10-K 1 kmp-20121231x10k.htm 10-K KMP-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

or
 
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
 

Commission file number: 1-11234

Kinder Morgan Energy Partners, L.P.
(Exact name of registrant as specified in its charter)

Delaware
76-0380342
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)

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
Common Units
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.  Yes [X]    No [   ]
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.  Yes [   ]   No [X]
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes [X]   No [   ]
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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 [X]   No [   ]
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filer [X]   Accelerated filer [   ]     Non-accelerated filer [   ]     Smaller reporting company [   ]
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).  Yes [   ]   No [X]
 
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 29, 2012 was approximately $17,538,123,334.  As of January 31, 2013, the registrant had 252,756,425 Common Units outstanding.




KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS

 
 
Page
Number
 
PART I
 
Items 1 and 2.
Business and Properties
 
General Development of Business
 
Organizational Structure
 
Recent Developments
 
Financial Information about Segments
 
Narrative Description of Business
 
Business Strategy
 
Business Segments
 
Products Pipelines
 
Natural Gas Pipelines
 
CO2
 
Terminals
 
Kinder Morgan Canada
 
Major Customers
 
Regulation
 
Environmental Matters
 
Other
 
Financial Information about Geographic Areas
 
Available Information
Item 1A.
Risk Factors      
Item 1B.
Unresolved Staff Comments
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
 
 
 
 
PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
   Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
General
 
Critical Accounting Policies and Estimates
 
Results of Operations
 
Liquidity and Capital Resources
 
Recent Accounting Pronouncements
 
Information Regarding Forward-Looking Statements
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
Energy Commodity Market Risk
 
Interest Rate Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
 
 
 
 
PART III
 
Item 10.
Directors, Executive Officers and Corporate Governance
 
Directors and Executive Officers of our General Partner and its Delegate
 
Corporate Governance
 
Section 16(a) Beneficial Ownership Reporting Compliance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
 
 
 
 
PART IV
 
Item 15.
Exhibits and Financial Statement Schedules
 
Index to Financial Statements
Signatures                                                                                                                                  




PART I

Items 1 and 2.  Business and Properties.

Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America, and unless the context requires otherwise, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., our operating limited partnerships and their majority-owned and controlled subsidiaries. We own an interest in or operate approximately 46,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described more fully below in “-(c) Narrative Description of Business-Business Segments”).
Our pipelines transport natural gas, refined petroleum products, crude oil, carbon dioxide and other products, and our terminals store petroleum products and chemicals, and handle such products as ethanol, coal, petroleum coke and steel. We are also the leading producer and transporter of carbon dioxide, commonly called CO2, for enhanced oil recovery projects in North America. 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.
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, referred to as the SEC. Our accounting records are maintained in United States dollars, and all references to dollars in this report are to United States dollars, except where stated otherwise. Canadian dollars are designated as C$. Our consolidated financial statements include our accounts and those of our operating limited partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.
(a) General Development of Business
 

Organizational Structure
 
We are a Delaware limited partnership formed in August 1992, and our common units, which represent limited partner interests in us, trade on the New York Stock Exchange under the symbol “KMP.” In general, our limited partner units, consisting of common units, Class B units (the Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange) and i-units, will vote together as a single class, with each common unit, Class B unit, and i-unit having one vote. Our partnership agreement requires us to distribute all of our available cash, as defined in our partnership agreement, to our partners on a quarterly basis within 45 days after the end of each calendar quarter. We pay our quarterly distributions to our common unitholders, our sole Class B unitholder and our general partner in cash, and we pay our quarterly distributions to our sole i-unitholder in additional i-units rather than in cash. For further information about our distributions, see Note 11 “Related Party Transactions-Partnership Interests and Distributions” to our consolidated financial statements included elsewhere in this report.
Kinder Morgan, Inc. and Kinder Morgan G.P., Inc.

Kinder Morgan, Inc., a Delaware corporation referred to as KMI in this report, indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation; however, in July 2007, our general partner issued and sold to a third party 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057. The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line LLC. KMI’s common stock trades on the New York Stock Exchange under the symbol “KMI.”
Effective on May 25, 2012, KMI 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. and this EP acquisition created one of the largest energy companies in the United States.
As of December 31, 2012, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management, LLC (discussed following), an approximate 12.8% interest in us. In addition to the distributions it receives from its limited and general partner interests, KMI also receives an incentive distribution from us as a result of its ownership of our general partner. Including both its general and limited partner interests in us, at the 2012 distribution level, KMI received approximately 51% of all quarterly distributions of




available cash from us, with approximately 45% and 6% of all quarterly distributions from us attributable to KMI’s general partner and limited partner interests, respectively.
Kinder Morgan Management, LLC

Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company formed in February 2001. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. KMR’s shares represent limited liability company interests and trade on the New York Stock Exchange under the symbol “KMR.”
Under the delegation of control agreement, KMR, as the delegate of our general partner, manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their majority-owned and controlled subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR’s activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their majority-owned and controlled subsidiaries. As of December 31, 2012, KMR, through its sole ownership of our i-units, owned approximately 30.8% of all of our outstanding limited partner units.

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.

Products Pipelines
 
In August 2012, we and Valero Energy Corporation began construction on our previously announced Parkway Pipeline, a new 141-mile, 16-inch diameter pipeline that will transport refined petroleum products from refineries located in Norco, Louisiana, to Plantation Pipe Line Company’s (our approximately 51%-owned equity investee) petroleum transportation hub located in Collins, Mississippi. We have substantially completed the Lake Pontchartrain portion of the pipeline, and construction activities continue on land in Louisiana and Mississippi. Upon completion, we 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, we announced that we would invest approximately $90 million to build a 27-mile, 12-inch diameter lateral pipeline that will extend our Kinder Morgan crude oil/condensate pipeline to Phillips 66’s Sweeny refinery located in Brazoria County, Texas. We 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. We 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. We began construction in December 2012. We expect to place the lateral into initial service at the beginning of the fourth quarter of 2013, and we expect the entire system to be operational by year-end 2013;
In October 2012, we began transporting crude oil and condensate volumes on previously announced Kinder Morgan crude oil/condensate pipeline, which transports available crude oil and condensate 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, we completed our previously announced refined petroleum products storage expansion project at our 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. We 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, we also completed facility modifications to provide for the receipt, storage and blending of biodiesel at our Las Vegas, Nevada; Phoenix, Arizona; and Fresno, California terminals. We began blending operations at all three terminals by the end of January 2013;
As of the date of this report, we continue design and pre-construction activities for our approximately $200 million petroleum condensate processing facility located near our 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. We expect the facility to be in service in the first quarter of 2014. In light of the growth of Eagle Ford shale natural gas liquids production and the associated need for additional condensate processing capacity, we expect to obtain additional customer commitments to underwrite an expansion at this facility; and
As of the date of this report, we are in the final permitting stage for our previously announced Cochin Pipeline reversal project, which will allow us to offer a new service to move light condensate from Kankakee County, Illinois to existing terminal facilities located near Fort Saskatchewan, Alberta, Canada. We received more than 100,000 barrels per day of binding commitments (meaning the project was oversubscribed) for a minimum ten-year term during a successful open season that we completed on May 31, 2012. Due to capacity limitations and the need to reserve some capacity for spot shipments, shippers’ requests were allocated to a total of 85,000 barrels per day of firm capacity. The approximately $260 million project involves both modifying the Western leg of our Cochin Pipeline to Fort Saskatchewan from a point of interconnection with Explorer Pipeline Company’s pipeline in Kankakee County, and building a one million barrel tank farm and associated piping 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.
Natural Gas Pipelines
 
Effective November 1, 2012, KMI sold our FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, L.P. for approximately $1.8 billion (before selling costs) to satisfy terms of a March 15, 2012 agreement with the U.S. Federal Trade Commission (FTC) to divest certain of our assets in order to receive regulatory approval for its EP acquisition. Our FTC Natural Gas Pipelines disposal group’s assets included our (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 our FTC Natural Gas Pipelines disposal group. We recognized a combined $829 million loss from both the 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, we 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 is owned by KMI, which it acquired as part of its 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, KMI has offered to sell both its 50% ownership interest in EPMIC and its 50% ownership interest in the El Paso Natural Gas pipeline system (discussed following) to us in 2013 (in a future drop-down transaction);
On August 1, 2012, we 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 KMI 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 this acquisition of assets from KMI as the drop-down transaction; the combined group of assets acquired from KMI 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.
KMI acquired the drop-down asset group as part of its acquisition of EP 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 KMI to us 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, our 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 El Paso Natural Gas Company, L.L.C.’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 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 constructions 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, we and Copano Energy, L.L.C., referred to in this report as Copano, announced a definitive agreement whereby we 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, which has been approved by the board of directors of both our general partner and Copano, will be a 100% unit for unit transaction with an exchange ratio of 0.4563 of our common units for each Copano unit. The transaction is subject to customary closing conditions, regulatory approvals, and a vote of the Copano unitholders; however, TPG Advisors VI, Inc., Copano’s largest unitholder, has agreed to support the transaction and we expect the transaction to close in the third quarter of




2013.
Copano is a midstream natural gas company that provides comprehensive services to natural gas producers, including natural gas gathering, processing, treating and natural gas liquids fractionation. Copano owns an interest in or operates approximately 6,900 miles of pipelines with 2.7 billion cubic feet per day of natural gas transportation capacity, and also owns nine natural gas processing plants with more than 1.0 billion cubic feet per day of natural gas processing capacity and 315 million cubic feet per day of natural gas treating capacity. Its operations are located primarily in Texas, Oklahoma and Wyoming.
CO2 
 
On January 18, 2012, we announced an approximately $255 million investment to expand the carbon dioxide capacity of our approximately 87%-owned Doe Canyon Deep unit in southwestern Colorado. The expansion project will include the installation of both primary and booster compression and is expected to increase Doe Canyon’s -production rate from 105 million cubic feet of carbon dioxide per day to 170 million cubic feet per day. As of the date of this report, construction continues on both primary and booster compression. We expect 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, we plan 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, we 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. We refer to this combined group of assets as the St. Johns CO2 source field, and as of the date of this report, we continue testing wells and performing predevelopment activities. We anticipate 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

On July 17, 2012, we and Peabody Energy announced that we 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 our Houston Bulk and Deepwater terminal facilities located near Houston; and (ii) through 2020 at our International Marine Terminals facility (IMT), a multi-product, import-export facility located in Myrtle Grove, Louisiana and owned 66 2/3% by us.
Due to the finalization of these agreements, and to previously announced coal throughput agreements with Arch Coal Company, we are proceeding with Phase 3 of our export coal expansion project at IMT. The Phase 3 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 Phase 3 project to be operational in the second quarter 2014. We estimate our share of the total expansion project at IMT (including all phases) will cost approximately $150 million. When completed, our total export coal capacity (for all terminals combined) will be approximately 44.7 million short-tons per year;
On July 19, 2012, we 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 our Galena Park, Texas liquids terminal located on the Houston Ship Channel. BP’s products will be processed at the condensate splitter that we are also currently building near the Galena Park facility, and in conjunction with the lease agreement, we agreed to build five new tanks, which will provide storage for BP’s product. As of the date of this report, construction continues on our approximately $75 million investment;
Effective December 1, 2012, TransMontaigne exercised its previously announced option to acquire up to 50% of our 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 us for an aggregate consideration of $79 million, and following this acquisition, we now own a 55% Class A member interest in BOSTCO (we 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 that will have 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, we 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 and will include the purchase of 42 acres of land, the construction of a new ship dock to handle ocean going vessels, and the construction of 1.2 million barrels of liquids storage tanks (six 150,000-barrel tanks and four 75,000-barrel tanks). We have 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 our 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 to be fully completed in December 2013 and is underpinned by long-term commercial agreements with major Canadian oil producers.  On January 23, 2013, we announced that we 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 we expect to complete construction late third quarter of 2014. We estimate 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 our North 40 crude oil tank farm).
Kinder Morgan Canada

On May 23, 2012, our subsidiary Trans Mountain Pipeline L.P. confirmed binding commercial support for its previously announced proposed expansion of our 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, our 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 United States and on the west coast of British Columbia, and based on the current confirmed shipper response, we 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, which will 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. Our current estimate of total project construction costs is approximately $5.4 billion; and

On December 11, 2012, we announced that we had entered into a definitive agreement to sell both our one-third equity ownership interest in the Express pipeline system and our 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 United States producers to refineries located in the U.S. Rocky Mountain and Midwest regions. Based on the structure of our investment with our Express-Platte partners, we receive approximately $15 million of cash flow on an annual basis from this investment, which is primarily debenture interest. We will redeploy the proceeds from this sale into various growth projects to further benefit our unitholders. The transaction is subject to customary consents and regulatory approvals and is expected to close in the second quarter of 2013. On this date, Spectra also announced that it will acquire the remaining ownership interests in Express, and following its acquisitions, will fully own the Express pipeline system.

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 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report.

2013 Outlook

As previously announced, we anticipate that for the year 2013, (i) we will declare cash distributions of $5.28 per unit, a 6% increase over our cash distributions of $4.98 per unit for 2012; (ii) our 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 our proportionate share of all non-cash depreciation, depletion and amortization expenses of certain joint ventures accounted for under the equity-method of accounting; (iii) we will distribute over $2.0 billion to our limited partners; (iv) we will produce excess cash flow of more than $30 million above our cash distribution target of $5.28 per unit; and (v) we will invest approximately $2.9 billion for our capital expansion program (including small acquisitions and contributions to joint ventures, but excluding acquisitions from KMI). Our anticipated 2013 expansion investment will help drive earnings and cash flow growth in 2013 and beyond, and we estimate that approximately $625 million of the equity required for our 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.
Our 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 our assets is fee based and is not sensitive to commodity prices, our CO2 business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. We hedge the majority of our crude oil production, but do have exposure to unhedged volumes, the majority of which are natural gas liquids volumes. For 2013, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 segment’s cash flows by approximately $6 million (or approximately 0.1% of our combined business segments’ anticipated earnings before depreciation, depletion and amortization expenses).
(b) Financial Information about Segments
 
For financial information on our five reportable business segments, see Note 15 “Reportable Segments” to our consolidated financial statements included elsewhere in this report.

(c) Narrative Description of Business


Business Strategy
 
Our business strategy is to:
 
focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America;

increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound 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 unitholders.
 
It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances.  However, as discussed under Item 1A. “Risk Factors” below, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.
 
We regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions.  Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions, 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 our five operating limited partnerships and their subsidiaries and are grouped into five reportable business segments. These segments are as follows:
Products Pipelines-which consists of approximately 8,600 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 United States;
Natural Gas Pipelines-which consists of approximately 33,000 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;
CO2- which produces, markets and transports, through approximately 1,500 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-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 United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and
Kinder Morgan Canada-which transports crude oil and refined petroleum products through over 2,500 miles of pipelines from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States; plus five associated product terminal facilities.

Products Pipelines

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

West Coast Products Pipelines

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

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

Our Calnev pipeline system consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from our facilities at Colton, California to Las Vegas, Nevada.  The pipeline serves the Mojave Desert through deliveries to a terminal at Barstow, California and two nearby major railroad yards.  It also serves Nellis Air Force Base, located in Las Vegas, and also includes approximately 55 miles of pipeline serving Edwards Air Force Base in California.  In 2012, our Calnev pipeline system transported approximately 108,300 barrels per day of refined products, with the product mix being approximately 40% gasoline, 30% diesel fuel, and 30% jet fuel.





Our West Coast Products Pipelines operations include 15 truck-loading terminals (13 on our 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.

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

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

Plantation Pipe Line Company

We own approximately 51% of Plantation Pipe Line Company, the sole owner of the approximately 3,100-mile refined petroleum products Plantation pipeline system serving the southeastern United States.  We operate the system pursuant to agreements with Plantation and its wholly-owned subsidiary, Plantation Services LLC.  The Plantation pipeline system 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, with the product mix being 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 United States.  Plantation’s principal customers are Gulf Coast refining and marketing companies, and fuel wholesalers.

Central Florida Pipeline

Our 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.  Our Central Florida pipeline operations also include two separate liquids terminals located in Tampa and Taft, Florida, which we own and operate.

In addition to being connected to our 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 our 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, with the product mix being approximately 70% gasoline and ethanol, 10% diesel fuel, and 20% jet fuel.

Our 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 also connected to an ethanol unit train off-load facility.  Our 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

Our Cochin pipeline system consists of an approximately 1,900-mile, 12-inch diameter multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor, Ontario, along with five terminals.  The pipeline operates on a batched basis and has an estimated system capacity of 70,000 barrels per day.  It includes 31 pump stations spaced at 60 mile intervals and




five United States propane terminals.  Underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario through third parties.  The pipeline traverses three provinces in Canada and seven states in the United States and can transport ethane, propane, butane and natural gas liquids to the midwestern United States 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, we 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.

Cypress Pipeline

We own 50% of Cypress Interstate Pipeline LLC, the sole owner of the Cypress pipeline system.  We operate 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 United States.  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

Our Southeast terminal operations consist of 28 high-quality, liquid petroleum products terminals located along the Plantation/Colonial pipeline corridor in the Southeastern United States.  The marketing activities of our Southeast terminal operations are focused on the Southeastern United States from Mississippi through Virginia, including Tennessee.  The primary function involves the receipt of petroleum products from common carrier pipelines, short-term storage in terminal tankage, and subsequent loading onto tank trucks.  Combined, our Southeast 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

Our Transmix operations include the processing of petroleum pipeline transmix, a blend of dissimilar refined petroleum products that have become co-mingled in the pipeline transportation process.  During pipeline transportation, different products are transported through the pipelines abutting each other, and generate a volume of different mixed products called transmix.  We process and separate pipeline transmix into pipeline-quality gasoline and light distillate products at six separate processing facilities located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina.  Combined, our transmix facilities handled approximately 9.2 million barrels in 2012.

Kinder Morgan Crude and Condensate Pipeline

Our 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

Our 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.  Our 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.


Natural Gas Pipelines

Our Natural Gas Pipelines segment contains both interstate and intrastate pipelines, which are FERC regulated and non-FERC regulated natural gas assets, respectively.  Our non-FERC regulated natural gas assets are included in the KM Midstream




Group. Its primary businesses consist of natural gas sales, transportation, storage, gathering, processing and treating.  Within this segment, we own approximately 33,000 miles of natural gas pipelines and associated storage and supply lines. Our transportation network provides access to the major gas supply areas in the western United States, Texas, the Midwest and Northeast, as well as major consumer markets.

KM Midstream Group

Texas Intrastate Natural Gas Pipeline Group

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

The two largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder Morgan Tejas Pipeline.  These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability.  The combined system includes approximately 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 five of which expires in March of 2013.  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.

Our Mier-Monterrey Pipeline consists of a 95-mile natural gas pipeline that stretches from the international border between the United States and Mexico in Starr County, Texas, to Monterrey, Mexico and can transport up to 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.  We have entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for substantially all of the pipeline’s capacity.

Our Kinder Morgan North Texas Pipeline consists of an 82-mile pipeline that transports natural gas from an interconnect with the facilities of Natural Gas Pipeline Company of America LLC (a 20%-owned equity investee of KMI and referred to in this report as NGPL) in Lamar County, Texas to a 1,750-megawatt electricity generating facility located in Forney, Texas, 15 miles east of Dallas, Texas and to a 1,000-megawatt 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 our Texas intrastate natural gas pipeline group’s market area is primarily composed of industrial (including on-site cogeneration facilities), merchant and utility power, and local natural gas distribution consumption.  The industrial demand is primarily year-round load.  Merchant and utility power demand peaks in the summer months and is complemented by local natural gas distribution demand that peaks in the winter months.

Collectively, our 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 our 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, we purchase natural gas directly from producers with reserves connected to our intrastate natural gas system in South Texas, East Texas, West Texas, and along the Texas Gulf Coast.  In addition, we also purchase gas at interconnects with third-party interstate and intrastate pipelines.  While our intrastate group does not produce gas, it does maintain an active well connection program in order to offset natural declines in production along its system and to secure supplies for additional demand in its market area.  Our intrastate system has access to both onshore and offshore sources of supply, and is interconnected with both liquefied natural gas import terminals located on the Texas Gulf Coast.  Our 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.





Our 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. Our 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

We own 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 us 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

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

El Paso Midstream Investment Company 

We acquired our 50% equity interest in EPMIC on June 1, 2012 from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. The remaining 50% interest in EPMIC is owned by KMI. 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 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.

Endeavor Gathering LLC

We own 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

We own 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, the largest privately held shortline railroad company in the United States. We own a preferred equity position in Watco.

Tennessee Gas Pipeline Company, L.L.C.

Our subsidiary, TGP, owns the approximate 13,900-mile Tennessee Gas natural gas pipeline system. We acquired TGP from KMI 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.

Our 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. The TGP system 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 us and El Paso Pipeline Partners, L.P., or EPB, an affiliate of KMI. The facility has 58 billion cubic feet of working natural gas storage capacity that is committed equally to EPB and us.

Our 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 marketing and trading companies. Its existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity, and our ability to extend our 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 we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariff, we frequently enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. As of December 31, 2012, our 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

Our Western interstate natural gas pipeline systems, which operate along the South Central region and the Rocky Mountain region of the Western portion of the United States, 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.

Our 50%-owned equity investee, EPNG, is the sole owner of (i) the 10,200-mile El Paso Natural Gas pipeline system; and (ii) Mojave Pipeline Company, LLC, the sole owner of the approximate 500-mile Mojave Pipeline system. We acquired our 50% equity interest in EPNG in the August 2012 drop-down transaction. KMI owns the remaining ownership interest in both pipeline systems. 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 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

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

Our 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

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

Kinder Morgan Louisiana Pipeline     

Our subsidiary, Kinder Morgan Louisiana Pipeline LLC owns the Kinder Morgan Louisiana natural gas pipeline system.  The pipeline system provides approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron Parish, Louisiana, 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

We own a 50% interest in Midcontinent Express Pipeline LLC, the sole owner of the approximate 500-mile Midcontinent Express natural gas pipeline system.  We also operate the Midcontinent Express pipeline system.  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 United States’ 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

We own a 50% interest in Fayetteville Express Pipeline LLC, the sole owner of the Fayetteville Express natural gas pipeline system.  The 187-mile Fayetteville Express pipeline system originates in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnect with Trunkline Gas Company’s pipeline in Panola County, Mississippi.  The system also interconnects with NGPL’s pipeline in White County, Arkansas, Texas Gas Transmission’s pipeline in Coahoma County, Mississippi, and ANR Pipeline Company’s pipeline in Quitman County, Mississippi.  On January 1, 2011, Fayetteville Express Pipeline LLC began firm contract pipeline transportation service to its customers.  Capacity on the Fayetteville Express system is over 90% contracted under long-term firm service agreements.

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.


CO2 

Our CO2 segment consists of our subsidiary Kinder Morgan CO2 Company, L.P. and its consolidated affiliates, collectively referred to in this report as KMCO2.  Our CO2 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.  KMCO2 also holds ownership interests in several oil-producing fields and owns a crude oil pipeline, all located in the Permian Basin region of West Texas.

Oil and Gas Producing Activities

Oil Producing Interests

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 United States using carbon dioxide flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas.  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 United States.  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 we 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 we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us:





 
Productive Wells (a)
 
Service Wells (b)
 
Drilling Wells (c)
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude Oil
2,089

 
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, we did not operate any productive wells with multiple completions.

(b)
Consists of injection, water supply, disposal wells and service wells temporarily shut-in.  A disposal well is used for disposal of salt water into an underground formation; 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 our net productive and dry wells that were completed in each of the years ended December 31, 2012, 2011 and 2010:

 
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 we 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, we have 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.

Our principal market for carbon dioxide is for injection into mature oil fields in the Permian Basin, where industry demand is expected to remain strong for the next several years.

Carbon Dioxide Pipelines

As a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50% equity interest in and operate the approximate 500-mile Cortez pipeline.  The pipeline carries carbon dioxide from the McElmo Dome and Doe Canyon source fields near Cortez, Colorado to the Denver City, Texas hub.  The Cortez pipeline 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 our carbon dioxide pipelines is to customers, including ourselves, using carbon dioxide for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain strong for the next several years.

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

Our primary competitors for the sale of carbon dioxide include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide resources, and Oxy USA, Inc., which controls waste carbon dioxide extracted from natural gas production in the Val Verde Basin of West Texas.  Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines.  We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of carbon dioxide to the Denver City, Texas market area.


Terminals

Our Terminals segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities, including all transload, engineering, conveying and other in-plant services.  Combined, the segment is composed of approximately 113 owned or operated liquids and bulk terminal facilities and approximately 35 rail transloading and materials handling facilities.  Our terminals are located throughout the United States and in portions of Canada.  We believe the location of our facilities and our ability to provide flexibility to customers helps keep customers at our terminals and provides us opportunities for expansion. We often classify our terminal operations based on their handling of either liquids or bulk material products.

Liquids Terminals

Our liquids terminals operations primarily store refined petroleum products, petrochemicals, 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, our 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

Our bulk terminal operations primarily involve dry-bulk material handling services.  We also provide conveyor manufacturing and installation, engineering and design services, and in-plant services covering material handling, conveying, maintenance and repair, truck-railcar-marine transloading, railcar switching and miscellaneous marine services.  We own or operate approximately 83 dry-bulk terminals in the United States and Canada, and combined, our 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)

Our 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.  We also design and build transloading facilities, perform inventory management services, and provide value-added services such as blending, heating and sparging.

As of March 31, 2013 TRANSFLO, a wholly owned subsidiary of CSX has elected to 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 United States. KMMS performed transloading services at the 25 terminals, which included rail-to-truck and truck-to-rail transloading of bulk and liquid products.
 
Competition

We are one of the largest independent operators of liquids terminals in the United States, based on barrels of liquids terminaling capacity.  Our liquids terminals compete with other publicly or privately held independent liquids terminals, and terminals owned by oil, chemical and pipeline companies.  Our 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, our competitors are smaller, independent operators with lower cost structures.  Our rail transloading (material services) operations compete with a variety of single- or multi-site transload, warehouse and terminal operators across the United States.  Our ethanol rail transload operations compete with a variety of ethanol handling terminal sites across the United States, many offering waterborne service, truck loading, and unit train capability serviced by Class 1 rail carriers.


Kinder Morgan Canada

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

Trans Mountain Pipeline System

Our 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.  We also own 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 us 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 National Energy Board approval in the second quarter of 2013.





Express System

We own a one-third ownership interest in the Express pipeline system.  We operate the Express pipeline system and account for our one-third investment under the equity method of accounting.  The Express pipeline system is a batch-mode, common-carrier, crude oil pipeline system comprised of the Express Pipeline and the Platte Pipeline, collectively referred to in this report as the Express pipeline system.  The approximate 1,700-mile integrated oil transportation pipeline connects Canadian and United States producers to refineries located in the U.S. Rocky Mountain and Midwest regions.

The Express Pipeline is a 780-mile, 24-inch diameter pipeline that begins at the crude oil pipeline 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, we announced that we had entered into a definitive agreement to sell our interest in the Express Pipeline system to Spectra. Such sale is expected to close in the second quarter of 2013.

Jet Fuel Pipeline System

We also own and operate 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 our Jet Fuel pipeline 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.


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. Our Texas intrastate natural gas pipeline group buys and sells significant volumes of natural gas within the state of Texas, and, to a far lesser extent, our CO2 business segment also sells natural gas. Combined, total revenues from the sales of natural gas from our Natural Gas Pipelines and CO2 business segments in 2012, 2011 and 2010 accounted for 29%, 42% and 46%, respectively, of our total consolidated revenues. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

Regulation

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

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




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

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

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

Common Carrier Pipeline Rate Regulation – Canadian Operations

The Canadian portion of our crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of Canada’s National Energy Board, referred to in this report as the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service.
Trans Mountain Pipeline. Our subsidiary Trans Mountain Pipeline, L.P. previously had a one-year toll settlement with shippers that expired on December 31, 2012. In February 2013, Trans Mountain Pipeline completed negotiations with the Canadian Association of Petroleum Producers for a new negotiated toll settlement for our Trans Mountain Pipeline to be effective for 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 United States falls under the jurisdiction of the FERC. See “-Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations.”
Express Pipeline. The Canadian segment of the Express Pipeline is regulated by the NEB as a Group 2 pipeline, which results in rates and terms of service being regulated on a complaint basis only. Express committed contract rates are subject to a 2% inflation adjustment April 1 of each year. The U.S. segment of the Express Pipeline and the Platte Pipeline are regulated by the FERC. See “-Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations.” Additionally, movements on the Platte Pipeline within the state of Wyoming are regulated by the Wyoming Public Service Commission, which regulates the tariffs and terms of service of public utilities that operate in the state of Wyoming. The Wyoming Public Service Commission standards applicable to rates are similar to those of the FERC and the NEB.
Interstate Natural Gas Transportation and Storage Regulation

Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines.  Within that range, each pipeline is permitted to charge discounted rates to meet competition, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination.  Apart from discounted rates offered within the range of tariff maximums and minimums, the pipeline is permitted to offer negotiated rates where the pipeline and shippers want rate certainty, irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels.  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 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 our Pacific operations’ pipelines in California are subject to regulation by the California Public Utilities Commission, referred to in this report as the CPUC, under a “depreciated book plant” methodology, which is based on an original cost measure of investment.  Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of our Pacific operations’ business.  Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC.  A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to our intrastate rates.  Certain of our Pacific operations’ pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 16 to our consolidated financial statements included elsewhere in this report.

Texas Railroad Commission Rate Regulation

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

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 that defines the general and directional conditions for the pipeline to carry out activity and provide 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 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 United States and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities.
Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
In accordance with 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 $119 million as of December 31, 2012. Our reserve estimates range in value from approximately $119 million to approximately $170 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 United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal, state or Canadian authorities.  The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills.  Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release.

Climate Change
 
Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earth’s atmosphere.  Methane, a primary component of natural gas, and carbon dioxide, which is naturally occurring and also a byproduct of 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 United States, 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 operations, including our compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and carbon dioxide, such new legislation or regulation could increase our costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we could be required to incur capital expenditures for installing new emission controls on our facilities, acquire and surrender 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, 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 pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond our 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 and prospects.

Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding.  We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather.  To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions.  However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon.  Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or 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 our CO2 business segment.  However, these positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels.  Although the magnitude and direction of these impacts cannot now be predicted, greenhouse gas regulations could have material adverse effects on our business, financial position, results of operations 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 which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.


Other

Employees

KMGP Services Company, Inc., KMI, Kinder Morgan Canada Inc. and another affiliate employ all persons necessary for the operation of our business. Generally, we reimburse these entities for the services of their employees. As of December 31, 2012, KMGP Services Company, Inc., KMI, Kinder Morgan Canada Inc. and other affiliated entities had, in the aggregate, 10,685 full-time employees. Approximately 818 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2013 and 2017. KMGP Services Company, Inc., KMI, Kinder Morgan Canada Inc. and other affiliated entities each consider relations with their employees to be good. For more information on our related party transactions, see Note 11 to our consolidated financial statements included elsewhere in this report.
Properties

We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses.  Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us.  In some cases, the real property we lease is on federal, state, provincial or local government land.

We generally do not own the land on which our pipelines are constructed.  Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time.  Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property.  In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants.  In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained.  Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense.  Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.  Some such permits require annual or other periodic payments.  In a few minor cases, property for pipeline purposes was purchased in fee.






(d) Financial Information about Geographic Areas

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


(e) Available Information

We make available free of charge on or through our internet Website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (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 position, results of operations or cash flows.  There are also risks associated with being an owner of common units in a partnership that are different than being an owner of common stock in a corporation.  Investors in our common units should be aware that the realization of any of those risks could result in a decline in the trading price of our common units, and they might lose all or part of their investment.

Risks Related to Our Business

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

Our pipelines and storage facilities are subject to regulation and oversight by federal, state and local regulatory authorities.  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, 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 allows us 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 our pipelines.  Any successful challenge could materially adversely affect our future earnings, cash flows and financial condition.

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

There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities and refined petroleum products and carbon dioxide transportation activities—such as leaks, explosions and mechanical problems—that could result in substantial financial losses.  In addition, these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses.  For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks 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.

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 compliance costs are pipeline integrity testing and the repairs. 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 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 were not under our control.  These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the United States such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct.  Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors.  Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators.  Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

In addition, our oil and gas development and production activities are subject to numerous federal, state and local laws and regulations relating to environmental quality and pollution control.  These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation.  Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, 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, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters.”

Climate change regulation at the federal, state, provincial or regional levels could result in 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 United States beginning in 2011 for emissions occurring in 2010 from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, like our McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.

Because our operations, including our compressor stations and natural gas processing plants in our Natural Gas Pipelines 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 our revenues by decreasing the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines.

The natural gas industry is increasingly relying on natural gas supplies from unconventional sources, such as shale, tight sands and coal bed methane.  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 crude oil, petroleum products or natural gas 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 recontract for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired.  We also could experience competition for the supply of 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.

We regularly undertake major construction projects to expand our existing assets and to construct new assets.  A variety of factors outside of our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction.  Significant cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows.

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

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

Our business, financial condition and operating results may be adversely affected 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 our business, financial condition and results of operations.




In addition, due to our relationship with KMI, our credit ratings, and thus our ability to access the capital markets and the terms and pricing we receive therein, may be adversely affected by any impairment to KMI’s financial condition or adverse changes in its credit ratings. Similarly, 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 debt instruments, as well as the market value of our common units.
Our acquisition strategy and expansion programs require access to new capital.  Limitations on our access to capital would impair our ability to grow.

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

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 $15.9 billion of consolidated debt (excluding the value of interest rate swap agreements).  This level of debt could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) limiting our ability to use operating cash flow in other areas of our business or to pay distributions because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions.

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

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

As of December 31, 2012, approximately $6.2 billion (39%) of our total $15.9 billion consolidated debt (excluding the value of interest rate swap agreements) was subject to variable interest rates, either as short-term or long-term debt of variable rate debt obligations or as long-term fixed-rate debt 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 growth strategy may cause difficulties integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions or expansions.

Part of our business strategy includes acquiring additional businesses, some of which may occur in drop-down transactions from KMI, expanding existing assets and constructing new facilities.  If we do not successfully integrate acquisitions, expansions or newly constructed facilities, we may not realize anticipated operating advantages and cost savings.  The integration of acquired companies or new assets involves a number of risks, including (i) demands on management related to the increase in our size; (ii) the diversion of management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v) potential adverse effects on operating results.

We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately.  Successful integration of each acquisition, expansion or construction project will depend upon our ability to manage those operations and to eliminate redundant and excess costs.  Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we




may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

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

Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.  We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows.  Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities.  In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations, 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 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 pipelines 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 in the Alberta oil sands.  Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our gas plants and pipelines may not be able to maintain existing volumes of throughput.  Commodity prices and tax incentives may not remain at levels that encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.

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

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

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

The rate of production from oil and natural gas properties declines as reserves are depleted.  Without successful development activities, the reserves and revenues of the oil and gas producing assets within our CO2 business segment will




decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future.  Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.

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

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

The volatility of natural gas and oil prices could have a material adverse effect on our CO2 business segment.

The revenues, profitability and future growth of our CO2 business segment and the carrying value of its oil, natural gas liquids and natural gas properties depend to a large degree on prevailing oil and gas prices.  For 2013, we estimate that every $1 change in the average West Texas Intermediate crude oil price per barrel would impact our CO2 segment’s cash flows by approximately $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 our control.  These factors include, among other things (i) weather conditions and events such as hurricanes in the United States; (ii) the condition of the United States economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political stability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources.

A sharp decline in the prices of oil, natural gas liquids or natural gas would result in a commensurate reduction in our 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 our proved reserves.  In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss.  In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts.  Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis.  These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas.  The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand.  These fluctuations impact the accuracy of assumptions used in our budgeting process.  For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Energy Commodity Market Risk.”

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

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

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




completely effective hedge.  For more information about our hedging activities, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities” and Note 13 to our consolidated financial statements included elsewhere in this report.

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.

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

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

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

Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services.  Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the United States and Canada.  Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us.  In addition, decreases in the prices of crude oil and natural gas liquids will have a negative impact on the results of our CO2 business segment.  If global economic and market conditions (including volatility in commodity markets), or economic conditions in the United States or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.

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

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





Risks Related to Ownership of Our Common Units

The interests of KMI may differ from our interests and the interests of our unitholders.

KMI indirectly owns all of the common stock of our general partner and elects all of its directors.  Our general partner owns all of KMR’s voting shares and elects all of its directors.  Furthermore, some of KMR’s and our general partner’s directors and officers are also directors and officers of KMI and its other subsidiaries, including EPB, and have fiduciary duties to manage the businesses of KMI and its other subsidiaries in a manner that may not be in the best interests of our unitholders.  KMI has a number of interests that differ from the interests of our unitholders.  As a result, there is a risk that important business decisions will not be made in the best interests of our unitholders.

Our partnership agreement and the KMR limited liability company agreement restrict or eliminate a number of the fiduciary duties that would otherwise be owed by our general partner and/or its delegate to our unitholders.

Modifications of state law standards of fiduciary duties may significantly limit the ability of our unitholders to successfully challenge the actions of our general partner in the event of a breach of fiduciary duties.  These state law standards include the duties of care and loyalty.  The duty of loyalty, in the absence of a provision in the limited partnership agreement to the contrary, would generally prohibit our general partner from taking any action or engaging in any transaction as to which it has a conflict of interest.  Our limited partnership agreement contains provisions that prohibit limited partners from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law.  For example, that agreement provides that the general partner may take into account the interests of parties other than us in resolving conflicts of interest.  It also provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general partner will not be a breach of any duty.  The provisions relating to the general partner apply equally to KMR as its delegate.  It is not necessary for a limited partner to sign our limited partnership agreement in order for the limited partnership agreement to be enforceable against that person.

Common unitholders have limited voting rights and limited control.

Holders of common units have only limited voting rights on matters affecting us.  Our general partner manages partnership activities.  Under a delegation of control agreement, our general partner has delegated the management and control of our and our subsidiaries’ business and affairs to KMR.  Holders of common units have no right to elect the general partner or any of the directors of the general partner or KMR on an annual or other ongoing basis.  If the general partner withdraws, however, its successor may be elected by the holders of a majority of the outstanding units of all classes (excluding common units and Class B units owned by the departing general partner and its affiliates and excluding the number of i-units corresponding to the number of any KMR shares owned by the departing general partner and its affiliates).

The limited partners may remove the general partner only if (i) the holders of at least 66 2/3% of the outstanding units of all classes, excluding common units and Class B units owned by the general partner and its affiliates and excluding the number of i-units corresponding to the number of any KMR shares owned by the general partner and its affiliates, vote to remove the general partner; (ii) a successor general partner is approved by the same vote; and (iii) we receive an opinion of counsel opining that the removal would not result in the loss of the limited liability of any limited partner or of the limited partner of an operating partnership, or cause us or an operating partnership to be taxed as a corporation or otherwise to be taxed as an entity for federal income tax purposes.

A person or group owning 20% or more of the common units and KMR shares on a combined basis cannot vote.

Any common units or KMR shares held by a person or group that owns 20% or more of the aggregate number of common units and KMR shares on a combined basis cannot be voted.  This limitation does not apply to the general partner and its affiliates.  This provision may (i) discourage a person or group from attempting to remove the general partner or otherwise change management; and (ii) reduce the price at which the common units will trade under certain circumstances.  For example, a third party will probably not attempt to take over our management by making a tender offer for the common units at a price above their trading market price without removing the general partner and substituting an affiliate of its own.

The general partner’s liability to us and our unitholders may be limited.

Our partnership agreement contains language limiting the liability of the general partner to us or the holders of common units.  For example, our partnership agreement provides that (i) the general partner does not breach any duty to us or the holders of common units by borrowing funds or approving any borrowing (the general partner is protected even if the purpose or effect of the borrowing is to increase incentive distributions to the general partner); (ii) the general partner does not breach




any duty to us or the holders of common units by taking any actions consistent with the standards of reasonable discretion outlined in the definitions of available cash and cash from operations contained in our partnership agreement; and (iii) the general partner does not breach any standard of care or duty by resolving conflicts of interest unless the general partner acts in bad faith.

Unitholders may have liability to repay distributions.

Unitholders will not be liable for assessments in addition to their initial capital investment in the common units.  Under certain circumstances, however, holders of common units may have to repay us amounts wrongfully returned or distributed to them.  Under Delaware law, we may not make a distribution to unitholders if the distribution causes our liabilities to exceed the fair value of our assets.  Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted.  Delaware law provides that for a period of three years from the date of such a distribution, a limited partner who receives the distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount.  Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership.  However, such an assignee is not obligated for liabilities unknown to the assignee at the time the assignee became a limited partner if the liabilities could not be determined from the partnership agreement.

Unitholders may be liable if we have not complied with state partnership law.

We conduct our business in a number of states.  In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established.  The unitholders might be held liable for the partnership’s obligations as if they were a general partner if (i) a court or government agency determined that we were conducting business in the state but had not complied with the state’s partnership statute; or (ii) unitholders’ rights to act together to remove or replace the general partner or take other actions under our partnership agreement constitute “control” of our business.

The general partner may buy out minority unitholders if it owns 80% of the aggregate number of common units and KMR shares.

If at any time the general partner and its affiliates own 80% or more of the aggregate number of issued and outstanding common units and KMR shares, the general partner will have the right to purchase all, and only all, of the remaining common units, but only if KMI elects to purchase all, and only all, of the outstanding KMR shares that are not held by KMI and its affiliates pursuant to the purchase provisions that are a part of the limited liability company agreement of KMR.  Because of this right, a unitholder could have to sell its common units at a time or price that may be undesirable.  The purchase price for such a purchase will be the greatest of (i) the 20-day average closing price for the common units or the KMR shares as of the date five days prior to the date the notice of purchase is mailed; or (ii) the highest purchase price paid by the general partner or its affiliates to acquire common units or KMR shares during the prior 90 days.  The general partner can assign this right to its affiliates or to us.

We may sell additional limited partner interests, diluting existing interests of unitholders.

Our partnership agreement allows the general partner to cause us to issue additional common units and other equity securities. When we issue additional equity securities, including additional i-units to KMR when it issues additional shares, unitholders’ proportionate partnership interest in us will decrease.  Such an issuance could negatively affect the amount of cash distributed to unitholders and the market price of common units.  Issuance of additional common units will also diminish the relative voting strength of the previously outstanding common units.  Our partnership agreement does not limit the total number of common units or other equity securities we may issue.

The general partner can protect itself against dilution.

Whenever we issue equity securities to any person other than the general partner and its affiliates, the general partner has the right to purchase additional limited partnership interests on the same terms.  This allows the general partner to maintain its proportionate partnership interest in us.  No other unitholder has a similar right.  Therefore, only the general partner may protect itself against dilution caused by issuance of additional equity securities.

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S.




federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our common unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.  We have not requested, and do not plan to request, a ruling from the IRS on this or any tax other matter affecting us.

Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes.  Although we do not believe, based on our current operations, that we are or will be so treated, the IRS could disagree with the positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay state income taxes at varying rates.  Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to our unitholders.  Because tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced.  Therefore, treatment of us as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units 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.  For example, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas.  If any additional state income taxes were imposed upon us as an entity, our cash available for distribution would be reduced. 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 an investment in our units.

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely affected and the costs of such contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.  The IRS may adopt positions that differ from the conclusions of our counsel or the positions we take, and the IRS’s positions may ultimately be sustained.  It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take.  A court may not agree with some or all of our counsel’s conclusions or positions we take.  Any contest with the IRS, and the outcome of any IRS contest, may materially and adversely impact the market for our common units and the price at which they trade.  In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

Our common unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our common unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, they are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us.  Common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our income.

Tax gain or loss on the disposition of our common units could be more or less than expected.





If a common unitholder sells its common units, the common unitholder will recognize a gain or loss equal to the difference between the amount realized and that common unitholder’s adjusted tax basis in those common units.  Because distributions in excess of a common unitholder’s allocable share of our net taxable income result in a decrease of that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income allocated to that unitholder if the unitholder sells such common units at a price greater than that unitholder’s tax basis in those common units, even if the price received is less than the original cost.  Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture.  In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, a unitholder that sells its common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them.  For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.  Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.  Any tax-exempt entity or non-U.S. person should consult its tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.  The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we treat each purchaser of our common units as having the same tax benefits with regard to the actual common units purchased and we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations.  A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.  The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method.  If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

Our valuation methodologies may result in a shift of income, gain, loss and deduction between our general partner and the common unitholders.  The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our common unitholders and our general partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders.  Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.





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

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in a termination of our partnership for U.S. federal income tax purposes.

We will be considered to have technically terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.  Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief from the IRS was not available, as described below) for one fiscal year. The termination could result in a deferral of depreciation deductions allowable in computing our taxable income.  In the case of a common unitholder reporting on a taxable year other than a calender year, the closing of our taxable year may also result in more than twelve months of our taxable income being includable in the common unitholder’s taxable income for the year of termination.  Under current law, a technical termination would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, after our termination we would be treated as a new partnership for U.S. federal income tax purposes.  If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby a publicly traded partnership that technically terminated may request publicly traded partnership technical termination relief which, if granted by the IRS, among other things would permit the partnership to provide only one Schedule K-1 to unitholders for the year notwithstanding the two partnership tax years.

A common unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units.  If so, the common unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a common unitholder whose common units are loaned to a “short seller” to effect a short sale may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income.  Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

The issuance of additional i-units may cause more taxable income and gain to be allocated to the common units.

The i-units we issue to KMR generally are not allocated income, gain, loss or deduction for U.S. federal income tax purposes until such time as we are liquidated.  Therefore, the issuance of additional i-units may cause more taxable income and gain to be allocated to the common unitholders.

As a result of investing in our common units, a common unitholder will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, our common unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions.  Our common unitholders will likely be required to file foreign, state and local income tax returns and pay foreign, state and local income taxes in some or all of these various jurisdictions.  Further, our common unitholders may be subject to penalties for failure to comply with those requirements.  We currently own assets and conduct business in numerous states in the United States and in Canada.  It is the responsibility of each common unitholder to file all required U.S. federal, foreign, state and local tax returns.  Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

Unitholders may have negative tax consequences if we default on our debt or sell assets.





If we default on any of our debt, the lenders will have the right to sue us for non-payment.  Such an action could cause an investment loss and cause negative tax consequences for unitholders through the realization of taxable income by unitholders without a corresponding cash distribution.  Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, unitholders could have increased taxable income without a corresponding cash distribution.

There is the potential for a change of control of our general partner if KMI defaults on debt.

KMI indirectly owns all the common stock of Kinder Morgan G.P., Inc., our general partner.  If KMI or Kinder Morgan Kansas, Inc. defaults on its debt, then the lenders under such debt, in exercising their rights as lenders, could acquire control of our general partner or otherwise influence our general partner through control of KMI or Kinder Morgan Kansas, Inc.


Item 1B.  Unresolved Staff Comments.

None.


Item 3.  Legal Proceedings.

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


Item 4.  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.
 
The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the New York Stock Exchange, the principal market in which our common units are traded, the amount of cash distributions declared per common and Class B unit, and the fractional i-unit distribution declared per i-unit.

 
Price Range
 
 
 
 
 
High
 
Low
 
Declared Cash
Distributions
 
i-unit
Distributions
2012
 
 
 
 
 
 
 
First Quarter
$
90.60

 
$
80.40

 
$
1.20

 
0.016044

Second Quarter
85.50

 
74.15

 
1.23

 
0.015541

Third Quarter
86.47

 
78.60

 
1.26

 
0.016263

Fourth Quarter
86.32

 
74.76

 
1.29

 
0.015676

 
 
 
 
 
 
 
 
2011
 
 
 
 
 
 
 
First Quarter
$
74.51

 
$
69.66

 
$
1.14

 
0.017102

Second Quarter
78.00

 
69.50

 
1.15

 
0.017895

Third Quarter
74.00

 
63.42

 
1.16

 
0.017579

Fourth Quarter
84.95

 
65.00

 
1.16

 
0.014863


Distribution information is for distributions declared with respect to that quarter.  The declared distributions were paid within 45 days after the end of the quarter.  We currently expect to declare cash distributions of $5.28 per unit for 2013; however, no assurance can be given that we will be able to achieve this level of distribution.

Our common units are traded on the New York Stock Exchange under the symbol “KMP.” As of January 31, 2013, we had 1,728 unitholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank. Additionally, as of January 31, 2013, there was one holder of our Class B units and one holder of our i-units.

For information on our equity compensation plans, see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Equity Compensation Plan Information” and Note 12 “Commitments and Contingent Liabilities—Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements included elsewhere in this report.

We did not repurchase any units during the fourth quarter of 2012 or sell any unregistered units in the fourth quarter of 2012.


Item 6.  Selected Financial Data
 
The following tables set forth, for the periods and at the dates indicated, our summary historical financial and operating data.  The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements.  See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information.




 
Year Ended December 31,
 
2012(e)
 
2011(e)
 
2010(e)
 
2009(f)
 
2008(g)
 
(In millions, except per unit and ratio data)
Income and Cash Flow Data:
 
 
 
 
 
 
 
 
 
Revenues  
$
8,642

 
$
7,889

 
$
7,739

 
$
6,697

 
$
11,362

Operating income  
$
2,340

 
$
1,557

 
$
1,460

 
$
1,367

 
$
1,399

Earnings from equity investments  
$
339

 
$
224

 
$
136

 
$
91

 
$
76

Income from continuing operations  
$
2,025

 
$
1,067

 
$
1,092

 
$
1,036

 
$
1,078

(Loss) income from discontinued operations(a)
$
(669
)
 
$
201

 
$
235

 
$
248

 
$
240

Net income
$
1,356

 
$
1,268

 
$
1,327

 
$
1,284

 
$
1,319

Limited Partners’ interest in net income
$
(78
)
 
$
83

 
$
431

 
$
332

 
$
499

 
 
 
 
 
 
 
 
 
 
Limited Partners’ net income (loss) per unit:
 

 
 

 
 

 
 

 
 

Income (loss) per unit from continuing operations
$
1.64

 
$
(0.35
)
 
$
0.65

 
$
0.32

 
$
1.02

(Loss) income from discontinued operations   
(1.86
)
 
0.60

 
0.75

 
0.86

 
0.92

Net (loss) income per unit   
$
(0.22
)
 
$
0.25

 
$
1.40

 
$
1.18

 
$
1.94

 
 
 
 
 
 
 
 
 
 
Per unit cash distribution declared(b)  
$
4.98

 
$
4.61

 
$
4.40

 
$
4.20

 
$
4.02

Ratio of earnings to fixed charges(c)  
3.81

 
2.82

 
3.07

 
3.20

 
3.26

Capital expenditures  
$
1,806

 
$
1,199

 
$
1,004

 
$
1,324

 
$
2,533

 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at end of period):
 

 
 

 
 

 
 

 
 

Net property, plant and  equipment  
$
19,603

 
$
15,596

 
$
14,604

 
$
14,154

 
$
13,241

Total assets  
$
32,094

 
$
24,103

 
$
21,861

 
$
20,262

 
$
17,886

Long-term debt(d)
$
14,714

 
$
11,183

 
$
10,301

 
$
10,022

 
$
8,293

____________

(a)
Represents income (loss) from the operations and disposal of (i) our Kinder Morgan Interstate Gas Transmission natural gas pipeline system; (ii) our Trailblazer natural gas pipeline system; (iii) our Casper and Douglas natural gas processing operations; (iv) our 50% equity investment in the Rockies Express natural gas pipeline system; and (v) for 2008, our North System natural gas liquids pipeline system.  See Notes 1, 2 and 3 of the accompanying notes to our consolidated financial statements for further information about the first four assets listed above. 

(b)
Represents the amount of cash distributions declared with respect to that year.

(c)
For the purpose of computing the ratio of earnings to fixed charges, earnings are defined as income from continuing operations before income taxes, equity earnings (including amortization of excess cost of equity investments) and unamortized capitalized interest, plus fixed charges and distributed income of equity investees.  Fixed charges are defined as the sum of interest on all indebtedness (excluding capitalized interest), amortization of debt issuance costs and that portion of rental expense which we believe to be representative of an interest factor.

(d)
Excludes debt fair value adjustments.  Increases to long-term debt for debt fair value adjustments totaled $1,461 million as of December 31, 2012, $1,055 million as of December 31, 2011, $582 million as of December 31, 2010, $308 million as of December 31, 2009, and $933 million as of December 31, 2008.

(e)
For each of the years 2012, 2011 and 2010, includes results of operations for net assets acquired since effective dates of acquisition.  For further information on our significant acquisitions for each of these years, see Note 3 to our consolidated financial statements included elsewhere in this report. 2012 also includes results of operations for the net assets of the drop-down asset group for the period beginning May 25, 2012 to the acquisition date.  We acquired the drop-down asset group from KMI on August 1, 2012.

(f)
Includes results of operations for the terminal assets acquired from Megafleet Towing Co., Inc., the Portland Airport refined products pipeline assets acquired from Chevron Pipe Line Company, the natural gas treating business acquired from Crosstex Energy, L.P. and Crosstex Energy, Inc., and the 40% equity membership interest in Endeavor Gathering LLC acquired from GMX Resources Inc. since effective dates of acquisition.  We acquired the terminal assets from Megafleet effective April 23, 2009, the Portland Airport Pipeline




assets from Chevron effective July 31, 2009, the natural gas treating business from Crosstex effective October 1, 2009, and the 40% membership interest in Endeavor effective November 1, 2009.

(g)
Includes results of operations for the terminal assets acquired from Chemserve, Inc., and the refined petroleum products terminal located in Phoenix, Arizona acquired from ConocoPhillips since effective dates of acquisition.  We acquired the terminal assets from Chemserve, Inc. effective August 15, 2008, and we acquired the refined petroleum products terminal from ConocoPhillips effective December 10, 2008. The increase in overall revenues in 2008 was primarily due to incremental revenues earned from the sales of natural gas by our Natural Gas Pipelines business segment.




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:
the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. Accordingly, we have excluded the disposal group’s financial results from our Natural Gas Pipelines business segment disclosures for the periods presented in this report; and
our August 1, 2012 acquisition of assets from KMI as if such acquisition had taken place on May 25, 2012, the effective date that KMI acquired the same assets from El Paso Corporation. We refer to this transfer of assets from KMI to us as the drop-down transaction, and we refer to the transferred assets as our drop-down asset group. We accounted for the drop-down transaction as a transfer of net assets between entities under common control, and accordingly, the financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations include the financial results of the drop-down asset group for the period subsequent to May 25, 2012.
Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements.  These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties.  Our actual results could differ materially from those discussed in the forward-looking statements.  Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and below in “—Information Regarding Forward-Looking Statements.”


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

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

creating long-term value for our unitholders.
 
To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, 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:
 
Products Pipelines—the ownership and operation of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;





Natural Gas Pipelines—the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems, plus the ownership and/or operation of associated natural gas processing and treating facilities;

CO2(i) the production, transportation and marketing of carbon dioxide, referred to as CO2, to oil fields that use CO2 to increase production of oil; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;

Terminals—the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the United States and portions of Canada; and

Kinder Morgan Canada—(i) the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington; (ii) the 33 1/3% interest in the Express crude oil pipeline system, which connects Canadian and U.S. producers to refineries located in the U.S. Rocky Mountain and Midwest regions; and (iii) the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.
 
As an energy infrastructure owner and operator in multiple facets of the United States’ and Canada’s various energy businesses and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future.  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 our Texas Intrastate Natural Gas Group, we currently derive approximately 75% of our 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 natural gas transportation contracts (including our intrastate pipelines’ purchase and sales contracts) was approximately six years.
 
Our 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 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 our CO2 segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add.  In that regard, our production during any period is an important measure.  In addition, the revenues we receive from our crude oil, natural gas liquids and carbon dioxide sales are affected by the prices we realize from the sale of these products.  Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products.  In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.  Our realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $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 our Terminals business segment generally differ depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored.  As with our 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 invested approximately $2.1 billion for both strategic business acquisitions and expansions of existing assets (not including our August 1, 2012 acquisition of net assets from KMI).  Our capital investments have helped us to achieve compound annual growth rates in cash distributions to our limited partners of 8.0%, 5.8% and 7.4%, respectively, for the one-year, three-year and five-year periods ended December 31, 2012.
 
Thus, the amount that we are able to increase distributions to our unitholders will, to some extent, be a function of our ability to complete successful acquisitions and expansions.  We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $2.9 billion for our 2013 capital expansion program (including small acquisitions and investment contributions, but excluding asset acquisitions from KMI).  We regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions. These potential acquisitions include the following:

KMI has offered to sell us (drop-down), in 2013, the remaining 50% ownership interest that we do not already own in (i) EPNG, the sole owner of the El Paso and Mojave natural gas pipeline systems; and (ii) EPMIC, the joint venture that owns both the Altamont natural gas gathering system, processing plant and fractionation facilities located in the Uinta basin of Utah, and the Camino Real natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas; and

On January 29, 2013, we and Copano Energy, L.L.C. announced a definitive agreement whereby we 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 our unitholders upon closing. Our general partner, has agreed to forego a portion of its incremental incentive distributions in 2013 in an amount dependent on the time of closing. Additionally, our general partner intends to forgo incentive distribution amounts of $120 million in 2014, $120 million in 2015, and $110 million in 2016 and annual amounts thereafter decreasing by $5 million per year from this level. The transaction is expected to be modestly accretive to us in 2013, given the partial year, and about $0.10 per unit accretive for at least the next five years beginning in 2014.
Based on our historical record and because there is continued demand for energy infrastructure in the areas we serve, we expect to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict. 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. Furthermore, 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 ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions.  

As a master limited partnership, we distribute all of our available cash and we access capital markets to fund acquisitions and asset expansions.  Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, 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 our stable cash flows, our investment grade credit rating, and our historical record of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required.  For a further discussion of our liquidity, including our public debt and equity offerings in 2012, please see “—Liquidity and Capital Resources” below.

In addition, a portion of our business portfolio (including our Kinder Morgan Canada business segment, the Canadian portion of our Cochin Pipeline, and our bulk and liquids terminal facilities located in Canada) uses the local Canadian dollar as the functional currency for its Canadian operations and enters into foreign currency-based transactions, both of which affect segment results due to the inherent variability in U.S. - Canadian dollar exchange rates.  To help understand our reported operating results, all of the following references to “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.


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.
 
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, our most significant ongoing litigation proceedings involved our West Coast Products Pipelines.  Transportation rates charged by certain of these pipeline systems are subject to proceedings at the FERC and the CPUC involving shipper challenges to the pipelines’ interstate and intrastate (California) rates, respectively.  For more information on our regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report.
 
Intangible Assets
 
Intangible assets are those assets which provide future economic benefit but have no physical substance.  Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite.  Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value.  We evaluate our goodwill for impairment on May 31 of each year.  There were no impairment charges resulting from our May 31, 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.
 
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.


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)
 
 
 
 
 
Products Pipelines
$
670

 
$
463

 
$
505

Natural Gas Pipelines
1,349

 
546

 
576

CO2
1,322

 
1,099

 
965

Terminals
709

 
704

 
641

Kinder Morgan Canada
229

 
202

 
182

Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(b)
4,279

 
3,014

 
2,869

 
 
 
 
 
 
Depreciation, depletion and amortization expense(c)
(1,093
)
 
(928
)
 
(879
)
Amortization of excess cost of equity investments
(7
)
 
(7
)
 
(6
)
General and administrative expenses(d)
(493
)
 
(473
)
 
(375
)
Interest expense, net of unallocable interest income(e)
(652
)
 
(531
)
 
(507
)
Unallocable income tax expense
(9
)
 
(8
)
 
(10
)
Income from continuing operations
2,025

 
1,067

 
1,092

(Loss) income from discontinued operations(f)
(669
)
 
201

 
235

Net income
1,356

 
1,268

 
1,327

Net income attributable to noncontrolling interests(g)
(17
)
 
(10
)
 
(11
)
Net income attributable to Kinder Morgan Energy Partners, L.P.
$
1,339

 
$
1,258

 
$
1,316

____________




 
(a)
Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income).  Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

(b)
2012, 2011 and 2010 amounts include an increase in earnings of $62 million, a decrease in earnings of $387 million, and a decrease in earnings of $183 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 amount includes a $31 million increase in expense attributable to our drop-down asset group for the period prior to our acquisition date of August 1, 2012.

(d)
2012, 2011 and 2010 amounts include increases in expense of $70 million, $94 million and $10 million, respectively, related to the combined effect from the 2012, 2011 and 2010 certain items related to general and administrative expenses disclosed below in “—Other.”

(e)
2012 and 2010 amounts include increases in expense of $20 million and $1 million, respectively, related to the combined effect from the 2012 and 2010 certain items related to interest expense disclosed below in “—Other.”

(f)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group. 2012 amount includes a combined $829 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.

(g)
2012, 2011 and 2010 amounts include decreases of $5 million, $7 million and $5 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2012, 2011 and 2010 certain items disclosed below in both our management discussion and analysis of segment results and “—Other.”

Distributable Cash Flow

Our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement generally consists of all our cash receipts, less cash disbursements and changes in reserves). Distributable cash flow, sometimes referred to as DCF, is an overall performance metric we use as a measure of available cash. The following table discloses the calculation of our DCF for each of the years ended December 31, 2012, 2011 and 2010 (calculated before the combined effect from all of the 2012, 2011 and 2010 certain items disclosed in the footnotes to the tables above):

 
Year Ended December 31,
 
2012
 
2011
 
2010
 
(In millions)
Net Income
$
1,356

 
$
1,268

 
$
1,327

Add-back: Certain items - combined expense(a)
888

 
491

 
194

Net Income before certain items
2,244

 
1,759

 
1,521

Less: Net Income before certain items attributable to noncontrolling interests
(22
)
 
(17
)
 
(16
)
Net Income before certain items attributable to Kinder Morgan Energy Partners, L.P.
2,222

 
1,742

 
1,505

Less: General Partner’s interest in Net Income before certain items(b)
(1,412
)
 
(1,180
)
 
(887
)
Less: General Partner’s interim capital transaction impact(c)

 

 
(166
)
Limited Partners’ interest in Net Income before certain items
810

 
562

 
452

Depreciation, depletion and amortization(d)
1,252

 
1,133

 
1,056

Book (cash) taxes paid, net
(2
)
 
27

 
26

Incremental contributions from equity investments in the Express Pipeline, Endeavor Gathering LLC and for 2010 only, Eagle Ford Gathering LLC
3

 
15

 
5

Sustaining capital expenditures(e)
(285
)
 
(212
)
 
(179
)
Distributable cash flow before certain items
$
1,778

 
$
1,525

 
$
1,360

___________
(a)
Equal to the combined effect from the 2012, 2011 and 2010 items disclosed in the footnotes to the Results of Operations table included above.




(b)
2012, 2011 and 2010 amounts include reductions of $26 million, $29 million and $18 million, respectively, for waived general partner incentive amounts related to common units issued to finance a portion of our May 2010 and July 2011 KinderHawk Field Services LLC acquisitions.
(c)
2010 amount represents our portion (net of noncontrolling interest) of reduced general partner incentive distribution amount due to a portion of our available cash distribution for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations.
(d)
2012, 2011 and 2010 amounts include (i) expense amounts of $176 million, $171 million and $146 million, respectively, for our proportionate share of the depreciation expense associated with the following equity investments: Rockies Express Pipeline LLC; Midcontinent Express Pipeline LLC; Fayetteville Express Pipeline LLC; Cypress Interstate Pipeline LLC; EagleHawk Field Services LLC; Red Cedar Gathering LLC; Eagle Ford Gathering LLC; El Paso Midstream Investment Company LLC; El Paso Natural Gas Pipeline LLC; Bear Creek Storage LLC; and KinderHawk Field Services LLC; and (ii) expense amounts of $7 million, $27 million and $26 million, respectively, from our FTC Natural Gas Pipelines disposal group. 2012 amount also excludes a $31 million expense attributable to our drop-down asset group for the period prior to our acquisition date of August 1, 2012.
(e)
2012 and 2011 amounts include increases in expenditures of $19 million and $10 million, respectively, for our proportionate share of the sustaining capital expenditures associated with the following equity investments: Rockies Express Pipeline LLC; Midcontinent Express Pipeline LLC; Fayetteville Express Pipeline LLC; Cypress Interstate Pipeline LLC; EagleHawk Field Services LLC; Eagle Ford Gathering LLC; Red Cedar Gathering LLC; El Paso Natural Gas Pipeline LLC; Bear Creek Storage LLC; and El Paso Midstream Investment Company, LLC.

Segment earnings before depreciation, depletion and amortization expenses

With regard to our reportable business segments, we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, (EBDA) to be an important measure of our success in maximizing returns to our partners. We also use segment EBDA internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments.
 
For the comparable years of 2012 and 2011, total segment EBDA increased $1,265 million (42%) in 2012; however, this overall increase:
included a $449 million increase in EBDA from the effect of the certain items described in footnote (b) to the “—Results of Operations” table above; and
excluded a $71 million decrease in EBDA from discontinued operations (as described in footnote (f) to the “—Results of Operations” table above and excluding both the combined $829 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 $745 million (20%) increase in segment earnings before depreciation, depletion and amortization in 2012 versus 2011 resulted from higher earnings from all five of our reportable business segments, driven mainly by increases attributable to our Natural Gas Pipelines and CO2 business segments.
For the comparable years of 2011 and 2010, total segment EBDA increased $145 million (5%) in 2011; however, this overall increase:
included a $204 million decrease in EBDA from the effect of the certain items described in footnote (b) to the “—Results of Operations” table above; and
excluded a $23 million decrease in EBDA from discontinued operations (as described in footnote (f) to the “—Results of Operations” 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).
After adjusting for these two items, the remaining $326 million (10%) increase in segment EBDA in 2011 versus 2010 resulted from better performance from all five of our reportable business segments, primarily due to increases attributable to our CO2, Natural Gas Pipelines, and Terminals business segments.




Products Pipelines
 
 
Year Ended December 31,
 
2012
 
2011
 
2010
 
(In millions, except operating statistics)
Revenues
$
1,370

 
$
914

 
$
883

Operating expenses
(759
)
 
(500
)
 
(414
)
Other income (expense)
7

 
10

 
(4
)
Earnings from equity investments
58

 
51

 
33

Interest income and Other, net
11

 
8

 
16

Income tax (expense)
(17
)
 
(20
)
 
(9
)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
$
670

 
$
463

 
$
505

 
 
 
 
 
 
Gasoline (MMBbl)(b)
395.3

 
398.0

 
403.5

Diesel fuel (MMBbl)
141.5

 
148.9

 
148.3

Jet fuel (MMBbl)
110.6

 
110.5

 
106.2

Total refined product volumes (MMBbl)
647.4

 
657.4

 
658.0

Natural gas liquids (MMBbl)
31.7

 
26.1

 
25.2

Total delivery volumes (MMBbl)(c)
679.1

 
683.5

 
683.2

Ethanol (MMBbl)(d)
33.1

 
30.4

 
29.9

__________

(a)
2012, 2011 and 2010 amounts include decreases in earnings of $33 million, $231 million and $183 million, respectively, related to the combined effect from certain items. 2012 amount consists of a $32 million increase in expense associated with environmental liability and environmental recoverable receivable adjustments, and a combined $1 million decrease in earnings from other certain items. 2011 amount consists of a $168 million increase in expense associated with rate case liability adjustments, a $60 million increase in expense associated with rights-of-way lease payment liability adjustments, and a combined $3 million decrease in earnings from other certain items. 2010 amount consists of a $172 million increase in expense associated with rate case liability adjustments, an $18 million decrease in earnings associated with incremental expenses and losses from the disposal of property related to the sale of a portion of our former Gaffey Street, California terminal land, and a combined $7 million increase in earnings from other certain items.

(b)
Volumes include ethanol pipeline volumes.

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

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

Combined, the certain items described in the footnotes to the table above accounted for a $198 million increase in segment EBDA in 2012, and a $48 million decrease in EBDA in 2011, when compared with the respective prior year.  Following is information related to the segment’s (i) remaining $9 million (1%) and $6 million (1%) increases in EBDA; and (ii) $456 million (50%) and $31 million (4%) increases in operating revenues in both 2012 and 2011, when compared with the respective prior year:





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

 
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 
(In millions, except percentages)
Cochin Pipeline
$
22

 
43
 %
 
$
4

 
5
 %
Crude & Condensate Pipeline
5

 
230
 %
 
4

 
n/a

Plantation Pipeline
4

 
7
 %
 
1

 
3
 %
Southeast Terminals
4

 
5
 %
 
3

 
3
 %
Transmix operations
(18
)
 
(54
)%
 
447

 
928
 %
Pacific operations
(9
)
 
(3
)%
 
(10
)
 
(2
)%
Calnev Pipeline
(8
)
 
(16
)%
 
(6
)
 
(8
)%
All others (including eliminations)
9

 
7
 %
 
13

 
7
 %
Total Products Pipelines
$
9

 
1
 %
 
$
456

 
50
 %
__________
n/a - not applicable

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

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

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

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

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

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

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

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





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

 
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 
(In millions, except percentages)
Cochin Pipeline
$
18

 
53
 %
 
$
30

 
66
 %
Plantation Pipeline
9

 
19
 %
 
1

 
6
 %
West Coast Terminals
8

 
11
 %
 
10

 
10
 %
Pacific operations
(18
)
 
(6
)%
 
(11
)
 
(3
)%
Calnev Pipeline
(5
)
 
(8
)%
 
(4
)
 
(5
)%
Transmix operations
(4
)
 
(9
)%
 
3

 
6
 %
All others (including eliminations)
(2
)
 
(2
)%
 
2

 
1
 %
Total Products Pipelines
$
6

 
1
 %
 
$
31

 
4
 %
__________

The primary increases and decreases in our Products Pipelines business segment’s EBDA in 2011 compared to 2010 were attributable to the following:
 
an $18 million (53%) increase from our Cochin pipeline system—largely related to a 33% increase in system-wide throughput volumes, partially offset by increased income tax expense due to the year-over-year increase in pre-tax income;

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

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

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

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

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




Natural Gas Pipelines 
 
Year Ended December 31,
 
2012
 
2011
 
2010
 
(In millions, except operating statistics)
Revenues(a)
$
3,926

 
$
3,943

 
$
4,078

Operating expenses
(2,817
)
 
(3,370
)
 
(3,583
)
Other expense
(1
)
 

 

Earnings from equity investments
230

 
140

 
82

Interest income and Other, net
6

 
(164
)
 
2

Income tax benefit (expense)
5

 
(3
)
 
(3
)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments from continuing operations(b)
1,349

 
546

 
576

Discontinued operations(c)(d)
(662
)
 
228

 
261

Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments including discontinued operations
$
687

 
$
774

 
$
837

 
 
 
 
 
 
Natural gas transport volumes (Bcf)(e)
5,866.0

 
5,273.2

 
4,514.8

Natural gas sales volumes (Bcf)(e)
879.1

 
804.7

 
797.9

__________

(a)
2012 amount includes an increase of $181 million attributable to our drop-down asset group for the period prior to our acquisition date of August 1, 2012.

(b)
2012 amount includes an increase in earnings of $131 million attributable to our drop-down asset group for the period prior to our acquisition date of August 1, 2012, and a combined $11 million increase from other certain items. 2011 amount includes a $167 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value.

(c)
Represents EBDA attributable to our FTC Natural Gas Pipelines disposal group.  2012 amount includes a combined loss of $829 million from the remeasurement of net assets to fair value and the sale of net assets. 2011 amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011.  

(d)
2012, 2011 and 2010 amounts include revenues of $227 million, $322 million and $339 million, respectively.  

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

Combined, the certain items described in footnotes (a) through (c) to the table above decreased our Natural Gas Pipelines business segment’s EBDA (including discontinued operations) by $510 million in 2012, and by $177 million in 2011, when compared with the respective prior year. In addition, the certain items described in footnotes (a) and (d) to the table above accounted for a $181 million increase in segment revenues in 2012 versus 2011. Following is information, including discontinued operations, related to the segment’s remaining (i) $423 million (44%) and $114 million (14%) increases in EBDA; and (ii) $293 million (7%) and $152 million (3%) decreases in operating revenues in 2012 and 2011, when compared with the respective prior year:
 




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


EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 
(In millions, except percentages)
Tennessee Gas Pipeline
$
308

 
n/a

 
$
421

 
n/a

KinderHawk Field Services(a)
58

 
52
 %
 
95

 
96
 %
El Paso Natural Gas Pipeline(b)
36

 
n/a

 

 
n/a

Kinder Morgan Treating operations
33

 
70
 %
 
69

 
79
 %
Fayetteville Express Pipeline(b)
31

 
131
 %
 

 
n/a

Eagle Ford Gathering(b)
23

 
203
 %
 

 
n/a

Texas Intrastate Natural Gas Pipeline Group
(6
)
 
(2
)%
 
(776
)
 
(22
)%
All others (including eliminations)
11

 
6
 %
 
(7
)
 
(6
)%
Total Natural Gas Pipelines-continuing operations
494

 
69
 %
 
(198
)
 
(5
)%
Discontinued operations(c)
(71
)
 
(30
)%
 
(95
)
 
(29
)%
Total Natural Gas Pipelines-including discontinued operations
$
423

 
44
 %
 
$
(293
)
 
(7
)%
__________
n/a - not applicable

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

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

(c)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.

The significant increases and decreases in our Natural Gas Pipelines business segment’s EBDA in the comparable years of 2012 and 2011 included the following:
incremental earnings of $344 million from our drop-down asset group (our Tennessee Gas Pipeline and our 50%-owned El Paso Natural Gas Pipeline), which we acquired from KMI effective August 1, 2012;

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

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

a $31 million (131%) increase in equity earnings from our 50% interest in the Fayetteville Express pipeline system—driven by a ramp-up in firm contract transportation volumes, and to lower interest expense. Higher year-over-year transportation revenues reflected a 15% increase in natural gas transmission volumes, and the decrease in interest expense related to Fayetteville’s refinancing of its prior bank credit facility in July 2011;
incremental equity earnings of $23 million from our 50%-owned Eagle Ford Gathering LLC, which initiated flow on its natural gas gathering system on August 1, 2011; and
a $6 million (2%) decrease from our Texas intrastate natural gas pipeline group—driven by higher operating and maintenance expenses, lower margins on natural gas processing activities, and lower margins on natural gas sales. The increase in expenses was driven by both higher pipeline integrity maintenance and unexpected repairs at the Markham storage facility. The decrease in processing margin was mostly due to lower natural gas liquids prices, and the year-over-year decrease in sales margin was due to lower average natural gas sales prices relative to 2011.




The overall year-to-year decrease in EBDA from discontinued operations was largely due to the loss of income due to the sale of our discontinued operations effective November 1, 2012. EBDA from our Kinder Morgan Interstate Gas Transmission pipeline system and our Trailblazer pipeline system decreased $29 million (33%) and $20 million (59%), respectively, in 2012 versus 2011. In addition to the loss of income due to our divestiture, earnings from both pipeline systems decreased during the ten months we owned the assets in 2012 compared to the same period in 2011. The decrease was driven by lower operating revenues in 2012, generally related to lower net fuel recoveries, lower margins on operational natural gas sales, and excess natural gas transportation capacity existing out of the Rocky Mountain region, relative to 2011.
Year Ended December 31, 2011 versus Year Ended December 31, 2010


EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 
(In millions, except percentages)
KinderHawk Field Services(a)
$
92

 
n/a

 
$
99

 
n/a

Fayetteville Express Pipeline(b)
24

 
n/a

 
n/a

 
n/a

Midcontinent Express Pipeline(b)
12

 
42
 %
 
n/a

 
n/a

Texas Intrastate Natural Gas Pipeline Group
6

 
2
 %
 
(252
)
 
(6
)%
All others (including eliminations)
3

 
2
 %
 
18

 
9
 %
Total Natural Gas Pipelines-continuing operations
137

 
24
 %
 
(135
)
 
(3
)%
Discontinued operations(c)
(23
)
 
(9
)%
 
(17
)
 
(5
)%
Total Natural Gas Pipelines-including discontinued operations
$
114

 
14
 %
 
$
(152
)
 
(3
)%
__________
n/a - not applicable

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

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

(c)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.

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

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

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

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

a $6 million (2%) increase from our Texas intrastate natural gas pipeline group—primarily due to higher margins from both natural gas storage and transportation services (due to favorable storage price spreads and a 15% increase in transportation volumes) and incremental equity earnings from our 50% interest in Eagle Ford Gathering LLC. The overall increase in earnings was partly offset by lower natural gas sales margins (mainly attributable to higher costs of natural gas supplies relative to sales price), and higher operating expenses (attributable primarily to higher pipeline integrity and remediation expenses).
 
The primary increases and decreases in our Natural Gas Pipelines business segment’s EBDA from discontinued operations in 2011 compared to 2010 were attributable to the following:
 
an $18 million (17%) decrease from our Kinder Morgan Interstate Gas Transmission pipeline system— driven by a $12 million decrease due to lower net fuel recoveries, related to both lower recovery factors resulting from a FERC




regulatory settlement reached with shippers that became effective June 1, 2011, and lower average collection prices due to an overall drop in natural gas market prices relative to 2010; and

an $11 million (25%) decrease from our Trailblazer pipeline system—mainly attributable to both a $5 million increase in expense from the write-off of receivables for under-collected fuel (incremental to the $10 million increase in expense that is described in footnote (f) to the results of operations table above and which relates to periods prior to 2011), and a $3 million decrease in natural gas transmission revenues, due largely to lower transportation base rates implemented in 2011 as a result of a 2010 rate case settlement.
 
The overall changes in both segment revenues and segment operating expenses (from continuing operations) in both pairs of comparable years primarily relate to the natural gas purchase and sale activities of our Texas intrastate natural gas pipeline group, with the variances from year-to-year in both revenues and operating expenses (which include natural gas costs of sales) mainly due to corresponding changes in the intrastate group’s average prices and volumes for natural gas purchased and sold.  Our intrastate group both purchases and sells significant volumes of natural gas, which is often stored and/or transported on its pipelines, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases and decreases in its natural gas sales revenues are largely offset by corresponding increases and decreases in its natural gas purchase costs.  It realizes earnings by capturing the favorable differences between the changes in its gas sales prices, purchase prices and transportation costs, including fuel.  Our intrastate group accounted for 73%, 92% and 95%, respectively, of the segment’s revenues in 2012, 2011 and 2010, and 91%, 98% and 99%, respectively, of the segment’s operating expenses in 2012, 2011 and 2010.

CO2 

 
Year Ended December 31,
 
2012
 
2011
 
2010
 
(In millions, except operating statistics)
Revenues(a)
$
1,677

 
$
1,416

 
$
1,246

Operating expenses
(381
)
 
(342
)
 
(309
)
Other income
7

 

 

Earnings from equity investments
25

 
24

 
23

Interest income and Other, net
(1
)
 
5

 
4

Income tax (expense) benefit
(5
)
 
(4
)
 
1

Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)(b)
$
1,322

 
$
1,099

 
$
965

 
 
 
 
 
 
Southwest Colorado carbon dioxide production (gross) (Bcf/d)(c)
1.2

 
1.3

 
1.3

Southwest Colorado carbon dioxide production (net) (Bcf/d)(c)
0.5

 
0.5

 
0.5

SACROC oil production (gross)(MBbl/d)(d)
29.0

 
28.6

 
29.2

SACROC oil production (net)(MBbl/d)(e)
24.1

 
23.8

 
24.3

Yates oil production (gross)(MBbl/d)(d)
20.8

 
21.7

 
24.0

Yates oil production (net)(MBbl/d)(e)
9.3

 
9.6

 
10.7

Katz oil production (gross)(MBbl/d)(d)
1.7

 
0.5

 
0.3

Katz oil production (net)(MBbl/d)(e)
1.4

 
0.4

 
0.2

Natural gas liquids sales volumes (net)(MBbl/d)(e)
9.5

 
8.5

 
10.0

Realized weighted average oil price per Bbl(f)
$
87.72

 
$
69.73

 
$
59.96

Realized weighted average natural gas liquids price per Bbl(g)
$
50.95

 
$
65.61

 
$
51.03

__________

(a)
2012, 2011 and 2010 amounts include unrealized losses of $11 million, unrealized gains of $5 million and unrealized gains of $5 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales.

(b)
2012 amount also includes a $7 million gain from the sale of our ownership interest in the Claytonville oil field unit.





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

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

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

(f)
Includes all of our crude oil production properties.

(g)
Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

Our CO2 segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO2) and crude oil, and the production and marketing of natural gas and natural gas liquids. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and Sales and Transportation Activities.
 
Combined, the certain items described in footnotes (a) and (b) to the table above (i) decreased EBDA and revenues by $9 million in 2012, when compared to 2011; and (ii) decreased revenues by $16 million in 2012, when compared to 2011. For each of the segment’s two primary businesses, following is information related to the remaining (i) $232 million (21%) and $134 million (14%) increases in EBDA; and (ii) $277 million (20%) and $170 million (14%) increases in operating revenues in both 2012 and 2011, when compared with the respective prior year: