Edgar Filing: KINDER MORGAN, INC.

KMI-2012.12.31-10K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________

Form 10-K



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

For the fiscal year ended December 31, 2012



[ ]	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		80-0682103
(State or other jurisdiction of incorporation or organization)		(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	Name of each exchange on which registered
Class P Common Stock	New York Stock Exchange
Warrants to Purchase Class P Common Stock	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 o No þ

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 o No þ

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 þ No o

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 þ No o

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. þ

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 þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

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 o No þ

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



		Page Number
	PART I
Items 1. and 2.	Business and Properties	5
	General Development of Business	5
	Organizational Structure	5
	Recent Developments	6
	Financial Information about Segments	12
	Narrative Description of Business	12
	Business Strategy	12
	Business Segments	13
	Natural Gas Pipelines	13
	Products Pipelines—KMP	21
	CO2—KMP	23
	Terminals—KMP	27
	Kinder Morgan Canada—KMP	28
	Other	29
	Major Customers	29
	Regulation	29
	Environmental Matters	32
	Other	36
	Financial Information about Geographic Areas	36
	Available Information	36
Item 1A.	Risk Factors	36
Item 1B.	Unresolved Staff Comments	48
Item 3.	Legal Proceedings	48
Item 4.	Mine Safety Disclosures	48

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	49
Item 6.	Selected Financial Data	50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53
	General	53
	Critical Accounting Policies and Estimates	60
	Results of Operations	63
	Income Taxes—Continuing Operations	82
	Liquidity and Capital Resources	82
	Recent Accounting Pronouncements	88
	Information Regarding Forward-Looking Statements	88
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	91
	Energy Commodity Market Risk	91
	Interest Rate Risk	92
Item 8.	Financial Statements and Supplementary Data	93



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, CO₂ 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

Kinder Morgan, Inc. Form 10-K

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

Kinder Morgan, Inc. Form 10-K

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 Uinta 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, Sierrita 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, Sierrita 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 Sierrita Gas pipeline would interconnect with a new 36-inch diameter natural gas pipeline to be built in Mexico. Sierrita Gas Pipeline LLC filed an application with the FERC on February 7, 2013, and subject to FERC approval, we expect that construction of the Sierrita 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

Kinder Morgan, Inc. Form 10-K

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.

Kinder Morgan, Inc. Form 10-K

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. KMI 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.

CO₂-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

Kinder Morgan, Inc. Form 10-K

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

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 CO₂ 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

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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.

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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 CO₂-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 CO₂-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.

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

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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.;


▪	CO₂—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

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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

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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

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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 Uinta 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

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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.

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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 Piceance 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)

Kinder Morgan, Inc. Form 10-K

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

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 Overthrust, 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

Kinder Morgan, Inc. Form 10-K

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)

Kinder Morgan, Inc. Form 10-K

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.

Kinder Morgan, Inc. Form 10-K

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

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.

Kinder Morgan, Inc. Form 10-K

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; Indianola, 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.

CO₂—KMP

The CO₂—KMP business segment consists of Kinder Morgan CO₂ Company, L.P. and its consolidated affiliates, collectively referred to in this report as KMCO₂. The CO₂—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. KMCO₂’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. KMCO₂also 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

Kinder Morgan, Inc. Form 10-K

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

KMCO₂ 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. KMCO₂ 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 KMCO₂ 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. KMCO₂’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 KMCO₂ per day).

KMCO₂ 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 KMCO₂ 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, KMCO₂ 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:



	Productive Wells (a)		Service Wells (b)		Drilling Wells (c)
	Gross	Net	Gross	Net	Gross	Net
Crude Oil	2,089	1,311	924	718	3	3
Natural Gas	5	2	—	—	—	—
Total Wells	2,094	1,313	924	718	3	3

____________


(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:

Kinder Morgan, Inc. Form 10-K

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



	Year Ended December 31,
	2012	2011	2010
Productive
Development	59	85	70
Exploratory	—	—	—
Dry
Development	—	—	—
Exploratory	—	—	—
Total Wells	59	85	70

____________

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:



	Gross	Net
Developed Acres	68,945	65,811
Undeveloped Acres	14,557	13,971
Total	83,502	79,782

____________

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

KMCO₂ 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 KMCO₂ per day excluding the value associated to KMCO₂’s 28% net profits interest).

Sales and Transportation Activities

Carbon Dioxide

KMCO₂ 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.

KMCO₂ 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.

KMCO₂’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.

Kinder Morgan, Inc. Form 10-K

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

Carbon Dioxide Pipelines

As a result of KMCO₂’s 50% ownership interest in Cortez Pipeline Company, KMCO₂owns 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.

KMCO₂’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 KMCO₂) and the Bravo and Sheep Mountain pipelines (operated by Oxy Permian). Central Basin’s mainline terminates near McCamey, where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the Central Basin pipeline are not regulated.

KMCO₂’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.

KMCO₂’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.

KMCO₂ 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, KMCO₂ 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 KMCO₂’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

KMCO₂ 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 KMCO₂ to better manage crude oil deliveries from its oil field interests in West Texas. KMCO₂ 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

KMCO₂’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. KMCO₂’s ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines. KMCO₂ also competes with

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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.

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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

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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 CO₂-KMP business segment also sells natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines and CO₂-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

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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

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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

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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.

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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.

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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

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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 CO₂-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

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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 McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.

Because our operations, including our compressor stations and natural gas processing plants in our Natural Gas Pipelines 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 CO₂-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 CO₂-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 CO₂-KMP segment.

The revenues, profitability and future growth of the CO₂-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 CO₂-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 CO₂-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.



	Price Range Per Class P Share				Declared Cash Dividends (a)
	Low		High		Declared Cash Dividends (a)
2012
First Quarter	$	31.76	$	39.25	$	0.32
Second Quarter	$	30.51	$	40.25	$	0.35
Third Quarter	$	32.03	$	36.63	$	0.36
Fourth Quarter	$	31.93	$	36.50	$	0.37
2011
First Quarter (beginning February 11, 2011)(b)	$	29.50	$	32.14	$	0.14
Second Quarter	$	26.87	$	29.97	$	0.30
Third Quarter	$	23.51	$	29.45	$	0.30
Fourth Quarter	$	24.66	$	32.25	$	0.31

__________


(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



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


(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.

Kinder Morgan, Inc. Form 10-K

Item 6. Selected Financial Data. (continued)

Five-Year Review Kinder Morgan, Inc. and Subsidiaries

	Year Ended December 31,
	2012(a)			2011			2010			2009			2008
	(In millions, except per share and ratio data)
Revenues	$	9,973		$	7,943		$	7,852		$	6,879		$	11,716
Operating income (loss)(b)	$	2,593		$	1,423		$	1,133		$	1,257		$	(2,044	)
Earnings (loss) from equity investments(c)	$	153		$	226		$	(274	)	$	123		$	116
Income (loss) from continuing operations	$	1,204		$	449		$	64		$	523		$	(2,860	)
(Loss) income from discontinued operations, net of tax	$	(777	)	$	211		$	236		$	250		$	(343	)
Net income (loss)	$	427		$	660		$	300		$	773		$	(3,203	)
Net income attributable to noncontrolling interests	$	(112	)	$	(66	)	$	(341	)	$	(278	)	$	(396	)
Net income (loss) attributable to Kinder Morgan, Inc.	$	315		$	594		$	(41	)	$	495		$	(3,599	)
Class P Shares
Basic and Diluted Earnings Per Common Share From Continuing Operations	$	0.56		$	0.70
Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations	(0.21		)	0.04
Total Basic and Diluted Earnings Per Common Share	$	0.35		$	0.74
Class A Shares
Basic and Diluted Earnings Per Common Share From Continuing Operations	$	0.47		$	0.64
Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations	(0.21		)	0.04
Total Basic and Diluted Earnings Per Common Share	$	0.26		$	0.68
Basic Weighted Average Number of Shares Outstanding:
Class P shares	461			118
Class A shares	446			589
Diluted Weighted Average Number of Shares Outstanding:
Class P shares	908			708
Class A shares	446			589
Dividends per common share declared(d)	$	1.40		$	1.05
Capital expenditures – KMI	$	148		$	1		$	2		$	—		$	12
Capital expenditures – KMP	$	1,806		$	1,199		$	1,004		$	1,324		$	2,533
Capital expenditures – EPB (since May 25, 2012)	$	68		$	—		$	—		$	—		$	—
Ratio of earnings to fixed charges(e)	$	2.47		$	1.99		$	1.75		$	2.14		(e)



	December 31,
	2012(a)		2011		2010		2009		2008
	(In millions)
Net property, plant and equipment	$	30,996	$	17,926	$	17,071	$	16,804	$	16,110
Total assets	$	68,185	$	30,717	$	28,908	$	27,581	$	25,445
Long-term debt – KMI(f)	$	10,441	$	2,078	$	2,918	$	2,925	$	2,927
Long-term debt – KMP(g)	$	14,714	$	11,183	$	10,301	$	10,022	$	8,293
Long-term debt – EPB(h)	$	4,254	$	—	$	—	$	—	$	—

____________


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

Kinder Morgan, Inc. Form 10-K

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, $(14) 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 933 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;

Kinder Morgan, Inc. Form 10-K

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 transmix facilities;


•	CO2-KMP-(i) the production, transportation and marketing of carbon dioxide, referred to as CO₂, to oil fields that use CO₂ to increase production of oil; (ii) ownership interests in and/or operation of oil fields 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 transmix 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 CO₂ 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 CO₂-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 CO₂-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,

Kinder Morgan, Inc. Form 10-K

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

Kinder Morgan, Inc. Form 10-K

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.



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

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.

Kinder Morgan, Inc. Form 10-K

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

Kinder Morgan, Inc. Form 10-K

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 NGPL 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.

Kinder Morgan, Inc. Form 10-K

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

_____________


(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:



	Year Ended December 31,
	2012		2011
Depreciation, depletion and amortization from continuing operations	$	1,419	$	1,068
Depreciation, depletion and amortization from discontinued operations	$	7	$	24

(d)Consists of the following:



	Year Ended December 31,
	2012			2011
Earnings from equity investments from continuing operations (1)	$	(153	)	$	(226	)
Earnings from equity investments from discontinued operations	$	(70	)	$	(87	)

(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,

Kinder Morgan, Inc. Form 10-K

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.

Kinder Morgan, Inc. Form 10-K

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.

Kinder Morgan, Inc. Form 10-K

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.

Kinder Morgan, Inc. Form 10-K

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:



	Pension Benefits						Other Postretirement Benefits
	Net Benefits Cost			Change in Funded Status and Pretax Accumulated Other Comprehensive Income			Net Benefits Cost			Change in Funded Status and Pretax Accumulated Other Comprehensive Income
	(In millions)
One percent increase in:
Discount rates	$	4		$	245		$	1		$	56
Expected return on plan assets	$	(14	)	$	—		$	(1	)	$	—
Rate of compensation increase	$	1		$	(6	)	$	—		$	—
Health care cost trends	$	—		$	—		$	1		$	(47	)

One percent decrease in:
Discount rates	$	(6	)	$	(291	)	$	(2	)	$	(66	)
Expected return on plan assets	$	14		$	—		$	1		$	—
Rate of compensation increase	$	(1	)	$	6		$	—		$	—
Health care cost trends	$	—		$	—		$	(1	)	$	41

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.

Kinder Morgan, Inc. Form 10-K

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

Results of Operations

Consolidated



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

___________

(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.

Kinder Morgan, Inc. Form 10-K

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 CO2—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 CO2—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 CO2—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,

Kinder Morgan, Inc. Form 10-K

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