10-K 1 form10k_2011.htm KMP 10K 2011 form10k_2011.htm

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, 2011

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
(I.R.S. Employer
incorporation or organization)
Identification No.)

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

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

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

Title of each class
Name of each exchange on which registered
Common Units
New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.  Yes [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 30, 2011 was approximately $15,631,284,352.  As of January 31, 2012, the registrant had 232,837,732 Common Units outstanding.
 


 







KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES


   
Page
Number
 
PART I
   
Items 1 and 2.
Business and Properties
 
 
General Development of Business
4
 
 
Organizational Structure
4
 
 
Recent Developments
5
 
 
Financial Information about Segments
11
 
 
Narrative Description of Business
12
 
 
Business Strategy
12
 
 
Business Segments
12
 
 
Products Pipelines
12
 
 
Natural Gas Pipelines
15
 
 
CO2
20
 
 
Terminals
23
 
 
Kinder Morgan Canada
24
 
 
Major Customers
25
 
 
Regulation
25
 
 
Environmental Matters
28
 
 
Other
30
 
 
Financial Information about Geographic Areas
31
 
 
Available Information
31
 
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
47
 
 
Critical Accounting Policies and Estimates
49
 
 
Results of Operations
52
 
 
Liquidity and Capital Resources
69
 
 
Recent Accounting Pronouncements
76
 
 
Information Regarding Forward-Looking Statements
76
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
 
Energy Commodity Market Risk
78
 
 
Interest Rate Risk
79
 
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
82
 
 
Corporate Governance
84
 
 
Section 16(a) Beneficial Ownership Reporting Compliance
85
 
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 29,000 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 provider of carbon dioxide, commonly called CO2, for enhanced oil recovery projects in North America.  As one of the largest publicly traded pipeline limited partnerships in America, we have an enterprise value of over $40 billion.  The address of our principal executive offices is 500 Dallas Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000.
 
You should read the following in conjunction with our audited consolidated financial statements and the notes thereto included elsewhere in this report.  We have prepared our accompanying consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission.  Our accounting records are maintained in United States dollars, and all references to dollars in this report are United States dollars, except where stated otherwise.  Canadian dollars are designated as C$.  Our consolidated financial statements include our accounts and those of our operating limited partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.
 
(a) General Development of Business
 
Organizational Structure
 
We are a Delaware limited partnership formed in August 1992, and our common units, which represent limited partner interests in us, trade on the New York Stock Exchange under the symbol “KMP.”  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.
 
Our general partner is owned by Kinder Morgan, Inc., as discussed below.  In July 2007, our general partner issued and sold 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057.  The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line LLC.
 
Kinder Morgan, Inc., Kinder Morgan Kansas, Inc. and Kinder Morgan G.P., Inc.
 
Kinder Morgan, Inc., a Delaware corporation and referred to as KMI in this report, indirectly owns all the common stock of Kinder Morgan Kansas, Inc.  Kinder Morgan Kansas, Inc. is a Kansas corporation and indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation.  KMI was formed August 23, 2006 as a Delaware limited liability company principally for the purpose of acquiring (through a wholly-owned subsidiary) all of the common stock of Kinder Morgan Kansas, Inc.  The merger, referred to in this report as the going-private transaction, closed on May 30, 2007 with Kinder Morgan Kansas, Inc. continuing as the surviving legal entity.
 
On February 10, 2011, KMI converted from a Delaware limited liability company named Kinder Morgan Holdco LLC to a Delaware corporation named Kinder Morgan, Inc., and its outstanding units were converted into classes of capital stock.  On February 16, 2011, KMI completed the initial public offering of its common stock.  All of the common stock that was sold in the offering was sold by existing investors, consisting of funds advised by or affiliated with Goldman, Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC.  No members of management sold shares in the offering, and KMI did not receive any proceeds from the offering.  KMI’s common stock trades on the New York Stock Exchange under the symbol “KMI.”
 
As of December 31, 2011, 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 12.4% 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 2011 distribution level, KMI received approximately 50% of all quarterly distributions of available cash from us, with approximately 44% and 6% of all quarterly distributions from us attributable to KMI’s general partner and limited partner interests, respectively.
 
On October 16, 2011, KMI and El Paso Corporation announced a definitive agreement whereby KMI will acquire all of the outstanding shares of El Paso in a transaction that would, as of the announcement date, create an energy company that would have an enterprise value of approximately $94 billion and would own an interest in approximately 80,000 miles of pipelines.  As of the announcement date, the total purchase price, including the assumption of debt outstanding at both El Paso Corporation and El Paso Pipeline Partners, L.P., was approximately $38 billion.  El Paso Corporation owns a 42% limited partner interest and the 2% general partner interest in El Paso Pipeline Partners, L.P.  The transaction is expected to close in the second quarter of 2012 and is subject to customary regulatory approvals.
 
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, 2011, KMR, through its sole ownership of our i-units, owned approximately 29.3% of all of our outstanding limited partner units.
 
Recent Developments
 
The following is a brief listing of significant developments since December 31, 2010.  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 February 2011, our subsidiary SFPP, L.P. entered into a settlement agreement with a shipper regarding various interstate transportation rate challenges filed with the Federal Energy Regulatory Commission, referred to in this report as the FERC.  In March 2011, we made payments of $63.0 million pursuant to this settlement agreement.  Additionally, in September 2011, we made refund payments to various intrastate transportation shippers totaling $18.4 million.  During 2011, we recognized a combined $251.8 million increase in expense due to adjustments of our liabilities related to interstate and intrastate transportation rate challenges and certain other litigation matters involving our West Coast Products Pipeline operations;
 

 
 
 
On May 5, 2011, we announced an approximately $220 million investment to build a new crude oil/condensate pipeline that will initially transport 50,000 barrels of condensate per day for Petrohawk Energy Corporation (a wholly-owned subsidiary of BHP Billiton) from its production area in the Eagle Ford shale gas formation in South Texas to the Houston Ship Channel.  The pipeline will consist of approximately 70 miles of new pipeline construction and 113 miles of existing natural gas pipeline that will be converted to transport crude oil and condensate.  The pipeline will originate near Cuero, Texas, and extend to the Houston Ship Channel where it will initially deliver condensate to multiple terminaling facilities having access to local refineries, petrochemical plants and loading docks.  We began construction on the crude oil/condensate pipeline in December 2011 and we expect to place the pipeline into service during the second quarter of 2012.  When fully complete, the pipeline will have a capacity of approximately 300,000 barrels per day;
 
 
On September 14, 2011, we announced that we will partner with Valero Energy Corporation to build the Parkway Pipeline, a new 136-mile, 16-inch diameter pipeline that will transport refined petroleum products from refineries located in Norco, Louisiana, to Plantation Pipe Line Company’s petroleum transportation hub located in Collins, Mississippi.  From this hub, the products will be transported by various products pipeline systems (including Plantation, our approximately 51%-owned equity investee) that serve major markets in the southeastern United States.  We will operate the Parkway Pipeline and our ownership is through our 50% equity interest in Parkway Pipeline LLC, the sole owner of the Parkway Pipeline.  Valero Energy Corporation owns the remaining 50% ownership interest.  Pending receipt of environmental and regulatory approvals, the approximately $220 million pipeline project is expected to be in service by mid-year 2013.  The Parkway Pipeline will have an initial capacity of 110,000 barrels per day, with the ability to expand to over 200,000 barrels per day.  The project is supported by a long-term throughput agreement with a credit-worthy shipper;
 
 
As of the date of this report, construction continues on our previously announced refined petroleum products storage expansion project at our West Coast Terminals’ Carson, California products terminal.  The approximately $77 million expansion project will add seven storage tanks with a combined capacity of 560,000 barrels.  In October 2011, we completed and placed into service two storage tanks, and we expect to place the remaining five tanks into service in late 2012 and early 2013.  We have entered into a long-term agreement with a major oil company to lease six of these tanks;
 
 
As of the date of this report, construction continues on our West Coast Products Pipelines’ approximately $48 million expansion project at Travis Air Force Base located in Fairfield, California.  As previously announced, we are constructing three 150,000 barrel storage tanks that will be used for the transportation and storage of incremental military jet fuel.  Two of the three storage tanks were completed and placed into service in December 2011, and we expect to place the remaining tank into service in March 2012;
 
 
As of the date of this report, we continue to invest more than $35 million to further expand our renewable fuel handling capabilities at various terminal sites across the United States.  We completed biodiesel blending modifications at Plantation’s Collins, Mississippi hub in December 2011.  These modifications allow Plantation to transport blended biodiesel to several of our existing Southeast terminal facilities.  Additionally, construction continues at our Port of Tampa terminal related to our previously announced public-private partnership project with the Tampa Port Authority and CSX Corporation that will bring additional ethanol into the Tampa market via the nations’ first ethanol unit train to pipeline distribution system.  We expect this new ethanol hub will be operational by October 2012;
 
 
On December 14, 2011, we announced that we will build, own and operate a petroleum condensate processing facility near our Galena Park liquids terminal located on the Houston Ship Channel.  The processing facility will have an initial throughput of 25,000 barrels per day and will be designed for future expansions that will allow for throughput of up to 100,000 barrels per day.  The facility will split condensate into its various components such as light and heavy naphthas, kerosene and gas oil, and through a fee structure, a major oil industry customer is underwriting the initial throughput of the facility.  Our current estimate of total construction costs on the project is approximately $130.0 million and we expect to complete construction of this facility and commence service in January 2014; and
 
 
On December 15, 2011, we acquired a refined petroleum products terminal located on a 14-acre site in Lorton, Virginia from Motiva Enterprises, LLC for an aggregate consideration of $12.5 million in cash.  The terminal is served exclusively by the Plantation Pipeline and has storage capacity of approximately 450,000 barrels for refined petroleum products like gasoline and jet fuel.
 

 
Natural Gas Pipelines
 
 
On January 1, 2011, Fayetteville Express Pipeline LLC began firm contract pipeline transportation service to customers on its Fayetteville Express natural gas pipeline system, a 187-mile, 42-inch diameter pipeline that provides shippers in the Arkansas Fayetteville shale gas area with takeaway natural gas capacity and further access to growing markets.  We own a 50% interest in Fayetteville Express Pipeline LLC, and Energy Transfer Partners L.P. owns the remaining interest and also operates the Fayetteville Express pipeline system.  Construction of the pipeline system was completed in January 2011, and total costs for the project were slightly less than $1.0 billion (versus the original budget of $1.3 billion);
 
 
On April 14, 2011, our subsidiary Kinder Morgan Interstate Gas Transmission LLC completed construction and placed into service all remaining capital improvements that expanded its mainline natural gas pipeline facilities that run from Franklin to Hastings, Nebraska.  The pipeline expansion and capital improvements created up to ten million cubic feet per day of natural gas capacity to serve an ethanol plant located near Aurora, Nebraska.  Project construction commenced in October 2009 and total costs for the project were approximately $18.4 million;
 
 
In May 2011, we completed debrining a third underground storage cavern at our North Dayton natural gas storage facility located in Liberty County, Texas.  The completed cavern added approximately seven billion cubic feet of working natural gas storage capacity at the facility, and the development and mining of the cavern was part of an approximately $103 million expansion project at our North Dayton storage facility;
 
 
On July 1, 2011, our Texas intrastate natural gas pipeline group replaced an expiring 10-year services agreement with Calpine Corporation with a new 10-year agreement that extends to July 1, 2021.  Pursuant to the terms of the agreement, our intrastate group will provide Calpine approximately 300 million cubic feet per day of natural gas transport capacity and four billion cubic feet of natural gas storage capacity.  Calpine will use the service to supply fuel to seven of its electricity generating facilities in the state of Texas;
 
 
On July 1, 2011, we acquired from Petrohawk Energy Corporation both the remaining 50% equity ownership interest in KinderHawk Field Services LLC that we did not already own and a 25% equity ownership interest in EagleHawk Field Services, LLC (Petrohawk’s natural gas gathering and treating business located in the Eagle Ford shale gas formation) for an aggregate consideration of $912.1 million, consisting of $835.1 million in cash and assumed debt of $77.0 million (representing 50% of KinderHawk’s borrowings under its bank credit facility as of July 1, 2011).  We then repaid the outstanding $154.0 million of borrowings and following this repayment, KinderHawk had no outstanding debt.
 
 
Following our acquisition of the remaining ownership interest in KinderHawk on July 1, 2011, we changed our method of accounting from the equity method to full consolidation, and due to the fact that we acquired a controlling financial interest in KinderHawk, we remeasured our previous 50% equity investment in KinderHawk to its fair value.  We recognized a $167.2 million non-cash loss as a result of this remeasurement.  The loss amount represents the excess of the carrying value of our investment ($910.2 million as of July 1, 2011) over its fair value ($743.0 million), and we reported this loss separately within the “Other Income (Expense)” section in our accompanying consolidated statements of income for the year ended December 31, 2011.Further information on our KinderHawk operations is discussed below in “—(c) Narrative Description of Business—Natural Gas Pipelines—Texas Intrastate Natural Gas Pipeline Group and Other—KinderHawk Field Services LLC;”
 
 
On August 1, 2011, Eagle Ford Gathering LLC initiated flow on its natural gas gathering system with deliveries to Copano’s natural gas processing plant located in Colorado County, Texas.  Eagle Ford Gathering LLC is a joint venture that provides natural gas gathering, transportation and processing services to natural gas producers in the Eagle Ford shale gas formation.  It is owned 50% by us and 50% by Copano Energy, L.L.C.  Copano also serves as operator and managing member.  On October 3, 2011, Eagle Ford Gathering initiated flow on its new 56-mile, 24-inch diameter crossover pipeline and a 7-mile, 20-inch diameter lateral pipeline with deliveries to Williams Partners L.P.’s Markham processing plant located in Matagorda County, Texas.  The joint venture has also completed a 20-mile, 20-inch diameter pipeline to deliver natural gas to Formosa’s Point Comfort plant located in Jackson County, Texas and expects initial flow of natural gas to Formosa to occur in March 2012.  Including its 111 miles of 30-inch diameter and 24-inch diameter gathering pipelines, its crossover pipeline, its pipeline laterals to Williams and to Formosa, and the capacity rights it holds on certain of our natural gas pipelines, Eagle Ford Gathering has approximately 400 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; and
 
 
 
On November 30, 2011, we acquired a manufacturing complex and certain natural gas treating assets from SouthTex Treaters, Inc. for an aggregate consideration of $178.5 million, consisting of $151.5 million in cash and assumed liabilities of $27.0 million.  SouthTex Treaters, Inc. is a leading manufacturer, designer and fabricator of natural gas treating plants that are used to remove impurities (carbon dioxide and hydrogen sulfide) from natural gas before it is delivered into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications.  The acquisition complemented and expanded our existing natural gas treating business.
 
CO2
 
 
On November 17, 2011, we announced that we had entered into a purchase and sale agreement with a subsidiary of Enhanced Oil Resources to acquire a carbon dioxide source field and related assets located in Apache County, Arizona, and Catron County, New Mexico, for approximately $30 million in cash.  The acquisition includes 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, and we expect that this acquisition will provide us with opportunities to further grow our existing carbon dioxide business.  The transaction closed on January 31, 2012;
 
 
During 2011, we activated 15 additional patterns at our carbon dioxide flood in the Katz oil field located near Knox City, Texas.  The flood is part of our previously announced Eastern Shelf Pipeline project in the eastern Permian Basin area of Texas.  The approximately $230 million project also involved the installation of a 91-mile, 10-inch carbon dioxide distribution pipeline that begins near Snyder, Texas and ends west of Knox City.  We began injecting carbon dioxide into the Katz field in December 2010 and currently, we are producing approximately 1,400 barrels of crude oil per day from the Katz field.  The development of the carbon dioxide flood in the Katz field is projected to produce an incremental 25 million barrels of oil over the next 15 to 20 years and will provide a platform for future enhanced oil recovery operations in the region; and
 
 
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 current production rate from 105 million cubic feet of carbon dioxide per day to 170 million cubic feet per day.  We expect to begin construction in the second quarter of 2012, 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 three wells scheduled for completion in 2012.
 
Terminals
 
 
On January 3, 2011 and December 28, 2011, we made two separate $50 million preferred equity investments in Watco Companies, LLC, the largest privately held short line railroad company in the United States.  Watco also operates transload/intermodal and mechanical services divisions.  Our investments provided capital to Watco for further expansion of specific projects, and for pending acquisitions, including Watco’s previously announced acquisitions of both a controlling interest in the Wisconsin & Southern Railroad and the assets of Birmingham Southern Railway.  Our investment in Watco provides our customers access to more transportation related services and also offers us the opportunity to share in additional growth opportunities through new projects, such as crude oil unit train operations and incremental business at our terminal storage facilities.  Pursuant to the terms of our investments, we receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and we participate partially in additional profit distributions at a rate equal to 0.5%.  The preferred shares have no conversion features and hold no voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers.  As of December 31, 2011, our net equity investment totaled $101.7 million;
 
 
In January 2011, we completed construction of an approximately $16.2 million railcar loop track at our Deepwater petroleum coke terminal facility located in Pasadena, Texas.  The track is used to transport a major petroleum coke producer’s volumes to the facility;
 
 
On February 17, 2011, our subsidiary Kinder Morgan Cushing LLC, Deeprock Energy Resources, LLC and Mecuria Energy Trading, Inc., entered into formal agreements for a crude oil storage joint venture located in Cushing, Oklahoma.  On this date, we contributed $15.9 million for a 50% ownership interest in the Deeprock North, LLC joint venture, which operated an existing crude oil tank farm that had storage capacity of one million barrels.  During 2011, we contributed an additional $7.7 million for our proportionate share of costs related to the construction of three new storage tanks that provide for incremental storage capacity of 750,000 barrels.  The new tanks were completed and placed in service during the fourth quarter of 2011.  Deeprock Energy operates and owns a 12.02% member interest in the joint venture, and Mecuria owns the remaining 37.98% member interest and is the anchor tenant for the joint venture’s crude oil capacity for the next five years with an option to extend.  As of December 31, 2011, our net equity investment in Deeprock North, LLC totaled $24.0 million;
 
 
 
On February 24, 2011 and October 3, 2011, respectively, in order to capitalize on increasing demand for both coal export activity and domestic coal use, we entered into two separate agreements to expand our coal terminal operations at our International Marine Terminals facility (IMT), a multi-product, import-export facility located in Port Sulphur, Louisiana and owned 66 2/3% by us.  In February 2011, we entered into a 15-year services agreement with Massey Coal, a division of Alpha Natural Resources, to handle up to six million tons of coal annually.  The majority of the coal that will pass through IMT will originate from Massey’s Central Appalachia mines, be transported to IMT by river barges, and then offloaded and stored before being loaded onto ocean vessels for export to foreign markets.  We anticipate a minimum throughput tonnage increase of four million tons per year related to this agreement.  Secondly, in October 2011, we entered into a long-term agreement with Progress Energy Florida to handle up to four million toms of coal per year at IMT.  This agreement will commence in early 2013, and provides Progress Energy with options to extend the agreement for up to 20 years.  Together, we and our remaining one-third partner at IMT are investing approximately $114 million to expand and upgrade the facility to enable it to handle the incremental coal volumes related to these two agreements.  We expect the terminal upgrades to be completed by mid-2013;
 
 
In March 2011, we completed construction of our previously announced Deer Park Rail Terminal (DPRT) and related ethanol handling assets at our Pasadena, Texas terminal located along the Houston Ship Channel.  The approximately $19 million project included building a new ethanol unit train facility with space for multiple unit trains, an offloading rail rack for unit trains of approximately 100 railcars, and an 80,000 barrel ethanol storage tank.  As part of the expansion, we also extended an existing pipeline by approximately 2.4 miles so that ethanol can be moved from DPRT to our nearby Pasadena liquids terminal for either storage or blending at the terminal’s truck rack.  The project is supported by long-term customer contracts;
 
 
In March 2011, we entered into an agreement with a large western coal producer to handle up to 2.2 million tons of Colorado coal annually at our Houston, Texas bulk terminal facility located on the Houston Ship Channel.  Unit trains will transport bituminous coal from Colorado mines to our Houston bulk facility, where the coal will be offloaded and stored before being loaded onto ocean vessels.  We also announced an approximately $18 million investment to increase the facility’s coal handling capability by adding rail and conveying equipment, and outbound equipment needed to load coal onto ships.  We began handling coal for this new contract in July 2011, marking the first time that western coal was exported from the Port of Houston;
 
 
On June 10, 2011, we acquired a newly constructed petroleum coke terminal located in Port Arthur, Texas from TGS Development, L.P. (TGSD) for an aggregate consideration of $74.1 million, consisting of $42.9 million in cash, $23.7 million in common units, and an obligation to pay additional consideration of $7.5 million.  We estimate our remaining $7.5 million obligation will be paid to TGSD approximately one year from the closing (in May or June 2012), and will be settled in a combination of cash and common units, depending on TGSD’s election.  We operate the terminal, which receives petroleum coke from Total Petrochemicals USA Inc.’s Port Arthur refinery, and we provide conveying, storage and ship loading services to Total pursuant to a 25-year services agreement.  The refinery is expected to produce more than one million tons of petroleum coke annually;
 
 
On July 20, 2011, we announced an incremental $8.3 million investment at our DPRT (described above) which will add additional ethanol handling and storage capabilities.  The expansion includes building a second 80,000 barrel storage tank and related facilities.  We expect this project will be completed in the first quarter of 2012;
 
 
In September 2011, we completed an approximately $14 million expansion of our Philadelphia, Pennsylvania liquids terminal to provide storage and handling services to accommodate a large chemical company.  The project involved upgrading existing tank and pipeline systems and installing a new marine flare unit.  The project is secured with a five-year customer agreement;
 
 
In September 2011, we completed an approximately $62 million expansion of our Carteret, New Jersey liquids terminal that added 1.04 million barrels of new petroleum storage tank capacity.  In July 2009, we entered into an agreement with a major oil company for this additional capacity.  The project involved the construction of seven new blending tanks, consisting of three 125,000 barrel tanks and four 165,000 barrel storage tanks.  All of the tanks can be used for gasoline blending, and some have built-in flexibility for either ethanol or distillate service;
 
 
 
On November 8, 2011, we announced our equity participation in Battleground Oil Specialty Terminal Company LLC (BOSTCO), and we paid a combined $12.0 million to acquire our initial 50% Class A member interest (consisting of $11.6 million paid in October 2011 and $0.4 million of pre-development costs incurred and paid for during 2010).  On December 29, 2011, we acquired the remaining 50% Class A member interest in BOSTCO that we did not already own from TransMontaigne Partners, L.P. for an aggregate consideration of $8.1 million in cash (net of an acquired cash balance of $9.9 million).  TransMontaigne also received a transferrable option to buy 50% of our ownership interest at any time prior to January 20, 2013; however, we are currently unable to predict whether it will exercise this purchase option.
 
 
BOSTCO will construct, own and operate an approximately $430 million oil terminal located on the Houston Ship Channel.  Phase I of the project includes the design and construction of 52 tanks with combined storage capacity of approximately 6.6 million barrels for handling residual fuel, feedstocks, distillates and other black oils.  BOSTCO will initially be a water-in, water-out facility with the capability of handling ships with large drafts up to 45 feet, and we have executed terminal service contracts or letters of intent with customers for almost all of the Phase I storage capacity;
 
 
On November 30, 2011, we announced an approximately $212 million investment to construct seven tanks with a storage capacity of approximately 2.4 million barrels for crude oil and condensate at our Trans Mountain pipeline terminal located near Edmonton, Alberta, Canada.  We have entered into long-term contracts with customers to support this expansion, which will set the framework for two additional phases that will ultimately allow for up to six million barrels of dedicated storage.  Previously, we received National Energy Board (Canada) approval to construct merchant and regulated tanks at our Edmonton terminal, and we intend to commence construction in early 2012 following receipt of other supporting permits.  We anticipate that the new tanks will be placed in service in late 2013;
 
 
On January 18, 2012, we announced that we had entered into a long-term agreement with a major Canadian oil producer to support an approximately $8.5 million expansion of pipeline feeder connections into our Kinder Morgan North 40 terminal, a crude oil tank farm located in Strathcona County, just east of Edmonton, Alberta, Canada; and
 
 
On January 24, 2012, we announced plans to invest an additional $140 million to further expand our coal handling export facilities along the Gulf Coast.  Concurrently, Arch Coal Company signed a long-term throughput agreement with us that will help support this expansion, which we anticipate to complete in the second quarter of 2014.  Upon completion of the proposed terminal upgrades, and subject to certain rail service agreements, Arch will ship coal at guaranteed minimum volume levels through our owned terminal facilities.  In addition, we and Arch are in final discussions to include, in the throughput agreement, port space for coal shipments at our coal export facilities located on the East Coast and at our IMT facility, which when combined with our Gulf Coast expansions, will provide incremental port capacity for Arch’s growing seaborne coal volumes.  We are also extending certain existing long-term coal handling agreements with Arch at our coal facilities located in the state of Illinois.
 
Kinder Morgan Canada
 
 
From October 20, 2011 until February 16, 2012, our Trans Mountain pipeline system conducted a binding public open season to assess shipper interest for a proposed system expansion.  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.  Based on shipper response, we would construct a twin pipeline that could boost system capacity to over 600,000 barrels per day.  Our current estimate of total construction costs on the project is approximately $3.8 billion.
 
Financings
 
 
On March 4, 2011, we issued a total of $1.1 billion in principal amount of senior notes in two separate series, consisting of $500 million of 3.50% notes due March 1, 2016, and $600 million of 6.375% notes due March 1, 2041.  We used the net proceeds received from this debt offering to reduce the borrowings under our commercial paper program;
 
 
On March 15, 2011, we paid $700 million to retire the principal amount of our 6.75% senior notes that matured on that date;
 
 
 
On July 1, 2011, we amended our $2.0 billion three-year, senior unsecured revolving credit facility to, among other things, (i) allow for borrowings of up to $2.2 billion; (ii) extend the maturity of the credit facility from June 23, 2013 to July 1, 2016; (iii) permit an amendment to allow for borrowings of up to $2.5 billion; and (iv) decrease the interest rates and commitment fees for borrowings under this facility.  The credit facility is with a syndicate of financial institutions, and the facility permits us to obtain bids for fixed rate loans from members of the lending syndicate.  Wells Fargo Bank, National Association is the administrative agent, and borrowings under the credit facility can be used for general partnership purposes and as a backup for our $2.2 billion commercial paper program;
 
 
On August 17, 2011, we issued a total of $750 million in principal amount of senior notes in two separate series, consisting of $375 million of 4.15% notes due March 1, 2022, and $375 million of 5.625% notes due September 1, 2041.  We used the net proceeds received from this debt offering to reduce the borrowings under our commercial paper program;
 
 
In August 2011, we terminated two existing fixed-to-variable interest rate swap agreements in two separate transactions.  These swap agreements had a combined notional principal amount of $200 million, and we received combined proceeds of $73.0 million from the early termination of these swap agreements; and
 
 
In 2011, we issued 13,469,708 common units for $955.3 million in cash, described following.  We used the net proceeds received from the issuance of these common units to reduce the borrowings under our commercial paper program:
 
 
 
In June 2011, we completed a public offering of 7,705,000 of our common units at a price of $71.44 per unit.  After commissions and underwriting expenses, we received net proceeds of $533.9 million for the issuance of these common units; and
 
 
 
During 2011, we issued 5,764,708 of our common units pursuant to our equity distribution agreement with UBS Securities LLC.  After commissions, we received net proceeds of $421.4 million from the issuance of these common units.
 
2012 Outlook
 
 
As previously announced, we anticipate that for the year 2012, (i) we will declare cash distributions of $4.98 per unit, an 8% increase over our cash distributions of $4.61 per unit for 2011; (ii) our business segments will generate approximately $4.4 billion in earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments and our 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 approximately $1.7 billon to our limited partners; (iv) we will produce excess cash flow of $71.0 million above our cash distribution target of $4.98 per unit; and (v) we will invest approximately $1.7 billion for our capital expansion program (including small acquisitions and contributions to joint ventures).  Our anticipated 2012 expansion investment will help drive earnings and cash flow growth in 2012 and beyond, and we estimate that approximately $490 million of the equity required for our 2012 investment program will be funded by cash retained as a function of KMR distributions being paid in additional units rather than in cash.  In 2011, our capital expansion program was approximately $2.6 billion—including discretionary capital spending, equity contributions to our equity investees, and acquisition cash expenditures.
 
Our expectations assume an average West Texas Intermediate (WTI) crude oil price of approximately $93.75 per barrel in 2012.  Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO2 business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids.  We hedge the majority of our crude oil production, but do have exposure to unhedged volumes, the majority of which are natural gas liquids volumes.  For 2012, 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 $5.8 million (or slightly over 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 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 and approval of the parties’ respective boards of directors.  While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.
 
Business Segments
 
We own and manage a diversified portfolio of energy transportation and storage assets.  Our operations are conducted through our five operating limited partnerships and their subsidiaries and are grouped into five reportable business segments.  These segments are as follows:
 
 
Products Pipelines—which consists of approximately 8,400 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;
 
 
Natural Gas Pipelines—which consists of approximately 16,200 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 2,000 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates eight oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;
 
 
Terminals—which consists of approximately 115 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 regulated by the FERC, intrastate pipelines in the state of California regulated by the California Public Utilities Commission, and certain non rate-regulated operations and terminal facilities.
 
Our 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 2011, our Pacific operations’ mainline pipeline system transported approximately 1,071,400 barrels per day of refined products, with the product mix being approximately 59% gasoline, 24% 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 2011, our Calnev pipeline system transported approximately 118,800 barrels per day of refined products, with the product mix being approximately 41% gasoline, 33% diesel fuel, and 26% 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 9.1 million barrels of storage for both petroleum products and chemicals.  Our West Coast Products Pipelines and associated West Coast Terminals together handled 17.6 million barrels of ethanol in 2011.
 
Combined, our West Coast Products Pipelines operations’ pipelines transport approximately 1.2 million barrels per day of refined petroleum products, providing pipeline service to approximately 29 customer-owned terminals, 11 commercial airports and 15 military bases.  The pipeline systems serve approximately 70 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 2011, Plantation delivered approximately 518,000 barrels per day of refined petroleum products, with the product mix being approximately 67% gasoline, 20% 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, BP, 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 2011, the pipeline system transported approximately 93,000 barrels per day of refined products, with the product mix being approximately 69% gasoline and ethanol, 11% 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.  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 approximately 70,000 barrels per day.  It includes 31 pump stations spaced at 60 mile intervals and five United States propane terminals.  Underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario through third parties.  The pipeline traverses three provinces in Canada and seven states in the United States and can transport propane, butane and natural gas liquids to the midwestern United States and eastern Canadian petrochemical and fuel markets.  In 2011, the pipeline system transported approximately 26,500 barrels per day of propane, and in 2012, we expect to begin transporting additional natural gas liquids products.
 
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 2011, the system transported approximately 45,000 barrels per day.
 
Southeast Terminals
 
Our Southeast terminal operations consist of 27 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 2011, these terminals transferred approximately 353,000 barrels of refined products per day and together handled 9.2 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 processed approximately 10.6 million barrels of transmix in 2011.
 

 

 

 
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.  Its primary businesses consist of natural gas sales, transportation, storage, gathering, processing and treating.  Within this segment, we own approximately 16,300 miles of natural gas pipelines and associated storage and supply lines that are strategically located at the center of the North American pipeline grid.  Our transportation network provides access to the major gas supply areas in the western United States, Texas and the Midwest, as well as major consumer markets.
 
Texas Intrastate Natural Gas Pipeline Group and Other
 
Texas Intrastate Natural Gas Pipeline Group
 
Our Texas intrastate natural gas pipeline group, which operates primarily along the Texas Gulf Coast, consists of the following four natural gas pipeline systems: (i) our Kinder Morgan Texas Pipeline; (ii) our Kinder Morgan Tejas Pipeline; (iii) our Mier-Monterrey Mexico Pipeline; and (iv) our Kinder Morgan North Texas Pipeline.
 
The two largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder Morgan Tejas Pipeline.  These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability.  The combined system includes approximately 6,000 miles of intrastate natural gas pipelines with a peak transport and sales capacity of approximately 5.5 billion cubic feet per day of natural gas and approximately 144 billion cubic feet of on-system natural gas storage capacity, including 11 billion cubic feet contracted from a third party (which will be reduced to 5 billion cubic feet in April 2012).  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 65 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 375 million cubic feet per day.  The pipeline connects to a 1,000-megawatt power plant complex and to the Pemex natural gas transportation system.  We have entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for all of the pipeline’s capacity.
 
Our Kinder Morgan North Texas Pipeline consists of an 82-mile pipeline that transports natural gas from an interconnect with the facilities of 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.  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 2011, the four natural gas pipeline systems in our Texas intrastate group provided an average of approximately 2.23 billion cubic feet per day of natural gas transport services.  The Texas intrastate group also sold approximately 804.7 billion cubic feet of natural gas in 2011.
 
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 well positioned to interconnect with liquefied natural gas projects currently under development by others along 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 designs, constructs, and sells custom and stock natural gas treating plants.  Combined, our rental fleet of treating assets include approximately 213 natural gas amine-treating plants, approximately 56 hydrocarbon dew point control plants, and more than 140 mechanical refrigeration units that are used to remove impurities and hydrocarbon liquids from natural gas streams prior to entering transmission pipelines.
 
In addition, on November 30, 2011, we acquired certain natural gas treating assets from SouthTex Treaters, Inc., a leading manufacturer, designer and fabricator of natural gas treating plants.  Further information about this acquisition is discussed above in “—(a) General Development of Business—Recent Developments—Natural Gas Pipelines.”
 
KinderHawk Field Services LLC and EagleHawk Field Services LLC
 
On July 1, 2011, we acquired from Petrohawk Energy Corporation both the remaining 50% equity ownership interest in KinderHawk Field Services LLC that we did not already own and a 25% equity ownership interest in EagleHawk Field Services LLC.  Further information about this acquisition is discussed above in “—(a) General Development of Business—Recent Developments—Natural Gas Pipelines.”  On August 25, 2011, mining and oil company BHP Billiton completed its previously announced acquisition of Petrohawk Energy Corporation through a short-form merger under Delaware law.  The merger was closed with Petrohawk being the surviving corporation as a wholly owned subsidiary of BHP Billiton.  The acquisition will not affect the terms of our contracts with Petrohawk.
 
KinderHawk Field Services LLC gathers and treats natural gas in the Haynesville shale gas formation located in northwest Louisiana.  Its assets currently consist of more than 450 miles of natural gas gathering pipeline currently in service, with average throughput of approximately 1.1 billion cubic feet per day of natural gas.  Ultimately, KinderHawk is expected to have approximately 2.0 billion cubic feet per day of throughput capacity, which will make it one of the largest natural gas gathering and treating systems in the United States.  Additionally, the system’s natural gas amine treating plants have a current capacity of approximately 2,600 gallons per minute.
 
KinderHawk owns life of lease dedications to gather and treat all of Petrohawk’s operated Haynesville and Bossier shale gas production in northwest Louisiana at agreed upon rates, as well as minimum volume commitments from Petrohawk for a five year term that expires in May 2015.  During 2011, KinderHawk executed firm gathering and treating agreements with a third-party producer for the long-term dedication of five sections.  KinderHawk also holds additional third-party gas gathering and treating commitments.  In total, these contracts provide for the dedication of 36 sections, from four shippers, for three to ten years.
 
EagleHawk Field Services LLC provides natural gas gathering and treating services in the Eagle Ford shale formation in South Texas.  Petrohawk 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 280 miles of gas gathering pipelines and approximately 140 miles of condensate lines.  It also has a life of lease dedication of Petrohawk’s Eagle Ford reserves that will provide Petrohawk and other Eagle Ford producers with natural gas and condensate gathering, treating and condensate stabilization services.
 

 

 

 
Endeavor Gathering LLC
 
We own a 40% equity interest in Endeavor Gathering LLC, which provides natural gas gathering service to GMX Resources’ exploration and production activities in its Cotton Valley Sands and Haynesville/Bossier Shale horizontal well developments located in East Texas.  GMX Resources, 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 compressors that collect and compress natural gas from GMX Resources’ operated natural gas production from wells located in its core area.  The natural gas gathering system has takeaway capacity of approximately 115 million cubic feet per day.
 
Eagle Ford Gathering LLC
 
We own a 50% equity interest in Eagle Ford Gathering LLC, which provides natural gas gathering, transportation and processing services to natural gas producers in the Eagle Ford shale gas formation in south Texas.  Further information about Eagle Ford Gathering LLC is discussed above in “—(a) General Development of Business—Recent Developments—Natural Gas Pipelines.”
 
Upstream Operations
 
Our Natural Gas Pipelines’ upstream operations consist of our Casper and Douglas, Wyoming natural gas processing operations and our 49% ownership interest in the Red Cedar Gas Gathering Company.  We own and operate our Casper and Douglas, Wyoming natural gas processing plants, and combined, these plants have the capacity to process up to 185 million cubic feet per day of natural gas depending on raw gas quality.  Casper and Douglas are the only natural gas processing plants which provide straddle processing of natural gas flowing into our Kinder Morgan Interstate Gas Transmission LLC pipeline system.  We also own the operations of a carbon dioxide/sulfur treating facility located in the West Frenchie Draw field of the Wind River Basin of Wyoming, and we include this facility as part of our Casper and Douglas operations.  The West Frenchie Draw treating facility has a capacity of 50 million cubic feet per day of natural gas.
 
We own a 49% equity interest in the Red Cedar Gathering Company, a joint venture organized in August 1994 and referred to in this report as Red Cedar.  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 750 miles of gathering pipeline connecting more than 900 producing wells, 104,600 horsepower of compression at 22 field compressor stations and three carbon dioxide treating plants.  The capacity and throughput of the Red Cedar gathering system is approximately 600 million cubic feet per day of natural gas.   
 
Western Interstate Natural Gas Pipeline Group
 
Our Western interstate natural gas pipeline group, which operates primarily along the Rocky Mountain region of the Western portion of the United States, consists of the following three natural gas pipeline systems: (i) Kinder Morgan Interstate Gas Transmission Pipeline; (ii) TransColorado Pipeline; and (iii) our 50% ownership interest in the Rockies Express Pipeline.
 
Kinder Morgan Interstate Gas Transmission LLC
 
Our subsidiary, Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, owns approximately 5,100 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska.  Our KMIGT pipeline system is powered by 23 transmission and storage compressor stations having approximately 155,000 horsepower.  KMIGT also owns the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, which has approximately 35 billion cubic feet of total capacity, consisting of 15 billion cubic feet of working capacity and 20 billion cubic feet of cushion gas.  KMIGT has 11 billion cubic feet of firm capacity commitments and provides for withdrawals of up to 179 million cubic feet of natural gas per day.
 
Under transportation agreements and FERC tariff provisions, KMIGT offers its customers firm and interruptible transportation and storage services, including no-notice service and park and loan services.  KMIGT also has the authority to make gas purchases and sales, as needed for system operations, pursuant to its currently effective FERC natural gas tariff.  Our KMIGT system also offers its Cheyenne Market Center service, which provides nominated storage and transportation service between its Huntsman storage field and multiple interconnecting pipelines at the Cheyenne Hub, located in Weld County, Colorado.  Additionally, our KMIGT pipeline system includes the Colorado Lateral, which is a 41-mile, 12-inch pipeline extending from the Cheyenne Hub southward to the Greeley, Colorado area.  In 2011, KMIGT transported an average of approximately 451 million cubic feet per day of natural gas.
 
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 has a pipeline capacity of 1.0 billion cubic feet per day of natural gas and it has the ability to flow gas south or north.  In 2011, our TransColorado pipeline system transported an average of approximately 420 million cubic feet per day of natural gas.
 
Our TransColorado pipeline system receives natural gas from a single 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.
 
Rockies Express Pipeline     
 
We operate and own 50% of the 1,679-mile Rockies Express natural gas pipeline system, one of the largest natural gas pipelines constructed in North America in the last 25 years.  The Rockies Express system consists of the following three pipeline segments: (i) a 327-mile pipeline that extends from the Meeker Hub in northwest Colorado, across southern Wyoming to the Cheyenne Hub in Weld County, Colorado; (ii) a 713-mile pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri; and (iii) a 639-mile pipeline from Audrain County, Missouri to Clarington, Ohio.  Our ownership is through our 50% equity interest in Rockies Express Pipeline LLC, the sole owner of the Rockies Express pipeline system.  Sempra Pipelines & Storage, a unit of Sempra Energy, and ConocoPhillips each own 25% of Rockies Express Pipeline LLC.
 
The Rockies Express pipeline system is powered by 18 compressor stations totaling approximately 427,000 horsepower.  The system is capable of transporting 2.0 billion cubic feet per day of natural gas from Meeker, Colorado to the Cheyenne Market Hub in northeastern Colorado and 1.8 billion cubic feet per day from the Cheyenne Hub to the Clarington Hub in Monroe County in eastern Ohio.  Capacity on the Rockies Express system is nearly fully contracted under ten year firm service agreements with producers from the Rocky Mountain supply basin.  These agreements provide the pipeline with fixed monthly reservation revenues for the primary term of such contracts through 2019, with the exception of one agreement representing approximately 10% of the pipeline capacity that grants a shipper the one-time option to terminate effective late 2014.  With its connections to numerous other pipeline systems along its route, the Rockies Express system has access to almost all of the major gas supply basins in Wyoming, Colorado and eastern Utah.  Rockies Express is capable of delivering gas to multiple markets along its pipeline system, primarily through interconnects with other interstate pipeline companies and direct connects to local distribution companies.
 
     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 four natural gas pipeline systems: (i) Trailblazer Pipeline; (ii) Kinder Morgan Louisiana Pipeline; (iii) our 50% ownership interest in the Midcontinent Express Pipeline; and (iv) our 50% ownership interest in the Fayetteville Express Pipeline.
 
Trailblazer Pipeline Company LLC
 
Our subsidiary, Trailblazer Pipeline Company LLC, referred to in this report as Trailblazer, owns the 436-mile Trailblazer natural gas pipeline system.  Our Trailblazer pipeline system originates at an interconnection with Wyoming Interstate Company Ltd.’s pipeline system near Rockport, Colorado and runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where it interconnects with NGPL’s and Northern Natural Gas Company’s pipeline systems.  NGPL manages, maintains and operates the Trailblazer system for us, for which it is reimbursed at cost.  Trailblazer offers its customers firm and interruptible transportation, and in 2011, it transported an average of approximately 717 million cubic feet per day of natural gas.  All of the system’s firm transport capacity is currently subscribed.
 
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.  In 2011, our Kinder Morgan Louisiana pipeline system transported an average of approximately 21 million cubic feet per day of natural gas.
 
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.  Regency Midcontinent Express LLC owns the remaining 50% ownership interest.  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 2012 and 2021.  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 contact 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 65% working interest in the Claytonville unit; (v) an approximate 99% working interest in the Katz Strawn unit; and (vi) 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 2011, the average purchased carbon dioxide injection rate at SACROC was 154 million cubic feet per day.  The average oil production rate for 2011 was approximately 28,600 barrels of oil per day (23,800 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 2011, the average purchased carbon dioxide injection rate at SACROC was 107 million cubic feet per day, and during 2011, the Yates unit produced approximately 21,700 barrels of oil per day (9,600 net barrels to KMCO2 per day).
 
KMCO2 also operates and owns an approximate 65% gross working interest in the Claytonville oil field unit and operates and owns an approximate 99% working interest in the Katz Strawn unit, both located in the Permian Basin area of West Texas.  The Claytonville unit is located nearly 30 miles east of the SACROC unit, in Fisher County, Texas.  The unit produced approximately 200 gross barrels of oil per day during 2011 (100 net barrels to KMCO2 per day).  During 2011, the Katz Strawn unit produced approximately 500 barrels of oil per day (400 net barrels to KMCO2 per day).  In 2011, the average purchased carbon dioxide injection rate at the Katz Strawn unit was 46 million cubic feet per day.
 
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, 2011.  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
    2,191       1,358       919       699       3       3  
Natural Gas
    5       2       -       -       -       -  
Total Wells
    2,196       1,360       919       699       3       3  
____________
 

 
(a)
Includes active wells and wells temporarily shut-in.  As of December 31, 2011, 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; 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, 2011. 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, 2011, 2010 and 2009:
 
   
Year Ended December 31,
 
   
2011
   
2010
   
2009
 
Productive
                 
Development                                  
    85       70       42  
Exploratory                                  
    -       -       -  
Dry
                       
Development                                  
    -       -       -  
Exploratory                                  
    -       -       -  
Total Wells
    85       70       42  
____________
 
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, 2011:
 
   
Gross
   
Net
 
Developed Acres
    74,240       69,558  
Undeveloped Acres
    8,788       8,129  
Total
    83,028       77,687  
____________
 
Note:
As of December 31, 2011, we have no material amount of acreage expiring in the next three years.
 
 
See Note 20 to our consolidated financial statements included elsewhere in this report for additional information with respect to operating statistics and supplemental information on our oil and gas producing activities.
 
Gas and Gasoline Plant Interests
 
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 2011 averaged approximately 16,600 gross barrels per day (8,300 net barrels to KMCO2 per day excluding the value associated to KMCO2’s 28% net profits interest).
 
 
 

 

 
Sales and Transportation Activities
 
Carbon Dioxide Reserves
 
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 more than 870 billion cubic feet of carbon dioxide.  For both units combined, compression capacity exceeds 1.4 billion cubic feet per day of carbon dioxide and during 2011, the two units produced approximately 1.25 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 more than 800 billion cubic feet of recoverable carbon dioxide and produced approximately 300 million cubic feet of carbon dioxide per day in 2011.
 
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 over 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.  The pipeline has a current capacity of 70 million cubic feet per day, expandable to 200 million cubic feet per day in the future.  The Eastern Shelf Pipeline system is currently flowing 56 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, and it transported approximately 112,000 barrels of oil per day in 2011.  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 reserves, and Petro-Source Carbon Company, which gathers waste carbon dioxide 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 115 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 25 liquids terminals facilities possess liquids storage capacity of approximately 60.2 million barrels, and in 2011, these terminals handled approximately 616 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 90 dry-bulk terminals in the United States and Canada, and combined, our dry-bulk and material transloading facilities (described below) handled approximately 100.6 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2011.
 
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.
 

 
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, 2011.
 
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.  We believe these facilities provide us the opportunity to consider capacity expansions to the west coast, either in stages or as one project, as the market for offshore exports continues to develop.
 
In 2011, Trans Mountain delivered an average of 274,000 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 January 2012, Trans Mountain completed negotiations with the Canadian Association of Petroleum Producers for a new negotiated toll settlement effective for the period beginning January 1, 2012 and ending December 31, 2012.  Trans Mountain anticipates National Energy Board approval in the second quarter of 2012.
 
Express and Jet Fuel Pipeline Systems
 
We own a one-third ownership interest in the Express pipeline system, and a subordinated debenture issued by Express US Holdings LP, the partnership that maintains ownership of the U.S. portion of 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 175,000 barrels per day in 2011.
 

 

 
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 2011.
 
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, 2011, 2010 and 2009, 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 2011, 2010 and 2009 accounted for 40.6%, 44.8% and 44.8%, 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, 2011.  In January 2012, 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 2012.  Trans Mountain anticipates approval from the NEB in the second quarter of 2012.  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 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.
 
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.  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.
 
Safety Regulation
 
Our interstate pipelines are subject to regulation by the United States Department of Transportation, referred to in this report as the U.S. DOT, and our intrastate pipelines and other operations are subject to comparable state regulations with respect to their design, installation, testing, construction, operation, replacement and management.  Comparable regulation exists in some states in which we conduct pipeline operations.  In addition, our truck and terminal loading facilities are subject to U.S. DOT regulations dealing with the transportation of hazardous materials by motor vehicles and railcars.
 
On September 15, 2010, the secretary of the U.S. DOT sent to the U.S. Congress proposed legislation to provide stronger oversight of the nation’s pipelines and to increase the penalties for violations of pipeline safety rules.  The proposed legislation entitled “Strengthening Pipeline Safety and Enforcement Act of 2010,” would, among other things, increase the maximum fine for the most serious violations from $1 million to $2.5 million, provide additional resources for the enforcement program, require a review of whether safety requirements for “high consequence areas” should be applied instead to entire pipelines, eliminate exemptions and ensure standards are in place for bio-fuel and carbon dioxide pipelines.
 
The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication.  The Pipeline Safety Improvement Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as “high consequence areas.”  Testing consists of hydrostatic testing, internal magnetic flux or ultrasonic testing, or direct assessment of the piping.  In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained.  A similar integrity management rule exists for refined petroleum products pipelines.
 
We are also subject to the requirements of the Federal Occupational Safety and Health Act and other comparable federal and state statutes that address employee health and safety.  In general, we expect to 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 accurately 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 $74.7 million as of December 31, 2011.  Our reserve estimates range in value from approximately $74.7 million to approximately $129.7 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability.  For additional information related to environmental matters, see Note 16 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.  These regulations contain lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our pipelines, treating and processing facilities, storage facilities, terminals and wells.  Depending on the nature of those requirements and any additional requirements that may be imposed by state and local regulatory authorities, we may be required to incur capital and operating expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission-related issues.  At this time, we are unable to fully estimate the effect on earnings or operations or the amount and timing of such required capital expenditures; however, we do not believe that we will be materially adversely affected by any such requirements.
 
Clean Water Act
 
Our operations can result in the discharge of pollutants.  The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state waters or waters of the United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal, 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.  It is not possible at this time to predict what action, if any, the U.S. Congress may take in regard to greenhouse gas legislation.
 
As discussed above under “—Clean Air Act,” 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.  These regulations include the reporting of greenhouse gas emissions in the United States from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, like the McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.
 
Because our operations, including our compressor stations and gas processing plants in our Natural Gas Pipelines segment, emit various types of greenhouse gases, primarily methane and carbon dioxide, such legislation or regulation could increase our costs related to operating and maintaining our facilities and require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.  We are not able at this time to estimate such increased costs; however, they could be significant.  While we may be able to include some or all of such increased costs in the rates charged by our natural gas pipelines, such recovery of costs is uncertain in all cases and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations.  Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.
 
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.
 
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 and Kinder Morgan Canada Inc. employ all persons necessary for the operation of our business.  Generally, we reimburse these entities for the services of their employees.  As of December 31, 2011, KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. had, in the aggregate, 8,120 full-time employees.  Approximately 833 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2012 and 2016.  KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. each consider relations with their employees to be good.  For more information on our related party transactions, see Note 11 to our consolidated financial statements included elsewhere in this report.
 
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.  The information contained on or connected to our internet Website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the Securities and Exchange Commission.
 
 
Item 1A.  Risk Factors.
 
You should carefully consider the risks described below, in addition to the other information contained in this document.  Realization of any of the following risks could have a material adverse effect on our business, financial 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, such as the FERC, the CPUC and the NEB.  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 Department of homeland Security to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” 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 or the CPUC may establish pipeline tariff rates that have a negative impact on us.  In addition, the FERC, the CPUC, 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 such costs increase in an amount greater than what we are permitted by the FERC or the CPUC to recover in our rates, or to the extent that there is a lag before the pipeline can file and obtain rate increases, such events can have a negative impact upon our operating results.
 
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 FERC and the CPUC that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates on our West Coast Products Pipeline systems.  Further, the FERC has initiated 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 could 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, if losses in excess of our insurance coverage were to occur, they could have a material adverse effect on our business, financial condition and results of operations.
 
Increased regulatory requirements relating to the integrity of our pipelines will require us to spend additional money to comply with these requirements.
 
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 U.S. DOT issued final rules (effective February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as “High Consequence Areas.”  The ultimate costs of compliance with the integrity management rules are difficult to predict.  The majority of the costs to comply with the rules are associated with pipeline integrity testing and the repairs found to be necessary.  Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in High Consequence Areas can have a significant impact on the costs to perform integrity testing and repairs.  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.
 
We may face competition from competing 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 recently completed several major expansion and new build projects, including the joint venture projects Rockies Express Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline.  We also are conducting and conduct from time to time alone or with others what are referred to as “open seasons” to evaluate the potential customer interest for new construction projects.  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 affected negatively.  In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
 
Whether 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 acquisition strategy and expansion programs require access to new capital.  Tightened capital markets or more expensive 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 will impair our ability to execute this strategy.
 
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.
 
Part of our business strategy includes acquiring additional businesses, 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 companies that have previously operated separately involves a number of risks, including (i) demands on management related to the increase in our size after an acquisition, expansion or completed construction project; (ii) the diversion of management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v) potential adverse effects on operating results.
 
We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately.  Successful integration of each acquisition, expansion or construction project will depend upon our ability to manage those operations and to eliminate redundant and excess costs.  Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.
 
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 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 of certain stationary sources on January 2, 2011, and issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, like our McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.
 
Because our operations, including our compressor stations and 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 and the provisions of any final legislation or other regulations.  Any of the foregoing could have adverse effects on our business, financial position, results of operations 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.  Natural gas extracted 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.
 
Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.
 
As of December 31, 2011, we had $12.8 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 such as 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, 2011, approximately $6.0 billion (47%) of our total $12.8 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.”
 
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 the threat of them, may adversely affect our business.
 
The U.S. government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations.  These potential targets might include our pipeline systems or storage facilities.  Our operations could become subject to increased governmental scrutiny that would require increased security measures.  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.
 
Future business development of our pipelines 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 a level 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 may have a material adverse effect on our results of operations and financial condition.  We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas, crude oil and refined petroleum products.
 
The future success of 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 business.
 
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 2012, 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 $5.8 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 price 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 was signed into law by the President on July 21, 2010, and 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.  The act also requires the CFTC to institute broad new position limits for 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 Our Common Units
 
The interests of KMI may differ from our interests and the interests of our unitholders.
 
KMI indirectly owns all of the common stock of our general partner and elects all of its directors.  Our general partner owns all of KMR’s voting shares and elects all of its directors.  Furthermore, some of KMR’s directors and officers are also directors and officers of KMI and our general partner and have fiduciary duties to manage the businesses of KMI in a manner that may not be in the best interests of our unitholders.  KMI has a number of interests that differ from the interests of our unitholders.  As a result, there is a risk that important business decisions will not be made in the best interests of our unitholders.
 
Common unitholders have limited voting rights and limited control.
 
Holders of common units have only limited voting rights on matters affecting us.  Our general partner manages partnership activities.  Under a delegation of control agreement, our general partner has delegated the management and control of our and our subsidiaries’ business and affairs to KMR.  Holders of common units have no right to elect the general partner on an annual or other ongoing basis.  If the general partner withdraws, however, its successor may be elected by the holders of a majority of the outstanding common units (excluding units owned by the departing general partner and its affiliates).
 
The limited partners may remove the general partner only if (i) the holders of at least 66 2/3% of the outstanding common units, excluding common units owned by the departing general partner and its affiliates, vote to remove the general partner; (ii) a successor general partner is approved by at least 66 2/3% of the outstanding common units, excluding common units owned by the departing general partner and its affiliates; and (iii) we receive an opinion of counsel opining that the removal would not result in the loss of limited liability to any limited partner, or the limited partner of an operating partnership, or cause us or the operating partnership to be taxed other than as a partnership for federal income tax purposes.
 
A person or group owning 20% or more of the common units cannot vote.
 
Any common units held by a person or group that owns 20% or more of the common units cannot be voted.  This limitation does not apply to the general partner and its affiliates.  This provision may (i) discourage a person or group from attempting to remove the general partner or otherwise change management; and (ii) reduce the price at which the common units will trade under certain circumstances.  For example, a third party will probably not attempt to take over our management by making a tender offer for the common units at a price above their trading market price without removing the general partner and substituting an affiliate of its own.
 
The general partner’s liability to us and our unitholders may be limited.
 
Our partnership agreement contains language limiting the liability of the general partner to us or the holders of common units.  For example, our partnership agreement provides that (i) the general partner does not breach any duty to us or the holders of common units by borrowing funds or approving any borrowing (the general partner is protected even if the purpose or effect of the borrowing is to increase incentive distributions to the general partner); (ii) the general partner does not breach any duty to us or the holders of common units by taking any actions consistent with the standards of reasonable discretion outlined in the definitions of available cash and cash from operations contained in our partnership agreement; and (iii) the general partner does not breach any standard of care or duty by resolving conflicts of interest unless the general partner acts in bad faith.
 
Unitholders may have liability to repay distributions.
 
Unitholders will not be liable for assessments in addition to their initial capital investment in the common units.  Under certain circumstances, however, holders of common units may have to repay us amounts wrongfully returned or distributed to them.  Under Delaware law, we may not make a distribution to unitholders if the distribution causes our liabilities to exceed the fair value of our assets.  Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted.  Delaware law provides that for a period of three years from the date of such a distribution, a limited partner who receives the distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount.  Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership.  However, such an assignee is not obligated for liabilities unknown to the assignee at the time the assignee became a limited partner if the liabilities could not be determined from the partnership agreement.
 
Unitholders may be liable if we have not complied with state partnership law.
 
We conduct our business in a number of states.  In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established.  The unitholders might be held liable for the partnership’s obligations as if they were a general partner if (i) a court or government agency determined that we were conducting business in the state but had not complied with the state’s partnership statute; or (ii) unitholders’ rights to act together to remove or replace the general partner or take other actions under our partnership agreement constitute “control” of our business.
 
The general partner may buy out minority unitholders if it owns 80% of the units.
 
If at any time the general partner and its affiliates own 80% or more of the issued and outstanding common units, the general partner will have the right to purchase all, and only all, of the remaining common units.  Because of this right, a unitholder could have to sell its common units at a time or price that may be undesirable.  The purchase price for such a purchase will be the greater of (i) the 20-day average trading price for the common units as of the date five days prior to the date the notice of purchase is mailed; or (ii) the highest purchase price paid by the general partner or its affiliates to acquire common units during the prior 90 days.  The general partner can assign this right to its affiliates or to us.
 
We may sell additional limited partner interests, diluting existing interests of unitholders.
 
Our partnership agreement allows the general partner to cause us to issue additional common units and other equity securities.  When we issue additional equity securities, including additional i-units to KMR when it issues additional shares, unitholders’ proportionate partnership interest in us will decrease.  Such an issuance could negatively affect the amount of cash distributed to unitholders and the market price of common units.  Issuance of additional common units will also diminish the relative voting strength of the previously outstanding common units.  Our partnership agreement does not limit the total number of common units or other equity securities we may issue.
 
The general partner can protect itself against dilution.
 
Whenever we issue equity securities to any person other than the general partner and its affiliates, the general partner has the right to purchase additional limited partnership interests on the same terms.  This allows the general partner to maintain its proportionate partnership interest in us.  No other unitholder has a similar right.  Therefore, only the general partner may protect itself against dilution caused by issuance of additional equity securities.
 

Our partnership agreement and the KMR limited liability company agreement restrict or eliminate a number of the fiduciary duties that would otherwise be owed by our general partner and/or its delegate to our unitholders.
 
Modifications of state law standards of fiduciary duties may significantly limit the ability of our unitholders to successfully challenge the actions of our general partner in the event of a breach of fiduciary duties.  These state law standards include the duties of care and loyalty.  The duty of loyalty, in the absence of a provision in the limited partnership agreement to the contrary, would generally prohibit our general partner from taking any action or engaging in any transaction as to which it has a conflict of interest.  Our limited partnership agreement contains provisions that prohibit limited partners from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law.  For example, that agreement provides that the general partner may take into account the interests of parties other than us in resolving conflicts of interest.  It also provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general partner will not be a breach of any duty.  The provisions relating to the general partner apply equally to KMR as its delegate.  It is not necessary for a limited partner to sign our limited partnership agreement in order for the limited partnership agreement to be enforceable against that person.
 
Our tax treatment depends on our status as a partnership for 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 Internal Revenue Service 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.  To maintain our status as a partnership for U.S. federal income tax purposes, current law requires that 90% or more of our gross income for every taxable year consist of “qualifying income,” as defined in Section 7704 of the Internal Revenue Code of 1986, as amended, which we refer to as the Code. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other matter affecting us.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible under certain circumstances for such an entity to be treated as a corporation for U.S. federal income tax purposes.  If we were to be 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 would pay state income taxes at varying rates.  Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders.  Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced.  Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the amount of distributions we pay, and in the value of our common units.
 
Current law or our business may change, causing us to be treated as a corporation for U.S. federal income tax purposes or otherwise subjecting us to entity-level taxation.  Members of Congress are considering substantive changes to the existing U.S. federal income tax laws that could affect the tax treatment of certain publicly-traded partnerships.  For example, federal income tax legislation recently has been considered by Congress that would eliminate partnership tax treatment for certain publicly-traded partnerships. Although the legislation most recently considered by Congress would not appear to affect our tax treatment as a partnership for U.S. federal income tax purposes, we are unable to predict whether any other proposals will ultimately be enacted.  Any such changes could negatively impact our cash flows and the value of our common units.
 
In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation.  For example, we are now subject to an entity-level tax on the portion of our total revenue that is generated in Texas.  Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas.  This tax reduces, and the imposition of such a tax on us by another state will reduce, the cash available for distribution to our common unitholders.
 
Our partnership agreement provides that if a law is enacted that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal income tax purposes, the minimum quarterly distribution and the target distribution levels will be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time.  Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively.  Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any changes could negatively impact the value of an investment in our common units.
 
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.
 
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 use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method.  If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.
 
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our common 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 from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take.  A court may not agree with some or all of our counsel's conclusions or the positions we take.  Any contest with the IRS may materially and adversely impact the market for our 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 common unitholders and our general partner 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 which 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 even if they do not receive any 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 that results from that income.
 
Tax gain or loss on 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 decrease 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 may include a common unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, such unitholder 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 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.
 
Our treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of our common units.
 
Because we cannot match transferors and transferees of common units, we are required to maintain the uniformity of the economic and tax characteristics of these common units in the hands of the purchasers and sellers of these common units.  We do so by adopting certain depreciation conventions that do not conform to all aspects of the U.S. Treasury regulations.  A successful IRS challenge to these conventions could adversely affect the tax benefits to a common unitholder of ownership of our common units  and could have a negative impact on the value of our common units or result in audit adjustments to a common unitholder’s tax returns.
 
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.  The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations.  Our counsel is unable to opine on the validity of such filing positions.
 
We adopted certain valuation methodologies that 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 current valuation methods, subsequent purchasers of common units may have a greater portion of their adjustment under Section 743(b) of the Code 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 adjustment under Section 743(b) of the Code attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our 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 terminated 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 any twelve-month period.  Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a significant deferral of depreciation deductions allowable in computing our taxable income.  In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income being includable in the common unitholder's taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes.  If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
 
A common unitholder whose common units are loaned to a “short seller” to cover a short sale 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 cover 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 cover 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 may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
 
In addition to 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.
 
Risks Related to Ownership of Our Common Units if We or KMI Defaults on Debt
 
Unitholders may have negative tax consequences if we default on our debt or sell assets.
 
If we default on any of our debt, the lenders will have the right to sue us for non-payment.  Such an action could cause an investment loss and cause negative tax consequences for unitholders through the realization of taxable income by unitholders without a corresponding cash distribution.  Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, unitholders could have increased taxable income without a corresponding cash distribution.
 
There is the potential for a change of control 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.
 

 
 
None.
 
 
Item 3.  Legal Proceedings.
 
See Note 16 to our consolidated financial statements included elsewhere in this report.
 
 
 
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
 
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  
                                 
2010
First Quarter
  $ 65.55     $ 58.00     $ 1.07       0.017863  
Second Quarter
    69.33       57.40       1.09       0.018336  
Third Quarter
    69.90       63.15       1.11       0.017844  
Fourth Quarter
    71.72       68.19       1.13       0.017393  

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 $4.98 per unit for 2012; however, no assurance can be given that we will be able to achieve this level of distribution.
 
As of January 31, 2012, there were approximately 443,000 holders of our common units (based on the number of record holders and individual participants in security position listings), one holder of our Class B units and one holder of our i-units.
 
For information on our equity compensation plans, see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Equity Compensation Plan Information” and Note 12 “Commitments and Contingent Liabilities—Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements included elsewhere in this report.
 
We did not repurchase any units during the fourth quarter of 2011 or sell any unregistered units in the fourth quarter of 2011.
 


 
 
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,
 
   
2011(e)
   
2010(e)
   
2009(e)
   
2008(f)
   
2007(g)
 
   
(In millions, except per unit and ratio data)
 
Income and Cash Flow Data:
                             
Revenues                                                             
  $ 8,211.2     $ 8,077.7     $ 7,003.4     $ 11,740.3     $ 9,217.7  
Operating income                                                             
  $ 1,670.5     $ 1,605.1     $ 1,515.1     $ 1,551.5     $ 807.7  
Earnings from equity investments                                                             
  $ 311.1     $ 223.1     $ 189.7     $ 160.8     $ 69.7  
Income from continuing operations                                                             
  $ 1,268.4     $ 1,327.1     $ 1,283.8     $ 1,317.2     $ 423.4  
Income from discontinued operations(a)
  $ -     $ -     $ -     $ 1.3     $ 173.9  
Net income                                                             
  $ 1,268.4     $ 1,327.1     $ 1,283.8     $ 1,318.5     $ 597.3  
Limited Partners’ interest in net income (loss)
  $ 82.8     $ 431.4     $ 331.7     $ 499.0     $ (21.3 )
                                         
Limited Partners’ net income (loss) per unit:
                                       
Income (loss) per unit from continuing operations
  $ 0.25     $ 1.40     $ 1.18     $ 1.94     $ (0.82 )
Income from discontinued operations                                                             
    -       -       -       -       0.73  
Net income (loss) per unit                                                             
  $ 0.25     $ 1.40     $ 1.18     $ 1.94     $ (0.09 )
                                         
Per unit cash distribution declared(b)
  $ 4.61     $ 4.40     $ 4.20     $ 4.02     $ 3.48  
Ratio of earnings to fixed charges(c)
    3.16       3.50       3.82       3.77       2.13  
Capital expenditures                                                             
  $ 1,199.5     $ 1,000.9     $ 1,323.8     $ 2,533.0     $ 1,691.6  
                                         
Balance Sheet Data (at end of period):
                                       
Net property, plant and  equipment                                                             
  $ 15,595.8     $ 14,603.9     $ 14,153.8     $ 13,241.4     $ 11,591.3  
Total assets                                                             
  $ 24,102.7     $ 21,861.1     $ 20,262.2     $ 17,885.8     $ 15,177.8  
Long-term debt(d)                                                             
  $ 11,159.5     $ 10,277.4     $ 9,997.7     $ 8,274.9     $ 6,455.9  
____________
 
(a)
Represents income from the operations of our North System natural gas liquids pipeline system.  Due to the October 2007 sale of our North System, we accounted for the North System business as a discontinued operation.  In 2008, we recorded incremental gain adjustments of $1.3 million related to our sale of the North System, and except for this gain adjustment on our disposal of the North System, we recorded no other financial results from the operations of the North System during 2008.  The 2007 amount includes gains of $152.8 million on the disposal of our North System.
 
(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 value of interest rate swaps.  Increases to long-term debt for value of interest rate swaps totaled $1,078.9 million as of December 31, 2011, $604.9 million as of December 31, 2010, $332.5 million as of December 31, 2009, $951.3 million as of December 31, 2008 and $152.2 million as of December 31, 2007.
 
(e)
For each of the years 2011, 2010 and 2009, includes results of operations for net assets acquired since effective dates of acquisition.  For further information on these acquisitions, see Note 3 to our consolidated financial statements included elsewhere in this report.
 
(f)
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.
(g)
Includes results of operations for the remaining 50.2% interest in the Cochin pipeline system that we did not already own, the Vancouver Wharves bulk marine terminal, and the bulk terminal assets and operations acquired from Marine Terminals, Inc. since effective dates of acquisition.  We acquired the remaining interest in Cochin effective January 1, 2007, the Vancouver Wharves terminal effective May 30, 2007, and the assets and operations from Marine Terminals, Inc. effective September 1, 2007.  Also includes results of operations for the net assets of Trans Mountain for the four months prior to the acquisition date.  We acquired the net assets of Trans Mountain from KMI on April 30, 2007.
 

 
Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this report.  Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2011, found in Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”
 
Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements.  These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management's judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties.  Our actual results could differ materially from those discussed in the forward-looking statements.  Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in 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, bulk and liquids terminal facilities, and carbon dioxide and petroleum reserves. Our reportable business segments are based on the way our management organizes our enterprise, and each of our 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 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.  Many of our operations are regulated by various U.S. and Canadian regulatory bodies and 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.
 
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 Pipeline business, 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, 2011, the remaining average contract life of our natural gas transportation contracts (including our intrastate pipelines) was approximately eight years.
 
Our CO2 sales and transportation business primarily has contracts with minimum volume requirements, which as of December 31, 2011, had a remaining average contract life of four years (this remaining average contract life includes intercompany sales; when we eliminate intercompany sales, the remaining average contract life is approximately five 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 contracts making deliveries in 2012, and utilizing the average oil price per barrel contained in our 2012 budget, approximately 70% of our contractual volumes are based on a fixed fee or floor price, and 30% fluctuate with the price of oil (these percentages include intercompany sales; when we eliminate intercompany sales, the percentages are 72% and 28%, respectively).  In the long-term, our success in this business is driven by the demand for carbon dioxide.  However, short-term changes in the demand for carbon dioxide typically do not have a significant impact on us due to the required minimum 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 $69.73 per barrel in 2011, $59.96 per barrel in 2010 and $49.55 per barrel in 2009.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $92.61 per barrel in 2011, $76.93 per barrel in 2010 and $59.02 per barrel in 2009.
 
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 is typically 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 2011, we invested approximately $2.6 billion for both strategic business acquisitions and expansions of existing assets.  Our capital investments have helped us to achieve compound annual growth rates in cash distributions to our limited partners of 4.8%, 4.7% and 7.2%, respectively, for the one-year, three-year and five-year periods ended December 31, 2011.
 
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 $1.7 billion for our 2012 capital expansion program, including small acquisitions and investment contributions.  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.
 
In addition, we regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions.  While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.  Our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates at the right cost, and includes factors over which we have limited or no control.  Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates.
 
Our 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 2011, please see “—Liquidity and Capital Resources” below.
 
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.
 
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
 
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, 2011, 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, 2011 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 Note 20 to our consolidated financial statements included elsewhere in this report.
 
Hedging Activities
 
We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives.  According to the provisions of 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,
 
   
2011
   
2010
   
2009
 
   
(In millions)
 
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
                 
Products Pipelines(b)
  $ 463.1     $ 504.5     $ 584.5  
Natural Gas Pipelines(c)
    774.2       836.3       789.6  
CO2(d)
    1,098.6       965.5       782.9  
Terminals(e)
    704.5       641.3       599.0  
Kinder Morgan Canada(f)
    201.6       181.6       154.5  
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments
    3,242.0       3,129.2       2,910.5  
                         
Depreciation, depletion and amortization expense
    (954.5 )     (904.8 )     (850.8 )
Amortization of excess cost of equity investments
    (6.7 )     (5.8 )     (5.8 )
General and administrative expenses(g)
    (472.7 )     (375.2 )     (330.3 )
Interest expense, net of unallocable interest income(h)
    (531.0 )     (506.4 )     (431.3 )
Unallocable income tax expense
    (8.7 )     (9.9 )     (8.5 )
Net income
    1,268.4       1,327.1       1,283.8  
Net income attributable to noncontrolling interests(i)
    (10.6 )     (10.8 )     (16.3 )
Net income attributable to Kinder Morgan Energy Partners, L.P.
  $ 1,257.8     $ 1,316.3     $ 1,267.5  
____________
 
(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)
2011 amount includes (i) a $168.2 million increase in expense associated with rate case liability adjustments; (ii) a $60.0 million increase in expense associated with rights-of-way lease payment liability adjustments for periods prior to 2011; (iii) an $8.6 million increase in expense associated with environmental liability adjustments; (iv) a $6.7 million increase in expense associated with legal liability adjustments related to a litigation matter involving our Calnev pipeline’s Las Vegas terminal operations; (v) a $12.1 million increase in income from both the disposal of property and the settlement of a legal matter related to the sale of a portion of our Gaffey Street, California land; and (vi) a $0.1 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor did we pay any amounts or realize any direct benefits related to this compensation expense).  2010 amount includes (i) a $172.0 million increase in expense associated with rate case liability adjustments; (ii) an $18.0 million decrease in income associated with combined property environmental expenses and the demolition of physical assets in preparation for the sale of our Gaffey Street, California land; (iii) a $2.5 million increase in expense associated with environmental liability adjustments; (iv) an $8.8 million gain from the sale of a 50% ownership interest in the Cypress pipeline system and the revaluation of our remaining interest to fair value; and (v) a $0.7 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions.  2009 amount includes (i) a $23.0 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries; (ii) an $18.0 million increase in expense associated with rate case and other legal liability adjustments; (iii) an $11.5 million increase in expense associated with environmental liability adjustments; (iv) a $1.7 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions; and (v) a $0.2 million increase in income from hurricane casualty gains.
 
(c)
2011 amount includes a $167.2 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value, and a $9.7 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011.  2010 amount includes a $0.4 million increase in income from certain measurement period adjustments related to our October 1, 2009 natural gas treating business acquisition.  2009 amount includes (i) a $7.8 million increase in income from hurricane casualty gains; (ii) a decrease in income of $5.6 million resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas; and (iii) a $0.1 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries.
 
 
 
(d)
2011, 2010 and 2009 amounts include a $5.2 million unrealized gain, a $5.3 million unrealized gain and a $13.5 million unrealized loss, respectively, related to derivative contracts used to hedge forecasted crude oil sales.
 
(e)
2011 amount includes (i) a $4.8 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor did we pay any amounts or realize any direct benefits related to this compensation expense); (ii) a $4.3 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal; (iii) a $2.2 million increase in income associated with the sale of a 51% ownership interest in two of our subsidiaries: River Consulting LLC and Devco USA L.L.C.; (iv) a $1.5 million increase in income from the sale of our ownership interest in Arrow Terminals B.V.; (v) a $1.3 million increase in income from adjustments associated with the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009; (vi) a $7.6 million decrease in income from casualty insurance deductibles and the write-off of assets related to casualty losses; (vii) a $2.0 million increase in expense associated with environmental liability adjustments; (viii) a $0.6 million increase in expense associated with the settlement of a litigation matter at our Carteret, New Jersey liquids terminal; and (ix) a combined $0.5 million decrease in income from property write-offs and expenses associated with the on-going dissolution of our partnership interest in Globalplex Handling.  2010 amount includes (i) a combined $7.4 million decrease in income from casualty insurance deductibles and the write-off of assets related to casualty losses; (ii) a combined $4.1 million decrease in income associated with a write-down of the carrying value of net assets to be sold to their estimated fair values as of December 31, 2010 (associated with the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009); (iii) a $0.6 million increase in expense related to storm and flood clean-up and repair activities; (iv) a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminals; and (v) a $0.2 million decrease in expense from certain measurement period adjustments related to our March 5, 2010 Slay Industries terminal acquisition.  2009 amount includes (i) a $24.0 million increase in income from hurricane and fire casualty gains and clean-up and repair activities; (ii) a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal; (iii) a $0.9 million increase in expense associated with environmental liability adjustments; and (iv) a $0.7 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries.
 
(f)
2011 amount includes a $3.1 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor did we pay any amounts or realize any direct benefits related to this compensation expense).  2009 amount includes a $14.9 million increase in expense primarily due to certain non-cash regulatory accounting adjustments to Trans Mountain’s carrying amount of the previously established deferred tax liability, and a $3.7 million decrease in expense due to a certain non-cash accounting adjustment related to book tax accruals made by the Express pipeline system.
 
(g)
2011 amount includes (i) a combined $89.9 million increase in non-cash compensation expense (including $87.1 million related to a special bonus expense to non-senior management employees), allocated to us from KMI; however, we do not have any obligation, nor did we pay any amounts related to this expense; (ii) a combined $4.1 million increase in expense for unallocated legal expenses and certain asset and business acquisition expenses; and (iii) a $0.2 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.  2010 amount includes (i) a $4.6 million increase in non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor did we pay any amounts related to this expense); (ii) a $4.2 million increase in expense for certain asset and business acquisition costs; (iii) a $1.6 million increase in legal expense associated with items disclosed in these footnotes such as legal settlements and pipeline failures; and (iv) a $0.2 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.  2009 amount includes (i) a $5.7 million increase in non-cash compensation expense, allocated to us from KMI (we do not have any obligation, nor did we pay any amounts related to this expense); (ii) a $2.3 million increase in expense for certain asset and business acquisition costs, which under prior accounting standards would have been capitalized; (iii) a $1.3 million increase in expense for certain land transfer taxes associated with our April 30, 2007 Trans Mountain acquisition; and (iv) a $2.7 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.
 
(h)
2011, 2010 and 2009 amounts include increases in imputed interest expense of $0.7 million, $1.1 million and $1.6 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition.
 
(i)
2011, 2010 and 2009 amounts include decreases of $6.6 million, $4.6 million and $0.7 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2011, 2010 and 2009 items previously disclosed in these footnotes.
 

Segment earnings before depreciation, depletion and amortization expenses
 
Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement generally consists of all our cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use segment earnings before depreciation, depletion and amortization expenses (defined in the table above and sometimes referred to in this report as EBDA) internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments.
 
Total segment earnings before depreciation, depletion and amortization expenses increased by $112.8 million (4%) in 2011 compared to 2010; however, this overall increase in earnings included a decrease of $214.0 million from the effect of the certain items described in the footnotes to the table above (which combined to decrease total segment EBDA by $396.5 million and $182.5 million in 2011 and 2010, respectively).  The remaining $326.8 million (10%) increase in total segment earnings before depreciation, depletion and amortization in 2011 compared to 2010 resulted from better performance from all five of our reportable business segments, primarily due to increases attributable to our CO2 ($133.2 million), Natural Gas Pipelines ($115.2 million), and Terminals ($54.6 million) business segments.
 
In 2010, total segment earnings before depreciation, depletion and amortization increased $218.7 million (8%) compared to 2009, and the overall increase included a $132.2 million decrease in earnings from the effect of the certain items described in the footnotes to the table above (combining to decrease total segment EBDA by $182.5 million and $50.3 million in 2010 and 2009, respectively).  The remaining $350.9 million (12%) increase in total segment earnings before depreciation, depletion and amortization in 2010 versus 2009 resulted from better performance from all five of our reportable business segments, mainly due to increases attributable to our CO2 and Terminals business segments.
 
Products Pipelines
 
   
Year Ended December 31,
 
   
2011
   
2010
   
2009
 
   
(In millions, except operating statistics)
 
Revenues
  $ 914.0     $ 883.0     $ 826.6  
Operating expenses(a)
    (499.7 )     (414.6 )     (269.5 )
Other income (expense)(b)
    10.0       (4.2 )     (0.6 )
Earnings from equity investments
    50.6       33.1       29.0  
Interest income and Other, net(c)
    8.2       16.4       12.4  
Income tax expense(d)
    (20.0 )     (9.2 )     (13.4 )
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments
  $ 463.1     $ 504.5     $ 584.5  
                         
Gasoline (MMBbl)(e)
    398.0       403.5       400.1  
Diesel fuel (MMBbl)
    148.9       148.3       143.2  
Jet fuel (MMBbl)
    110.5       106.2       111.4  
Total refined product volumes (MMBbl)
    657.4       658.0       654.7  
Natural gas liquids (MMBbl)
    26.1       25.2       26.5  
Total delivery volumes (MMBbl)(f)
    683.5       683.2       681.2  
Ethanol (MMBbl)(g)
    30.4       29.9       23.1  
__________

(a)
2011, 2010 and 2009 amounts include increases in expense of $8.6 million, $2.5 million and $11.5 million, respectively, associated with environmental liability adjustments.  2011 amount also includes a $168.2 million increase in expense associated with rate case liability adjustments, a $60.0 million increase in expense associated with rights-of-way lease payment liability adjustments, and a $6.7 million increase in expense associated with legal liability adjustments related to a litigation matter involving our Calnev pipeline’s Las Vegas terminal operations.  2010 amount also includes a $172.0 million increase in expense associated with rate case liability adjustments, and a $14.1 million increase in expense associated with environmental clean-up expenses and the demolition of physical assets in preparation for the sale of our Gaffey Street, California land.  2009 amount also includes a $23.0 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries, and an $18.0 million increase in expense associated with rate case and other legal liability adjustments.
 
(b)
2011 amount includes a $10.8 million increase in income from the sale of a portion of our Gaffey Street, California land.  2010 amount includes disposal losses of $3.9 million related to the retirement of our Gaffey Street, California land.  2009 amount includes a gain of $0.2 million from hurricane casualty indemnifications.
 
(c)
2011 amount includes a $1.3 million increase in income from the settlement of a legal matter related to the sale of a portion of our Gaffey Street, California land.  2010 and 2009 amounts include increases in income of $0.7 million and $1.7 million, respectively, resulting from unrealized foreign currency gains on long-term debt transactions.  2010 amount also includes an $8.8 million gain from the sale of a 50% ownership interest in the Cypress pipeline system and the revaluation of our remaining interest to fair value.
 
(d)
2011 amount includes a $0.1 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor did we pay any amounts or realize any direct benefits related to this compensation expense).
 
(e)
Volumes include ethanol pipeline volumes.
 
(f)
Includes Pacific, Plantation, Calnev, Central Florida, Cochin, and Cypress pipeline volumes.
 
(g)
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 decreases in segment earnings before depreciation, depletion and amortization expenses of $48.3 million in 2011, and $132.4 million in 2010, when compared with the respective prior year.  Following is information related to the segment’s (i) remaining $6.9 million (1%) and $52.4 million (8%) increases in earnings before depreciation, depletion and amortization; and (ii) $31.0 million (4%) and $56.4 million (7%) increases in operating revenues in both 2011 and 2010, when compared with the respective prior year:
 
Year Ended December 31, 2011 versus Year Ended December 31, 2010
 
   
EBDA
increase/(decrease)
   
Revenues
increase/(decrease)
 
   
(In millions, except percentages)
 
Cochin Pipeline
  $ 17.5       53 %   $ 29.9       66 %
Plantation Pipeline
    8.6       19 %     1.2       6 %
West Coast Terminals
    8.5       11 %     9.8       10 %
Pacific operations
    (17.6 )     (6 )%     (11.1 )     (3 )%
Calnev Pipeline
    (4.6 )     (8 )%     (3.4 )     (5 )%
Transmix operations
    (3.5 )     (9 )%     2.8       6 %
All others (including eliminations)
    (2.0 )     (2 )%     1.8       1 %
Total Products Pipelines
  $ 6.9       1 %   $ 31.0       4 %
__________

The primary increases and decreases in our Products Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in 2011 compared to 2010 were attributable to the following:
 
 
a $17.5 million (53%) increase from our Cochin natural gas liquids 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;
 
 
an $8.6 million (19%) increase from our approximate 51% equity interest in the Plantation pipeline system.  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 $8.5 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;
 
 
a $17.6 million (6%) decrease from our Pacific operations—due largely to an $11.1 million decrease in revenues and a $6.1 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 lower military tenders.  This decrease was partially offset by higher terminal revenues attributable to a 10% increase in ethanol handling volumes.  The increase in operating expenses was mainly due to a $7.5 million increase in expense associated with liability adjustments made pursuant to an adverse tentative court decision on the amount of 2011 rights-of-way lease payment obligations;
 
 
a $4.6 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 $3.5 million (9%) decrease from our Transmix processing operations—due mainly to a $4.2 million decrease in income from lower product gains relative to 2010.
 

 

 

 

 

 
Year Ended December 31, 2010 versus Year Ended December 31, 2009
 
   
EBDA
increase/(decrease)
   
Revenues
increase/(decrease)
 
   
(In millions, except percentages)
 
Pacific operations
  $ 40.0       15 %   $ 49.9       13 %
Southeast Terminals
    14.9       28 %     12.0       15 %
West Coast Terminals
    10.5       16 %     10.7       12 %
Plantation Pipeline
    3.2       8 %     (0.3 )     (1 )%
Central Florida Pipeline
    2.9       6 %     1.4       2 %
Cochin Pipeline
    (20.4 )     (38 )%     (16.6 )     (27 )%
All others (including eliminations)
    1.3       1 %     (0.7 )     (1 )%
Total Products Pipelines
  $ 52.4       8 %   $ 56.4       7 %
__________

The primary increases and decreases in our Products Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in 2010 compared to 2009 were attributable to the following:
 
 
a $40.0 million (15%) increase from our Pacific operations—due largely to a $49.9 million (13%) increase in operating revenues, consisting of a $32.1 million (11%) increase in mainline delivery revenues and a $17.8 million (17%) increase in fee-based terminal revenues.  The increase in pipeline delivery revenues was attributable to higher average tariff rates in 2010 (due in part to FERC-approved rate increases) and to military tender rate increases.  Overall mainline delivery volumes were essentially flat across both years.  The increase in terminal revenues was mainly attributable to incremental ethanol handling services that were due in part to mandated increases in ethanol blending rates in California since the end of 2009;
 
 
a $14.9 million (28%) increase from our Southeast terminal operations—due to both increased ethanol throughput (driven by continued high demand during 2010 in the ethanol and biofuels markets) and higher product inventory gains relative to the prior year;
 
 
a $10.5 million (16%) increase from our West Coast terminal operations—driven by higher warehousing revenues and incremental customers at our combined Carson/Los Angeles Harbor terminal system, higher biodiesel revenues from our two Portland, Oregon liquids facilities, and incremental earnings contributions from the terminals’ Portland, Oregon Airport pipeline, which was acquired on July 31, 2009;
 
 
a $3.2 million (8%) increase from our equity investment in Plantation.  The increase in Plantation’s earnings was driven by both higher products transportation revenues and higher oil loss allowance revenues.  The increase in transportation revenues was due to a 2% increase in pipeline throughput volumes, resulting from both an upgrade at a refinery in Louisiana and to mainline allocation on a competing pipeline.  The increase in oil loss allowance revenues was associated with the increase in volumes and an increase in products prices, relative to the prior year;
 
 
a $2.9 million (6%) increase from our Central Florida Pipeline—due mainly to incremental product inventory gains and partly to higher ethanol handling revenues; and
 
 
a $20.4 million (38%) decrease from our Cochin pipeline system—attributable to a $16.6 million (27%) drop in revenues and a $3.8 million (35%) increase in operating expenses.  The lower revenues reflected a 32% decline in propane delivery volumes, due to milder weather, a drop in grain drying demand, and the negative impacts from unfavorable tariff changes in 2010.  The increase in operating expenses was primarily related to favorable settlements reached in the first quarter of 2009 with the seller of the remaining approximate 50.2% interest in the Cochin pipeline system that we purchased on January 1, 2007.
 

 

 

 

 

 

 
Natural Gas Pipelines
 
   
Year Ended December 31,
 
   
2011
   
2010
   
2009
 
   
(In millions, except operating statistics)
 
Revenues(a)
  $ 4,265.1     $ 4,416.5     $ 3,806.9  
Operating expenses(b)
    (3,551.6 )     (3,750.3 )     (3,193.0 )
Other income(c)
    -       -       7.8  
Earnings from equity investments
    227.2       169.1       141.8  
Interest income and Other, net(d)
    (162.4 )     4.3       31.8  
Income tax expense
    (4.1 )     (3.3 )     (5.7 )
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments
  $ 774.2     $ 836.3     $ 789.6  
                         
Natural gas transport volumes (Bcf)(e)
    2,925.0       2,584.2       2,285.1  
Natural gas sales volumes (Bcf)(f)
    804.7       797.9       794.5  
__________

(a)
2010 amount includes a $0.4 million increase in revenues from certain measurement period adjustments related to our October 1, 2009 natural gas treating business acquisition.
 
(b)
2011 amount includes a $9.7 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011.  2009 amount includes a $5.6 million decrease in income resulting from unrealized mark to market losses due to the discontinuance of hedge accounting at Casper Douglas.  Beginning in the second quarter of 2008, our Casper and Douglas gas processing operations discontinued hedge accounting, and the last of the related derivative contracts expired in December 2009.  2009 amount also includes a $0.1 million increase in expense associated with adjustments to long-term receivables for environmental cost recoveries.
 
(c)
2009 amount represents gains from hurricane casualty indemnifications.
 
(d)
2011 amount includes a $167.2 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value.
 
(e)
Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC and Texas intrastate natural gas pipeline group, and for 2011 only, Fayetteville Express Pipeline LLC.
 
(f)
Represents Texas intrastate natural gas pipeline group volumes.
 

Combined, the certain items described in the footnotes to the table above accounted for (i) decreases of $177.3 million and $1.7 million, respectively, in segment earnings before depreciation, depletion and amortization expenses in 2011 and 2010; and (ii) a decrease of $0.4 million and an increase of $0.4 million, respectively, in segment revenues in 2011 and 2010, when compared with the respective prior year.
 
Following is information related to the segment’s remaining (i) $115.2 million (14%) and $48.4 million (6%) increases in earnings before depreciation, depletion and amortization; and (ii) $151.0 million (3%) decrease and $609.2 million (16%) increase in operating revenues in 2011 and 2010, when compared with the respective prior year:
 


 
 

 
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)
  $ 92.5       n/a     $ 99.4       n/a  
Fayetteville Express Pipeline(b)
    23.8       n/a       n/a       n/a  
Midcontinent Express Pipeline(b)
    12.6       42 %     n/a       n/a  
Casper and Douglas Natural Gas Processing
    7.6       36 %     19.9       19 %
Texas Intrastate Natural Gas Pipeline Group
    5.8       2 %     (251.5 )     (6 )%
Kinder Morgan Interstate Gas Transmission
    (18.2 )     (17 )%     (29.6 )     (17 )%
Trailblazer Pipeline
    (11.3 )     (25 )%     (7.6 )     (14 )%
All others (including eliminations)
    2.4       1 %     18.4       10 %
Total Natural Gas Pipelines
  $ 115.2       14 %   $ (151.0 )     (3 )%
__________

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.
 

The primary increases and decreases in our Natural Gas Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in 2011 compared to 2010 were attributable to the following:
 
 
a $92.5 million increase from incremental earnings from our now wholly-owned KinderHawk Field Services LLC.  For more information about our two KinderHawk acquisitions, see Note 3 to our consolidated financial statements included elsewhere in this report;
 
 
a $23.8 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 $12.6 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;
 
 
a $7.6 million (36%) increase from our Casper Douglas gas processing operations—attributable to a 40% increase in net processing spreads;
 
 
a $5.8 million (2%) increase from our Texas intrastate natural gas pipeline group—primarily due to (i) a $29.8 million increase 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); (ii) an $11.3 million increase due to incremental equity earnings from our 50% interest in Eagle Ford Gathering LLC; (iii) a $23.7 million drop in natural gas sales margin (mainly attributable to higher costs of natural gas supplies relative to sales price); and (iv) a $12.2 million decrease due to higher operating expenses (attributable primarily to higher pipeline integrity and remediation expenses);
 
 
an $18.2 million (17%) decrease from our Kinder Morgan Interstate Gas Transmission pipeline system— driven by a $12.3 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 $11.3 million (25%) decrease from our Trailblazer pipeline system—mainly attributable to both a $4.8 million increase in expense from the write-off of receivables for under-collected fuel (incremental to the $9.7 million increase in expense that is described in footnote (b) to the results of operations table above and which relates to periods prior to 2011), and a $3.3 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.
 

 

 
Year Ended December 31, 2010 versus Year Ended December 31, 2009
 
   
EBDA
Increase/(decrease)
   
Revenues
Increase/(decrease)
 
   
(In millions, except percentages)
 
Kinder Morgan Natural Gas Treating
  $ 33.8       360 %   $ 48.1       339 %
KinderHawk Field Services(a)
    19.5       n/a       n/a       n/a  
Midcontinent Express Pipeline(a)
    15.4       105 %     n/a       n/a  
Kinder Morgan Louisiana Pipeline
    14.1       34 %     42.5       167 %
Casper and Douglas Natural Gas Processing
    8.8       71 %     30.5       41 %
Kinder Morgan Interstate Gas Transmission
    (17.2 )     (14 )%     3.8       2 %
Texas Intrastate Natural Gas Pipeline Group
    (16.0 )     (4 )%     487.6       14 %
Rockies Express Pipeline(a)
    (10.0 )     (10 )%     n/a       n/a  
All others (including eliminations)
    -       -       (3.3 )     (3 )%
Total Natural Gas Pipelines
  $ 48.4       6 %   $ 609.2       16 %
__________

(a)
Equity investments.  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.
 

The primary increases and decreases in our Natural Gas Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in 2010 compared to 2009 were attributable to the following:
 
 
a $33.8 million (360%) increase from our Kinder Morgan Natural Gas Treating operations—due mainly to our acquisitions of natural gas treating operations from CrossTex Energy, Inc. on October 1, 2009, and from Gas-Chill, Inc. on September 1, 2010.  Combined, the acquired operations contributed incremental earnings before depreciation, depletion and amortization of $33.8 million, revenues of $48.1 million and operating expenses of $14.1 million in 2010;
 
 
a $19.5 million increase due to incremental contributions from our initial 50% equity ownership interest in KinderHawk, acquired on May 21, 2010;
 
 
a $15.4 million (105%) increase from our equity investment in Midcontinent Express—due primarily to the inclusion of a full year of operations in 2010 and the June 2010 completion of the expansion project described above.  Midcontinent Express initiated interim natural gas transportation service for its Zone 1 pipeline segment on April 10, 2009, achieved full Zone 1 service on May 21, 2009, and achieved full Zone 2 service on August 1, 2009;
 
 
a $14.1 million (34%) increase from our Kinder Morgan Louisiana pipeline system—consisting of a $36.6 million increase in system operating income and a $22.5 million decrease in non-operating other income.  The increase from operations was mainly due to incremental transportation service (we commenced limited natural gas transportation service in April 2009 and we completed construction and began full transportation service on the system’s remaining portions in June 2009).  The drop in non-operating income, relative to 2009, reflected lower income pursuant to FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance);
 
 
an $8.8 million (71%) increase from our Casper Douglas gas processing operations—primarily attributable to higher natural gas processing spreads.  The $30.5 million (41%) year-to-year increase in revenues was driven by both a 4% increase in natural gas liquids sales volumes and a 41% increase in average natural gas liquids sales prices;
 
 
a $17.2 million (14%) decrease from our Kinder Morgan Interstate Gas Transmission pipeline system—driven by a $7.2 million decrease due to lower margins on operational sales of natural gas, and a $6.8 million decrease due to lower pipeline net fuel recoveries.  Both decreases were due mainly to lower average natural gas prices in 2010.  KMIGT’s operational gas sales are primarily made possible by both collection of fuel in kind pursuant to its currently effective gas transportation tariff, and by recoveries of storage cushion gas volumes;
 
 
 
a $16.0 million (4%) decrease from our Texas intrastate natural gas pipeline group—driven by (i) a $15.8 million decrease in earnings from overall storage activities (primarily due to lower price spreads due to unfavorable market conditions relative to 2009); (ii) a $3.5 million decrease from lower interest income, due to a one-time natural gas loan to a single customer in 2009; (iii) a $3.4 million decrease due to lower natural gas gains (primarily due to 2009 volume measurement gains related to the normal tracking of natural gas throughout the pipeline system); and (iv) a $2.8 million decrease in natural gas sales margins, largely attributable to higher costs of natural gas supplies relative to sales prices and less favorable market conditions.  The overall decrease in earnings in 2010 versus 2009 was partially offset by a $9.5 million increase in earnings due to higher natural gas processing margins, due mainly to higher natural gas liquids prices relative to 2009, and a $3.1 million increase in earnings due to incremental equity earnings from our 40%-owned Endeavor Gathering LLC, acquired effective November 1, 2009; and
 
 
a $10.0 million (10%) decrease from our 50% interest in the Rockies Express pipeline system.  Compared to 2009, Rockies Express’ net income (on a 100% basis) dropped $18.1 million (9%) in 2010.  The decrease consisted of (i) a $70.3 million decrease primarily related to higher interest expenses, net of interest income; and (ii) a $52.2 million increase from higher system operating income.  The increase in interest expenses was due to higher non-cash allowances for borrowed funds used during construction in 2009 (which reduces interest expenses), and to debt obligations shifting from short-term to long-term at higher interest rates in 2010.  (Rockies Express issued $1.7 billion aggregate principal amount of fixed rate senior notes in a private offering in March 2010 to secure permanent financing for the Rockies Express pipeline construction costs).  The increase in operating income was driven by incremental transportation service revenues related to the completion and start-up of the Rockies Express-East pipeline segment, the third and final phase of the Rockies Express system.  Rockies Express-East began initial pipeline service on June 29, 2009 and began full operations on November 12, 2009.
 
The overall changes in both segment revenues and segment operating expenses (which include natural gas costs of sales) 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 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 85%, 88% and 89%, respectively, of the segment’s revenues in 2011, 2010 and 2009, and 93%, 94% and 95%, respectively, of the segment’s operating expenses in 2011, 2010 and 2009.
 
CO2
 
   
Year Ended December 31,
 
   
2011
   
2010
   
2009
 
   
(In millions, except operating statistics)
 
Revenues(a)
  $ 1,416.2     $ 1,245.7     $ 1,035.7  
Operating expenses
    (342.5 )     (308.1 )     (271.1 )
Earnings from equity investments
    24.1       22.5       22.3  
Interest income and Other, net
    5.2       4.5       -  
Income tax benefit (expense)
    (4.4 )     0.9       (4.0 )
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments
  $ 1,098.6     $ 965.5     $ 782.9  
                         
Southwest Colorado carbon dioxide production (gross) (Bcf/d)(b)
    1.3       1.3       1.2  
Southwest Colorado carbon dioxide production (net) (Bcf/d)(b)
    0.5       0.5       0.5  
SACROC oil production (gross)(MBbl/d)(c)
    28.6       29.2       30.1  
SACROC oil production (net)(MBbl/d)(d)
    23.8       24.3       25.1  
Yates oil production (gross)(MBbl/d)(c)
    21.7       24.0       26.5  
Yates oil production (net)(MBbl/d)(d)
    9.6       10.7       11.8  
Katz oil production (gross)(MBbl/d)(c)
    0.5       0.3       0.3  
Katz oil production (net)(MBbl/d)(d)
    0.4       0.2       0.3  
Natural gas liquids sales volumes (net)(MBbl/d)(d)
    8.5       10.0       9.5  
Realized weighted average oil price per Bbl(e)
  $ 69.73     $ 59.96     $ 49.55  
Realized weighted average natural gas liquids price per Bbl(f)
  $ 65.61     $ 51.03     $ 37.96  
__________

(a)
2011, 2010 and 2009 amounts include unrealized gains of $5.2 million, unrealized gains of $5.3 million and unrealized losses of $13.5 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales.
 
(b)
Includes McElmo Dome and Doe Canyon sales volumes.
 
(c)
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 i