and Casper Gas Plants in Wyoming. In June 2011, KMP received two letters from the U.S. EPA alleging violations at both gas plants of the Risk Management Program requirements under the Clean Air Act. In September 2012, we entered into Combined Complaint and Consent Agreements, and paid a monetary penalty of $158,000 for each plant to resolve these issues.

The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC; California Superior Court, County of Los Angeles, Case No. NC041463.

KMLT is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles. The lawsuit was stayed beginning in 2009 and remains stayed through the next case management conference in March 2013. During the stay, the parties deemed responsible by the local regulatory agency (including the City of Los Angeles) have worked with that agency concerning the scope of the required cleanup and have now completed a sampling and testing program at the site. KMP anticipates that cleanup activities at the site will begin in the spring of 2013. The local regulatory agency issued specific cleanup goals in early 2010, and two of those parties, including KMLT, have appealed those cleanup goals to the state water board. The state water board has not yet taken any action with regard to KMP’s appeal petitions.

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. We are in settlement negotiations with the Port of Los Angeles.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC and ST Services, Inc.

On April 23, 2003, 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 Corp. from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The terminal is now owned by Plains Products, and it too is a party to the lawsuit.

On June 25, 2007, the NJDEP, 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 KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro terminal. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and KMLT filed third-party complaints against Support Terminals/Plains seeking to bring Support Terminals/Plains into the case. Support Terminals/Plains filed motions to dismiss the third-party complaints, which were denied. Support Terminals/Plains is now joined in the case, and it filed an Answer denying all claims. The court has consolidated the two cases. All private parties and the state participated in two mediation conferences in 2010.

In mid 2011, KMLT and Plains Products entered into an agreement in principle with the NJDEP for settlement of the state’s alleged natural resource damages claim. The parties then entered into a Consent Judgment which was subject to public notice and comment and court approval. The natural resource damage settlement includes a monetary award of $1 million and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. Simultaneously, KMLT and Plains Products entered into a settlement agreement that settled each parties’ relative share of responsibility (50/50) to the NJDEP under the Consent Judgment noted above. The Consent Judgment is now entered with the Court and the settlement is final. Now Plains will begin conducting remediation activities at the site and KMLT will provide oversight and 50% of the costs. The settlement with the state does not resolve the original complaint brought by ExxonMobil. KMLT and Plains received a settlement demand from ExxonMobil in the amount of approximately $1 million for past costs related to the remediation at the Paulsboro facility. Plains and KMLT have provided ExxonMobil a counteroffer. The parties are now very close to settlement. There is no trial date set.

## 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 KMP and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and methyl tertiary butyl ether (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, KMP removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. The City disclosed in discovery that it is seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.

In accordance with the Case Management Order, the parties filed their respective summary adjudication motions and motions to exclude experts on June 29, 2012. On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties' pending motions. The Court tentatively granted our motions to exclude certain of the City's proposed expert witnesses, tentatively granted our partial motions for summary judgment on the City's claims for water and real estate damages and the State's claims for violations of California Business and Professions Code § 17200, tentatively denied the City's motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims. On January 25, 2013, the Court issued its final order reaffirming in all respects its tentative rulings and rendered judgment in favor of all defendants on all claims asserted by the City. On February 20, 2013, the City filed a Notice of Appeal with the United States Court of Appeals for the Ninth Circuit. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. SFPP continues to conduct an extensive remediation effort at the City's stadium property site.

## Kinder Morgan, Inc., U.S. EPA Section 114 Information Request

On January 8, 2010, KMI, on behalf of Natural Gas Pipeline Company of America LLC, Horizon Pipeline Company and Rockies Express, received a Clean Air Act Section 114 information request from the U.S. EPA, Region V. This information request requires that the three affiliated companies provide the U.S. EPA with air permit and various other information related



## Item 15. Exhibits, Financial Statement Schedules. (continued)

to their natural gas pipeline compressor station operations located in Illinois, Indiana, and Ohio. The affiliated companies have responded to the request and believe the relevant natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.

## Administrative Agreement with the U.S. EPA

In April 2011, we received Notices of Proposed Debarment from the U.S. EPA SDD. The Notices proposed the debarment of KMP (along with four KMP subsidiaries), KMI, Kinder Morgan G.P., Inc., and KMR, from participation in future federal contracting and assistance activities. The Notices alleged that certain of the respondents' past environmental violations indicated a lack of present responsibility warranting debarment.

In May 2012, we reached an administrative agreement with the U.S. EPA which resolved this matter without the debarment of any Kinder Morgan entities. The agreement requires independent monitoring of our Environmental Compliance and Ethics Programs, independent auditing of our facilities, enhanced training and notification requirements, and certain enhancements to our operational and compliance policies and procedures. We take environmental compliance very seriously, and expect to comply with all aspects of this agreement.

## MTBE - El Paso Corporation and Subsidiaries

Certain of EP’s subsidiaries used, produced, sold or distributed MTBE as a gasoline additive. Various lawsuits were filed throughout the U.S. regarding the potential impact of MTBE on water supplies. The lawsuits have been brought by different parties, including state attorneys general, water districts and individual water companies seeking different remedies against EP and many other defendants, including remedial activities, damages, attorneys’ fees and costs. These cases were initially consolidated for pre-trial purposes in multi-district litigation (MDL) in the U.S. District Court for the Southern District of New York. Several cases were later remanded to state court. Ninety-seven of the cases have been settled or dismissed, and most of the settlements have been substantially funded by insurance. EP has two remaining lawsuits, both pending in the MDL. Based upon discovery conducted to date, EP’s share of the relevant markets upon which alleged damages have been historically allocated among individual defendants is relatively small. In addition, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to EP. Therefore, our costs and legal exposure related to these remaining lawsuits are not currently determinable.

## TGP, PHMSA Notice of Violation

On April 25, 2012, the PHMSA issued an NOPV against TGP proposing $118,500 in penalties for alleged violations discovered during an inspection prior to Kinder Morgan’s ownership of TGP. We responded to the NOPV and paid the penalty.

## Other Environmental

We are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or cash flows.

We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.

In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and



## Item 15. Exhibits, Financial Statement Schedules. (continued)

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, 2012, we have accrued an environmental reserve of $397 million, primarily consisting of (i) $224 million associated with EP and its subsidiaries (excluding TGP, which was included in the drop-down of EP assets to KMP, see Note 3); (ii) $119 million related to KMP; and (iii) $4 million related to KMI's discontinued operations. In addition, as of December 31, 2012, we have recorded a receivable of $22 million for expected cost recoveries that have been deemed probable. As of December 31, 2011, our environmental reserve totaled $80 million and our estimated receivable for environmental cost recoveries totaled $5 million. Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.

## Other

We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

## 17. Regulatory Matters

The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expanded the circumstances under which interstate petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2012, 2011 and 2010, 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 2012.

## TGP's Proposed Sale of Production Area Facilities

On July 26, 2012, TGP filed an application with the FERC seeking authority to abandon by sale certain offshore and onshore supply facilities as well as a related offer of settlement that addresses the proposed rate and accounting treatment associated with the sale. The offer of settlement provides for a rate adjustment to TGP's maximum tariff rates upon the transfer of the assets and the establishment of a regulatory asset for a portion of the unrecovered net book value of the facilities to be sold. The sale is conditioned on approval by the FERC of both the requested abandonment authorization and offer of settlement. As of December 31, 2012, these assets totaled $32 million and are included within "Assets held for sale" in our accompanying consolidated balance sheet. Additionally, we have recorded an approximately $113 million regulatory asset, which is included within "Deferred charges and other assets" in our accompanying consolidated balance sheet as of December 31, 2012, for the portion of the loss that we expect to recover through TGP's jurisdictional transportation rates as outlined in the FERC filing.

## TGP Northeast Supply Diversification Project (Docket No. CP11-30-00)

On September 10, 2011, the FERC issued an order authorizing the expansion of TGP's pipeline facilities in northern Pennsylvania and western New York along with an associated lease of transportation capacity from Dominion Transmission, Inc. in order to provide incremental firm transportation service to shippers of approximately 245 million cubic feet per day of natural gas produced in the Marcellus Shale supply area to northeast markets. The estimated capital cost of the project is



## Item 15. Exhibits, Financial Statement Schedules. (continued)

approximately $55 million and the capacity is fully subscribed under long-term contracts. The project was completed and placed into service on November 1, 2012

## TGP Northeast Upgrade Project (Docket No. CP11-161-000)

On May 29, 2012, the FERC issued an order authorizing the expansion of TGP’s pipeline facilities in Pennsylvania and New Jersey that will provide needed infrastructure to support continued development of Marcellus shale natural gas production and increase TGP’s delivery capacity in the region by approximately 620 million cubic feet per day. The estimated capital cost of the project is approximately $450 million and the capacity is fully subscribed under long term contracts. With no stay of construction granted, and subject to receipt of final FERC and other regulatory agency approvals, the project is anticipated to be placed in service in November 1, 2013.

## TGP MPP Project (Docket No. CP12-28-000)

On August 9, 2012, the FERC issued an order authorizing the expansion of TGP’s pipeline facilities in northwestern Pennsylvania that will provide needed infrastructure to support continued development of Marcellus shale natural gas production and increase TGP’s delivery capacity in the region by approximately 240 million cubic feet per day. The estimated capital cost of the project is approximately $86 million and the capacity is fully subscribed under long term contracts. The Marcellus Pooling project is anticipated to be placed in service in November 1, 2013.

## TGP Rose Lake Expansion Project (Docket No. CP13-03-000)

On October 10, 2012, TGP filed an application with the FERC requesting authority to expand its pipeline capacity in northern Pennsylvania through the installation and modification of new and existing compression facilities that will result in increased capacity of approximately 225 million cubic feet per day and will improve the efficiency and reduce emissions by replacing certain older existing compression facilities. The project will further support continued development of Marcellus shale natural gas production in the region. The estimated capital cost of the project is approximately $92 million and the capacity is fully subscribed under long term contracts. The project is anticipated to be placed in service on November 1, 2014.

## Sierra Natural Gas Pipeline LLC Project

On February 7, 2013, KMP’s wholly-owned subsidiary Sierra Gas Pipeline LLC (a newly created interstate natural gas pipeline company) filed an application with the FERC to build a new 60-mile, 36-inch diameter pipeline that would extend from EPNG’s existing south mainlines (near the City of Tucson, Arizona) to the U.S.-Mexico border (near the Town of Sasabe, Arizona). At an approximate cost of $200 million, the new Sierra Pipeline would interconnect with a new 36-inch diameter natural gas pipeline to be built in Mexico. The new facilities will provide approximately 200 million cubic feet per day of firm natural gas transportation capacity. Sierra Gas Pipeline LLC entered into a 25-year transportation service agreement for the entire capacity. Pending FERC approval, the construction of the Sierra Pipeline would begin as early as the first quarter of 2014. We anticipate that the pipeline would be placed into service in the fall of 2014.

## EPB Regulatory Matters

In November 2012, the FERC notified Wyoming Interstate Company, L.L.C. that it was beginning a rate proceeding under Section 5 of the Natural Gas Act. We are aggressively defending the current rates, which we believe are just and reasonable. Any outcome from this FERC action is not anticipated to have a substantial impact on our or EPB’s earnings.

## Products Pipelines and Natural Gas Pipelines Regulatory Proceedings

For information on our pipeline regulatory proceedings, see Note 16 “Litigation, Environmental and Other Contingencies—Federal Energy Regulatory Commission Proceedings” and “—California Public Utilities Commission Proceedings.”

## 18. Recent Accounting Pronouncements

## Accounting Standards Updates

None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, 2012 (including ASU No. 2011-8, “Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment”) had a material impact on our consolidated financial statements.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## ASU No. 2011-11

On December 16, 2011, the Financial Accounting Standards Board, referred to in this note as the FASB, issued ASU No. 2011-11, "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities." This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement. ASU No. 2011-11 also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements. The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements, and all disclosures provided by the amendments of ASU No. 2011-11 are required to be provided retrospectively for all comparative periods presented. For us, ASU No. 2011-11 was effective January 1, 2013, and the adoption of this ASU is not expected to have a material impact on our consolidated financial statements.

## ASU No. 2012-02

On July 27, 2012, the FASB issued ASU No. 2012-02, “Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment.” This ASU allows an entity the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not (that is, a likelihood of more than 50%) that an indefinite-lived intangible asset other than goodwill is impaired. If, after this assessment, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test prescribed by current accounting principles. Moreover, an entity can bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to the quantitative impairment test, and then resume performing the qualitative assessment in any subsequent period. For us, ASU No. 2012-02 was effective January 1, 2013, and the adoption of this ASU is not expected to have a material impact on our consolidated financial statements.

## ASU No. 2013-01

On January 31, 2013, the FASB issued ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This ASU amends and clarifies the scope of the balance sheet offsetting disclosures prescribed in ASU No. 2011-11 (described above). Specifically, ASU No. 2013-01 limits the scope of ASU No. 2011-11’s required disclosures to the following financial instruments, to the extent that they are offset in the financial statements or subject to an enforceable master netting arrangement or similar agreement: (i) recognized derivative contracts accounted for under ASC 815, “Derivatives and Hedging;” (ii) repurchase agreements and reverse repurchase agreements; and (iii) securities borrowing and securities lending transactions. For us, ASU No. 2013-01 was effective January 1, 2013, and the adoption of this ASU is not expected to have a material impact on our consolidated financial statements.

## ASU No. 2013-02

On February 5, 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends and clarifies the disclosure requirements prescribed in ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.” ASU No. 2013-02 requires that entities present information about reclassification adjustments from accumulated other comprehensive income in their annual financial statements in a single note or on the face of the financial statements. Public entities will also have to provide this information in their interim financial statements. Specifically, entities must present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. If a component is not required to be reclassified to net income in its entirety, entities would instead cross reference to the related footnote for additional information. For us, ASU No. 2013-02 was effective January 1, 2013, and we are currently reviewing the effect of this ASU.



## 19. Reconciliation of Significant Asset Balances

The following is a reconciliation between KMP’s and EPB’s significant asset balances as reported in KMP’s and EPB’s Annual Report on Form 10-K as of December 31, 2012 and 2011 and our consolidated asset balances as shown on our accompanying consolidated balance sheets (in millions):

<table><tr><td rowspan="2"></td><td colspan="3">December 31,</td></tr><tr><td>2012</td><td colspan="2">2011</td></tr><tr><td>Cash and cash equivalents - KMI(a)</td><td>$     82</td><td>$     2</td><td></td></tr><tr><td>Cash and cash equivalents - KMP</td><td></td><td>518</td><td>409</td></tr><tr><td>Cash and cash equivalents - EPB</td><td></td><td>114</td><td>—</td></tr><tr><td>Cash and cash equivalents</td><td>$     714</td><td>$     411</td><td></td></tr><tr><td>Property, plant and equipment, net-KMI(a)</td><td>$     5,497</td><td>$     2,330</td><td></td></tr><tr><td>Property, plant and equipment, net-KMP</td><td></td><td>19,568</td><td>15,596</td></tr><tr><td>Property, plant and equipment, net-EPB</td><td></td><td>5,931</td><td>—</td></tr><tr><td>Property, plant and equipment, net</td><td>$     30,996</td><td>$     17,926</td><td></td></tr><tr><td>Goodwill-KMI(a)</td><td>$     18,944</td><td>$     3,638</td><td></td></tr><tr><td>Goodwill-KMP</td><td></td><td>4,606</td><td>1,436</td></tr><tr><td>Goodwill-EPB</td><td></td><td>22</td><td>—</td></tr><tr><td>Goodwill</td><td>$     23,572</td><td>$     5,074</td><td></td></tr><tr><td>Current portion of debt-KMI(a)</td><td>$     1,153</td><td>$     1,261</td><td></td></tr><tr><td>Current portion of debt-KMP</td><td></td><td>1,155</td><td>1,638</td></tr><tr><td>Current portion of debt-EPB</td><td></td><td>93</td><td>—</td></tr><tr><td>Current portion of debt</td><td>$     2,401</td><td>$     2,899</td><td></td></tr><tr><td>Long-term debt outstanding-KMI(a)</td><td>$     10,341</td><td>$     1,978</td><td></td></tr><tr><td>Long-term debt outstanding-KMP</td><td></td><td>14,714</td><td>11,183</td></tr><tr><td>Long-term debt outstanding-EPB(b)</td><td></td><td>4,254</td><td>—</td></tr><tr><td>Long-term debt outstanding</td><td>$     29,309</td><td>$     13,161</td><td></td></tr></table>

(a) Includes assets and liabilities of KMI’s consolidated subsidiaries, excluding KMP and EPB.

(b) Excludes debt fair value adjustments. Decrease to long-term debt for debt fair value adjustments totaled $8 million as of December 31, 2012.

## 20. Guarantee of Securities of Subsidiaries

KMI and some of its direct and indirect subsidiaries (referred to as the “Combined Other Guarantor Subsidiaries”), guarantee the payment of certain of El Paso LLC’s (formerly known as El Paso Corporation) outstanding debt. As of the date of the guarantee, August 13, 2012, and as of December 31, 2012, each series of El Paso LLC outstanding notes totaling approximately $4.1 billion and $3.9 billion, respectively, in aggregate principal amount (referred to as the “Guaranteed Notes”) is guaranteed on a senior unsecured basis by KMI and the Combined Other Guarantor Subsidiaries. These Guaranteed Notes are guaranteed through their respective maturity dates, the latest of which is in 2037. Subject to the limitations set forth in the applicable guarantee agreements, the guarantees described above are full and unconditional and joint and several. A significant amount of KMI and the Combined Other Guarantor Subsidiaries’ income and cash flow are generated by their subsidiaries. As a result, the funds necessary to meet KMI and the Combined Other Guarantor Subsidiaries’ debt service or guarantee obligations are provided in large part by distributions or advances from their subsidiaries. The non-guarantor subsidiaries primarily consist of KMP and EPB, along with Kinder Morgan G.P., Inc., the general partner of KMP and El Paso Pipeline GP Company, L.L.C., the general partner of EPB. In the following condensed consolidating financial information, KMI is “Parent Guarantor,” the



## Item 15. Exhibits, Financial Statement Schedules. (continued)

Combined Other Guarantor Subsidiaries are “Guarantor Subsidiaries” and El Paso LLC is “Subsidiary Issuer.” All of the Guarantor Subsidiaries and the Subsidiary Issuer are 100% owned by KMI.

Following is a list of Guarantor Subsidiaries:

* El Paso Energy Service Company, L.L.C. * El Paso Tennessee Pipeline Co., L.L.C.

* El Paso TGPC Investments, L.L.C. * El Paso EPNG Investments, L.L.C.

* El Paso Pipeline Holding Company, L.L.C. * El Paso Holdco L.L.C.

* Kinder Morgan (Delaware), Inc. * Kinder Morgan Finance Company LLC

* KM International Services, Inc. * K N Gas Gathering, Inc.

* KN Telecommunications, Inc. * Knight Power Company LLC

* NGPL Holdco Inc.

Balances, results of operations and cash flows of El Paso Holdco L.L.C. and subsidiaries, including El Paso LLC, are reflected from the date of our acquisition, May 25, 2012, see Note 3.



Condensed Consolidating Balance Sheets as of December 31, 2012
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>ASSETS</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 3</td><td>$ —</td><td>$ 45</td><td>$ 666</td><td>$ —</td><td>$ 714</td></tr><tr><td>Other current assets</td><td>810</td><td>82</td><td>—</td><td>8,505</td><td>(6,437)</td><td>2,960</td></tr><tr><td>Property, plant and equipment, net</td><td>8</td><td>31</td><td>—</td><td>30,957</td><td>—</td><td>30,996</td></tr><tr><td>Investments</td><td>20,019</td><td>13,067</td><td>9,683</td><td>5,565</td><td>(42,530)</td><td>5,804</td></tr><tr><td>Goodwill</td><td>—</td><td>—</td><td>8,000</td><td>15,572</td><td>—</td><td>23,572</td></tr><tr><td>Deferred charges and other assets</td><td>1,758</td><td>3,195</td><td>1,204</td><td>4,211</td><td>(6,229)</td><td>4,139</td></tr><tr><td>Total assets</td><td>$ 22,598</td><td>$ 16,375</td><td>$ 18,932</td><td>$ 65,476</td><td>$ (55,196)</td><td>$ 68,185</td></tr><tr><td>LIABILITIES AND STOCKHOLDERS&#x27; EQUITY</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current portion of debt</td><td>$ 1,035</td><td>$ —</td><td>$ 115</td><td>$ 1,251</td><td>$ —</td><td>$ 2,401</td></tr><tr><td>Other current liabilities</td><td>161</td><td>408</td><td>6,162</td><td>2,514</td><td>(6,437)</td><td>2,808</td></tr><tr><td>Long-term debt</td><td>4,832</td><td>3,235</td><td>4,413</td><td>24,467</td><td>(4,947)</td><td>32,000</td></tr><tr><td>Deferred income taxes</td><td>2,095</td><td>—</td><td>—</td><td>3,220</td><td>(1,282)</td><td>4,033</td></tr><tr><td>Other long-term liabilities</td><td>610</td><td>553</td><td>171</td><td>1,510</td><td>—</td><td>2,844</td></tr><tr><td>Total liabilities</td><td>8,733</td><td>4,196</td><td>10,861</td><td>32,962</td><td>(12,666)</td><td>44,086</td></tr><tr><td>Stockholders&#x27; equity</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Accumulated other comprehensive (loss) income</td><td>(119)</td><td>23</td><td>(14)</td><td>45</td><td>(54)</td><td>(119)</td></tr><tr><td>Other stockholders&#x27; equity</td><td>13,984</td><td>12,156</td><td>8,085</td><td>22,235</td><td>(42,476)</td><td>13,984</td></tr><tr><td>Total KMI equity</td><td>13,865</td><td>12,179</td><td>8,071</td><td>22,280</td><td>(42,530)</td><td>13,865</td></tr><tr><td>Noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>10,234</td><td>—</td><td>10,234</td></tr><tr><td>Total stockholders&#x27; equity</td><td>13,865</td><td>12,179</td><td>8,071</td><td>32,514</td><td>(42,530)</td><td>24,099</td></tr><tr><td>Total liabilities and stockholders&#x27; equity</td><td>$ 22,598</td><td>$ 16,375</td><td>$ 18,932</td><td>$ 65,476</td><td>$ (55,196)</td><td>$ 68,185</td></tr></table>



Condensed Consolidating Balance Sheets as of December 31, 2011
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>ASSETS</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 2</td><td>$ —</td><td>$ —</td><td>$ 409</td><td>$ —</td><td>$ 411</td></tr><tr><td>Other current assets</td><td>53</td><td>120</td><td>—</td><td>1,203</td><td>(124)</td><td>1,252</td></tr><tr><td>Property, plant and equipment, net</td><td>2</td><td>17</td><td>—</td><td>17,907</td><td>—</td><td>17,926</td></tr><tr><td>Investments</td><td>8,557</td><td>1,113</td><td>—</td><td>3,435</td><td>(9,361)</td><td>3,744</td></tr><tr><td>Goodwill</td><td>—</td><td>—</td><td>—</td><td>5,074</td><td>—</td><td>5,074</td></tr><tr><td>Deferred charges and other assets</td><td>218</td><td>3,184</td><td>—</td><td>3,613</td><td>(4,705)</td><td>2,310</td></tr><tr><td>Total assets</td><td>$ 8,832</td><td>$ 4,434</td><td>$ —</td><td>$ 31,641</td><td>$ (14,190)</td><td>$ 30,717</td></tr><tr><td>LIABILITIES AND STOCKHOLDERS&#x27; EQUITY</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current portion of debt</td><td>$ 1,260</td><td>$ —</td><td>$ —</td><td>$ 1,639</td><td>$ —</td><td>$ 2,899</td></tr><tr><td>Other current liabilities</td><td>170</td><td>46</td><td>—</td><td>1,538</td><td>(124)</td><td>1,630</td></tr><tr><td>Long-term debt</td><td>3,500</td><td>3,121</td><td>—</td><td>12,440</td><td>(4,705)</td><td>14,356</td></tr><tr><td>Deferred income taxes</td><td>412</td><td>43</td><td>—</td><td>1,744</td><td>—</td><td>2,199</td></tr><tr><td>Other long-term liabilities</td><td>169</td><td>—</td><td>—</td><td>896</td><td>—</td><td>1,065</td></tr><tr><td>Total liabilities</td><td>5,511</td><td>3,210</td><td>—</td><td>18,257</td><td>(4,829)</td><td>22,149</td></tr><tr><td>Stockholders&#x27; equity</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Accumulated other comprehensive (loss) income</td><td>(115)</td><td>1</td><td>—</td><td>(7)</td><td>6</td><td>(115)</td></tr><tr><td>Other stockholders&#x27; equity</td><td>3,436</td><td>1,223</td><td>—</td><td>8,144</td><td>(9,367)</td><td>3,436</td></tr><tr><td>Total KMI equity</td><td>3,321</td><td>1,224</td><td>—</td><td>8,137</td><td>(9,361)</td><td>3,321</td></tr><tr><td>Noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>5,247</td><td>—</td><td>5,247</td></tr><tr><td>Total stockholders&#x27; equity</td><td>3,321</td><td>1,224</td><td>—</td><td>13,384</td><td>(9,361)</td><td>8,568</td></tr><tr><td>Total liabilities and stockholders&#x27; equity</td><td>$ 8,832</td><td>$ 4,434</td><td>$ —</td><td>$ 31,641</td><td>$ (14,190)</td><td>$ 30,717</td></tr></table>



Condensed Consolidating Statements of Income for Year Ended December 31, 2012
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Revenues</td><td>$ 35</td><td>$ —</td><td>$ —</td><td>$ 9,938</td><td>$ —</td><td>$ 9,973</td></tr><tr><td>Costs, expenses and other</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gas purchases and other costs of sales</td><td>—</td><td>—</td><td>—</td><td>3,057</td><td>—</td><td>3,057</td></tr><tr><td>Depreciation, depletion and amortization</td><td>—</td><td>5</td><td>—</td><td>1,414</td><td>—</td><td>1,419</td></tr><tr><td>Other operating expenses</td><td>232</td><td>5</td><td>61</td><td>2,606</td><td>—</td><td>2,904</td></tr><tr><td>Total costs, expenses and other</td><td>232</td><td>10</td><td>61</td><td>7,077</td><td>—</td><td>7,380</td></tr><tr><td>Operating (loss) income</td><td>(197)</td><td>(10)</td><td>(61)</td><td>2,861</td><td>—</td><td>2,593</td></tr><tr><td>Other income (expense)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Earnings from equity investments</td><td>123</td><td>529</td><td>24</td><td>356</td><td>(879)</td><td>153</td></tr><tr><td>Amortization of excess cost of equity investments and other, net</td><td>(1)</td><td>(14)</td><td>(1)</td><td>12</td><td>—</td><td>(4)</td></tr><tr><td>Interest, net</td><td>(381)</td><td>(5)</td><td>(269)</td><td>(744)</td><td>—</td><td>(1,399)</td></tr><tr><td>(Loss) income from continuing operations before income taxes</td><td>(456)</td><td>500</td><td>(307)</td><td>2,485</td><td>(879)</td><td>1,343</td></tr><tr><td>Income tax Benefit (expense)</td><td>771</td><td>(198)</td><td>(38)</td><td>(674)</td><td>—</td><td>(139)</td></tr><tr><td>Income (loss) from continuing operations</td><td>315</td><td>302</td><td>(345)</td><td>1,811</td><td>(879)</td><td>1,204</td></tr><tr><td>Loss from discontinued operations, net of tax</td><td>—</td><td>(3)</td><td>—</td><td>(774)</td><td>—</td><td>(777)</td></tr><tr><td>Net income (loss)</td><td>315</td><td>299</td><td>(345)</td><td>1,037</td><td>(879)</td><td>427</td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(112)</td><td>—</td><td>(112)</td></tr><tr><td>Net income (loss) attributable to controlling interests</td><td>$ 315</td><td>$ 299</td><td>$ (345)</td><td>$ 925</td><td>$ (879)</td><td>$ 315</td></tr></table>



Condensed Consolidating Statements of Income for the Year Ended December 31, 2011 (In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Revenues</td><td>$ 36</td><td>$ —</td><td>$ —</td><td>$ 7,907</td><td>$ —</td><td>$ 7,943</td></tr><tr><td>Costs, expenses and other</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gas purchases and other costs of sales</td><td>—</td><td>—</td><td>—</td><td>3,278</td><td>—</td><td>3,278</td></tr><tr><td>Depreciation, depletion and amortization</td><td>—</td><td>—</td><td>—</td><td>1,068</td><td>—</td><td>1,068</td></tr><tr><td>Other operating expenses</td><td>42</td><td>—</td><td>—</td><td>2,132</td><td>—</td><td>2,174</td></tr><tr><td>Total costs, expenses and other</td><td>42</td><td>—</td><td>—</td><td>6,478</td><td>—</td><td>6,520</td></tr><tr><td>Operating (loss) income</td><td>(6)</td><td>—</td><td>—</td><td>1,429</td><td>—</td><td>1,423</td></tr><tr><td>Other income (expense)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Earnings from equity investments</td><td>712</td><td>818</td><td>—</td><td>201</td><td>(1,505)</td><td>226</td></tr><tr><td>Amortization of excess cost of equity investments and other, net</td><td>(1)</td><td>(1)</td><td>—</td><td>(155)</td><td>—</td><td>(157)</td></tr><tr><td>Interest, net</td><td>(187)</td><td>23</td><td>—</td><td>(518)</td><td>—</td><td>(682)</td></tr><tr><td>Income from continuing operations before income taxes</td><td>518</td><td>840</td><td>—</td><td>957</td><td>(1,505)</td><td>810</td></tr><tr><td>Income tax benefit (expense)</td><td>68</td><td>(8)</td><td>—</td><td>(421)</td><td>—</td><td>(361)</td></tr><tr><td>Income from continuing operations</td><td>586</td><td>832</td><td>—</td><td>536</td><td>(1,505)</td><td>449</td></tr><tr><td>Income from discontinued operations, net of tax</td><td>8</td><td>—</td><td>—</td><td>203</td><td>—</td><td>211</td></tr><tr><td>Net income</td><td>594</td><td>832</td><td>—</td><td>739</td><td>(1,505)</td><td>660</td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(66)</td><td>—</td><td>(66)</td></tr><tr><td>Net income attributable to controlling interests</td><td>$ 594</td><td>$ 832</td><td>$ —</td><td>$ 673</td><td>$ (1,505)</td><td>$ 594</td></tr></table>



Condensed Consolidating Statements of Income for the Year Ended December 31, 2010
(In Millions)

<table><tr><td></td><td colspan="2">Parent Guarantor</td><td colspan="2">Guarantor Subsidiaries</td><td colspan="2">Non-guarantor Subsidiaries</td><td colspan="2">Eliminations</td><td colspan="2">Consolidated KMI</td></tr><tr><td>Revenues</td><td>$     49</td><td></td><td>$      —</td><td>$      —</td><td>$      —</td><td>$     7,803</td><td>$      —</td><td>$      —</td><td>$     7,852</td><td></td></tr><tr><td>Costs, expenses and other</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gas purchases and other costs of sales</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>3,505</td><td>—</td><td>—</td><td>3,505</td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>1,056</td><td>—</td><td>—</td><td>1,056</td><td></td></tr><tr><td>Other operating expenses</td><td>241</td><td></td><td>—</td><td>—</td><td>—</td><td>1,917</td><td>—</td><td>—</td><td>2,158</td><td></td></tr><tr><td>Total costs, expenses and other</td><td>241</td><td></td><td>—</td><td>—</td><td>—</td><td>6,478</td><td>—</td><td>—</td><td>6,719</td><td></td></tr><tr><td>Operating (loss) income</td><td>(192)</td><td></td><td>—</td><td>—</td><td>—</td><td>1,325</td><td>—</td><td>—</td><td>1,133</td><td></td></tr><tr><td>Other income (expense)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Earnings from equity investments</td><td>303</td><td>894,000,000</td><td>536</td><td>—</td><td>—</td><td>97</td><td>(1,210)</td><td></td><td>(274)</td><td></td></tr><tr><td>Amortization of excess cost of equity investments and other, net</td><td>2</td><td></td><td>—</td><td>—</td><td>—</td><td>16</td><td>—</td><td>—</td><td>18</td><td></td></tr><tr><td>Interest, net</td><td>(180)</td><td></td><td>25</td><td>—</td><td>—</td><td>(492)</td><td>—</td><td>—</td><td>(647)</td><td></td></tr><tr><td>(Loss) income from continuing operations before income taxes</td><td>(67)</td><td></td><td>561</td><td>—</td><td>—</td><td>946</td><td>(1,210)</td><td></td><td>230</td><td></td></tr><tr><td>Income tax benefit (expense)</td><td>27</td><td></td><td>118</td><td>—</td><td>—</td><td>(311)</td><td>—</td><td>—</td><td>(166)</td><td></td></tr><tr><td>(Loss) Income from continuing operations</td><td>(40)</td><td></td><td>679</td><td>—</td><td>—</td><td>635</td><td>(1,210)</td><td></td><td>64</td><td></td></tr><tr><td>(Loss) income from discontinued operations, net of tax</td><td>(1)</td><td></td><td>—</td><td>—</td><td>—</td><td>237</td><td>—</td><td>—</td><td>236</td><td></td></tr><tr><td>Net (loss) income</td><td>(41)</td><td></td><td>679</td><td>—</td><td>—</td><td>872</td><td>(1,210)</td><td></td><td>300</td><td></td></tr><tr><td>Net income attributable to noncontrolling</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>



<table><tr><td>interests</td><td>—</td><td>—</td><td>—</td><td>(341)</td><td>—</td><td>(341)</td></tr><tr><td>Net (loss) income attributable to controlling interests</td><td>$ (41)</td><td>$ 679</td><td>$ —</td><td>$ 531</td><td>$ (1,210)</td><td>$ (41)</td></tr></table>



## Condensed Consolidating Statements of Comprehensive Income for the Year Ended December 31, 2012
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Net Income (loss)</td><td>$ 315</td><td>$ 299</td><td>$ (345)</td><td>$ 1,037</td><td>$ (879)</td><td>$ 427</td></tr><tr><td>Other comprehensive income, net of tax</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>32</td><td>27</td><td>(5)</td><td>115</td><td>(87)</td><td>82</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>(5)</td><td>(4)</td><td>(2)</td><td>3</td><td>—</td><td>(8)</td></tr><tr><td>Foreign currency translation adjustments</td><td>14</td><td>12</td><td>—</td><td>44</td><td>(38)</td><td>32</td></tr><tr><td>Adjustments to pension and other postretirement benefit plan liabilities</td><td>(45)</td><td>(5)</td><td>(7)</td><td>17</td><td>4</td><td>(36)</td></tr><tr><td>Total other comprehensive (loss) income</td><td>(4)</td><td>30</td><td>(14)</td><td>179</td><td>(121)</td><td>70</td></tr><tr><td>Comprehensive income (loss)</td><td>311</td><td>329</td><td>(359)</td><td>1,216</td><td>(1,000)</td><td>497</td></tr><tr><td>Comprehensive income attributable to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(186)</td><td>—</td><td>(186)</td></tr><tr><td>Comprehensive income (loss) attributable to controlling interests</td><td>$ 311</td><td>$ 329</td><td>$ (359)</td><td>$ 1,030</td><td>$ (1,000)</td><td>$ 311</td></tr></table>



## Condensed Consolidating Statements of Comprehensive Income for the Year Ended December 31, 2011
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Net Income</td><td>$ 594</td><td>$ 832</td><td>$ —</td><td>$ 739</td><td>$ (1,505)</td><td>$ 660</td></tr><tr><td>Other comprehensive income, net of tax</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>6</td><td>7</td><td>—</td><td>13</td><td>(13)</td><td>13</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>67</td><td>73</td><td>—</td><td>242</td><td>(198)</td><td>184</td></tr><tr><td>Foreign currency translation adjustments</td><td>(14)</td><td>(15)</td><td>—</td><td>(42)</td><td>36</td><td>(35)</td></tr><tr><td>Adjustments to pension and other postretirement benefit plan liabilities</td><td>(38)</td><td>(11)</td><td>—</td><td>(32)</td><td>27</td><td>(54)</td></tr><tr><td>Total other comprehensive income</td><td>21</td><td>54</td><td>—</td><td>181</td><td>(148)</td><td>108</td></tr><tr><td>Comprehensive income</td><td>615</td><td>886</td><td>—</td><td>920</td><td>(1,653)</td><td>768</td></tr><tr><td>Comprehensive income attributable to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(153)</td><td>—</td><td>(153)</td></tr><tr><td>Comprehensive income attributable to controlling interests</td><td>$ 615</td><td>$ 886</td><td>$ —</td><td>$ 767</td><td>$ (1,653)</td><td>$ 615</td></tr></table>



Condensed Consolidating Statements of Comprehensive Income for the Year Ended December 31, 2010
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Net (loss) Income</td><td>$ (41)</td><td>$ 679</td><td>$ —</td><td>$ 872</td><td>$ (1,210)</td><td>$ 300</td></tr><tr><td>Other comprehensive income, net of tax</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>(19)</td><td>(36)</td><td>—</td><td>(51)</td><td>52</td><td>(54)</td></tr><tr><td>Reclassification of change in fair value of derivatives to net income</td><td>22</td><td>40</td><td>—</td><td>162</td><td>(116)</td><td>108</td></tr><tr><td>Foreign currency translation adjustments</td><td>38</td><td>56</td><td>—</td><td>67</td><td>(78)</td><td>83</td></tr><tr><td>Adjustments to pension and other postretirement benefit plan liabilities</td><td>(9)</td><td>(1)</td><td>—</td><td>(1)</td><td>1</td><td>(10)</td></tr><tr><td>Total other comprehensive income</td><td>32</td><td>59</td><td>—</td><td>177</td><td>(141)</td><td>127</td></tr><tr><td>Comprehensive (loss) income</td><td>(9)</td><td>738</td><td>—</td><td>1,049</td><td>(1,351)</td><td>427</td></tr><tr><td>Comprehensive income attributable to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(436)</td><td>—</td><td>(436)</td></tr><tr><td>Comprehensive (loss) income attributable to controlling interests</td><td>$ (9)</td><td>$ 738</td><td>$ —</td><td>$ 613</td><td>$ (1,351)</td><td>$ (9)</td></tr></table>



Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2012  
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Net cash provided by (used in) operating activities</td><td>$ 1,108</td><td>$ (19)</td><td>$ (305)</td><td>$ 3,624</td><td>$ (1,613)</td><td>$ 2,795</td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Acquisitions of assets and investments</td><td>6,333</td><td>—</td><td>—</td><td>(83)</td><td>(6,333)</td><td>(83)</td></tr><tr><td>Repayments from related party</td><td>(252)</td><td>—</td><td>10</td><td>(432)</td><td>750</td><td>76</td></tr><tr><td>Capital expenditures</td><td>(5)</td><td>—</td><td>—</td><td>(2,017)</td><td>—</td><td>(2,022)</td></tr><tr><td>Contributions to investments</td><td>(15)</td><td>(28)</td><td>(28)</td><td>(177)</td><td>56</td><td>(192)</td></tr><tr><td>Investment in KMP and EPB</td><td>(85)</td><td>—</td><td>(9)</td><td>—</td><td>94</td><td>—</td></tr><tr><td>Investment in El Paso (acquisition of EP)</td><td>(11,551)</td><td>—</td><td>6,339</td><td>242</td><td>—</td><td>(4,970)</td></tr><tr><td>Drop down assets to KMP</td><td>3,485</td><td>—</td><td>—</td><td>(3,485)</td><td>—</td><td>—</td></tr><tr><td>Proceeds from disposal of discontinued operations</td><td>—</td><td>—</td><td>—</td><td>1,791</td><td>—</td><td>1,791</td></tr><tr><td>Distributions from equity investments in excess of cumulative earnings</td><td>16</td><td>—</td><td>50</td><td>153</td><td>(19)</td><td>200</td></tr><tr><td>Other, net</td><td>—</td><td>3</td><td>—</td><td>113</td><td>—</td><td>116</td></tr><tr><td>Net cash (used in) provided by investing activities</td><td>(2,074)</td><td>(25)</td><td>6,362</td><td>(3,895)</td><td>(5,452)</td><td>(5,084)</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>7,889</td><td>—</td><td>112</td><td>10,147</td><td>—</td><td>18,148</td></tr><tr><td>Payment of debt</td><td>(5,418)</td><td>(1)</td><td>(274)</td><td>(9,062)</td><td>—</td><td>(14,755)</td></tr><tr><td>Repayments from related party</td><td>2</td><td>26</td><td>483</td><td>239</td><td>(750)</td><td>—</td></tr><tr><td>Debt issuance costs</td><td>(91)</td><td>—</td><td>—</td><td>(20)</td><td>—</td><td>(111)</td></tr><tr><td>Cash dividends</td><td>(1,184)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1,184)</td></tr><tr><td>Repurchase of warrants</td><td>(157)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(157)</td></tr><tr><td>Contributions from parent</td><td>—</td><td>28</td><td>—</td><td>73</td><td>(101)</td><td>—</td></tr><tr><td>Distribution to parent</td><td>—</td><td>(9)</td><td>(6,333)</td><td>(1,599)</td><td>7,941</td><td>—</td></tr><tr><td>Contributions from noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>1,957</td><td>(18)</td><td>1,939</td></tr><tr><td>Distributions to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(1,219)</td><td>—</td><td>(1,219)</td></tr><tr><td>Other, net</td><td>(74)</td><td>—</td><td>—</td><td>4</td><td>(7)</td><td>(77)</td></tr><tr><td>Net cash provided by (used in) financing activities</td><td>967</td><td>44</td><td>(6,012)</td><td>520</td><td>7,065</td><td>2,584</td></tr><tr><td>Effect of exchange rate changes on cash and cash equivalents</td><td>—</td><td>—</td><td>—</td><td>8</td><td>—</td><td>8</td></tr><tr><td>Net increase in cash and cash equivalents</td><td>1</td><td>—</td><td>45</td><td>257</td><td>—</td><td>303</td></tr><tr><td>Cash and cash equivalents, beginning of period</td><td>2</td><td>—</td><td>—</td><td>409</td><td>—</td><td>411</td></tr><tr><td>Cash and cash equivalents, end of period</td><td>$ 3</td><td>$ —</td><td>$ 45</td><td>$ 666</td><td>$ —</td><td>$ 714</td></tr></table>



Condensed Consolidating Statements of Cash Flow for the Year Ended December 30, 2011  
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Net cash provided by (used in) operating activities</td><td>$ 106</td><td>$ 751</td><td>$ —</td><td>$ 2,866</td><td>$ (1,357)</td><td>$ 2,366</td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Acquisitions of assets and investments</td><td>—</td><td>—</td><td>—</td><td>(1,179)</td><td>—</td><td>(1,179)</td></tr><tr><td>Repayments from related party</td><td>—</td><td>—</td><td>—</td><td>31</td><td>—</td><td>31</td></tr><tr><td>Capital expenditures</td><td>(1)</td><td>—</td><td>—</td><td>(1,199)</td><td>—</td><td>(1,200)</td></tr><tr><td>Contributions to investments</td><td>(92)</td><td>—</td><td>—</td><td>(371)</td><td>92</td><td>(371)</td></tr><tr><td>Distributions from equity investments in excess of cumulative earnings</td><td>22</td><td>—</td><td>—</td><td>214</td><td>—</td><td>236</td></tr><tr><td>Other, net</td><td>—</td><td>—</td><td>—</td><td>91</td><td>—</td><td>91</td></tr><tr><td>Net cash (used in) provided by investing activities</td><td>(71)</td><td>—</td><td>—</td><td>(2,413)</td><td>92</td><td>(2,392)</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>2,070</td><td>—</td><td>—</td><td>7,502</td><td>—</td><td>9,572</td></tr><tr><td>Payment of debt</td><td>(1,649)</td><td>(750)</td><td>—</td><td>(6,394)</td><td>—</td><td>(8,793)</td></tr><tr><td>Debt issuance costs</td><td>(57)</td><td>(1)</td><td>—</td><td>(18)</td><td>—</td><td>(76)</td></tr><tr><td>Cash dividends</td><td>(770)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(770)</td></tr><tr><td>Distributions to parents</td><td>—</td><td>—</td><td>—</td><td>(1,275)</td><td>1,275</td><td>—</td></tr><tr><td>Contributions from noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>980</td><td>(10)</td><td>970</td></tr><tr><td>Distributions to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(956)</td><td>—</td><td>(956)</td></tr><tr><td>Other, net</td><td>—</td><td>—</td><td>—</td><td>(4)</td><td>—</td><td>(4)</td></tr><tr><td>Net cash (used in) provided by financing activities</td><td>(406)</td><td>(751)</td><td>—</td><td>(165)</td><td>1,265</td><td>(57)</td></tr><tr><td>Effect of exchange rate changes on cash and cash equivalents</td><td>—</td><td>—</td><td>—</td><td>(8)</td><td>—</td><td>(8)</td></tr><tr><td>Net (decrease) increase in cash and cash equivalents</td><td>(371)</td><td>—</td><td>—</td><td>280</td><td>—</td><td>(91)</td></tr><tr><td>Cash and cash equivalents, beginning of period</td><td>373</td><td>—</td><td>—</td><td>129</td><td>—</td><td>502</td></tr><tr><td>Cash and cash equivalents, end of period</td><td>$ 2</td><td>$ —</td><td>$ —</td><td>$ 409</td><td>$ —</td><td>$ 411</td></tr></table>



Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2010  
(In Millions)

<table><tr><td></td><td>Parent Guarantor</td><td>Guarantor Subsidiaries</td><td>Subsidiary Issuer</td><td>Non-guarantor Subsidiaries</td><td>Eliminations</td><td>Consolidated KMI</td></tr><tr><td>Net cash provided by (used in) operating activities</td><td>$ 1,225</td><td>$ (744)</td><td>$ —</td><td>$ 2,398</td><td>$ (966)</td><td>$ 1,913</td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Acquisitions of assets and investments</td><td>—</td><td>—</td><td>—</td><td>(1,214)</td><td>—</td><td>(1,214)</td></tr><tr><td>Repayments from related party</td><td>—</td><td>—</td><td>—</td><td>3</td><td>—</td><td>3</td></tr><tr><td>Capital expenditures</td><td>(2)</td><td>—</td><td>—</td><td>(1,004)</td><td>—</td><td>(1,006)</td></tr><tr><td>Contributions to investments</td><td>—</td><td>—</td><td>—</td><td>(299)</td><td>—</td><td>(299)</td></tr><tr><td>Distributions from equity investments in excess of cumulative earnings</td><td>35</td><td>—</td><td>—</td><td>190</td><td>—</td><td>225</td></tr><tr><td>Other, net</td><td>(12)</td><td>—</td><td>—</td><td>6</td><td>9</td><td>3</td></tr><tr><td>Net cash provided by (used in) investing activities</td><td>21</td><td>—</td><td>—</td><td>(2,318)</td><td>9</td><td>(2,288)</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>1,483</td><td>750</td><td>—</td><td>7,140</td><td>—</td><td>9,373</td></tr><tr><td>Payment of debt</td><td>(1,655)</td><td>—</td><td>—</td><td>(6,186)</td><td>—</td><td>(7,841)</td></tr><tr><td>Debt issuance costs</td><td>(2)</td><td>(6)</td><td>—</td><td>(23)</td><td>—</td><td>(31)</td></tr><tr><td>Cash dividends</td><td>(700)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(700)</td></tr><tr><td>Distributions to parents</td><td>—</td><td>—</td><td>—</td><td>(966)</td><td>9,66</td><td>—</td></tr><tr><td>Contributions from noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>768</td><td>(9)</td><td>7,59</td></tr><tr><td>Distributions to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(849)</td><td>—</td><td>(849)</td></tr><tr><td>Other, net</td><td>—</td><td>—</td><td>—</td><td>(1)</td><td>—</td><td>(1)</td></tr><tr><td>Net cash (used in) provided by financing activities</td><td>(874)</td><td>744</td><td>—</td><td>(117)</td><td>957</td><td>710</td></tr><tr><td>Effect of exchange rate changes on cash and cash equivalents</td><td>—</td><td>—</td><td>—</td><td>2</td><td>—</td><td>2</td></tr><tr><td>Net increase (decrease) in cash and cash equivalents</td><td>372</td><td>—</td><td>—</td><td>(35)</td><td>—</td><td>337</td></tr><tr><td>Cash and cash equivalents, beginning of period</td><td>1</td><td>—</td><td>—</td><td>164</td><td>—</td><td>165</td></tr><tr><td>Cash and cash equivalents, end of period</td><td>$ 373</td><td>$ —</td><td>$ —</td><td>$ 129</td><td>$ —</td><td>$ 502</td></tr></table>



## Supplemental Selected Quarterly Financial Data (Unaudited)

<table><tr><td rowspan="3"></td><td colspan="6">Three Months Ended</td></tr><tr><td colspan="2">March 31</td><td colspan="2">June 30</td><td>September 30</td><td>December 31</td></tr><tr><td colspan="6">(In millions)</td></tr><tr><td>2012</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues</td><td>$     1,857</td><td>$     2,167</td><td>$     2,870</td><td>$     3,079</td><td></td><td></td></tr><tr><td>Operating Income</td><td>$     516</td><td>$     260</td><td>$     852</td><td>$     965</td><td></td><td></td></tr><tr><td>Income from Continuing Operations</td><td>$     305</td><td>$     37</td><td>$     386</td><td>$     476</td><td></td><td></td></tr><tr><td>(Loss) Income from Discontinued Operations (a)</td><td>$      (378)</td><td>$      (280)</td><td>$      (131)</td><td>$     12</td><td></td><td></td></tr><tr><td>Net (Loss) Income (b)</td><td>$      (73)</td><td>$      (243)</td><td>$     255</td><td>$     488</td><td></td><td></td></tr><tr><td>Net Income (Loss) Attributable to Kinder Morgan, Inc.</td><td>$     21</td><td>$      (126)</td><td>$     200</td><td>$     220</td><td></td><td></td></tr><tr><td>Class P Shares</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings (Loss) Per Common Share From Continuing Operations</td><td>$     0.23</td><td>$      (0.11)</td><td>$     0.21</td><td>$     0.21</td><td></td><td></td></tr><tr><td>Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations</td><td>(0.20)</td><td>(0.04)</td><td>(0.02)</td><td>—</td><td></td><td></td></tr><tr><td>Total Basic and Diluted Earnings (Loss) Per Common Share</td><td>$     0.03</td><td>$      (0.15)</td><td>$     0.19</td><td>$     0.21</td><td></td><td></td></tr><tr><td>Class A Shares</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings (Loss) Per Common Share From Continuing Operations</td><td>$     0.21</td><td>$      (0.13)</td><td>$     0.19</td><td>$     0.19</td><td></td><td></td></tr><tr><td>Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations</td><td>(0.20)</td><td>(0.04)</td><td>(0.02)</td><td>—</td><td></td><td></td></tr><tr><td>Total Basic and Diluted Earnings (Loss) Per Common Share</td><td>$     0.01</td><td>$      (0.17)</td><td>$     0.17</td><td>$     0.19</td><td></td><td></td></tr></table>

(a) First, second, third and fourth quarters for 2012 include losses on remeasurement to fair value and sale of KMP's FTC Natural Gas Pipelines disposal group (after-tax) of $428 million, $327 million, $179 million and $3 million, respectively.

(b) Fourth quarter for 2012 includes a non-cash NGPL Holdco LLC investment impairment charge of $128 million (after-tax).



Item 15. Exhibits, Financial Statement Schedules. (continued)

<table><tr><td rowspan="3"></td><td colspan="6">Three Months Ended</td></tr><tr><td colspan="2">March 31(a)</td><td colspan="2">June 30(b)</td><td colspan="2">September 30(c)</td></tr><tr><td colspan="6">(In millions)</td></tr><tr><td></td><td>2011</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues</td><td>$     1,932</td><td>$     1,952</td><td>$     2,122</td><td>$     1,937</td><td></td><td></td></tr><tr><td>Operating income</td><td>$     365</td><td>$     236</td><td>$     381</td><td>$     441</td><td></td><td></td></tr><tr><td>Income from continuing operations</td><td>$     150</td><td>$     42</td><td>$     29</td><td>$     228</td><td></td><td></td></tr><tr><td>Income from discontinued operations</td><td>$     51</td><td>$     40</td><td>$     55</td><td>$     65</td><td></td><td></td></tr><tr><td>Net Income</td><td>$     201</td><td>$     82</td><td>$     84</td><td>$     293</td><td></td><td></td></tr><tr><td>Net Income Attributable to Kinder Morgan, Inc.</td><td>$     155</td><td>$     132</td><td>$     152</td><td>$     155</td><td></td><td></td></tr><tr><td>Class P Shares(d)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Continuing Operations</td><td>$     0.11</td><td>$     0.18</td><td>$     0.20</td><td>$     0.21</td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Discontinued Operations</td><td>0.01</td><td>0.01</td><td>0.01</td><td>0.01</td><td></td><td></td></tr><tr><td>Total Basic and Diluted Earnings Per Common Share</td><td>$     0.12</td><td>$     0.19</td><td>$     0.21</td><td>$     0.22</td><td></td><td></td></tr><tr><td>Class A Shares(d)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Continuing Operations</td><td>$     0.11</td><td>$     0.16</td><td>$     0.18</td><td>$     0.19</td><td></td><td></td></tr><tr><td>Basic and Diluted Earnings Per Common Share From Discontinued Operations</td><td>0.01</td><td>0.01</td><td>0.01</td><td>0.01</td><td></td><td></td></tr><tr><td>Total Basic and Diluted Earnings Per Common Share</td><td>$     0.12</td><td>$     0.17</td><td>$     0.19</td><td>$     0.20</td><td></td><td></td></tr></table>

(a) First quarter 2011 includes a $100 million increase in expense associated with a special cash bonus paid to non-senior management employees in May 2011. The cost of this bonus was not borne by our Class P shareholders. We paid for these bonuses, which included the amounts allocated to KMP, using $64 million in available earnings and profits reserved for this purpose and not paid in dividends to our Class A shareholders.

(b) Second quarter 2011 includes a $165 million increase in expense associated with rate case liability adjustments.

(c) Third quarter 2011 includes a $167 million loss from the remeasurement of KMP's previously held 50% equity interest in KinderHawk Field Services LLC to fair value, and a $69 million increase in expense primarily associated with rights-of-way lease payment liability adjustments.

(d) Earnings per share for the first quarter of 2011 includes the period from February 16, 2011, the day we completed an initial public offering of our Class P Common Stock, through March 31, 2011.



## Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Operating statistics from our oil and gas producing activities for each of the years 2012, 2011 and 2010 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="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Production costs per barrel of oil equivalent(b)(c)(d)</td><td>$ 16.44</td><td>$ 15.37</td><td>$ 12.58</td><td></td></tr><tr><td>Crude oil production (MBbl/d)</td><td>35.0</td><td>34.2</td><td>35.5</td><td></td></tr><tr><td>SACROC crude oil production (MBbl/d)</td><td>24.1</td><td>23.8</td><td>24.3</td><td></td></tr><tr><td>Yates crude oil production (MBbl/d)</td><td>9.3</td><td>9.6</td><td>10.7</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas liquids production (MBbl/d)(d)</td><td>3.9</td><td>3.5</td><td>5.8</td><td></td></tr><tr><td>Natural gas liquids production from gas plants(MBbl/d)(e)</td><td>5.6</td><td>5.0</td><td>4.2</td><td></td></tr><tr><td>Total natural gas liquids production(MBbl/d)</td><td>9.5</td><td>8.5</td><td>10.0</td><td></td></tr><tr><td>SACROC natural gas liquids production (MBbl/d)(d)</td><td>3.7</td><td>3.3</td><td>5.5</td><td></td></tr><tr><td>Yates natural gas liquids production (MBbl/d)(d)</td><td>0.2</td><td>0.2</td><td>0.2</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas production (MMcf/d)(d)(f)</td><td>1.2</td><td>1.5</td><td>1.4</td><td></td></tr><tr><td>Natural gas production from gas plants(MMcf/d)(e)(f)</td><td>0.7</td><td>0.5</td><td>1.9</td><td></td></tr><tr><td>Total natural gas production(MMcf/d)(f)</td><td>1.9</td><td>2.0</td><td>3.3</td><td></td></tr><tr><td>Yates natural gas production (MMcf/d)(d)(f)</td><td>1.1</td><td>1.4</td><td>1.3</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Average sales prices including hedge gains/losses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil price per Bbl(g)</td><td>$ 87.72</td><td>$ 69.73</td><td>$ 59.96</td><td></td></tr><tr><td>Natural gas liquids price per Bbl(g)</td><td>$ 51.79</td><td>$ 65.65</td><td>$ 50.34</td><td></td></tr><tr><td>Natural gas price per Mcf(h)</td><td>$ 2.58</td><td>$ 3.86</td><td>$ 4.08</td><td></td></tr><tr><td>Total natural gas liquids price per Bbl(e)</td><td>$ 50.95</td><td>$ 65.61</td><td>$ 51.03</td><td></td></tr><tr><td>Total natural gas price per Mcf(e)</td><td>$ 2.72</td><td>$ 3.76</td><td>$ 4.10</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Average sales prices excluding hedge gains/losses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil price per Bbl(g)</td><td>$ 89.91</td><td>$ 92.61</td><td>$ 76.93</td><td></td></tr><tr><td>Natural gas liquids price per Bbl(g)</td><td>$ 51.79</td><td>$ 65.65</td><td>$ 50.34</td><td></td></tr><tr><td>Natural gas price per Mcf(h)</td><td>$ 2.58</td><td>$ 3.86</td><td>$ 4.08</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan CO2 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 (thousand cubic feet) 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 KMP’s 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 following three tables provide supplemental information on oil and gas producing activities, including (i) capitalized costs related to oil and gas producing activities; (ii) costs incurred for the acquisition of oil and gas producing properties and for exploration and development activities; and (iii) the results of operations from oil and gas producing activities.



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="3">As of December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td></tr><tr><td>Wells and equipment, facilities and other</td><td>$ 3,927</td><td>$ 3,586</td><td>$ 3,159</td></tr><tr><td>Leasehold</td><td>428</td><td>433</td><td>433</td></tr><tr><td>Total proved oil and gas properties</td><td>4,355</td><td>4,019</td><td>3,592</td></tr><tr><td>Unproved property(b)</td><td>8</td><td>34</td><td>88</td></tr><tr><td>Accumulated depreciation and depletion</td><td>(3,072)</td><td>(2,661)</td><td>(2,235)</td></tr><tr><td>Net capitalized costs</td><td>$ 1,291</td><td>$ 1,392</td><td>$ 1,445</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.
(b) The unproved amounts consist of capitalized costs related to the Katz field unit, which is in the initial stages of the carbon dioxide flooding operation.

For each of the years 2012, 2011 and 2010, our 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="4">Year Ended December 31,</td></tr><tr><td colspan="2">2012</td><td colspan="2">2011</td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Development</td><td>$ 310</td><td>$ 373</td><td>$ 326</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan CO \( _{2} \)  Company, L.P. and its consolidated subsidiaries. During 2012 and 2011, we spent $69 million and $89 million, respectively, on development costs related to the Katz field unit, which was in the initial stages of the carbon dioxide flooding operation. As of December 31, 2012, capitalized costs related to unproved property for the Katz unit was $6 million. No exploration costs were incurred for the periods reported.

Our results of operations from oil and gas producing activities for each of the years 2012, 2011 and 2010 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="4">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td>Consolidated Companies(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues(b)</td><td>$ 1,235</td><td>$ 993</td><td>$ 903</td><td></td></tr><tr><td>Expenses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Production costs</td><td>288</td><td>246</td><td>229</td><td></td></tr><tr><td>Other operating expenses(c)</td><td>77</td><td>79</td><td>63</td><td></td></tr><tr><td>Depreciation, depletion and amortization expenses</td><td>387</td><td>394</td><td>406</td><td></td></tr><tr><td>Total expenses</td><td>752</td><td>719</td><td>698</td><td></td></tr><tr><td>Results of operations for oil and gas producing activities</td><td>$ 483</td><td>$ 274</td><td>$ 205</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan CO \( _{2} \)  Company, L.P. and its consolidated subsidiaries.

(b) Revenues include losses attributable to our hedging contracts of $28 million, $285 million and $220 million for each of the years ended December 31, 2012, 2011 and 2010, respectively.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

## (c) Consists primarily of carbon dioxide expense.

Supplemental information is also provided for the following three items (i) estimated quantities of proved oil and gas reserves; (ii) the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and (iii) a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

The technical persons responsible for preparing the reserves estimates presented in this Note meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. They are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our oil and gas properties; and we do not employ them on a contingent basis.

The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. Mike Norton. Mr. Newton has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Newton is a Licensed Professional Engineer in the State of Texas (No. 97689) and has over 27 years of practical experience in petroleum engineering, with over 15 years experience in the estimation and evaluation of reserves. He graduated from University College, Cardiff, Wales, in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University, Scotland, in 1986 with a Master of Science Degree in Petroleum Engineering. Mr. Norton has been practicing consulting petroleum geology at NSAI since 1989. Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441) and has over 30 years of practical experience in petroleum geosciences, with over 23 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our employee who is primarily responsible for overseeing Netherland, Sewell and Associate, Inc.'s preparation of the reserves estimates is a registered Professional Engineer in the states of Texas and Kansas with a Doctorate of Engineering from the University of Kansas. He is a member of the Society of Petroleum Engineers and has over 25 years of professional engineering experience. We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change.

Furthermore, our management is responsible for establishing and maintaining adequate internal control over financial reporting, which includes the estimation of our oil and gas reserves. We maintain internal controls and guidance to ensure the reliability of our crude oil, natural gas liquids and natural gas reserves estimations, as follows:

• no employee’s compensation is tied to the amount of recorded reserves;

• we follow comprehensive SEC compliant internal policies to determine and report proved reserves, and our reserve estimates are made by experienced oil and gas reservoir engineers or under their direct supervision;

• we review our reported proved reserves at each year-end, and at each year-end, the CO2—KMP business segment managers and the Vice President (President, CO2) reviews all significant reserves changes and all new proved developed and undeveloped reserves additions; and

• the CO2—KMP business segment reports independently of our four remaining reportable business segments.

For more information on our controls and procedures, see Item 9A “Controls and Procedures—Management’s Report on Internal Control Over Financial Reporting” included in our Annual Report on Form 10-K for the year ended December 31, 2012.

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. Pricing is applied based upon the twelve month unweighted arithmetic average of the first day of the month price for the year. 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.

As of December 31, 2010, we had 56.4 million barrels of crude oil and 2.2 million barrels of natural gas liquids classified as proved developed reserves. Also, as of year end December 31, 2010, we had 27.8 million barrels of crude oil and 2.6 million barrels of natural gas liquids classified as proved undeveloped reserves. Total proved reserves as of December 31, 2010 were 84.2 million barrels of crude oil and 4.9 million barrels of natural gas liquids.

During 2011, production from the fields totaled 12.5 million barrels of crude oil and 1.3 million barrels of natural gas liquids. In addition, KMP incurred $373 million in capital costs which resulted in the development of 7.3 million barrels of crude oil and 0.9 million barrels of natural gas liquids and their transfer from the proved undeveloped category to the proved developed category. We also developed 3.0 million barrels of crude oil with the development of the Katz (Strawn) unit CO \( _{2} \)  flood, where the produced natural gas containing natural gas liquids is injected with the CO \( _{2} \) . The reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 26.2% of crude oil and 35.2% of natural gas liquids from the proved undeveloped reserves reported as of December 31, 2010 to the proved developed classification of reserves reported as of December 31, 2011. The developed reserves for the Katz (Strawn) unit CO \( _{2} \)  flood represent 5.4% of proved developed reserves.

Also during 2011, previous estimates of proved developed reserves were revised upwards by 1.4 million barrels of crude oil and proved undeveloped reserves were revised upward by 3.3 million barrels of crude oil and 0.6 million barrels of natural gas liquids. These revisions are attributed to utilizing a higher prescribed oil price basis (92.71 per barrel for year end 2011 versus 75.96 per barrel for year end 2010) and higher projected CO \( _{2} \)  flood recoveries resulting from updated performance at SACROC used to calculate reserves. All natural gas reserves are associated with crude oil production and are not impacted by natural gas pricing.

These revisions to the previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves decreasing from 33.9% at year end 2010 to 31.0% at year end 2011. After giving effect to production and revisions to previous estimates during 2011, total proved reserves of crude oil decreased by 4.7 million barrels and total proved reserves of natural gas liquids decreased by 0.7 million barrels.

As of December 31, 2011, we had 55.7 million barrels of crude oil and 1.8 million barrels of natural gas liquids classified as proved developed reserves. Also, as of year end 2011, we had 23.8 million barrels of crude oil and 2.3 million barrels of natural gas liquids classified as proved undeveloped reserves. Total proved reserves as of December 31, 2011, were 79.4 million barrels of crude oil and 4.1 million barrels of natural gas liquids.

During 2012, production from the fields totaled 12.8 million barrels of crude oil and 1.4 million barrels of natural gas liquids. For 2012, we incurred $353 million in capital costs, and this capital investment resulted in the development of 6.0 million barrels of crude oil and 1.8 million barrels of natural gas liquids and their transfer from the proved undeveloped category to the proved developed category. During 2012, we sold our interest in the Claytonville Canyon Sand Unit which reduced proved developed reserves by 0.2 million barrels of crude oil. The reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 25.4.0% of crude oil and 79.4% of natural gas liquids from the proved undeveloped reserves reported as of December 31, 2011 to the proved developed classification of reserves reported as of December 31, 2012.

Also during 2012, previous estimates of proved developed reserves were revised upwards by 4.3 million barrels of crude oil and 0.2 million barrels of natural gas liquids, and proved undeveloped reserves were revised upward by 11.2 million barrels of crude oil and 3 million barrels of natural gas liquids. These revisions are attributed to utilizing higher projected  \( CO_{2} \)  flood recoveries resulting from updated performance at SACROC used to calculate reserves. There are 2.6 million barrels of crude oil reserves attributed to future development of the Katz (Strawn) unit  \( CO_{2} \)  flood where the produced gas containing natural gas liquids is injected with the  \( CO_{2} \) . The proved undeveloped reserves for the Katz (Strawn) unit  \( CO_{2} \)  flood represent 9.0% of proved undeveloped reserves.

These revisions to our previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 31.0% at year end



2011 to 36.4% at year end 2012. After giving effect to production and revisions to previous estimates during 2012, total proved reserves of crude oil increased by 2.5 million barrels and total proved reserves of natural gas liquids increased by 1.8 million barrels.

As of December 31, 2012, we had 53.0 million barrels of crude oil and 2.4 million barrels of natural gas liquids classified as proved developed reserves. Also, as of year end 2012, we had 28.9 million barrels of crude oil and 3.5 million barrels of natural gas liquids classified as proved undeveloped reserves. Total proved reserves as of December 31, 2012, were 82.0 million barrels of crude oil and 6.0 million barrels of natural gas liquids. We currently expect that the proved undeveloped reserves we report as of December 31, 2012 will be developed within the next five years.

During 2012, we filed estimates of our oil and gas reserves for the year 2011 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this Note exceeds 5%.

The following Reserve Quantity Information table discloses estimates, as of December 31, 2012, 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. This data has been prepared using current prices and costs, as discussed above, and the estimates of reserves and future revenues in this Note conform to the guidelines of the U.S. Securities and Exchange Commission (SEC).

Reserve Quantity Information

<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, 2009</td><td>80,844</td><td>5,920</td><td>698</td></tr><tr><td>Revisions of previous estimates(c)</td><td>16,294</td><td>1,059</td><td>2,923</td></tr><tr><td>Production</td><td>(12,962)</td><td>(2,116)</td><td>(523)</td></tr><tr><td>As of December 31, 2010</td><td>84,176</td><td>4,863</td><td>3,098</td></tr><tr><td>Revisions of previous estimates(d)</td><td>4,719</td><td>567</td><td>687</td></tr><tr><td>Improved recovery(e)</td><td>3,018</td><td>—</td><td>—</td></tr><tr><td>Production</td><td>(12,466)</td><td>(1,285)</td><td>(544)</td></tr><tr><td>As of December 31, 2011</td><td>79,447</td><td>4,145</td><td>3,241</td></tr><tr><td>Revisions of previous estimates(f)</td><td>15,540</td><td>3,285</td><td>4,881</td></tr><tr><td>Extensions and Discoveries</td><td>26</td><td>—</td><td>—</td></tr><tr><td>Sales of Reserves in place</td><td>(239)</td><td>(38)</td><td>(143)</td></tr><tr><td>Production</td><td>(12,824)</td><td>(1,416)</td><td>(440)</td></tr><tr><td>As of December 31, 2012</td><td>81,950</td><td>5,976</td><td>7,539</td></tr><tr><td>Proved developed reserves:</td><td></td><td></td><td></td></tr><tr><td>As of December 31, 2010</td><td>56,423</td><td>2,221</td><td>3,098</td></tr><tr><td>As of December 31, 2011</td><td>55,652</td><td>1,823</td><td>3,241</td></tr><tr><td>As of December 31, 2012</td><td>53,006</td><td>2,433</td><td>7,539</td></tr><tr><td>Proved undeveloped reserves:</td><td></td><td></td><td></td></tr><tr><td>As of December 31, 2010</td><td>27,753</td><td>2,642</td><td>—</td></tr><tr><td>As of December 31, 2011</td><td>23,795</td><td>2,322</td><td>—</td></tr><tr><td>As of December 31, 2012</td><td>28,944</td><td>3,543</td><td>—</td></tr></table>

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries.



## Item 15. Exhibits, Financial Statement Schedules. (continued)

(b) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

(c) Predominantly due to higher product prices used to determine reserve volumes and a change in methodology used for the Yates Field Unit. In 2010, our third party oil and gas consultants revised the methodology used to estimate reserves for our Yates Field Unit in order to take greater account of the reservoir mechanisms associated with carbon dioxide injection.

(d) Predominantly due to higher product prices used to determine reserve volumes.

(e) Represents volumes added with the development of the Katz (Strawn) unit carbon dioxide flood.

(f) Predominantly due to higher  \( CO_{2} \)  flood recoveries based on updated performance at the SACROC Unit.

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 underlie 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;

• pricing is applied based upon the 12 month unweighted arithmetic average of the first day of the month price for 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>2012</td><td>2011</td><td>2010</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>$     7,807</td><td>$     7,648</td><td>$     6,666</td><td></td></tr><tr><td>Future production costs</td><td>(2,923)</td><td>(2,806)</td><td>(2,388)</td><td></td></tr><tr><td>Future development costs(b)</td><td>(1,011)</td><td>(1,443)</td><td>(1,434)</td><td></td></tr><tr><td>Undiscounted future net cash flows</td><td>3,873</td><td>3,399</td><td>2,844</td><td></td></tr><tr><td>10% annual discount</td><td>(1,168)</td><td>(1,205)</td><td>(946)</td><td></td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$     2,705</td><td>$     2,194</td><td>$     1,898</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries.

(b) Includes abandonment costs.

The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in millions):



## Changes in the Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves

<table><tr><td rowspan="2"></td><td colspan="4">As of December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</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>$ 2,194</td><td>$ 1,898</td><td>$ 1,263</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>(895)</td><td>(949)</td><td>(828)</td><td></td></tr><tr><td>Net changes in prices, production and other costs(b)</td><td>(88)</td><td>697</td><td>890</td><td></td></tr><tr><td>Development costs incurred</td><td>353</td><td>416</td><td>248</td><td></td></tr><tr><td>Net changes in future development costs</td><td>64</td><td>(317)</td><td>(296)</td><td></td></tr><tr><td>Improved recovery</td><td>—</td><td>10</td><td>—</td><td></td></tr><tr><td>Extensions and recoveries(c)</td><td>5</td><td>—</td><td>—</td><td></td></tr><tr><td>Sales of reserves in place(d)</td><td>(5)</td><td>—</td><td>—</td><td></td></tr><tr><td>Revisions of previous quantity estimates(e)</td><td>871</td><td>257</td><td>494</td><td></td></tr><tr><td>Accretion of discount</td><td>206</td><td>182</td><td>127</td><td></td></tr><tr><td>Net change for the year</td><td>511</td><td>296</td><td>635</td><td></td></tr><tr><td>Present value as of December 31,</td><td>$ 2,705</td><td>$ 2,194</td><td>$ 1,898</td><td></td></tr></table>

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries.

(b) Excludes the effect of losses attributable to KMP’s hedging contracts of $28 million, $285 million and $220 million for each of the years ended December 31, 2012, 2011 and 2010, respectively.

(c) Primarily due to the extension of the SACROC Unit.

(d) Sale of the Claytonville Field Unit.

(e) 2012 revisions were primarily due to higher projected CO \( _{2} \)  flood recoveries resulting from updated performance at SACROC and the addition of proved undeveloped reserve volumes at the Katz (Strawn) Unit carbon dioxide flood. 2011 revisions were primarily due to higher product prices used to determine reserve volumes and the addition of the Katz (Strawn) carbon dioxide flood. 2010 revisions were primarily due to higher product prices used to determine reserve volumes and the change in methodology discussed above.



## 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

(principal financial and accounting officer)

Date: February 28, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.



<table><tr><td>Signature</td><td>Title</td><td>Date</td></tr><tr><td>/s/ KIMBERLY A. DANG</td><td>Vice President and Chief Financial Officer (principal financial officer and principal accounting officer)</td><td>February 28, 2013</td></tr><tr><td>Kimberly A. Dang</td><td></td><td></td></tr><tr><td>/s/ RICHARD D. KINDER</td><td>Director, Chairman and Chief Executive Officer (principal executive officer)</td><td>February 28, 2013</td></tr><tr><td>Richard D. Kinder</td><td></td><td></td></tr><tr><td>/s/ ANTHONY W. HALL, JR.</td><td>Director</td><td></td></tr><tr><td>Anthony W. Hall, Jr.</td><td></td><td>February 28, 2013</td></tr><tr><td></td><td></td><td></td></tr><tr><td>Steven J. Kean</td><td>Director</td><td></td></tr><tr><td>Deborah A. Macdonald</td><td>Director</td><td></td></tr><tr><td>/s/ MICHAEL MILLER</td><td>Director</td><td></td></tr><tr><td>Michael Miller</td><td></td><td>February 28, 2013</td></tr><tr><td>/s/ MICHAEL C. MORGAN</td><td>Director</td><td></td></tr><tr><td>Michael C. Morgan</td><td></td><td>February 28, 2013</td></tr><tr><td>/s/ FAYEZ SAROFIM</td><td>Director</td><td></td></tr><tr><td>Fayez Sarofim</td><td></td><td>February 28, 2013</td></tr><tr><td>/s/ C. PARK SHAPER</td><td>Director</td><td></td></tr><tr><td>C. Park Shaper</td><td></td><td>February 28, 2013</td></tr><tr><td>/s/ JOEL V. STAFF</td><td>Director</td><td></td></tr><tr><td>Joel V. Staff</td><td></td><td>February 28, 2013</td></tr><tr><td>/s/ JOHN STOKES</td><td>Director</td><td></td></tr><tr><td>John Stokes</td><td></td><td>February 28, 2013</td></tr><tr><td>/s/ ROBERT F. VAGT</td><td>Director</td><td></td></tr><tr><td>Robert F. Vagt</td><td></td><td>February 28, 2013</td></tr></table>

Representing a majority of the Board of Directors of Kinder Morgan, Inc.



## KINDER MORGAN, INC. AND SUBSIDIARIES

## EXHIBIT 12.1 - STATEMENT RE: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

## (Dollars in millions except ratio amounts)

<table><tr><td rowspan="2"></td><td colspan="6">Year Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td>2009</td><td>2008</td><td></td></tr><tr><td>Earnings:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pre-tax income from continuing operations before cumulative effect of a change in accounting principle and before adjustment for noncontrolling interests and equity earnings (including amortization of excess cost of equity investments) per statements of income</td><td>$ 1,873</td><td>$ 591</td><td>$ 510</td><td>$ 730</td><td>$ (3,249)</td><td></td></tr><tr><td>Add:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fixed charges</td><td>1,486</td><td>766</td><td>704</td><td>656</td><td>751</td><td></td></tr><tr><td>Amortization of capitalized interest</td><td>5</td><td>5</td><td>4</td><td>4</td><td>3</td><td></td></tr><tr><td>Distributed income of equity investees</td><td>311</td><td>200</td><td>132</td><td>128</td><td>158</td><td></td></tr><tr><td>Less:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest capitalized from continuing operations</td><td>(27)</td><td>(15)</td><td>(13)</td><td>(33)</td><td>(50)</td><td></td></tr><tr><td>Noncontrolling interest in pre-tax income of subsidiaries with no fixed charges</td><td>17</td><td>(22)</td><td>(107)</td><td>(83)</td><td>(126)</td><td></td></tr><tr><td>Income (loss) as adjusted</td><td>$ 3,665</td><td>$ 1,525</td><td>$ 1,230</td><td>$ 1,402</td><td>$ (2,513)</td><td></td></tr><tr><td>Fixed charges:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest and debt expense, net per statements of income (includes amortization of debt discount, premium, and debt issuance costs; excludes capitalized interest)</td><td>$ 1,454</td><td>$ 718</td><td>$ 681</td><td>$ 632</td><td>$ 725</td><td></td></tr><tr><td>Add:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Portion of rents representative of the interest factor</td><td>32</td><td>48</td><td>23</td><td>24</td><td>26</td><td></td></tr><tr><td>Fixed charges</td><td>$ 1,486</td><td>$ 766</td><td>$ 704</td><td>$ 656</td><td>$ 751</td><td></td></tr><tr><td>Ratio of earnings to fixed charges</td><td>2.47</td><td>1.99</td><td>1.75</td><td>2.14</td><td>(a)</td><td></td></tr></table>

(a) For the year ended December 31, 2008, fixed charges exceeded earnings by $3,264 million. In 2008, Kinder Morgan, Inc. recognized a $4,033 million non-cash goodwill impairment charge associated with its investment in Kinder Morgan Energy Partners, L. P.



## Kinder Morgan, Inc.

## Subsidiaries of the Registrant

Kinder Morgan (Delaware), Inc.
Kinder Morgan G. P., Inc.
Kinder Morgan Energy Partners, L.P.
KN Telecommunications, Inc.
Kinder Morgan Foundation (nonprofit)
K N Gas Gathering, Inc.
Horizon Pipeline Company, L.L.C. (50%)
Wildhorse Energy Partners, LLC (55%)
KM Insurance Ltd.
Kinder Morgan Illinois Pipeline LLC
NGPL PipeCo LLC
Knight Power Company LLC
NGPL HoldCo Inc.
Natural Gas Pipeline Company of America LLC
Kinder Morgan Finance Company LLC
Kinder Morgan Canada LLC
NGPL Holdco LLC
Midco LLC
El Paso Holdco LLC
KMGP Contracting Services LLC



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-3 (Nos. 333-179812, 333-179813 and 333-179814) and (ii) Form S-8 (Nos. 333-172170, 333-172582, 333-172584, 333-172606, 333-172808 and 333-181782) of Kinder Morgan, Inc. of our report dated February 28, 2013 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2013



As oil and gas consultants, we hereby consent to the use of our name and our report dated January 4, 2013, in this Form 10-K, incorporated by reference into Kinder Morgan Energy Partners, L.P.'s previously filed Registration Statement File Nos. 333-122424, 333-25995, 333-62155, 333-33726, 333-54616, 333-60912-01, 333-55866-01, 333-91316-01, 333-102961, 333-102962-01, 333-124471, 333-141491, 333-142584, 333-153598, 333-164408, 333-171864, 333-179814-02, and 333-179377 on Form S-3; 333-167562, 333-18181, and 333-179813-02 on Form S-3ASR; and 333-122168 and 333-56343 on Form S-8.

NETHERLAND, SEWELL & ASSOCIATES, INC.

/s/ Danny D. Simmons

By:___

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

February 11, 2013



# KINDER MORGAN, INC.
CERTIFICATION 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

I, Richard D. Kinder, certify that:

1. I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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 in the United States;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 28, 2013

/s/ RICHARD D. KINDER

Richard D. Kinder

Chairman and Chief Executive Officer



# KINDER MORGAN, INC.
CERTIFICATION 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

I, Kimberly A. Dang, certify that:

1. I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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 in the United States;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 28, 2013

/s/ KIMBERLY A. DANG

Kimberly A. Dang

Vice President and Chief Financial Officer



# KINDER MORGAN, INC.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Kinder Morgan, Inc. (the "Company") for the yearly period ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 28, 2013

/s/ RICHARD D. KINDER

Richard D. Kinder

Chairman and Chief Executive Officer



# KINDER MORGAN, INC.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Kinder Morgan, Inc. (the "Company") for the yearly period ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 28, 2013

/s/ KIMBERLY A. DANG

Kimberly A. Dang

Vice President and Chief Financial Officer



# KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
EXHIBIT 95.1 – MINE SAFETY DISCLOSURES

This exhibit contains the information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

The following table provides information about citations, orders and notices issued under the Federal Mine Safety and Health Act of 1977 by the federal Mine Safety and Health Administration (the "Mine Act") by the federal Mine Safety and Health Administration ("MSHA") for our mines during the year ended December 31, 2012:

<table><tr><td>Mine or Operating Name/MSHA Identification Number</td><td>Section 104 S&amp;S citations 9(#)</td><td>Section 104 (b) and Orders (#)</td><td>Section 110 (b) (2) and Orders Violations (#)</td><td>Section 106 (a) and Orders (#)</td><td>Total Dollar Value of MSHA Assessments Related Proposed ($)</td><td>Total Number of Mining Related Faltaltilities</td><td>Received Notice of Potential to Legal Violations Pattern under Section 104(e) (yes/no)</td><td>Received Notice of Potential to Legal Actions Violations Pattern under Section 104(e) (yes/no)</td><td>Legal Actions Initiated as During Period of Day of Period (#)</td><td>Legal Actions During Period (Day)</td><td>Legal Actions Resolved During Period (#)</td></tr><tr><td>1103225</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cahokia</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>$ 362</td><td>—</td><td>No</td><td>No</td><td>1</td><td>—</td></tr><tr><td>1103224</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Kellogg</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>$ 200</td><td>—</td><td>No</td><td>No</td><td>—</td><td>—</td></tr><tr><td>1103140 Cora</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>$ 200</td><td>—</td><td>No</td><td>No</td><td>—</td><td>—</td></tr><tr><td>1518234</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Grand Rivers</td><td>11</td><td>—</td><td>1</td><td>—</td><td>—</td><td>$ 10,130</td><td>—</td><td>No</td><td>No</td><td>2</td><td>4</td></tr></table>

The dollar value represents the total dollar value of all MSHA citations issued and assessed for the four terminals noted above. The value includes S&S and non-S&S citations issued during calendar year 2012. The dollar value represents citations paid, pending payment, and citations in contest as of December 31, 2012.

The MSHA citations, orders and assessments reflected above are those initially issued or proposed by MSHA. They do not reflect subsequent changes in the level of severity of a citation or order or the value of an assessment that may occur as a result of proceedings conducted in accordance with MSHA rules.

As of December 31, 2012, there were no pending legal actions before the Federal Mine Safety and Health Review Commission involving any of our mines other than actions filed under the following docket numbers (all of which are contests of citations or orders under Section 104 of the Mine Act):

1103225-Cahokia Terminal: 2011 Filings “Open” status

• Docket LAKE 2011-995

1518234-Grand Rivers Terminal: 2012 Filings “Open” status

• Docket KENT 2012-1562

• Docket KENT 2012-1561

During the year ended December 31, 2012, the following legal actions before the Federal Mine Safety and Health Review Commission involving our mines were resolved:

1518234-1103225-Cahokia Terminal

• Docket LAKE 2012-114

• Docket LAKE 2011-624






1518234-Grand Rivers Terminal

• Docket KENT 2012-703

• Docket KENT 2012-704

• Docket KENT 2012-65

• Docket KENT 2012-154



Mr. Charles E. Fox

Kinder Morgan CO2 Company, L.P.

500 Dallas Street, Suite 1000

Houston, Texas 77002

Dear Mr. Fox:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, to the Kinder Morgan CO2 Company, L.P. (Kinder Morgan) interest in certain oil and gas properties located in Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Kinder Morgan. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Kinder Morgan Energy Partners, L.P.'s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Kinder Morgan interest in these properties, as of December 31, 2012, to be:

<table><tr><td rowspan="2">Category</td><td colspan="3">Net Reserves</td><td colspan="2">Future Net Revenue (MS)</td></tr><tr><td>Oil (MBBL)</td><td>NGL (MBBL)</td><td>Gas (MMCF)</td><td>Total</td><td>Present Worth at 10%</td></tr><tr><td>Proved Developed Producing</td><td>51,349</td><td>2,433</td><td>7,540</td><td>2,487,493</td><td>1,764,951</td></tr><tr><td>Proved Developed Non-Producing</td><td>1,657</td><td>—</td><td>—</td><td>55,004</td><td>33,077</td></tr><tr><td>Proved Undeveloped</td><td>28,944</td><td>3,542</td><td>—</td><td>1,330,599</td><td>906,713</td></tr><tr><td>Total Proved</td><td>81,950</td><td>5,975</td><td>7,540</td><td>3,873,096</td><td>2,704,741</td></tr></table>

The oil reserves shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Kinder Morgan's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Kinder Morgan's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2012. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.21 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $2.757 per MMBTU is adjusted by field for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $90.82 per barrel of oil, $57.35 per barrel of NGL, and $2.894 per MCF of gas.

Operating costs used in this report are based on operating expense records of Kinder Morgan. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct



lease- and field-level costs and Kinder Morgan's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Kinder Morgan and are based on capital budgets and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Kinder Morgan's estimates of the costs to abandon the wells and production facilities; these estimates do not include any salvage value for the lease and well equipment. Capital costs and abandonment costs are held constant to the date of expenditure.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Kinder Morgan interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Kinder Morgan receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations and for properties that rely on continued CO \( _{2} \)  injection; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Kinder Morgan, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHIERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

/s/ Derek F. Newton /s/ Mike K. Norton



By: By:

Derek F. Newton, P.E. 97689 Mike K. Norton, P.G. 441

Vice President Senior Vice President

Date Signed: January 4, 2013 Date Signed: January 4, 2013

DFN:JLM



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