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EX-12 - EX-12 - El Paso Pipeline Partners, L.P.h69778exv12.htm
EX-21 - EX-21 - El Paso Pipeline Partners, L.P.h69778exv21.htm
EX-32.A - EX-32.A - El Paso Pipeline Partners, L.P.h69778exv32wa.htm
EX-31.A - EX-31.A - El Paso Pipeline Partners, L.P.h69778exv31wa.htm
EX-31.B - EX-31.B - El Paso Pipeline Partners, L.P.h69778exv31wb.htm
EX-10.M - EX-10.M - El Paso Pipeline Partners, L.P.h69778exv10wm.htm
EX-32.B - EX-32.B - El Paso Pipeline Partners, L.P.h69778exv32wb.htm
EX-23.B - EX-23.B - El Paso Pipeline Partners, L.P.h69778exv23wb.htm
EX-23.A - EX-23.A - El Paso Pipeline Partners, L.P.h69778exv23wa.htm
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2009
OR
     
o   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 1-33825
El Paso Pipeline Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)
     
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  26-0789784
(I.R.S. Employer
Identification No.)
     
El Paso Building    
1001 Louisiana Street    
Houston, Texas   77002
(Address of Principal Executive Offices)   (Zip Code)
Telephone Number: (713) 420-2600
Internet Website:
www.eppipelinepartners.com
Securities registered pursuant to Section 12(b) of the Act:
     
    Name of Each Exchange
Title of Each Class   on which Registered
     
Common Units Representing Limited Partnership Interests   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. Yes þ No o.
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ.
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o.
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ.
     The aggregate market value of the common units representing limited partner interests held by non-affiliates of the registrant was approximately $712,410,891 on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, based on the price of $17.53 per unit, the closing price of the common units as reported on the New York Stock Exchange on such date.
     There were 107,484,747 Common Units, 27,727,411 Subordinated Units and 2,759,432 General Partner Units outstanding as of February 23, 2010:
Documents Incorporated by Reference: None.
 
 


 

EL PASO PIPELINE PARTNERS, L.P.
TABLE OF CONTENTS
         
Caption   Page
PART I
 
       
    1  
    7  
    25  
    25  
    25  
    25  
 
       
PART II
 
       
    26  
    28  
    29  
    45  
    46  
    80  
    80  
    80  
 
       
PART III
 
       
    81  
    86  
    89  
    91  
    99  
 
       
PART IV
 
       
    100  
    123  
 EX-10.M
 EX-12
 EX-21
 EX-23.A
 EX-23.B
 EX-31.A
 EX-31.B
 EX-32.A
 EX-32.B
     Below is a list of terms that are common to our industry and used throughout this document:
             
/d
  = per day   LNG   = liquefied natural gas
BBtu
  = billion British thermal units   MDth   = thousand dekatherm
Bcf
  = billion cubic feet   MMcf   = million cubic feet
Dth
  = dekatherm   MMcf/d   = million cubic feet per day
Tonne
  = metric ton        
     When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
     When we refer to “us”, “we”, “our”, or “ours”, we are describing El Paso Pipeline Partners, L.P. and/or our subsidiaries.


Table of Contents

ITEM 1.   BUSINESS
Overview and Strategy
     We are a Delaware master limited partnership (MLP) formed in November 2007 by El Paso Corporation (El Paso) to own and operate natural gas transportation pipelines and storage assets. We conduct our business activities through various natural gas pipeline systems and storage facilities including the Wyoming Interstate Company, Ltd. (WIC) system, a 58 percent general partner interest in Colorado Interstate Gas Company (CIG) and a 25 percent general partner interest in Southern Natural Gas Company (SNG). In November 2007, we completed an initial public offering of our common units, issuing 28.8 million common units to the public. In conjunction with our formation, El Paso contributed to us 100 percent of WIC, as well as 10 percent general partner interests in each of CIG and SNG. In September 2008, we acquired from El Paso an additional 30 percent general partner interest in CIG and an additional 15 percent general partner interest in SNG. On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG from El Paso.
     WIC is an interstate pipeline transportation business located in Wyoming, Utah and Colorado. CIG is an interstate pipeline transportation and storage business that extends from production areas in the U.S. Rocky Mountain region to interconnection points on pipelines transporting gas to the midwest, southwest and northwest U.S. and to market areas in the Front Range of Colorado and Wyoming. SNG is an interstate pipeline transportation and storage business that extends from production fields in the southern U.S. and the Gulf of Mexico to market areas across the Southeast.
     Our pipeline systems and storage facilities operate under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.
     Our primary business objectives are to generate stable cash flows sufficient to make distributions to our unitholders and to grow our business through the construction, development and acquisition of additional energy infrastructure assets. We intend to increase our cash distributions over time by enhancing the value of our transportation and storage assets by:
    providing outstanding customer service;
    executing successfully on time and on budget for our committed expansion projects;
    focusing on increasing utilization, efficiency and cost control in our operations;
    pursuing economically attractive organic and greenfield expansion opportunities;
    successfully recontracting expiring contracts for transportation capacity;
    pursuing strategic asset acquisitions from third parties and El Paso to grow our business; and
    maintaining the integrity and ensuring the safety of our pipeline systems and other assets.

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Our Assets
     The table below and discussion that follows provide detail on our pipeline systems as of December 31, 2009:
                                                         
    As of December 31, 2009    
Transmission   Ownership   Miles of   Design   Storage   Average Throughput(1)
System   Interest   Pipeline   Capacity   Capacity   2009   2008   2007
    (Percent)           (MMcf/d)   (Bcf)           (BBtu/d)        
WIC
    100       800       3,340             2,652       2,543       2,071  
CIG (2)(3)
    58       4,200       3,750       35       2,299       2,225       2,339  
SNG (2)(4)
    25       7,600       3,700       60       2,322       2,339       2,345  
 
(1)   The WIC throughput includes 131 BBtu/d, 181 BBtu/d and 239 BBtu/d transported by WIC on behalf of CIG for the years ended December 31, 2009, 2008, and 2007.
 
(2)   Volumes reflected are 100 percent of the volumes transported on the CIG system and the SNG system, respectively.
 
(3)   CIG’s storage capacity includes 6 Bcf of storage capacity from Totem Gas Storage, which is owned by WYCO Development LLC (WYCO), CIG’s 50 percent equity investee.
 
(4)   SNG’s storage capacity includes the storage capacity associated with their 50 percent ownership interest in Bear Creek Storage Company, LLC (Bear Creek), a joint venture with Tennessee Gas Pipeline Company (TGP), our affiliate.
     WIC. WIC is comprised of a mainline system that extends from western Wyoming to northeast Colorado (the Cheyenne Hub) and several lateral pipeline systems that extend from various interconnections along the WIC mainline into western Colorado and northeast Wyoming and into eastern Utah. WIC is one of the primary interstate natural gas transportation systems providing takeaway capacity from the mature Overthrust, Piceance, Uinta, Powder River and Green River Basins. CIG is the operator of the WIC system pursuant to a service agreement with WIC.
     CIG. CIG is comprised of pipelines that deliver natural gas from production areas in the U.S. Rocky Mountains and the Anadarko Basin directly to customers in Colorado, Wyoming and indirectly to the midwest, southwest, California and Pacific northwest. CIG also owns interests in five storage facilities located in Colorado and Kansas with approximately 35 Bcf of underground working natural gas storage capacity and one natural gas processing plant located in Wyoming.
     CIG owns a 50 percent ownership interest in WYCO, a joint venture with an affiliate of Public Service Company of Colorado (PSCo). WYCO owns Totem Gas Storage and the High Plains pipeline, which were placed in service in June 2009 and November 2008, respectively, and are operated by CIG. The High Plains pipeline consists of a 164-mile interstate gas pipeline extending from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain electric generation plant and other points of interconnections with PSCo’s system. The system added approximately 900 MMcf/d of overall transportation capacity to our system. The increased capacity is fully contracted with PSCo and Coral Energy Resources pursuant to firm contracts through 2029 and 2019. The Totem Gas Storage facility consists of a natural gas storage field that services and interconnects with the High Plains Pipeline. The Totem Gas Storage field has 6 Bcf of working natural gas storage capacity with a maximum withdrawal rate of 200 MMcf/d and a maximum injection rate of 100 MMcf/d. All of the storage capacity of this new storage field is fully contracted with PSCo pursuant to a firm contract through 2040. WYCO also owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain’s electric generation plant, which CIG does not operate, and a compressor station in Wyoming operated by WIC.
     SNG. SNG is comprised of pipelines extending from natural gas supply basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. SNG is the principal natural gas transporter to southeastern markets in Alabama, Georgia and South Carolina. SNG owns interests in two storage facilities along the system with approximately 60 Bcf of underground working natural gas storage capacity. The SNG system is also connected to El Paso’s Elba Island LNG terminal near Savannah, Georgia.

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Markets and Competition
     Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline systems connect with multiple pipelines that provide our customers with access to diverse sources of supply, including supply from unconventional sources, and various natural gas markets. The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources such as shale, tight sands, and coal bed methane is rapidly increasing. This shift will change the supply patterns and flows of pipelines. The impacts will vary among pipelines according to the proximity of the new supply sources.
     Electric power generation has been a growing demand sector of the natural gas market. The market slowdown had a minimal impact on SNG as electric market demand increased due to attractive natural gas pricing relative to coal. The growth of natural gas fired electric power benefits the natural gas industry by creating more demand for natural gas. This potential benefit is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity and the use and availability of other fuel sources for power generation. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and electric transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm transportation contracts with natural gas pipelines.
     Growth of the natural gas market has been adversely affected by the current economic slowdown in the U.S. and world economies. The decline in economic activity reduced industrial demand for natural gas and electricity, which affected natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. We expect the demand and growth for natural gas to return as the economy recovers. Natural gas has a favorable competitive position as an electric generation fuel because it is a clean and abundant fuel with lower capital requirements compared with other alternatives. The lower demand and the credit restrictions on investments in the recent past may slow development of supply projects. While WIC’s, CIG’s and SNG’s pipelines could experience some level of reduced throughput and revenues, or slower development of future expansion projects as a result of these factors, each of these pipelines generates a significant (approximately 90 percent) portion of its revenues through fixed monthly reservation or demand charges on long-term contracts at rates stipulated under its tariffs or in its contracts. Additionally, on CIG and WIC, we do not expect production in the U.S. Rocky Mountain region to significantly decrease from current levels due to the need to replace diminishing exports from Canada and declining production from traditional domestic sources.
     WIC. Our WIC system competes with other interstate and intrastate pipelines for deliveries to multiple-connection customers and its four largest customers are generally able to obtain a significant portion of their natural gas transportation requirements from other pipelines, including the Rockies Express Pipeline LLC (Rockies Express Pipeline) and CIG. In addition, WIC competes with CIG, third party pipelines and gathering systems for connection to the rapidly growing supply sources in the U.S. Rocky Mountain region. Natural gas delivered from the WIC system competes with alternative energy sources used to generate electricity, such as hydroelectric power, solar, wind, coal and fuel oil.
     WIC and CIG are competitors for lateral expansions to various U.S. Rocky Mountain supply basins. Both WIC and CIG have supply laterals in the Piceance Basin, Powder River Basin and the Uinta Basin. Since the WIC mainline system and the Wyoming portion of the CIG system parallel each other, a supply lateral can effectively interconnect with either system. Additionally, for many years CIG has contracted for firm capacity on the WIC system to support CIG’s Wyoming area contract obligations and CIG uses its capacity on the WIC system as an operational loop of the CIG system. WIC and CIG may compete for the same business opportunities. Economic, market and other factors related to each individual opportunity will have a significant impact on the determination of whether WIC, CIG or another affiliate pursue such business opportunities and ultimately carry out expansion projects or acquisitions, but the decision will be at the sole discretion of El Paso.

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     CIG. Our CIG system serves two major markets, an on-system market, consisting of utilities and other customers located along the Front Range of the U.S. Rocky Mountains in Colorado and Wyoming, and an off-system market, consisting of the transportation of U.S. Rocky Mountain natural gas production from multiple supply basins to users accessed through interconnecting pipelines in the midwest, southwest, California and the Pacific northwest. Recent growth in the on-system market from both the space heating segment and electric generation segment has provided CIG with incremental demand for transportation services. Competition for our on-system market consists of an intrastate pipeline, an interstate pipeline, local production from the Denver-Julesburg basin, and long-haul shippers who elect to sell into this market rather than the off-system market. Competition for our off-system market consists of other interstate pipelines, including WIC, that are directly connected to our supply sources. CIG also faces competition from other existing pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, wind, solar, coal and fuel oil.
     CIG also competes with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Some of CIG’s largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines. CIG’s most direct competitor in the U.S. Rocky Mountain region is the Rockies Express Pipeline. The Rockies Express Pipeline could result in additional discounting on the CIG system.
     SNG. The southeastern market served by the SNG system is one of the fastest growing natural gas demand regions in the U.S. Demand for deliveries from the SNG system is characterized by two peak delivery periods, the winter heating season and the summer cooling season.
     SNG competes with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative delivery points. Natural gas delivered from the SNG system competes with alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. Some of SNG’s largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines. In addition, SNG competes with third party pipelines and gathering systems for connection to new supply sources.
     SNG’s most direct competitor is Transco, which owns an approximately 10,500-mile pipeline extending from Texas to New York. It has firm transportation contracts with some of SNG’s largest customers, including Atlanta Gas Light Company, Alabama Gas Corporation, SCANA, and Southern Company Services.
     The following table details our customers and contracts for each of our pipeline systems as of December 31, 2009. Our firm customers reserve capacity on our pipeline system or storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Our interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn.
     
WIC    
Customer Information   Contract Information
Approximately 50 firm and interruptible customers.
  Approximately 60 firm transportation contracts. Weighted average remaining contract term of approximately eight years.
 
   
Major Customers:
   
Williams Gas Marketing, Inc.
   
(1,320 BBtu/d)
  Expires in 2010-2021.
 
   
Anadarko Petroleum Corporation
   
(1,260 BBtu/d)
  Expires in 2010-2023.

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CIG    
Customer Information   Contract Information
Approximately 100 firm and interruptible customers.
  Approximately 170 firm transportation contracts. Weighted average remaining contract term of approximately eight years.
 
   
Major Customers:
   
PSCo
   
(1,787 BBtu/d)
  Expires in 2010-2029.
 
   
Williams Gas Marketing, Inc.
   
(498 BBtu/d)
  Expires in 2010-2014.
 
   
Anadarko Petroleum Corporation
   
(280 BBtu/d)
  Expires in 2011-2015.
     
SNG    
Customer Information   Contract Information
Approximately 270 firm and interruptible customers.
  Approximately 200 firm transportation contracts. Weighted average remaining contract term of approximately six years.
 
   
Major Customers:
   
Atlanta Gas Light Company(1)
   
(1,063 BBtu/d)
  Expires in 2013-2024.
 
   
Southern Company Services
   
(433 BBtu/d)
  Expires in 2011-2018.
 
   
Alabama Gas Corporation
   
(372 BBtu/d)
  Expires in 2010-2013.
 
   
SCANA Corporation
   
(315 BBtu/d)
  Expires in 2013-2019.
 
(1)   Atlanta Gas Light Company is currently releasing a significant portion of its firm capacity to a subsidiary of SCANA Corporation under terms allowed by SNG’s tariff.
Regulatory Environment
     Our interstate natural gas transmission systems transport and store natural gas for local distribution companies (LDCs), other natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. Our systems do not take title to the natural gas transported or stored for our customers, which mitigates our direct commodity price risk. The rates our systems charge are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. The FERC approves tariffs that establish rates, cost recovery mechanisms, and other terms and conditions of services to our customers. The fees or rates established under our tariffs are a function of providing services to our customers, including a reasonable return on our invested capital. The FERC’s authority also extends to:
    rates and charges for natural gas transportation and storage and related services;
    certification and construction of new facilities;
    extension or abandonment of services and facilities;
    maintenance of accounts and records;

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    relationships between pipelines and certain affiliates;
    terms and conditions of service;
    depreciation and amortization policies;
    acquisition and disposition of facilities; and
    initiation and discontinuation of services.
     Our interstate pipeline systems are also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation (DOT) and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our systems are in material compliance with the applicable regulations. For a further discussion of the potential impact of regulatory matters on us, see Item 1A, Risk Factors and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Our Relationship with El Paso Corporation
     El Paso is an energy company founded in 1928 in El Paso, Texas that primarily operates in the regulated natural gas transportation sector and the exploration and production sector of the energy industry. El Paso owns our two percent general partner interest, all of our incentive distribution rights, a 60 percent limited partner interest in us including both common and subordinated units and the remaining 42 percent general partner interest in CIG and 75 percent general partner interest in SNG not owned by us. We have an omnibus agreement with El Paso and our general partner that governs our relationship with them regarding the provision of specified services to us, as well as certain reimbursement and indemnification matters.
     As a substantial owner in us, El Paso is motivated to promote and support the successful execution of our business strategies, including utilizing our partnership as a growth vehicle for its natural gas transportation, storage and other energy infrastructure businesses. Although we expect to have the opportunity to make additional acquisitions directly from El Paso in the future, El Paso is under no obligation to make acquisition opportunities available to us.
Environmental
     A description of our environmental activities is included in Part II, Item 8 Financial Statements and Supplementary Data, Note 8.
Employees
     We do not have employees. We are managed and operated by the directors and officers of our general partner, El Paso Pipeline GP Company, L.L.C., a subsidiary of El Paso. Additionally, WIC is operated by CIG, and SNG is operated by El Paso and its affiliates. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit, for direct expenses incurred by El Paso on our behalf and for expenses allocated to us as a result of us being a public entity. A further discussion of our affiliate transactions is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 12.
Available Information
     Our website is http://www.eppipelinepartners.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after these reports are filed with the Securities and Exchange Commission (SEC). Information about each of our Board members, as well as each of our Board’s standing committee charters, our Corporate Governance Guidelines and our Code of Business Conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.

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ITEM 1A.   RISK FACTORS
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS
     This report contains forward-looking statements that are based on assumptions or beliefs that we believe to be reasonable; however assumed facts almost always vary from the actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.
     With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the SEC from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf.
     Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.
     The risks referred to herein refer to risks inherent to both our wholly-owned operations through WIC and our general partner interests in CIG and SNG.
Risks Inherent in Our Business
Our success depends on factors beyond our control.
     The results of operations of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volumes of natural gas we are able to transport and store depend on the actions of third parties and are beyond our control. Such actions include factors that impact our customers’ demand and producers’ supply, including factors that negatively impact our customers’ need for natural gas from us, as well as the continued availability of natural gas production and reserves connected to our pipeline systems. Further, the following factors, most of which are also beyond our control, may unfavorably impact our ability to maintain or increase current throughput or to remarket unsubscribed capacity:
    service area competition;
    price competition;
    expiration or turn back of significant contracts;
    changes in regulation and actions of regulatory bodies;
    weather conditions that impact natural gas throughput and storage levels;
    weather fluctuations or warming and cooling trends that may impact demand in the markets in which we do business, including trends potentially attributable to climate change;
    drilling activity and decreased availability of conventional gas supply sources and the availability and timing of other natural gas sources such as LNG and gas shale supplies;
    continued development of additional sources of gas supply that can be accessed;

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    decreased natural gas demand due to various factors, including economic recession (as further discussed below), availability of alternative energy sources and increases in prices;
    legislative, regulatory or judicial actions, such as mandatory renewable portfolio standards and greenhouse gas (GHG) regulations and/or legislation that could result in (i) changes in the demand for natural gas and oil, (ii) changes in the availability of or demand for alternative energy sources such as hydroelectric and nuclear power, wind and solar energy or (iii) changes in the demand for lower carbon intensive energy sources;
    availability and cost to fund ongoing maintenance and growth projects, especially in periods of prolonged economic decline;
    opposition to energy infrastructure development, especially in environmentally sensitive areas;
    adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets;
    our ability to achieve targeted annual operating and administrative expenses achieved primarily by reducing internal costs and improving efficiencies from leveraging a consolidated supply chain organization; and
    unfavorable movements in natural gas prices in supply and demand areas.
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at our current quarterly distribution.
     We may not have sufficient available cash each quarter to continue to pay quarterly distributions at our current quarterly distribution rate. Under this circumstance, we may be required to borrow under our revolving credit facility to pay the annualized quarterly distribution. Under our cash distribution policy, the amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations and not on reported net earnings for financial accounting purposes. Our cash flows will fluctuate based on, among other things:
    the rates we charge and the volumes under contract for our transportation and storage services;
    the quantities of natural gas available for transport and the demand for natural gas;
    the price of natural gas;
    legislative or regulatory action affecting demand for and supply of natural gas, and the rates we are allowed to charge in relation to our operating costs;
    the level of our operating and maintenance and general and administrative costs; and
    the creditworthiness of our shippers.
     In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
    the level of capital expenditures we make;
    our debt service requirements, retirement of debt and other liabilities;
    fluctuations in working capital needs;
    our ability to borrow funds and access capital markets;
    the amount of cash distributed to us by the entities in which we own a minority interest;
    restrictions on distributions contained in debt agreements; and
    the amount of cash reserves established by our general partner, which may include reserves for tariff rates that are subject to refund.

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We own minority interests in one of our three primary assets, with the remaining interest in this asset owned by El Paso or its other subsidiaries. As a result, we will be unable to control the amount of cash we will receive from its operations and we could be required to contribute significant cash to fund our share of its operations, including capital expenditures. If we fail to make these contributions, we will be subject to specified penalties.
     Our inability to control the operations of SNG and its respective subsidiaries and unconsolidated affiliates may mean that we do not receive the amount of cash we expect to be distributed to us. We expect our interest in SNG to generate in excess of 20 percent of the cash we distribute in 2010 and, accordingly, our performance is substantially dependent on SNG’s distributions to us. Since we only have a 25 percent interest in SNG, we are unable to control its ongoing operational and investment decisions, which may adversely affect the amount of cash otherwise available for distribution to us, including:
    decisions with respect to incurrence of expenses and distributions to us;
    establishing reserves for working capital, maintenance capital expenditures, environmental matters and legal and rate proceedings;
    incurring additional indebtedness and principal and interest payments; and
    requiring us to make additional capital contributions to SNG to fund working capital, maintenance capital and expansion capital expenditures which could be material. In the event we elect not to make a required capital contribution or are unable to do so, our partnership interest could be diluted or it could affect the receipt of distributions until we have forgone distributions equal to our portion of the capital call plus a specified premium.
Our natural gas transportation and storage systems are subject to regulation by agencies, including the FERC, which could have an adverse impact on our ability to establish transportation and storage rates that would allow recovery of the full cost of operating these pipeline systems and storage facilities, including a reasonable return, and our ability to make distributions.
     Our interstate natural gas transportation and storage operations are subject to federal, state and local regulatory authorities. Specifically, our natural gas pipeline systems and our storage facilities and related assets are subject to regulation by the FERC, the DOT, the United States Department of the Interior, and various state and local regulatory agencies. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. Federal regulation extends to such matters as:
    rates, operating terms and conditions of service, with CIG required to file a new rate case to be effective no later than October 2011;
    the types of services we may offer to our customers;
    the contracts for service entered into with our customers;
    construction and abandonment of new facilities;
    the integrity and safety of our pipeline systems and related operations;
    acquisition, extension or abandonment of services or facilities;
    accounts and records; and
    relationships with affiliated companies involved in certain aspects of the natural gas business.

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     We are subject to various governmental investigations from time to time, including investigations by the FERC and the U.S. Department of Transportation Office of Pipeline Safety. The results of any investigation could have a material adverse effect on our business, financial condition or results of operation. In addition, pursuant to laws and regulations, our existing rates may be challenged by complaint. The FERC commenced several complaint proceedings in 2009 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on one or more of our pipeline systems and that a successful complaint against our pipelines’ rates could have an adverse impact on our business, financial condition, results of operations and thus our ability to make distributions.
     Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 to impose penalties for current violations of up to $1,000,000 per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.
     Finally, we do not know how future regulations will impact the operation of our natural gas transportation and storage businesses or the effect such regulations could have on our business, financial condition, results of operations and thus our ability to make distributions.
The application of certain FERC policy statements could affect the rate of return on our equity we are allowed to recover through rates and the amount of any allowance (if any) our systems can include for income taxes in establishing their rates for service, which would in turn impact our revenues and/or equity earnings.
     In setting authorized rates of return, the FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC allows MLPs to be included in the proxy group to determine return on equity. However, as to such MLPs, the FERC will generally adjust the long-term growth rate used to calculate the equity cost of capital. The FERC stated that the long-term growth projection for natural gas pipeline MLPs will be equal to fifty percent of gross domestic product (GDP), as compared to the unadjusted GDP used for corporations. Therefore, to the extent that master limited partnerships are included in a proxy group, the FERC’s policy lowers the return on equity that might otherwise be allowed if there were no adjustment to the master limited partnership growth projection used for the discounted cash flow model. This could lower the return on equity that we would otherwise be able to obtain.
     The FERC currently allows partnerships to include in their cost-of-service an income tax allowance. Any changes to the FERC’s treatment of income tax allowances in cost-of-service and to potential adjustment in a future rate case of our pipelines’ respective equity rates of return that underlie their recourse rates may cause their recourse rates to be set at a level that is different, and in some instances lower than the level otherwise in effect.
Certain of our systems provide a portion of their transportation services pursuant to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
     It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease the cash flow realized by WIC, CIG and SNG and, therefore, the cash we have available for distribution to our unitholders. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated “recourse rate” for that service, and that contract must be filed and accepted by FERC. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation, increases in cost of capital and taxes or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers.

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Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial impact on us.
     Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by activities of other interstate and intrastate pipelines and storage facilities that may expand or construct competing transportation and storage systems. In addition, future pipeline transportation and storage capacity could be constructed in excess of actual demand and with lower fuel requirements, operating and maintenance costs than our facilities, which could reduce the demand for and the rates that we receive for our services in particular areas. Further, natural gas also competes with alternative energy sources available to our customers that are used to generate electricity, such as hydroelectric power, solar, wind, nuclear, coal and fuel oil.
     We also compete as it relates to rates, terms of service, access to natural gas supplies, flexibility and reliability. The FERC’s policies promoting competition may cause us to experience some “turnback” of firm capacity as existing agreements with customers expire. If WIC, CIG or SNG are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, they may have to bear the costs associated with the turned back capacity. Increased competition could also reduce the volumes of natural gas transported or stored or, in cases where we do not have long-term fixed rate contracts, could force us to lower our rates. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions.
Competition in more actively priced markets from pipelines that may be able to provide our shippers with capacity at a lower price could cause us to reduce our rates or otherwise reduce our revenues.
     We face competition from other pipelines, including the Rockies Express Pipeline, that may be able to provide our shippers with capacity on a more competitive basis or access to consuming markets that would pay a higher price for the shippers’ gas. An increase in competition in our key markets could arise from new ventures or expanded operations from existing competitors. As a result, significant competition from the Rockies Express Pipeline and other third-party competitors could have a material adverse effect on our financial condition, results of operations and ability to make distributions.
Any significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for distribution to unitholders.
     All of our businesses are dependent on the continued availability of natural gas production and reserves. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that are accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our pipelines will naturally decline over time without development of additional reserves. Additionally, the amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the volume of natural gas transported, or throughput, on our pipelines and cash flows associated with the transportation of gas, our customers must continually obtain new supplies of natural gas. For example, if expected increases of natural gas supplies in the U.S. Rocky Mountain region do not materialize or there is a decline in supply from such producing region to our interstate pipelines that is not replaced with new supplies, our operating results and our cash available for distribution could be adversely affected as our firm contracts expire.
A substantial portion of the revenues of our pipeline businesses are generated from transportation contracts that must be renegotiated periodically.
     Substantially all of our pipeline revenues are generated under contracts which expire periodically and must be renegotiated and extended or replaced. If we or El Paso are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts on terms comparable to prior contracts or on any terms at all, could be adversely affected by factors we cannot control, as discussed in more detail above.

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     Our systems rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2009, the four largest natural gas transportation customers for each of WIC, CIG and SNG accounted for approximately 71 percent, 60 percent and 44 percent of their respective operating revenues. The loss of all or even a portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on our financial condition, results of operations and our ability to make distributions.
Fluctuations in energy commodity prices could adversely affect our business.
     Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. On the other hand, decreased natural gas prices could result in reduced development of additional gas supplies and in reduced volume of natural gas available for transportation and storage through our system.
     Pricing volatility may, in some cases for CIG or WIC, impact our fuel imbalance revaluations and related gas balance items. We obtain in-kind fuel reimbursements from shippers in accordance with each individual tariff or applicable contract terms. We revalue our natural gas imbalances and other gas owed to or from shippers to an index price and periodically settle these obligations in cash pursuant to each individual tariff, regulatory approval or each balancing contract. Currently, both the CIG and WIC tariffs provide that the difference between the quantity of fuel retained and fuel used in operations will be flowed-through or charged to shippers. The CIG tariff provides that all liquid revenue proceeds, including those proceeds associated with CIG’s processing plants, are used to reimburse shrinkage or other system fuel and lost-or-unaccounted-for costs and variations in liquid revenues and variations in shrinkage volumes are included in the reconciliation of retained fuel and burned fuel. CIG must purchase gas volumes from time to time due, in part, to such shrinkage associated with liquid production and such expenses vary with both price and quantity.
     If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Consequently, a significant prolonged downturn in natural gas prices could have a material adverse effect on our financial condition, results of operations and ability to make distributions.
     Fluctuations in energy prices are caused by a number of factors, including:
    regional, domestic and international supply and demand, including changes in supply and demand due to general economic conditions and weather;
    availability and adequacy of gathering, processing and transportation facilities;
    energy legislation and regulation, including potential changes associated with greenhouse gas (GHG) emissions and renewable portfolio standards;
    federal and state taxes, if any, on the transportation and storage of natural gas;
    the price and availability of supplies of alternative energy sources; and
    the level of imports, including the potential impact of political unrest among countries producing oil and LNG, as well as the ability of certain foreign countries to maintain natural gas and oil price, production and export controls.

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Adverse general domestic economic conditions could negatively affect our operating results, financial condition, liquidity or our ability to make cash distributions.
     We are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. The global economy is experiencing a recession and the financial markets have experienced extreme volatility and instability. If we experience prolonged periods of recession or slowed economic growth in the United States, demand growth from consumers for natural gas transported by us may continue to decrease, which could impact the development of our future expansion projects. Additionally, our access to capital could be impeded and the cost of capital we obtain could be higher. We are also subject to the risks arising from changes in legislation and government regulation associated with any such recession or economic slowdown, including creating preferences for renewables, as part of a legislative package to stimulate the economy. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and ability to make cash distributions.
We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.
     We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers, including default risk associated with adverse economic conditions. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future customers fail to pay and/or perform and we are unable to re-market the capacity, our business, results of operations, financial condition and ability to make cash distributions could be adversely affected. We may not be able to effectively re-market capacity during and after insolvency proceedings involving a shipper.
We are exposed to the credit and performance risk of our key contractors and suppliers.
     As an owner of large energy infrastructure, including significant capital expansion programs, we rely on contractors for certain construction and drilling operations and we rely on suppliers for key materials and supplies, including steel mills and pipe manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us. This could result in delays or defaults in performing such contractual obligations, which could adversely impact our financial condition and results of operations.
SNG is not prohibited from incurring indebtedness, which may affect our ability to make distributions.
     SNG is not prohibited by the terms of its general partnership agreement from incurring indebtedness. If SNG were to incur significant amounts of additional indebtedness, it may inhibit its ability to make distributions to us which would materially and adversely affect our ability to make our minimum quarterly distributions because we expect SNG’s distributions to us will be a significant portion of the cash we distribute.
Restrictions in our credit facility and note purchase agreement could limit our ability to make distributions to our unitholders. The conditions of the U.S. and international capital markets may adversely affect our ability to draw on our current credit facility.
     Our credit facility and the note purchase agreement related to our issuance of senior unsecured notes contain covenants limiting our ability to make distributions to our unitholders and equity repurchases. Our ability to comply with any restrictions and covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we are unable to comply with these restrictions and covenants, a significant portion of indebtedness under our credit facility or the note purchase agreement may become immediately due and payable, and our lenders’ commitment to make further loans to us under our credit facility may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. For a further discussion of our covenants related to our debt obligations, see Part II, Item 8, Financial Statements and Supplementary Data, Note 6.

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     In September 2008, Lehman Brothers Holdings Inc., whose subsidiaries have a $48 million credit commitment under the credit facility, filed for bankruptcy. We have determined the potential exposure to a loss of available capacity under the credit facility to be approximately $15 million. If other financial institutions that have extended credit commitments to us and our subsidiaries are adversely affected by the conditions of the U.S. and international capital markets, they may become unable to fund borrowings under their credit commitments, which could have a material and adverse impact on our financial condition and our ability to borrow additional funds, if needed.
     Our payment of principal and interest on any future indebtedness will reduce our cash available for distribution on our units. Further, our credit facility limits our ability to pay distributions to our unitholders during an event of default or if an event of default would result from the distribution.
     In addition, any future levels of indebtedness may:
    adversely affect our ability to obtain additional financing for future operations or capital needs;
    limit our ability to pursue acquisitions and other business opportunities; or
    make our results of operations more susceptible to adverse economic or operating conditions.
     Various limitations in any future financing agreements may reduce our ability to incur additional indebtedness, to engage in some transactions or to capitalize on business opportunities.
Increases in interest rates and general volatility in the financial markets and economy could adversely impact our unit price, our ability to make distributions and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.
     We cannot predict how interest rates will react to changing market conditions and potential deficits of federal and state governments. Interest rates on our credit facilities, variable rate senior unsecured notes and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, to incur debt or for other purposes. In addition, the general volatility in the financial markets and economy may also alter the yield requirements of investors and could adversely impact our unit price.
The credit and risk profile of our general partner and its owner, El Paso, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
     Any adverse change in the financial condition of El Paso, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness, may adversely affect our credit ratings and risk profile.
     If we were to seek credit ratings in the future, our credit ratings may be adversely affected by the leverage of our general partner or El Paso, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of El Paso and its affiliates because of their ownership interest in and control of us and the strong operational links between El Paso and us. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade. The ratings assigned to both CIG’s and SNG’s senior unsecured indebtedness by Moody’s Investor Services and Fitch Ratings are currently investment grade, with a Baa3 and a BBB- rating. Standard & Poor’s has assigned a below investment grade rating of BB to CIG’s and SNG’s senior unsecured indebtedness. El Paso and all of its subsidiaries, including CIG and SNG, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review El Paso’s, CIG’s and SNG’s leverage, liquidity and credit profile. Any reduction in El Paso’s, CIG’s or SNG’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital.

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If our systems do not successfully complete expansion projects or make and integrate acquisitions that are accretive, our future growth may be limited.
     A principal focus of our strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends on our ability to complete expansion projects and make acquisitions that result in an increase in cash per unit generated from operations. We may be unable to successfully complete accretive expansion projects or acquisitions, which could adversely affect our financial position, results of operations and ability to make distributions, for any of the following reasons:
    unable to identify attractive expansion projects or acquisition candidates or we are outbid by competitors;
    El Paso elects not to sell or contribute additional interests in its pipeline systems that it owns to us or to offer attractive expansion projects or acquisition candidates to us;
    unable to identify attractive acquisitions that are accretive to our limited partner unitholders due to the incentive distributions to our general partner;
    unable to obtain necessary approvals by the FERC and other regulatory agencies on a timely basis and on terms that are acceptable to us, including the potential impact of delays and increased costs or such approvals caused by certain environmental and landowner groups with interests along the route of our pipelines;
    impediments on our ability to obtain necessary rights of way or land rights or to commence and complete construction on a timely basis or on terms that are acceptable to us;
    unable to realize anticipated costs savings and successful integration of the businesses we build or acquire;
    unable to raise financing for expansion projects or acquisitions on economically acceptable terms, especially in periods of prolonged economic decline;
    mistaken assumptions about volumes, revenues and costs, including synergies and potential growth;
    unable to secure adequate transportation, storage or throughput commitments to support the expansion or acquisition of new facilities;
    the assumption of unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate;
    the diversion of management’s and employees’ attention to other business concerns;
    unforeseen difficulties operating in new product areas or new geographic areas including opposition to energy infrastructure development, especially in environmentally sensitive areas;
    there is a lack of available of skilled labor, equipment, and materials to complete expansion projects;
    potential changes in federal, state and local statutes and regulations, such as environmental requirements, including climate change requirements, that delay or prevent a project from proceeding or increase the anticipated cost of the project;
    our ability to construct expansion projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials, labor, a lack of contractor productivity, delays in construction or other factors beyond our control, that may be material; and
    the lack of future growth in natural gas supply or demand.
     Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return, which could adversely affect our results of operations, cash flows, financial position and our ability to make distributions.

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The amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
     The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
     We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.
Our operations are subject to operational hazards and uninsured risks.
     Our operations are subject to the inherent risks normally associated with those operations, including pipeline failures, pollution, release of toxic substances, fires, adverse weather conditions (such as hurricanes and flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses. In addition, although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas could have a negative impact upon our operations in the future.
     While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles and self-insurance levels, limits on our maximum recovery, and do not cover all risks. There is also the risk that our coverages will change over time in light of increased premiums or changes in the terms of the insurance coverages that could result in our decision to either terminate certain coverages, increase our deductibles and self-insurance levels or decrease our maximum recoveries. In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our financial condition and ability to make cash distributions could be adversely affected if a significant event occurs that is not fully covered by insurance.
Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.
     Our natural gas transportation, storage and processing activities are subject to stringent and complex federal, state and local environmental laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. For instance, we may be required to obtain and maintain permits and approvals issued by various federal, state and local governmental authorities; limit or prevent releases of materials from our operations in accordance with these permits and approvals; and install pollution control equipment. Also, under certain environmental laws and regulations, we may be exposed to potentially substantial liabilities for any pollution or contamination that may result from our operations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material.

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In estimating our environmental liabilities, we face uncertainties that include:
    estimating pollution control and clean up costs, including sites where preliminary site investigation or assessments have been completed;
    discovering new sites or additional information at existing sites;
    forecasting cash flow timing to implement proposed pollution control and cleanup costs;
    receiving regulatory approval for remediation programs;
    quantifying liability under environmental laws that may impose joint and several liability on potentially responsible parties and managing allocation responsibilities;
    evaluating and understanding environmental laws and regulations, including their interpretation and enforcement;
    interpreting whether various maintenance activities performed in the past and currently being performed require pre-construction permits pursuant to the Clean Air Act; and
    changing environmental laws and regulations that may increase our costs.
     In addition to potentially increasing the cost of our environmental liability, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards, emission standards with regard to our reciprocating internal combustion engines on our pipeline systems, GHG reporting and potential mandatory GHG emissions reductions. Future environmental compliance costs relating to GHGs associated with our operations are not yet clear. For a further discussion on GHG’s see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies.
     Although it is uncertain what impact legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances or pay taxes related to our GHG and other emissions and (v) administer and manage an emissions program for GHG and other emissions. Changes in regulations, including adopting new standards for emission controls for certain of our facilities, could also result in delays in obtaining required permits to construct or operate our facilities. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipelines, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.
Risks Inherent in Our Structure and Relationship with El Paso
El Paso controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including El Paso, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.
     El Paso owns and controls our general partner, and appoints all of the directors of our general partner. Some of our general partner’s directors, and some of its executive officers, are directors or officers of El Paso or its affiliates. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to El Paso. Therefore, conflicts of interest may arise between El Paso and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.

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Affiliates of our general partner, including El Paso and its other subsidiaries, are not limited in their ability to compete with us and are not obligated to offer us the opportunity to pursue additional assets or businesses, which could limit our commercial activities or our ability to acquire additional assets or businesses.
     Neither our partnership agreement nor the omnibus agreement among us, El Paso and others will prohibit affiliates of our general partner, including El Paso, El Paso Natural Gas Company (EPNG), Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains) and TGP, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, El Paso and its affiliates may acquire, construct or dispose of additional transportation or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Each of these entities is a large, established participant in the interstate pipeline and/or storage business, and each may have greater resources than we have, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact our results of operations and cash available for distribution.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.
     Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by its owners and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at such annual meetings of stockholders. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Cost reimbursements to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution.
     Pursuant to an omnibus agreement we entered into with El Paso, our general partner and certain of their affiliates, El Paso and its affiliates will receive reimbursement for the payment of operating and capital expenses related to our operations and for the provision of various general and administrative services for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us, which amounts will be determined by the general partner in good faith. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. In addition, WIC reimburses CIG for the costs incurred to operate and maintain the WIC system pursuant to an operating agreement. CIG also reimburses certain of its affiliates for costs incurred and services it receives (primarily from EPNG and TGP) and receives reimbursements for costs incurred and services it provides to other affiliates (primarily Cheyenne Plains and Young Gas Storage Company Ltd.). Similarly, the El Paso subsidiary that is the operator and general partner of CIG or SNG will be entitled to be reimbursed for the costs incurred to operate and maintain such system. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

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Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
     Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, the general partnership agreements of CIG and SNG contain similar provisions that define the fiduciary standards of each partner (a subsidiary of El Paso owns a 42 percent and 75 percent general partner interest in CIG and SNG, and we own a 58 percent and 25 percent general partner interest in CIG and SNG) to the other. In addition, the general partnership agreements include provisions that define the fiduciary standards that the members of the management committee of each such partnership appointed by a partner (El Paso has appointed one member to CIG’s committee and three members to SNG’s committee, and we have appointed three members to CIG’s committee and one member to SNG’s committee) owe to the partners that did not designate such person. In both instances, the defined fiduciary standards are more limited than those that would apply under Delaware law in the absence of such definition.
Limited unitholders cannot remove our general partner without its consent.
     The vote of the holders of at least 662/3 percent of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Our general partner and its affiliates own 61 percent of our aggregate outstanding common and subordinated units. Accordingly, our unitholders are currently unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent the general partner’s removal. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. In addition, under certain circumstances the successor general partner may be required to purchase the combined general partner interest and incentive distribution rights of the removed general partner, or alternatively, such interests will be converted into common units. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.
Our general partner may elect to cause us to issue Class B common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.
     Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48 percent) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

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     In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B common units. The Class B common units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B common units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B common units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights.
The control of our general partner may be transferred to a third party without unitholder consent.
     Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their member interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of the general partner with their own choices and to control the decisions taken by the board of directors and officers of the general partner. This effectively permits a “change of control” of the partnership without unitholders’ vote or consent. In addition, pursuant to the omnibus agreement with El Paso, any new owner of the general partner would be required to change our name so that there would be no further reference to El Paso.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
     Our assets consist of a 100 percent ownership interest in WIC, a 58 percent general partner interest in CIG and a 25 percent general partner interest in SNG. If a sufficient amount of our assets, such as our ownership interests in CIG or SNG or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Although general partner interests are typically not considered securities or “investment securities,” there is a risk that our ownership interests in CIG and SNG could be deemed investment securities. In that event, it is possible that our ownership of these interests, combined with our assets acquired in the future, could result in our being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying our organizational structure or applicable contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
     Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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We may issue additional units without approval which would dilute existing ownership interests.
     Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
    each unitholder’s proportionate ownership interest in us will decrease;
    the amount of cash available for distribution on each unit may decrease;
    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
    the ratio of taxable income to distributions may increase;
    new classes of securities could be issued that provide preferences to the new class in relation to existing unitholders, including preferences on distributions of available cash, distributions upon our liquidation and voting rights;
    the relative voting strength of each previously outstanding unit may be diminished; and
    the market price of the common units may decline.
Our general partner has a limited call right that may require unitholders to sell common units at an undesirable time or price.
     If at any time our general partner and its affiliates own more than 75 percent of the common units excluding, until September 30, 2010, common units received by El Paso’s affiliates in connection with El Paso’s contribution to us of additional general partner interest in each of CIG and SNG in September 2008, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders would be required to sell common units at an undesirable time or price and may not receive any return on investment. Unitholders might also incur a tax liability upon a sale of such units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934. Our general partner and its affiliates own approximately 51 percent of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our general partner and its affiliates will own approximately 61 percent of our aggregate outstanding common units.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.
     Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.

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Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.
     A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as if they were a general partner if a court or government agency determined that:
    we were conducting business in a state but had not complied with that particular state’s partnership statute; or
    unitholders’ right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by affiliates of our general partner.
     As of December 31, 2009, we had 97,622,247 common units and 27,727,411 subordinated units outstanding, which includes 55,326,397 common units held by affiliates of our general partner. All of the subordinated units will convert into common units at the end of the subordination period, which could occur as early as the first business day after December 31, 2010, assuming certain tests are met, and all of the subordinated units may convert into common units before December 31, 2010 if additional tests are satisfied. Sales by any of our existing unitholders, including affiliates of our general partner, of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by states. If the Internal Revenue Service were to treat us as a corporation or if we become subject to a material amount of additional entity-level taxation for state tax purposes, then it would substantially reduce the amount of cash available for distribution to our unitholders.
     The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. 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 tax matter affecting us.
     If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
     Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state was to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. We are, for example, subject to an entity-level tax on the portion of our income that is generated in Texas. The imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution.

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     Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts 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. For example, in response to certain events that occurred in previous years, members of Congress have considered substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. Recently, the House of Representatives passed the Tax Extenders Act of 2009, H.R. 4213, a bill which includes a provision that would treat items of income and gain generated by a publicly traded partnership that is engaged in the performance of “investment management services” as non-qualifying income. Although we do not believe that this provision would apply to us as currently drafted, we are unable to predict whether any changes will be made to the provision or whether the legislation will ultimately be enacted. Moreover, even if this current proposal is not enacted, it is possible that these efforts could resume and result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such 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 units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
     We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. 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 unitholders.
An Internal Revenue Service contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any Internal Revenue Service contest will reduce our cash available for distribution to our unitholders.
     We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all 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, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
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 unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than cash we distribute, they will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not cash is distributed from us. Cash distributions may not equal a unitholder’s share of our taxable income or even equal the actual tax liability that results from the unitholder’s share of our taxable income.

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The tax gain or loss on the disposition of our common units could be different than expected.
     If our unitholders sell units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to our unitholders due to potential recapture items, including depreciation recapture. In addition, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
     Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities or foreign persons should consult their tax advisor regarding their investment in our common units.
We will treat each purchaser of units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
     Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from their sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.
We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
     When we issue additional units or engage in certain other transactions, we will 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 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 the general partner, which may be unfavorable to such unitholders. Moreover, under our methodologies subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the 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 unitholders. It also could affect the amount of gain from our 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 unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50 percent or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.
     We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

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Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of their investment in our common units.
     In addition to federal income taxes, 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 do business or own property, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose an income tax. It is the unitholder’s responsibility to file all federal, state and local tax returns.
ITEM 1B.   UNRESOLVED STAFF COMMENTS
     None.
ITEM 2.   PROPERTIES
     A description of our properties is included in Part I, Item 1, Business, and is incorporated herein by reference.
     We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.
ITEM 3.   LEGAL PROCEEDINGS
     A description of our legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8, and is incorporated herein by reference.
     Natural Buttes. In May 2004, the Environmental Protection Agency (EPA) issued a Compliance Order to CIG related to alleged violations of a Title V air permit in effect at CIG’s Natural Buttes Compressor Station. In September 2005, the matter was referred to the U.S. Department of Justice (DOJ). CIG entered into a tolling agreement with the United States and conducted settlement discussions with the DOJ and the EPA. While conducting some testing at the facility, CIG discovered that three generators installed in 1992 may have been emitting oxides of nitrogen at levels which suggested the facility should have obtained a Prevention of Significant Deterioration (PSD) permit when the generators were first installed, and CIG promptly reported those test data to the EPA. CIG executed a Consent Decree with the DOJ and has paid a total of $1.02 million to settle all of these Title V and PSD issues at the Natural Buttes Compressor Station. In addition, as required by the Consent Decree, ambient air monitoring at the Uintah Basin commenced on January 1, 2010 for a period of two years. In November 2009, CIG sold its Natural Buttes compressor station and gas processing plant to a third party for $9.0 million.
     In addition to the above matters, we and our affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business.
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     None.

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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
     Our common units are traded on the New York Stock Exchange under the symbol EPB. As of February 23, 2010, we had 24 unitholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.
     The following table reflects the quarterly high and low sales prices for our common units based on the daily composite listing of stock transactions for the New York Stock Exchange and the cash distributions per unit we declared in each quarter:
                         
    High   Low   Distributions
2009
                       
Fourth Quarter
  $ 26.52     $ 19.98     $ 0.35000  
Third Quarter
  $ 21.30     $ 17.14     $ 0.33000  
Second Quarter
  $ 19.80     $ 16.53     $ 0.32500  
First Quarter
  $ 20.00     $ 14.91     $ 0.32000  
2008
                       
Fourth Quarter
  $ 21.80     $ 11.95     $ 0.30000  
Third Quarter
  $ 21.95     $ 11.72     $ 0.29500  
Second Quarter
  $ 24.35     $ 20.57     $ 0.28750  
First Quarter
  $ 25.00     $ 18.53     $ 0.12813  
     Cash Distribution Policy. We will distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.28750 per common unit ($1.15 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay cash distributions at this minimum quarterly distribution rate is subject to various restrictions and other factors. On February 12, 2010, we paid a distribution of $0.36000 per unit to all unitholders of record at the close of business on February 1, 2010. Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash”. Our partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter in the following manner: first, 98 percent to the holders of common units and 2 percent to our general partner, until each common unit has received a minimum quarterly distribution of $0.28750 plus any arrearages from prior quarters; second, 98 percent to the holders of subordinated units and 2 percent to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.28750; and third, 98 percent to all unitholders, pro rata, and 2 percent to our general partner, until each unit has received a distribution of $0.33063. If cash distributions to our unitholders exceed $0.33063 per unit in any quarter, our general partner will receive, in addition to distributions on its 2 percent general partner interest, increasing percentages, up to 48 percent, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Our general partner received incentive distributions of $0.4 million in 2009. In February 2010, our general partner received incentive distributions of $0.6 million.

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     Incentive Distribution Rights. Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. In connection with this election, our general partner will be entitled to receive a number of newly issued Class B common units and general partner units based on a predetermined formula. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner is based, may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase.
     The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distribution” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2 percent general partner interest and assume our general partner has contributed any additional capital necessary to maintain its two percent general partner interest and has not transferred its incentive distribution rights.
             
        Marginal Percentage
    Total Quarterly   Interest in Distribution
    Distribution per Unit       General
    Target Amount   Unitholders   Partner
Minimum Quarterly Distribution
  $0.28750   98%   2%
First Target Distribution
  above $0.28750 up to $0.33063   98%   2%
Second Target Distribution
  above $0.33063 up to $0.35938   85%   15%
Third Target Distribution
  above $0.35938 up to $0.43125   75%   25%
Thereafter
  above $0.43125   50%   50%
     Subordination Period. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.28750 per common unit, which is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
     The subordination period will end on the first business day after we have earned and paid at least $0.43125 (150 percent of the minimum quarterly distribution) on each outstanding limited partner unit and general partner unit for each quarter in any four quarter period ending or after December 31, 2008, or on the first business day after we have earned and paid at least $0.28750 on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods ending on or after December 31, 2010. The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

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ITEM 6. SELECTED FINANCIAL DATA
     The historical operating results data for each of the four years ended December 31, 2009 and the financial position data as of December 31, 2009, 2008 and 2007 were derived from our audited financial statements. We derived the operating results data for the year ended December 31, 2005 and the financial position data as of December 31, 2006 and 2005 from our accounting records. Our historical results are not necessarily indicative of results to be expected in the future. In conjunction with our formation on November 21, 2007, El Paso contributed to us 10 percent general partner interests in CIG and SNG. On September 30, 2008, we acquired an additional 30 percent general partner interest in CIG and an additional 15 percent general partner interest in SNG from El Paso. On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG and, as a result, own a 58 percent general partner interest in CIG. We have the ability to control CIG’s operating and financial decisions and policies and accordingly have consolidated CIG and have retrospectively adjusted our historical financial statements in all periods to reflect the change in reporting entity. Prior to November 2007, our historical financial statements only reflect the operating results and financial position of WIC and CIG. We have recorded our share of SNG’s operating results as earnings from unconsolidated affiliates from the dates we received interests in SNG. The selected financial data should be read together with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary Data included in this Report on Form 10-K.
                                         
    As of or for the Year Ended December 31,
    2009   2008   2007   2006   2005
            (In millions, except per unit amounts)        
Operating Results Data:
                                       
Operating revenues
  $ 537.6     $ 457.2     $ 418.1     $ 393.6     $ 373.9  
Operating income
    292.5       229.8       207.8       210.6       146.9  
Earnings from unconsolidated affiliates(1)
    53.4       32.9       4.1       0.4        
Income from continuing operations
    279.5       234.0       169.4       152.7       106.0  
Net income
    279.5       234.0       175.2       158.4       110.1  
Net income attributable to El Paso Pipeline Partners, L.P.
    213.5       171.6       127.9       119.0       79.6  
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit-basic and diluted
                                       
Common units(2)
  $ 1.64     $ 1.26     $ 0.11     $     $  
Subordinated units(2)
    1.56       1.12       0.11              
 
                                       
Distributions declared per common unit(3)
  $ 1.33     $ 1.01     $     $     $  
 
                                       
Financial Position Data:
                                       
Property, plant and equipment, net
  $ 2,018.5     $ 1,908.1     $ 1,633.2     $ 1,347.0     $ 1,245.2  
Investment in unconsolidated affiliates(1)
    417.5       410.8       171.8       15.9        
Total assets
    2,668.2       2,675.8       2,585.8       2,310.9       2,135.3  
Long-term debt and other financing obligations, less current maturities
    1,357.6       1,357.3       1,037.7       608.2       708.6  
Total partners’ capital
    1,161.6       1,117.4       1,351.7       1,236.7       1,083.6  
 
(1)    El Paso contributed to us 10 percent general partner interests in SNG on November 21, 2007. On September 30, 2008, we acquired an additional 15 percent general partner interest in SNG from El Paso, as further described in Item 8, Financial Statements and Supplementary Data, Note 2.
 
(2)     Earnings per unit in 2007 are based on income allocable to us subsequent to completion of our initial public offering.
 
(3)     In 2007, there were no distributions declared or paid per common unit.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
     Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part 1, Item 1A, Risk Factors.
     In November 2007, we completed an initial public offering of 28.8 million common units. In conjunction with our formation, El Paso contributed to us 100 percent of WIC, an interstate natural gas system, as well as 10 percent general partner interests in each of El Paso’s SNG and CIG interstate natural gas pipeline systems. On July 24, 2009 and September 30, 2008, we acquired 18 percent and 30 percent general partner interests in CIG, respectively, from El Paso. Subsequent to the July 2009 acquisition, we own a 58 percent general partner interest in CIG and have the ability to control its operating and financial decisions and policies. Accordingly, we have consolidated CIG and retrospectively adjusted our historical financial statements in all periods to reflect the change in reporting entity. We have reflected El Paso’s 42 percent general partner interest in CIG as a non-controlling interest in our financial statements for all periods presented. The transaction was accounted for as a reorganization of entities under common control. We began recording earnings from unconsolidated affiliates from our 10 percent ownership interest in SNG from the date of its contribution in November 2007. Effective September 30, 2008, we acquired from El Paso an additional 15 percent general partner interest in SNG. We accounted for the acquisition of our additional equity interest in SNG prospectively beginning on September 30, 2008. For a further discussion of each of these acquisitions, see Item 8, Financial Statements and Supplementary Data, Note 2. Since our interest in SNG is not reflected for periods prior to November 2007, the historical results of operations and the period to period comparison of results may not be indicative of future results.
     We have included a discussion in this MD&A of items that may affect the partnership and our general partner interests in each of CIG and SNG as they operate in the future. The matters discussed in our MD&A are as follows:
    General description of our business assets and operations and growth projects;
 
    Comparative discussion of our historical results of operations; and
 
    Liquidity and capital resource related matters, including our available liquidity, sources and uses of cash, our historical cash flow activities, contractual obligations and commitments, and critical accounting policies, among other items.
     Our Business. We are a Delaware limited partnership formed by El Paso (our general partner) to own and operate natural gas transportation and storage assets. We hold a 100 percent ownership interest in the approximately 800-mile WIC interstate natural gas pipeline system with a design capacity of approximately 3.3 Bcf/d and an average daily throughput in 2009 of 2,652 BBtu/d.
     We also own a 58 percent general partner interest in CIG and a 25 percent general partner interest in SNG whose operations are summarized below:
    CIG. CIG is an interstate natural gas pipeline system with approximately 4,200 miles of pipeline with a design capacity of approximately 3.8 Bcf/d and an average daily throughput in 2009 of 2,299 BBtu/d. It has associated storage facilities with 35 Bcf of underground working natural gas storage capacity, which includes 6 Bcf of storage capacity from Totem Gas Storage associated with CIG’s 50 percent ownership interest in WYCO.
 
    SNG. SNG is an interstate natural gas pipeline system with approximately 7,600 miles of pipeline with a design capacity of approximately 3.7 Bcf/d and an average daily throughput in 2009 of 2,322 BBtu/d. It has associated storage facilities with a total of approximately 60 Bcf of underground working natural gas storage capacity, which includes the storage capacity associated with a 50 percent ownership interest in Bear Creek, a joint venture with TGP, our affiliate.

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     Each of these businesses faces varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types:
                 
Type   Description   Percent of Total Revenues in 2009(1)
        WIC   CIG   SNG
Reservation
  Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.   98   91   88
 
               
Usage and Other
  Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenues from other miscellaneous sources.   2   9   12
 
(1)   Excludes liquids transportation revenue, amounts associated with retained fuel, and, in the case of CIG, liquids revenue associated with CIG’s processing plants. The revenues described in this table constituted approximately 100%, 94% and 99% of WIC’s, CIG’s and SNG’s total revenues, respectively, earned during the year ended December 31, 2009.
     The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather. In January 2010, the FERC approved SNG’s settlement in which SNG (i) increased its base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next general rate case to be effective after August 31, 2012 and no later than September 1, 2013, and (iv) extended the vast majority of SNG’s firm transportation contracts until August 31, 2013. CIG is required to file a new rate case to be effective no later than October 2011.
     Growth Projects. We intend to grow our business through organic expansion opportunities and through strategic asset acquisitions from third parties, El Paso or both. As of December 31, 2009, each of WIC, CIG and SNG have significant expansion projects in progress as described below:
     WIC. WIC expects to spend approximately $60 million on contracted organic growth projects from 2010 through 2014. Of this amount, we expect to spend approximately $47 million in 2010. These expenditures are related to the WIC Expansion project.
    WIC Expansion. We estimate the total cost of this project will be approximately $71 million. Due to increased shipper commitments, WIC expanded the scope of this project to add a second compressor unit on the Kanda Lateral, which increased its capital cost from $55 million to $71 million. This portion of the project will add a 12,400 horsepower compressor station on the Kanda Lateral which will increase the Kanda Lateral capacity to 595 MDth/d. WIC filed an application with the FERC for certificate authorization to construct this portion of the project in July 2009, and the anticipated in-service date is November 2010. WIC also plans to install three miles of pipeline and reconfigure one compressor at its Wamsutter station which will provide 155 MDth/d natural gas deliveries from the WIC Mainline into a third-party pipeline and onto the Opal Hub and El Paso’s proposed Ruby Pipeline. WIC filed an application with the FERC for certificate authorization to construct this portion of the project in November 2009, and it is anticipated to be placed in service in the first quarter of 2011.

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     CIG. CIG expects to spend approximately $110 million on contracted organic growth projects from 2010 through 2014. Of this amount, CIG expects to spend $86 million in 2010 primarily on its Raton 2010 expansion described below:
    Raton 2010. The Raton 2010 expansion project will consist of approximately 118 miles of pipeline from the Raton Basin Wet Canyon Lateral to the south end of the Valley Line. This project will provide additional capacity of approximately 130 MMcf/d from the Raton Basin in southern Colorado to the Cheyenne Hub in northern Colorado. The estimated total cost of the project is $146 million. The estimated in-service date is December 2010. In September 2009, CIG filed an application for certificate authorization with the FERC for this project.
     SNG. SNG expects to spend approximately $403 million on contracted organic growth projects from 2010 through 2014. Of this amount, SNG expects to spend $249 million in 2010. Our share of SNG’s future expected capital expenditures is approximately $101 million. These expenditures are primarily related to the South System III and the Southeast Supply Header projects.
    South System III. The South System III expansion project will expand SNG’s pipeline system in Mississippi, Alabama and Georgia by adding approximately 81 miles of pipeline looping and replacement on SNG’s south system and 17,310 horsepower of compression to serve an existing power generation facility owned by the Southern Company in the Atlanta, Georgia area that is being converted from coal fired to cleaner burning natural gas. This expansion project will be completed in three phases at a total estimated cost of $352 million, with each phase expected to add an additional 122 MMcf/d of capacity. In August 2009, we received certification of authorization from the FERC to construct this project. The project has estimated in-service dates of January 2011 for Phase I, June 2011 for Phase II and June 2012 for Phase III. SNG has entered into a precedent agreement with Southern Company Services as agent for its affiliated operating companies, Georgia Power Company, Alabama Power Company, Mississippi Power Company, Southern Power Company and Gulf Power Company to provide an incremental firm transportation service to such operating companies, commencing in phases beginning January 1, 2011, and ending May 31, 2032, which is 20 years after the estimated in-service date for Phase III.
 
    Southeast Supply Header. SNG owns an undivided interest in the northern portion of the Southeast Supply Header project jointly owned by Spectra Energy Corp (Spectra) and CenterPoint Energy, which added a 115-mile supply line to the western portion of the SNG system. This project is expected to provide access through pipeline interconnects to several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale basins. The estimated cost to SNG for Phase II of this project is $69 million and is expected to provide SNG with an additional 350 MMcf/d of supply capacity. In August 2009, we received certification of authorization from the FERC to construct Phase II, which is anticipated to be placed in service in June 2011.
 
    Cypress Phase III. During 2009, BG LNG Services (BG) informed SNG of its intent not to exercise their option to have SNG construct the Cypress Phase III expansion. However, BG has made alternative commitments to subscribe to certain other firm capacity on another of El Paso’s pipeline systems and to provide certain rate considerations on its existing transportation contract for Cypress Phases I and II.

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     In addition to our backlog of contracted organic growth projects, we have other projects that are in various phases of commercial development. Many of the potential projects involve expansion capacity to serve increased natural gas-fired generation loads. Most of these potential expansion projects would have in-service dates for 2014 and beyond. If we are eventually successful in contracting for these new loads, the capital requirements could be substantial and would be incremental to our backlog of contracted organic growth projects. Although we pursue the development of these potential projects from time to time, there can be no assurance that we will be successful in negotiating the definitive binding contracts necessary for such projects to be included in our backlog of contracted organic growth projects.
     CIG. Along the Front Range of CIG’s system, utilities have various projects under development that involve constructing new natural gas-fired generation in part to provide backup capacity required when renewable generation is not available during certain daily or seasonal periods.
     SNG. Similar to SNG’s South System III expansion project, SNG is pursuing various expansion projects to service increased natural-gas fired generation loads, either to meet increased electric loads or to convert existing coal or oil-fired power plants to natural gas usage.
     For a further discussion of the capital requirements of us and our unconsolidated affiliates, see Liquidity and Capital Resources.

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Results of Operations
     Our management uses earnings before interest expense and income taxes from continuing operations (EBIT from continuing operations) as a measure to assess the operating results and effectiveness of our businesses, which consists of consolidated operations as well as investments in unconsolidated affiliates. We believe EBIT from continuing operations is useful to our investors to provide them with the same measure used by El Paso to measure our performance. We define EBIT from continuing operations as net income adjusted for items such as (i) interest and debt expense, net, (ii) affiliated interest expense, net, (iii) income taxes, (iv) the impact of discontinued operations, and (v) net income attributable to noncontrolling interest so that investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT from continuing operations may not be comparable to measurements used by other companies. Additionally, EBIT from continuing operations should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT from continuing operations to net income, our throughput volumes and an analysis and discussion of our results for each of the three years ended December 31:
                         
    2009     2008     2007  
    (in millions, except volumes)  
Operating revenues
  $ 537.6     $ 457.2     $ 418.1  
Operating expenses
    (245.1 )     (227.4 )     (210.3 )
 
                 
Operating income
    292.5       229.8       207.8  
Earnings from unconsolidated affiliates
    53.4       32.9       4.1  
Other income, net
    5.6       9.7       11.0  
 
                 
EBIT from continuing operations before noncontrolling interests
    351.5       272.4       222.9  
Net income attributable to noncontrolling interests
    (66.0 )     (62.4 )     (47.3 )
 
                 
EBIT from continuing operations
    285.5       210.0       175.6  
Interest and debt expense, net
    (73.7 )     (61.6 )     (51.1 )
Affiliated interest income, net
    1.7       23.2       41.7  
Income tax expense
                (44.1 )
Discontinued operations, net of income taxes
                5.8  
 
                 
Net income attributable to El Paso Pipeline Partners, L.P.
    213.5       171.6       127.9  
Net income attributable to noncontrolling interests
    66.0       62.4       47.3  
 
                 
Net income
  $ 279.5     $ 234.0     $ 175.2  
 
                 
 
                       
Throughput volumes (BBtu/d) (1)
    4,820       4,587       4,171  
 
                 
 
(1)     Throughput volumes are presented for WIC and CIG only.
                                                                 
    2009 to 2008   2008 to 2007  
    Revenue     Expense     Other     Total     Revenue     Expense     Other     Total  
                            Favorable/(Unfavorable)                          
                            (In millions)                          
Transportation revenues
  $ (6.4 )   $     $     $ (6.4 )   $ 7.2     $     $     $ 7.2  
Expansions
    90.1       (19.7 )     (3.7 )     66.7       32.3       (12.4 )     2.1       22.0  
Operational gas, revaluations and processing revenues
    (2.0 )     (5.0 )           (7.0 )     (0.7 )     13.1             12.4  
Operating and general and administrative expenses
          0.9             0.9             (12.9 )           (12.9 )
Transportation expenses
          (3.9 )           (3.9 )           (2.5 )           (2.5 )
Gain on sale of long-lived asset
          7.8             7.8                          
Equity earnings from SNG
                22.7       22.7                   27.2       27.2  
Net income attributable to noncontrolling interests
                (3.6 )     (3.6 )                 (15.1 )     (15.1 )
Other(1)
    (1.3 )     2.2       (2.6 )     (1.7 )     0.3       (2.4 )     (1.8 )     (3.9 )
 
                                               
Total impact on EBIT from continuing operations
  $ 80.4     $ (17.7 )   $ 12.8     $ 75.5     $ 39.1     $ (17.1 )   $ 12.4     $ 34.4  
 
                                               
 
(1)   Consists of individually insignificant items.

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     Transportation Revenues. For the year ended December 31, 2009, our EBIT from continuing operations decreased primarily as a result of decreased usage revenues on both CIG and WIC. For the year ended December 31, 2008, we experienced higher revenues as a result of increased demand for firm capacity on WIC’s mainline system and for CIG’s off-system capacity.
     Expansions. Our EBIT from continuing operations increased during the years ended December 31, 2009 and 2008 due to expansion projects placed into service, as follows:
                 
    2009 to 2008     2008 to 2007  
    (In millions)  
CIG
               
High Plains pipeline
  $ 28.0     $ 7.7  
Totem Gas Storage
    14.4       1.1  
Other
    4.0        
WIC
               
Piceance lateral
    9.9       4.4  
Medicine Bow lateral
    9.3       1.7  
Kanda Lateral
    1.1       7.1  
 
           
Total impact on EBIT from continuing operations
  $ 66.7     $ 22.0  
 
           
     Operational Gas, Revaluations and Processing Revenues. Our EBIT from continuing operations from operational gas, revaluations, and processing revenues was lower during the year ended December 31, 2009 compared with the same period in 2008. CIG processing revenues were lower during the year ended December 31, 2009 compared with the same period in 2008, primarily due to an unfavorable price change for natural gas liquids. This impact, however, was largely offset by favorable prices for gas consumed in processing these liquids and regulatory-related cost tracking compared with the same period in 2008. In addition, WIC recorded a cost and revenue tracker adjustment in 2009, resulting in lower EBIT from continuing operations for the period.
     During 2008, CIG and WIC implemented FERC-approved fuel and related gas cost recovery mechanisms, subject to the outcome of technical conferences. In 2008, we recorded a net favorable fuel cost and revenue tracker estimated adjustment to reflect the effect of CIG’s order on its current fuel recovery filing period. During the first quarter of 2008, prior to the implementation of WIC’s fuel and related gas cost recovery mechanism, we also benefited from increasing natural gas prices on fuel and related gas balance items owed to WIC from shippers and other interconnecting pipelines. The implementation of these mechanisms was protested by a limited number of shippers. On July 31, 2009 and October 1, 2009, the FERC issued orders to CIG and WIC, respectively, directing us to remove the cost and revenue components from our fuel recovery mechanisms. Due to these orders, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to fuel imbalance revaluations, their settlement, and other gas balance related items. We continue to explore options to minimize the price volatility associated with these operational activities. Our tariffs continue to provide that the difference between the quantity of fuel retained and fuel used in operations and lost and unaccounted for will be flowed-through or charged to shippers. These fuel trackers remove the impact of over or under collecting fuel and lost and unaccounted for from our operational gas costs. For a further discussion of CIG and WIC fuel recovery mechanisms, see Item 8, Financial Statements and Supplementary Data, Note 8.
     Operating and General and Administrative Expenses. For the year ended December 31, 2009, our operating and general and administrative expense decreased primarily as a result of lower field repair and maintenance expenses, partially offset by higher benefit costs. For the year ended December 31, 2008, our operating and general and administrative expense increased primarily due to higher general and administrative costs for the transaction fees associated with the acquisition of additional interests in SNG and CIG and as a result of being a publicly traded limited partnership. Operating and general and administrative expenses also increased due to higher allocated costs from El Paso Natural Gas Company and Tennessee Gas Pipeline Company, our affiliates, associated with shared pipeline services.

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     Transportation Expenses. For the years ended December 31, 2009 and 2008 we experienced higher expenses as a result of increased third party capacity commitments.
     Gain on Sale of Long-Lived Asset. In the fourth quarter of 2009, we recorded a gain of $7.8 million related to the sale of CIG’s Natural Buttes compressor station and gas processing plant. For a further discussion of the sale of Natural Buttes, see Item 8, Financial Statements and Supplementary Data, Note 2.
     Earnings from SNG. We recorded equity earnings from SNG of $52.5 million and $29.8 million for the years ended December 31, 2009 and 2008. We began recording equity earnings from our 10 percent general partner interests in SNG on November 21, 2007, the date these interests were contributed to us from El Paso in connection with our initial public offering. We began recording equity earnings on our additional 15 percent general partner interest in SNG on September 30, 2008, the date we acquired these additional interests from El Paso.
     In January 2010, the FERC approved SNG’s settlement in which SNG (i) increased its base tariff rates effective September 1, 2009 (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next general rate case to be effective after August 31, 2012 and no later than September 1, 2013, and (iv) extended the vast majority of SNG’s firm transportation contracts until August 31, 2013.
     Net Income Attributable to Noncontrolling Interests. We have reflected El Paso’s 42 percent interest in CIG as noncontrolling interest in our financial statements in all periods presented. For the year ended December 31, 2009, our net income attributable to noncontrolling interest increased due to an increase in CIG’s net income primarily related to additional revenue generated by CIG from its High Plains pipeline and Totem Gas Storage expansion projects, offset in part by increased interest and debt expense due to CIG’s financing obligations to WYCO and lower affiliated interest income received from El Paso. During the year ended December 31, 2008, our net income attributable to noncontrolling interests increased as compared to the same period in 2007 due to an increase in CIG’s net income primarily related to the fact that CIG was no longer subject to income taxes following its conversion into a partnership on November 1, 2007, as well as the completion of its High Plains pipeline expansion.
Interest and Debt Expense
     For the year ended December 31, 2009, interest and debt expense was $12.1 million higher than in 2008 primarily due to an increase in average balances outstanding under our credit facility, the financing obligations to WYCO (see Item 8, Financial Statements and Supplementary Data, Note 6), and the issuance of $175.0 million of senior unsecured notes and a $10.0 million note payable to El Paso issued in September 2008 in conjunction with the acquisition of additional interests in CIG and SNG. The $175.0 million of senior unsecured notes had an average interest rate of 7.2% in 2009. These increases were partially offset by lower average interest rates on our credit facility borrowings and by CIG’s repurchase of $100 million of its senior notes in June 2008.
     During 2008, our interest and debt expense increased $10.5 million primarily due to amounts borrowed under our credit facility entered into in November 2007. Also contributing to the increase were the $175.0 million of senior unsecured notes and a $10.0 million note payable issued in September 2008 as discussed above. The $175.0 million of senior unsecured notes had an average interest rate of 7.8% in 2008. These increases were partially offset by lower average debt balances at CIG, primarily due to CIG’s repurchase of $100 million of its senior notes in June 2008. For a further discussion of our long-term financing obligations, see Item 8, Financial Statements and Supplementary Data, Note 6. The following table shows the average balance outstanding and the average interest rates under our credit facility for the years ended December 31, 2009 and 2008:
                 
    2009   2008
    (In millions, except for rates)
Average credit facility balance outstanding
  $ 565     $ 517  
Average interest rate on credit facility borrowings
    0.8 %     3.3 %

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Affiliated Interest Income, Net
     Prior to our acquisition of additional interests in CIG in July 2009, CIG participated in El Paso’s cash management program. In conjunction with our acquisition, CIG terminated its participation in El Paso’s cash management program and converted its note receivable with El Paso under its cash management program into a demand note receivable. Prior to our initial public offering, WIC also participated in El Paso’s cash management program. In 2007, WIC repaid the outstanding balance and is no longer a participant in El Paso’s cash management program. Affiliated interest income decreased $21.5 million for the year ended December 31, 2009 as compared to 2008 and decreased $18.5 million for the year ended December 31, 2008 as compared to 2007 primarily due to lower average advances due from El Paso and lower short-term interest rates. The following table shows the average advances due from El Paso and the average short-term interest rates for the years ended December 31:
                         
    2009   2008   2007
    (In millions, except for rates)
Average advance due from El Paso
  $ 138     $ 540     $ 684  
Average short-term interest rate
    1.7 %     4.4 %     6.2 %
Income Taxes
     Effective November 1, 2007, CIG no longer pays income taxes as a result of its conversion into a partnership. Our effective tax rate of 21 percent for the years ended December 31, 2007 was lower than the statutory rate of 35 percent due to income associated with nontaxable entities, partially offset by the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 13.

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Distributable Cash Flow
     We use the non-GAAP financial measure “Distributable Cash Flow” as it provides important information relating our financial operating performance to our cash distribution capability. Additionally, we use Distributable Cash Flow in setting forward expectations and in communications with the board of directors of our general partner. We define Distributable Cash Flow as Adjusted EBITDA less cash interest expense, maintenance capital expenditures, and other income and expenses, net, which primarily includes a non-cash allowance for equity funds used during construction (“AFUDC equity”) and other non-cash items. Adjusted EBITDA, which is also a non-GAAP financial measure, is defined as net income adjusted for (i) interest and debt expense, net of interest income, (ii) affiliated interest income, net of affiliated interest expense, (iii) depreciation and amortization expense, (iv) the partnership’s share of distributions declared by unconsolidated affiliates for the applicable period, (v) earnings from unconsolidated affiliates, and (vi) CIG’s declared distributions to El Paso.
     We believe that the non-GAAP financial measures described above are useful to investors because these measures are used by many companies in the industry as measures of operating and financial performance and are commonly employed by financial analysts and others to evaluate the operating and financial performance of the partnership and to compare it with the performance of other publicly traded partnerships within the industry.
     Neither Distributable Cash Flow nor Adjusted EBITDA should be considered an alternative to net income, earnings per unit, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with U.S. generally accepted accounting principles (GAAP). These non-GAAP measures both exclude some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, Distributable Cash Flow and Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Furthermore, these non-GAAP measures should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period, nor do they equate to Available Cash as defined in our partnership agreement.
     Our distributable cash flow was $241.2 million and $147.7 million for the years ended December 31, 2009 and 2008. The increase in distributable cash flow in 2009 was due primarily to higher expansion revenues and our increased ownership interest in CIG and SNG. The tables below provide our reconciliations of Distributable Cash Flow and Adjusted EBITDA for the years ended December 31, 2009 and 2008:
Reconciliation of Distributable Cash Flow to Net Income.
                 
    Year Ended December 31,  
    2009     2008  
    (In millions)  
Net income
  $ 279.5     $ 234.0  
Net income attributable to noncontrolling interests
    (66.0 )     (62.4 )
 
           
Net income attributable to El Paso Pipeline Partners, L.P.
    213.5       171.6  
Add: Interest and debt expense, net
    73.7       61.6  
Less: Affiliated interest income, net
    (1.7 )     (23.2 )
 
           
EBIT from continuing operations (1)
    285.5       210.0  
Add:
               
Depreciation and amortization
    67.0       58.6  
Distributions declared by unconsolidated affiliates
    58.4       32.9  
Net income attributable to noncontrolling interests
    66.0       62.4  
Less:
               
Earnings from unconsolidated affiliates
    (53.4 )     (32.9 )
CIG declared distributions to El Paso (2)
    (68.1 )     (101.6 )
 
           
 
Adjusted EBITDA
    355.4       229.4  
 
               
Less:
               
Cash interest expense, net
    (71.3 )     (41.2 )
Maintenance capital expenditures
    (25.8 )     (27.4 )
Other, net (3)
    (17.1 )     (13.1 )
 
           
 
               
Distributable Cash Flow
  $ 241.2     $ 147.7  
 
           
 
(1)     For a further discussion of our use of EBIT from continuing operations, see Results of Operations.
 
(2)     CIG declared distributions to El Paso include distributions of pre-acquisition earnings at El Paso’s historical ownership interest levels of $7.2 million and $44.2 million for the years ended December 31, 2009 and 2008.
 
(3)     Includes certain non-cash items such as AFUDC equity and other items.

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Reconciliation of Distributable Cash Flow to Net Cash Provided by Operating Activities.
                 
    Year Ended December 31,  
    2009     2008  
    (In millions)  
Net cash provided by operating activities
  $ 347.0     $ 247.9  
Interest and debt expense, net
    73.7       61.6  
Affiliated interest income, net
    (1.7 )     (23.2 )
CIG declared distributions to El Paso (1)
    (68.1 )     (101.6 )
Changes in working capital and other
    4.5       44.7  
 
           
 
Adjusted EBITDA
    355.4       229.4  
 
               
Less:
               
Cash interest expense, net
    (71.3 )     (41.2 )
Maintenance capital expenditures
    (25.8 )     (27.4 )
Other, net (2)
    (17.1 )     (13.1 )
 
           
 
               
Distributable Cash Flow
  $ 241.2     $ 147.7  
 
           
 
(1)   CIG declared distributions to El Paso include distributions of pre-acquisition earnings at El Paso’s historical ownership interest levels of $7.2 million and $44.2 million for the years ended December 31, 2009 and 2008.
 
(2)   Includes certain non-cash items such as AFUDC equity and other items.
Liquidity and Capital Resources
     Our ability to finance our operations, including our ability to make cash distributions, fund capital expenditures, make acquisitions and satisfy any indebtedness obligations, will depend on our ability to generate cash in the future and our ability to access the capital markets. Our ability to generate cash and our ability to access the capital markets is subject to a number of factors, some of which are beyond our control as discussed below.
     Our sources of liquidity include cash generated from our operations, quarterly cash distributions received from SNG, notes receivable from El Paso and available borrowing capacity under our $750 million revolving credit facility. This facility is expandable to $1.25 billion for certain expansion projects and acquisitions. We may also generate additional sources of cash through future issuances of additional partnership units and/or future debt offerings. As of December 31, 2009, our remaining availability under the credit facility was approximately $215 million. As part of our determination of available capacity under our credit agreements, we completed an assessment of the available lenders under the credit facility. This assessment is based upon the fact that one of our lenders has failed to fund previous requests under this facility and has filed for bankruptcy. Based on this assessment as of December 31, 2009, our available capacity noted above was reduced to reflect the potential exposure to a loss of available capacity of approximately $15 million assuming this lender continues to fail to fund the facility.
     At December 31, 2009, we had notes receivable from El Paso of approximately $93.2 million which was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs.
     Although recent financial market conditions have shown signs of improvement, continued volatility in 2010 and beyond in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Prolonged restricted access to the financial markets could impact our ability to grow our distributable cash flow through acquisitions. However, we believe that cash flows from operating activities, including the cash distributions received from SNG, availability under our credit facility and our note receivables from El Paso will be adequate to meet our operating needs, our anticipated cash distributions to our partners and our planned expansion opportunities for the foreseeable future. Additionally, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base at WIC, CIG, and SNG that is significantly comprised of long term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas. For further detail on our operations including risk factors including adverse general economic conditions and our ability to access financial markets which could impact our operations and liquidity, see Part 1, Item 1A, Risk Factors.

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     SNG, our investee, participates in El Paso’s cash management program and is required to make quarterly distributions of its available cash to its partners, including us. As of December 31, 2009, SNG’s sources of cash primarily include cash provided by operations, amounts available from notes receivable under El Paso’s cash management program, and/or contributions from its partners (including us), if necessary. SNG’s uses of cash primarily include capital expenditures, debt service, and required quarterly distributions to partners.
     Overview of Cash Flow Activities. Our cash flows for the year ended December 31, 2009 are summarized as follows:
         
    2009  
    (In millions)  
Cash Flow from Operations
       
Net income
  $ 279.5  
Non-cash income adjustments
    42.3  
Change in other assets and liabilities
    25.2  
 
     
Total cash flow from operations
  $ 347.0  
 
     
 
       
Other Cash Inflows
       
Investing activities
       
Net change in notes receivable from affiliates
  $ 105.8  
Proceeds from sale of assets
    10.1  
Returns of capital on investment in unconsolidated affiliates
    2.4  
 
       
Financing activities
       
Net proceeds from issuance of common and general partner units
    216.4  
 
     
Total other cash inflows
  $ 334.7  
 
     
 
       
Cash Outflows
       
Investing activities
       
Capital expenditures
  $ (154.0 )
Cash paid to acquire additional interests in CIG
    (143.2 )
Other
    (0.5 )
 
       
Financing activities
       
Payments on borrowings under credit facility
    (64.9 )
Payments to retire long-term debt, including capital lease obligations
    (4.1 )
Cash distributions to unitholders and general partner
    (161.5 )
Cash distributions to El Paso
    (75.7 )
Excess of cash paid for CIG interests over contributed book value
    (71.3 )
 
     
Total cash outflows
  $ (675.2 )
 
     
Net change in cash and cash equivalents
  $ 6.5  
 
     
     For the year ended December 31, 2009, we generated cash flow from operations of $347.0 million compared with $247.9 million in the same period in 2008. Our operating cash flow in 2009 increased primarily due to higher expansion revenue related to our High Plains pipeline, Totem Gas Storage, Piceance lateral and Medicine Bow expansion projects, increased distributions from the acquisition of additional ownership interest in SNG in September 2008 and changes in working capital. We also generated $216.4 million in net proceeds from the issuance of additional common and general partner units, $214.5 million of which was used to acquire an additional 18 percent general partner interest in CIG from El Paso. For a further discussion of this acquisition, see Item 8, Financial Statements and Supplementary Data, Note 2.
     During 2009, we utilized our cash inflows to pay distributions, including CIG’s distribution to El Paso of its share of available cash (see Item 8, Financial Statements and Supplementary Data, Note 12), to fund maintenance and growth projects as further noted below, to make payments to retire certain long term debt and to acquire additional interests in CIG.

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     As of December 31, 2009, our cash capital expenditures for the year ended December 31, 2009 and those planned for 2010 were as follows:
                 
            Expected  
    2009     2010  
    (In millions)  
Maintenance
  $ 25.8     $ 37  
Expansion
    128.2       146  
 
           
Total
  $ 154.0     $ 183  
 
           
     Our expected 2010 expansion capital expenditures include amounts primarily related to our WIC Expansion and Raton 2010 growth projects. While we expect to fund maintenance capital expenditures through internally generated funds, we intend to fund our expansion capital expenditures through borrowings under our credit facility and the repayment of our note receivable from El Paso.
Unconsolidated Affiliates
     Capital Requirements. SNG’s source of cash primarily includes cash provided by operations, amounts available from notes receivable under El Paso’s cash management program, and/or contributions from its partners (including us), if necessary. SNG’s uses of cash primarily includes capital expenditures, debt service, and distributions to partners. The balance of the notes receivable under El Paso’s cash management programs was approximately $154 million for SNG as of December 31, 2009. For 2010, we anticipate SNG will utilize amounts recovered from its notes receivable with El Paso, together with capital contributions from its partners, including us, to fund its capital investment needs. We estimate that we will be required to make capital contributions to SNG of approximately $40 million during 2010. As of December 31, 2009, SNG’s capital expenditures, including committed projects, and other projects, for the year ended December 31, 2009 and those planned for 2010 were as follows:
                 
            Anticipated  
      2009     2010  
    (In millions)  
SNG      
Maintenance
  $ 60.2     $ 95  
Expansion/Other
    83.7       249  
Hurricanes
    (6.5 )      
 
           
Total
  $ 137.4     $ 344  
 
           

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Commitments and Contingencies
     Climate Change and Energy Legislation and Regulation. There are various legislative and regulatory measures relating to climate change and energy policies that have been proposed and, if enacted, will likely impact our business.
     Climate Change Legislation and Regulation. Measures to address climate change and GHG emissions are in various phases of discussions or implementation at international, federal, regional and state levels. Over 50 countries, including the US, have submitted formal pledges to cut or limit their emissions in response to the United Nation-sponsored Copenhagen Accord. It is reasonably likely that federal legislation requiring GHG controls will be enacted within the next few years in the United States. Although it is uncertain what legislation will ultimately be enacted, it is our belief that cap-and-trade or other market-based legislation that sets a price on carbon emissions will increase demand for natural gas, particularly in the power sector. We believe this increased demand will occur due to substantially less carbon emissions associated with the use of natural gas compared with alternative fuel sources for power generation, including coal and oil-fired power generation. However, the actual impact on demand will depend on the legislative provisions that are ultimately adopted, including the level of emission caps, allowances granted, offset programs established, cost of emission credits and incentives provided to other fossil fuels and lower carbon technologies like nuclear, carbon capture sequestration and renewable energy sources.
     It is also reasonably likely that any federal legislation that is enacted would increase our cost of environmental compliance by requiring us to install additional equipment to reduce carbon emissions from our larger facilities as well as to potentially purchase emission allowances. Based on 2008 operational data we reported to the California Climate Action Registry (CCAR) that our operations in the United States, which include our 58 percent interest in CIG and 25 percent interest in SNG, emitted approximately 1.4 million tonnes of carbon dioxide equivalent emissions during 2008. We believe that approximately 1.3 million tonnes of the GHG emissions that we reported to CCAR would be subject to regulations under the climate change legislation that passed in the U.S. House of Representatives in June 2009. Of these amounts that would be subject to regulation, we believe that approximately 44 percent would be subject to the cap-and-trade rules contained in the proposed legislation and the remainder would be subject to performance standards. As proposed by the House, the portion of our GHG emissions that would be subject to cap-and-trade rules could require us to purchase allowances or offset credits and the portion of our GHG emissions that would be subject to performance standards could require us to install additional equipment or initiate new work practice standards to reduce emission levels at many of our facilities. The costs of purchasing emission allowances or offset credits and installing additional equipment or changing work practices would likely be material. Increases in costs of our suppliers to comply with such cap-and-trade rules and performance standards could also materially increase our costs of operations. Although we believe that many of these costs should be recoverable in the rates we charge our customers, recovery is still uncertain at this time. A climate change bill was also voted upon favorably by the Senate Committee on Energy and Public Works (the Committee) in November 2009 and has been ordered to be reported out of the Committee. Any final bill passed out of the U.S. Senate will likely see further substantial changes and we cannot yet predict the form it may take, the timing of when any legislation will be enacted or implemented, or how it may impact our operations if ultimately enacted.
     The EPA finalized regulations to monitor and report GHG emissions on an annual basis. The EPA also proposed new regulations to regulate GHGs under the Clean Air Act, which the EPA has indicated could be finalized as early as March 2010. The effective date and substantive requirements of any EPA final rule is subject to interpretation and possible legal challenges. In addition, it is uncertain whether federal legislation might be enacted that either delays the implementation of any climate change regulations of the EPA or adopts a different statutory structure for regulating GHGs than is provided for pursuant to the Clean Air Act. Therefore, the potential impact on our operations and construction projects remains uncertain.

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     In addition, in March 2009, the EPA proposed a rule impacting emissions from reciprocating internal combustion engines, which would require us to install emission controls on our pipeline systems. It is expected that the rule will be finalized in August 2010. As proposed, engines subject to the regulations would have to be in compliance by August 2013. Based upon that timeframe, we would expect that we would commence incurring expenditures in late 2010, with the majority of the work and expenditures incurred in 2011 and 2012. If the regulations are adopted as proposed, we would expect to incur approximately $16 million in capital expenditures over the period from 2010 to 2013.
     Legislative and regulatory efforts are underway in various states and regions. These rules once finalized may impose additional costs on our operations and permitting our facilities, which could include costs to purchase offset credits or emission allowances, to retrofit or install equipment or to change existing work practice standards. In addition, various lawsuits have been filed seeking to force further regulation of GHG emissions, as well as to require specific companies to reduce GHG emissions from their operations. Enactment of additional regulations by the federal or state governments, as well as lawsuits, could result in delays and have negative impacts on our ability to obtain permits and other regulatory approvals with regard to existing and new facilities, could impact our costs of operations, as well as require us to install new equipment to control emissions from our facilities, the costs of which would likely be material.
     Energy Legislation. In conjunction with these climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint.” These proposals would establish renewable energy and efficiency standards at both the federal and state level, some of which would require a material increase in renewable sources, such as wind and solar power generation, over the next several decades. There have also been proposals to increase the development of nuclear power and commercialize carbon capture and sequestration especially at coal fired facilities. Other proposals would establish incentives for energy efficiency and conservation. Although it is reasonably likely that many of these proposals will be enacted over the next few years, we cannot predict the form of any laws and regulations that might be enacted, the timing of their implementation, or the precise impact on our operations or demand for natural gas. However, such proposals if enacted could negatively impact natural gas demand over the longer term.
Off-Balance Sheet Arrangements
     For a further discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Note 12.

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Contractual Obligations
     We are party to various contractual obligations, a portion of which are reflected in our financial statements, such as long-term debt and our capital lease. Other obligations, such as capital commitments and demand charges under transportation commitments, are not reflected on our balance sheet. The following table and discussion that follows summarizes our contractual cash obligations as of December 31, 2009 for each of the periods presented:
                                         
    Due in     Due in     Due in              
    Less Than     1-3     3-5              
Contractual Obligations   1 Year     Years     Years     Thereafter     Total  
                    (in millions)                  
Long-term financing obligations
                                       
Principal
  $ 5.0     $ 627.0     $ 98.0     $ 632.6     $ 1,362.6  
Interest
    76.6       147.4       121.1       560.7       905.8  
Other contractual liabilities
    1.8       4.0       0.9       3.6       10.3  
Operating leases
    2.2       4.6       4.8       0.6       12.2  
Other contractual commitments and purchase obligations
                                       
Transportation and storage
    21.1       51.0       51.8       52.7       176.6  
Other
    35.4       3.5                   38.9  
 
                             
Total
  $ 142.1     $ 837.5     $ 276.6     $ 1,250.2     $ 2,506.4  
 
                             
     Long-term Financing Obligations (Principal and Interest). Long-term financing obligations represent stated maturities. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual interest rates for fixed rate debt, (ii) current market interest rates and the contractual credit spread for our variable rate debt. Included in these amounts are payments related to the financing obligations of CIG for the construction of WYCO’s High Plains Pipeline and Totem Gas Storage facility. CIG makes monthly interest payments on these obligations that are based on 50 percent of the operating results of the High Plains Pipeline and Totem Gas Storage facility. Also included in these amounts is a compressor station under a capital lease from an affiliate of CIG, WYCO. The compressor station lease expires November 2029. For a further discussion of our long-term financing and capital lease obligations see Financial Statements and Supplementary Data, Note 6.
     Other contractual liabilities. Included in this amount are environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we perform remediation activities. These liabilities are included in other current and non-current liabilities in our balance sheet.
     Operating Leases. For a further discussion of these obligations, see Financial Statements and Supplementary Data, Note 8.
     Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:
    Transportation and Storage Commitments. Included in these commitments are agreements for capacity on third party pipeline systems and storage capacity from an affiliate.
    Other Commitments. Included in these amounts are commitments for construction contracts and purchase obligations. We exclude asset retirement obligations and reserves for litigation and environmental remediation, other than those disclosed above, when these liabilities are not contractually fixed as to timing and amount. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

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Critical Accounting Policies and Estimates
     The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as, of our current accounting policies, its application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material impact on our results of operations, partners’ capital or cash flows. For additional information concerning our other accounting policies, please read the notes to the financial statements included in Item 8, Financial Statements and Supplementary Data, Note 1
     Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standards Board (FASB) accounting standards for rate-regulated operations. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of this standard, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.
     Accounting for Environmental Reserves. We accrue environmental reserves when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Estimates of our liabilities are based on an evaluation of potential outcomes, currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of societal and economic factors, estimates of associated onsite, offsite and groundwater technical studies and legal costs. Actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon actual outcomes or changes in expectations based on the facts surrounding each matter.
     As of December 31, 2009, we had accrued approximately $11 million for environmental matters related to CIG and its subsidiaries. Our environmental estimates range from approximately $11 million to approximately $35 million and the amounts we have accrued represent a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($3 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($8 million to $32 million) and the lower end of the expected range has been accrued.
     Accounting for Other Postretirement Benefits. We reflect an asset or liability for CIG’s postretirement benefit plan based on its over funded or under funded status. As of December 31, 2009, CIG’s postretirement benefit plan was over funded by $8.6 million. CIG’s postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. Various assumptions are used in performing these calculations, including those related to the return that CIG’s plan assets are expected to return, the estimated cost of health care when benefits are provided under CIG’s plan and other factors. A significant assumption utilized is the discount rate used in calculating CIG’s benefit obligation. The discount rate is selected by matching the timing and amount of CIG’s expected future benefit payments for CIG’s postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.
     Actual results may differ from the assumptions included in these calculations, and as a result, estimates associated with CIG’s postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on CIG’s related benefit obligation, along with changes to CIG’s plan and other items, are deferred and recorded as either a regulatory asset or liability. A one percent change in the primary assumptions would not have a material impact on CIG’s funded status or net postretirement benefit cost.

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New Accounting Pronouncements Issued But Not Yet Adopted
     See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     Our primary market risk is exposure to changing interest rates. The table below shows the maturity of the carrying amounts and related weighted-average interest rates on our long-term interest-bearing securities by expected maturity date as well as the total fair value of those securities. The fair value on our fixed and variable rate obligations have been estimated based on quoted market prices for the same or similar issues.
                                                                                 
    December 31, 2009   December 31, 2008
    Expected Fiscal Year of Maturity of Carrying Amounts           Fair   Carrying   Fair
    2010   2011   2012   2013   2014   Thereafter   Total   Value   Amounts   Value
                                    (In millions)                                
Long-term debt and other financing obligations, including current portion — fixed rate
  $ 5.0     $ 42.0     $ 20.0     $ 93.0     $ 5.0     $ 632.6     $ 797.6     $ 845.6     $ 731.0     $ 638.1  
Average interest rate
    14.5 %     8.6 %     9.6 %     8.3 %     14.5 %     8.7 %                                
Long-term debt and other financing obligations, including current portion — variable rate
  $     $     $ 565.0     $     $     $     $ 565.0     $ 529.1     $ 629.9     $ 488.2  
Average interest rate
                    1.4 %                                                        

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index
     Below is an index to the items contained in Part II, Item 8, Financial Statements and Supplementary Data.
         
    Page  
    47  
    48  
    50  
    51  
    52  
    53  
    54  
    54  
    59  
    61  
    62  
    64  
    66  
    68  
    68  
    71  
    73  
    73  
    73  
    77  
    78  

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:
    Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
 
    Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
 
    Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
     Under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2009. The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of El Paso Pipeline GP Company, L.L.C.
as General Partner of El Paso Pipeline Partners, L.P.,
and the Partners of El Paso Pipeline Partners, L.P.:
We have audited the accompanying consolidated balance sheets of El Paso Pipeline Partners, L.P. (the Partnership) as of December 31, 2009 and 2008, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2009. These financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of El Paso Pipeline Partners, L.P. at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2008, the Partnership adopted the provisions of an accounting standard update related to measurement date and changed the measurement date of its postretirement benefit plan.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), El Paso Pipeline Partners, L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 26, 2010

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of El Paso Pipeline GP Company, L.L.C.
as General Partner of El Paso Pipeline Partners, L.P.,
and the Partners of El Paso Pipeline Partners, L.P.:
We have audited El Paso Pipeline Partners, L.P.’s (the Partnership) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). El Paso Pipeline Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, El Paso Pipeline Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of El Paso Pipeline Partners, L.P. as of December 31, 2009 and 2008, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009 of El Paso Pipeline Partners, L.P. and our report dated February 26, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 26, 2010

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El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per unit amounts)
                         
    Year Ended December 31,  
    2009     2008     2007  
Operating revenues
  $ 537.6     $ 457.2     $ 418.1  
Operating expenses
                       
Operation and maintenance
    154.4       147.2       144.2  
Depreciation and amortization
    67.0       58.6       46.7  
Taxes, other than income taxes
    23.7       21.6       19.4  
 
                 
 
    245.1       227.4       210.3  
 
                 
Operating income
    292.5       229.8       207.8  
Earnings from unconsolidated affiliates
    53.4       32.9       4.1  
Other income, net
    5.6       9.7       11.0  
Interest and debt expense, net
    (73.7 )     (61.6 )     (51.1 )
Affiliated interest income, net
    1.7       23.2       41.7  
 
                 
Income before income taxes
    279.5       234.0       213.5  
Income tax expense
                44.1  
 
                 
Income from continuing operations
    279.5       234.0       169.4  
Discontinued operations, net of income taxes
                5.8  
 
                 
Net income
    279.5       234.0       175.2  
Net income attributable to noncontrolling interest
    (66.0 )     (62.4 )     (47.3 )
 
                 
Net income attributable to El Paso Pipeline Partners, L.P.
  $ 213.5     $ 171.6     $ 127.9  
 
                 
 
                       
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit —
                       
Basic and Diluted:
                       
Common units
  $ 1.64     $ 1.26     $ 0.11  
Subordinated units
  $ 1.56     $ 1.12     $ 0.11  
See accompanying notes.

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El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In millions, except units)
                 
    December 31,  
    2009     2008  
ASSETS
               
Current assets
               
Cash and cash equivalents
  $ 17.4     $ 10.9  
Accounts receivable
               
Customer, net of allowance of $0.5 in 2008
    14.2       22.0  
Affiliates
    114.5       138.2  
Other
    0.7       3.1  
Materials and supplies
    11.2       8.2  
Regulatory assets
    4.2       28.4  
Other
    3.8       3.7  
 
           
Total current assets
    166.0       214.5  
 
           
Property, plant and equipment, at cost
    2,672.2       2,542.5  
Less accumulated depreciation and amortization
    653.7       634.4  
 
           
Total property, plant and equipment, net
    2,018.5       1,908.1  
 
           
Other assets
               
Investment in unconsolidated affiliates
    417.5       410.8  
Note receivable from affiliates
          75.9  
Other
    66.2       66.5  
 
           
 
    483.7       553.2  
 
           
Total assets
  $ 2,668.2     $ 2,675.8  
 
           
 
               
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities
               
Accounts payable and accrued liabilities
               
Trade
  $ 7.3     $ 17.5  
Affiliates
    26.9       10.2  
Other
    15.6       34.4  
Taxes payable
    16.1       11.9  
Accrued interest
    6.7       10.6  
Regulatory liabilities
    14.7       29.2  
Contractual deposits
    8.7       9.7  
Deferred credits
    6.3       0.8  
Other
    7.3       8.8  
 
           
Total current liabilities
    109.6       133.1  
 
           
Other liabilities
               
Long-term debt and other financing obligations, less current maturities
    1,357.6       1,357.3  
Other liabilities
    39.4       68.0  
 
           
 
    1,397.0       1,425.3  
 
           
Commitments and contingencies (Note 8)
               
Partners’ capital
               
El Paso Pipeline Partners L.P. partners’ capital
               
Common units (97,622,247 and 84,970,498 units issued and outstanding
at December 31, 2009 and 2008)
    1,304.6       1,064.8  
Subordinated units (27,727,411 units issued and outstanding at December 31, 2009 and 2008)
    297.4       289.4  
General partner units (2,558,028 and 2,299,526 units issued and outstanding
at December 31, 2009 and 2008)
    (783.8 )     (574.9 )
 
           
Total El Paso Pipeline Partners L.P. partners’ capital
    818.2       779.3  
Noncontrolling interests
    343.4       338.1  
 
           
Total partners’ capital
    1,161.6       1,117.4  
 
           
Total liabilities and partners’ capital
  $ 2,668.2     $ 2,675.8  
 
           
See accompanying notes.

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El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In millions)  
Cash flows from operating activities
                       
Net income
  $ 279.5     $ 234.0     $ 175.2  
Less: income from discontinued operations, net of income taxes
                5.8  
 
                 
Income from continuing operations
    279.5       234.0       169.4  
Adjustments to reconcile net income to net cash from operating activities
                       
Depreciation and amortization
    67.0       58.6       46.7  
Earnings from unconsolidated affiliates, adjusted for cash distributions
    (9.6 )     (9.8 )     (4.1 )
Deferred income taxes
                7.7  
Other non-cash income items
    (15.1 )     (9.3 )     (7.0 )
Asset and liability changes
                       
Accounts receivable
    3.9       (7.7 )     3.5  
Accounts payable
    4.4       1.6       6.4  
Taxes payable
                (56.4 )
Regulatory assets
    25.0       (26.7 )     1.4  
Regulatory liabilities
    (11.0 )     12.3       23.3  
Non-current liabilities
    (0.9 )     3.3       (199.8 )
Other, net
    3.8       (8.4 )     (0.1 )
 
                 
Cash provided by (used in) continuing activities
    347.0       247.9       (9.0 )
Cash provided by discontinued activities
                3.3  
 
                 
Net cash provided by (used in) operating activities
    347.0       247.9       (5.7 )
 
                 
Cash flows from investing activities
                       
Capital expenditures
    (154.0 )     (218.4 )     (268.6 )
Cash paid to acquire additional interests in CIG and SNG
    (143.2 )     (254.3 )      
Proceeds from sale of assets
    10.1              
Returns of capital on investment in unconsolidated affiliates
    2.4       6.9        
Net change in notes receivable from affiliates
    105.8       193.2       160.2  
Other
    (0.5 )     1.4       0.2  
 
                 
Net cash used in investing activities
    (179.4 )     (271.2 )     (108.2 )
 
                 
Cash flows from financing activities
                       
Net proceeds from issuance of common and general partner units
    216.4       15.0       537.2  
Net proceeds from (payments on) borrowings under credit facility
    (64.9 )     129.9       453.9  
Net proceeds from issuance of long-term debt
          174.0        
Payments to retire long-term debt, including capital lease obligations
    (4.1 )     (104.0 )     (128.5 )
Cash distributions to unitholders and general partner
    (161.5 )     (96.1 )      
Cash distributions to El Paso
    (75.7 )     (89.3 )     (747.8 )
Excess of cash paid for CIG interests over contributed book value
    (71.3 )            
Contribution from parent
                7.1  
 
                 
Cash provided by (used in) financing activities
    (161.1 )     29.5       121.9  
Cash used in discontinued activities
                (3.3 )
 
                 
Net cash provided by (used in) financing activities
    (161.1 )     29.5       118.6  
 
                 
Net change in cash and cash equivalents
    6.5       6.2       4.7  
Cash and cash equivalents
                       
Beginning of period
    10.9       4.7        
 
                 
End of period
  $ 17.4     $ 10.9     $ 4.7  
 
                 
See accompanying notes.

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El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In millions, except units)
                                                         
    Predecessor     El Paso Pipeline Partners, L.P. Partners’ Capital             Total  
    Partners’     Limited Partners     General             Noncontrolling     Partners’  
    Capital     Common     Subordinated     Partner     Total     Interests     Capital  
Balance at December 31, 2006
  $ 854.6     $     $     $     $     $ 382.1     $ 1,236.7  
 
                                                       
Net income
    108.0                                   38.6       146.6  
Reclassification to regulatory liabilities (Note 9)
    (2.9 )                             (2.1 )     (5.0 )
 
                                         
Balance at November 20, 2007
    959.7                               418.6       1,378.3  
 
                                                       
Contribution of interests in CIG and SNG
    253.7                                     253.7  
Elimination of CIG additional acquired interest from historical capital
    (102.2 )                                   (102.2 )
Distribution to noncontrolling interests
    (18.6 )                             18.6        
Distribution of discontinued operations
    (3.4 )                             (2.4 )     (5.8 )
Contributions
    5.8                               4.2       10.0  
Cash distributions to El Paso
    (11.4 )                                   (11.4 )
Conversion to El Paso Pipeline Partners, L.P.
    (1,083.6 )     288.1       280.9       514.6       1,083.6              
Issuance of common units, net of issuance costs
          537.2                   537.2             537.2  
Net income
          6.5       3.2       10.2       19.9       8.7       28.6  
Cash distributions to El Paso
                      (736.4 )     (736.4 )           (736.4 )
Other
                      0.3       0.3       (0.6 )     (0.3 )
 
                                         
Balance at December 31, 2007
          831.8       284.1       (211.3 )     904.6       447.1       1,351.7  
 
                                                       
Net income
          78.9       33.3       59.4       171.6       62.4       234.0  
Issuance of common units, net of issuance costs
          15.0                   15.0             15.0  
Cash distributions to unitholders and general partner
          (66.1 )     (28.0 )     (2.0 )     (96.1 )           (96.1 )
Cash distributions to El Paso
                      (43.7 )     (43.7 )     (45.6 )     (89.3 )
Non-cash distribution to El Paso
                      (144.1 )     (144.1 )     (125.9 )     (270.0 )
Excess of contributed book value of CIG and SNG over cash paid
          205.2             4.5       209.7             209.7  
Elimination of CIG additional acquired interest from historical capital
                      (237.9 )     (237.9 )           (237.9 )
Other
                      0.2       0.2       0.1       0.3  
 
                                         
Balance at December 31, 2008
          1,064.8       289.4       (574.9 )     779.3       338.1       1,117.4  
 
                                                       
Net income
          149.1       44.8       19.6       213.5       66.0       279.5  
Issuance of common and general partner units, net of issuance costs
          211.9             4.5       216.4             216.4  
Cash distributions to unitholders and general partner
          (121.2 )     (36.7 )     (3.6 )     (161.5 )           (161.5 )
Cash distributions to El Paso
                      (15.0 )     (15.0 )     (60.7 )     (75.7 )
Cash paid to general partner to acquire additional interest in CIG
                      (214.5 )     (214.5 )           (214.5 )
Other
                (0.1 )     0.1                    
 
                                         
Balance at December 31, 2009
  $     $ 1,304.6     $ 297.4     $ (783.8 )   $ 818.2     $ 343.4     $ 1,161.6  
 
                                         
See accompanying notes.

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El PASO PIPELINE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Significant Accounting Policies
Organization
     We are a publicly-traded partnership. El Paso Corporation (El Paso) owned a 65 percent limited partner interest and a two percent general partner interest in us as of December 31, 2009. We own a 100 percent ownership interest in Wyoming Interstate Company, Ltd. (WIC), an interstate natural gas system. In November 2007, El Paso contributed to us, at their historical cost, 10 percent general partner interests in each of Colorado Interstate Gas Company (CIG) and Southern Natural Gas Company (SNG) which consist of interstate natural gas pipeline systems and related storage facilities. In connection with our initial public offering, we issued 28.8 million common units to the public for approximately $537 million, net of issuance costs and expenses. We used the net proceeds from the common unit offering, together with proceeds of approximately $425 million borrowed under our revolving credit facility (Note 6), to primarily repay notes payable to El Paso of $225 million and distribute $737 million to El Paso, in part to reimburse El Paso for capital expenditures incurred prior to our initial public offering related to the assets contributed to us.
     On September 30, 2008, we acquired from El Paso an additional 30 percent interest in CIG and an additional 15 percent interest in SNG. The acquisition increased our interest in CIG to 40 percent and our interest in SNG to 25 percent. El Paso operates these systems and owns the remaining general partner interests in CIG and SNG. For a further discussion of this acquisition, see Note 2.
     On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG from El Paso for $214.5 million. Subsequent to the acquisition, we own a 58 percent general partner interest in CIG and have the ability to control its operating and financial decisions and policies. Accordingly, we have consolidated CIG and have retrospectively adjusted our historical financial statements in all periods to reflect the change in reporting entity. El Paso owns the remaining 42 percent interest in CIG which is reflected as a noncontrolling interest. For a further discussion of this acquisition, see Note 2.
Basis of Presentation and Principles of Consolidation
     Our consolidated financial statements are prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. We consolidate WIC and CIG based on our ability to control their operating and financial decisions and policies. Both the contribution of CIG and SNG interests in conjunction with the initial public offering and our acquisitions of additional interests were recorded at their historical cost since the transactions were between entities under common control. For a further discussion of our acquisitions, see Note 2.
     We account for our investment in SNG using the equity method of accounting based on our ability to exert significant influence over, but not control, SNG. We reflect our proportionate share of the operating results of SNG as earnings from unconsolidated affiliates in our financial statements. Earnings from unconsolidated affiliates includes our 10 percent ownership in SNG from the date of its contribution to us on November 21, 2007 through September 30, 2008, and our 25 percent ownership in SNG beginning on the date of our acquisition of additional interests on September 30, 2008.

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     We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control, the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. Where we are unable to exert significant influence over the entity, we use the cost method of accounting.
Use of Estimates
     The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts reported as assets, liabilities, revenues and expenses and the disclosures in these financial statements. Actual results can, and often do, differ from those estimates.
Regulated Operations
     Our interstate natural gas pipelines and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement benefit plan costs, loss on reacquired debt, an equity return component on regulated capital projects and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.
Cash and Cash Equivalents
     We consider short-term investments with an original maturity of less than three months to be cash equivalents.
Allowance for Doubtful Accounts
     We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.
Materials and Supplies
     We value our materials and supplies at the lower of cost or market value with cost determined using the average cost method.
Natural Gas Imbalances
     Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system differs from the scheduled amount of gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up in-kind, subject to the terms of the tariff.
     Imbalances due from others are reported in the balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported in the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect them to be settled within a year.

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Property, Plant and Equipment
     Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For constructed assets, direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component are capitalized, as allowed by the FERC. Major units of property replacements or improvements are capitalized and minor items are expensed.
     We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. The FERC-accepted depreciation rate is applied to the total cost of the group until the net book value equals the salvage value. For certain general plant, the asset is depreciated to zero. Currently, depreciation rates vary from approximately two percent to 25 percent per year. Using these rates, the remaining depreciable lives of these assets range from four to 50 years. We re-evaluate depreciation rates each time we redevelop our transportation and storage rates to file with the FERC for an increase or decrease in rates. When property, plant and equipment is retired, accumulated depreciation and amortization is charged for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less salvage value. We do not recognize a gain or loss unless we sell or retire an entire operating unit, as defined by the FERC. We include gains or losses on dispositions of operating units in operations and maintenance expense in our income statements.
     At December 31, 2009 and 2008, we had approximately $83.8 million and $127.5 million of construction work in progress included in our property, plant and equipment.
     We capitalize a carrying cost (an allowance for funds used during construction) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs on debt amounts capitalized during the years ended December 31, 2009, 2008 and 2007 were $1.9 million, $2.8 million and $2.6 million. These debt amounts are included as a reduction to interest and debt expense in the income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized during each of the years ended December 31, 2009, 2008 and 2007 were $5.5 million, $8.7 million and $7.0 million. These equity amounts are included as other income in our income statement.
Asset and Investment Divestitures/Impairments
     We evaluate our assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of long-lived assets’ carrying values based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and the established time frame for completing the sale, among other factors.
     We reclassify assets to be sold in our financial statements as either held-for-sale or from discontinued operations when it becomes probable that we will dispose of the assets within the next twelve months and when they meet other criteria, including whether we will have significant long-term continuing involvement with those assets after they are sold. We cease depreciating assets in the period that they are reclassified as either held for sale or from discontinued operations, and reflect the results of our discontinued operations in our income statement separately from those of continuing operations.
     Cash flows from our discontinued businesses are reflected as discontinued operating, investing, and financing activities in our statement of cash flows. Cash provided by discontinued activities in the operating activities section of our cash flow statement includes all operating cash flows generated by our discontinued business during the period. Our discontinued business participated in El Paso’s cash management program as it did not maintain separate bank accounts for its cash balances. We reflected transactions between our continuing operations and discontinued operations related to El Paso’s cash management program as financing activities in our cash flow statement.

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Revenue Recognition
     Our revenues are primarily generated from natural gas transportation, storage and processing services and include estimates of amounts earned but unbilled. We estimate these unbilled revenues based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation services and storage services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.
Environmental Costs and Other Contingencies
     Environmental Costs. We record environmental liabilities at their undiscounted amounts on our balance sheet when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period expense when clean-up efforts do not benefit future periods.
     We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.
     Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
Income Taxes
     We are a partnership for income tax purposes and are not subject to either federal income taxes or generally to state income taxes. Our partners are responsible for income taxes on their allocated share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities. We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because information regarding each partner’s tax attributes in us is not available to us.

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     Effective November 1, 2007, CIG, our consolidated subsidiary, converted into a general partnership in conjunction with our formation and accordingly, CIG is also no longer subject to income taxes. As a result of its conversion into a general partnership, CIG settled their existing current and deferred tax balances with recoveries of note receivables from El Paso under its cash management program pursuant to its tax sharing agreement with El Paso (see Note 12). Prior to that date, CIG recorded current income taxes based on its taxable income and provided for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represented the income tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We accounted for tax credits under the flow-through method, which reduced the provision for income taxes in the year the tax credits first became available. We reduced deferred tax assets by a valuation allowance when, based on our estimates, it was more likely than not that a portion of those assets would not be realized in a future period.
Accounting for Asset Retirement Obligations
     We record a liability for legal obligations associated with the replacement, removal and retirement of our long-lived assets. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.
     We have legal obligations associated with the retirement of our natural gas pipeline, related transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities primarily involve purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We accrue a liability for legal obligations based on an estimate of the timing and amount of their settlement.
     We are required to operate and maintain our natural gas pipeline system, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that the substantial majority of our natural gas pipeline system assets have indeterminate lives. Accordingly, our asset retirement liabilities as of December 31, 2009 and 2008 were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.
Partners’ Capital
     We allocate our net income to the capital accounts of our general partner, common unitholders and subordinated unitholders based on the terms of the partnership agreement. The agreement requires these allocations to be made based on the relative percentage of their ownership interests, adjusted for any replenishment of previously allocated aggregate net losses and/or special allocations, each as defined in our partnership agreement. As a result of the retrospective consolidation of CIG, earnings prior to the acquisition of the incremental interests in CIG (“pre-acquisition earnings”) in historical periods have been allocated to our general partner. Accordingly, the allocation of pre-acquisition earnings to our general partner reflects 58 percent of CIG’s earnings prior to November 21, 2007, 48 percent of CIG’s earnings between November 21, 2007 and September 30, 2008 and 18 percent of CIG’s earnings between September 30, 2008 and July 24, 2009.
     Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders. Accordingly, all of our issued units are authorized and outstanding, and there is an unlimited number of units that are authorized beyond those currently issued.

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Postretirement Benefits
     CIG, our consolidated subsidiary, maintains a postretirement benefit plan covering certain of its former employees. This plan requires CIG to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. We record the net benefit cost related to this plan in our income statement. This net benefit cost is a function of many factors including benefits earned during the year by plan participants (which is a function of the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to CIG’s postretirement benefit plan, see Note 9.
     In accounting for CIG’s postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.
     Effective January 1, 2008, we adopted the provisions of an accounting standard update related to measurement date and changed the measurement date of CIG’s postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements.
     Effective December 31, 2009, we expanded our disclosures about postretirement benefit plan assets as a result of new disclosure requirements. See Note 9 for these expanded disclosures.
New Accounting Pronouncements Issued But Not Yet Adopted
     As of December 31, 2009, the following accounting standards had not yet been adopted by us:
     Transfers of Financial Assets. In June 2009, the FASB updated accounting standards for financial asset transfers. Among other items, this update eliminated the concept of a qualifying special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated or not. These changes are effective for existing QSPEs as of January 1, 2010 and for transactions entered into on or after January 1, 2010. The adoption of this accounting standard in January 2010 did not have an impact on our financial statements as we amended our existing accounts receivable sales program in January 2010, see Note 12.
     Variable Interest Entities. In June 2009, the FASB updated accounting standards for variable interest entities to revise how companies determine the primary beneficiary of these entities, among other changes. Companies will now be required to use a qualitative approach based on their responsibilities and power over the entities’ operations, rather than a quantitative approach in determining the primary beneficiary as previously required. The adoption of this accounting standard in January 2010 did not have a material impact on our financial statements.
2. Contribution of Assets, Acquisitions and Divestitures
     Initial Contribution of Assets (IPO). In conjunction with our initial public offering of common units in November 2007, El Paso contributed to us, at their historical cost, 10 percent general partner interests in CIG and SNG. Because our financial statements have been retrospectively adjusted to reflect the consolidation of CIG, we have eliminated the historical capital balance related to the 10 percent interest we acquired in CIG in November 2007. Accordingly, for accounting purposes, we have reflected a $102.2 million decrease in our general partner’s capital during the year ended December 31, 2007 related to this elimination. We began recording our proportionate share of SNG’s operating results as earnings from unconsolidated affiliates from the date of El Paso’s contribution of these interests to us.
     Acquisition of Additional Interests in CIG and SNG. On September 30, 2008, we acquired an additional 30 percent general partner interest in CIG and an additional 15 percent general partner interest in SNG from El Paso for $736.4 million. The consideration paid to El Paso consisted of the issuance of 26,888,611 common units, 566,563 general partner units, a $10 million note payable and $254 million of cash. We financed the $254 million cash payment through the issuance of $175 million of private placement debt, $65 million from our revolving credit facility and the issuance of 873,000 common units to private investors for $15 million. For accounting purposes, we recorded these additional interests in CIG and SNG at their historical cost of $474 million and the difference

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between historical cost and the cash and note payable consideration paid to El Paso as an increase to partners’ capital. Because our financial statements have been retrospectively adjusted to reflect the consolidation of CIG, we have eliminated the historical capital balance related to the 30 percent interest we acquired in CIG on September 30, 2008. Accordingly, for accounting purposes, we have reflected a $237.9 million decrease in our general partner’s capital during the year ended December 31, 2008 related to this elimination. We accounted for the acquisition of SNG prospectively beginning with the date of acquisition and will continue to utilize the equity method of accounting for our total investment in SNG.
     On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG from El Paso for $214.5 million in cash. Subsequent to this acquisition, we own a 58 percent general partner interest in CIG and have the ability to control its operating and financial decisions and policies. Because the transaction was accounted for as a reorganization of entities under common control, we have consolidated CIG and have retrospectively adjusted our historical financial statements in all periods to reflect the change in reporting entity. Accordingly, the condensed consolidated balance sheets reflect the historical carrying value of CIG’s assets and liabilities. We have reflected El Paso’s 42 percent interest in CIG as a noncontrolling interest in our financial statements in all periods presented. As a result of the retrospective consolidation of CIG, earnings prior to the acquisition of the incremental interests in CIG (“pre-acquisition earnings”) in historical periods have been allocated to our general partner. Accordingly, the allocation of pre-acquisition earnings to our general partner reflects 58 percent of CIG’s earnings prior to November 21, 2007, 48 percent of CIG’s earnings between November 21, 2007 and September 30, 2008 and 18 percent of CIG’s earnings between September 30, 2008 and July 24, 2009.
     Divestitures. In November 2009, CIG sold its Natural Buttes compressor station and gas processing plant to a third party for $9.0 million and recorded a gain of $7.8 million related to the sale, which is included in our income statement as a reduction of operating and maintenance expense. The historical gross cost of the assets were $34.8 million. Pursuant to the FERC order approving the sale of the processing plant, we recently filed our proposed accounting entries associated with the sale with the FERC for its approval which utilized a technical obsolescence appraisal methodology for determining the portion of the composite accumulated depreciation attributable to the plant which resulted in us recording a gain on the sale. Although we believe the entries proposed are appropriate for this sale, the FERC also utilizes other methodologies in estimating the associated accumulated depreciation that if applied could result in a non-cash loss on the sale.
     In November 2007, in conjunction with our formation, CIG distributed certain of its assets to El Paso. We have reflected these operations as discontinued operations in our financial statements for periods prior to their distribution. We classify assets (or groups of assets) to be disposed of as held for sale or, if appropriate, from discontinued operations when they have received appropriate approvals to be disposed of by our management and when they meet other criteria. The table below summarizes the operating results of our discontinued operations for the year ended December 31, 2007.
         
    2007  
    (In millions)  
Revenues
  $  
Operating expenses
     
Other income, net
    0.1  
Interest and debt expense
     
Affiliated interest income, net
    8.9  
 
     
Income before income taxes
    9.0  
Income taxes
    3.2  
 
     
Income from discontinued operations, net of income taxes
  $ 5.8  
 
     

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3. Partners’ Capital
     In November 2007, in connection with our initial public offering, we issued 28,750,000 common units to the public for $537.2 million, net of issuance costs and expenses.
     On September 30, 2008, we issued 26,888,611 common units and 566,563 general partner units to El Paso, and issued 873,000 common units to private investors in conjunction with our acquisition of an additional 30 percent general partner interest in CIG and an additional 15 percent general partner interest in SNG.
     In June and July 2009, we publicly issued 258,502 common units and issued 258,502 general partner units to El Paso for net proceeds of $216.5 million. The net proceeds from this offering were used to acquire an additional 18 percent general partner interest in CIG. For a further discussion of these acquisitions, see Note 2.
     The table below provides a reconciliation of our limited and general partner units.
                                 
    Unit Reconciliation  
                            Total  
    Limited Partner Units     General     Partners’  
    Common     Subordinated     Partner     Capital  
Balance at December 31, 2006
                       
 
                               
Formation of El Paso Pipeline Partners, L.P
    28,437,786       27,727,411       1,732,963       57,898,160  
Issuance of units to public
    28,750,000                   28,750,000  
 
                       
Balance at December 31, 2007
    57,187,786       27,727,411       1,732,963       86,648,160  
 
                               
Unit based compensation to non-employee directors
    21,101                   21,101  
Issuance of units to public
    873,000                   873,000  
Acquisition of additional interests in CIG and SNG
    26,888,611             566,563       27,455,174  
 
                       
Balance at December 31, 2008
    84,970,498       27,727,411       2,299,526       114,997,435  
 
                               
Unit-based compensation to non-employee directors (1)
    1,749                   1,749  
Issuance of units to public
    12,650,000             258,502       12,908,502  
 
                       
Balance at December 31, 2009
    97,622,247       27,727,411       2,558,028       127,907,686  
 
                       
 
(1)     Amount is net of 4,575 forfeited unvested restricted common units.
     Subsequent Event. In January 2010, we publicly issued 9,862,500 common units and issued 201,404 general partner units to El Paso for net proceeds of $236.1 million.

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4. Earnings Per Unit and Cash Distributions
     Earnings per unit. During the first quarter of 2009, we adopted an accounting standard, applied retrospectively to our earnings per unit, which changes the manner in which master limited partnerships calculate earnings per unit. This standard requires the calculation of earnings per unit based on actual distributions made to a master limited partnership’s unitholders, including the holders of incentive distribution rights, for the related reporting period. To the extent net income attributable to El Paso Pipeline Partners, L.P. exceeds cash distributions, the excess is allocated to unitholders based on their contractual participation rights to share in those earnings. If cash distributions exceed net income attributable to El Paso Pipeline Partners, L.P., the excess distributions are allocated proportionately to all participating units outstanding based on their respective ownership percentages. Additionally, under this standard, the calculation of earnings per unit does not reflect an allocation of undistributed earnings to the IDR holders beyond amounts distributable under the terms of the partnership agreement. Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit reported prior to the adoption of this standard was $1.22 per common and subordinated unit for the year ended December 31, 2008 and $0.13 per common unit and $0.09 per subordinated unit for the year ended December 31, 2007. Payments made to our unitholders are determined in relation to actual declared distributions, and are not based on the net income allocations used in the calculation of earnings per unit.
     As discussed in Note 2, we have retrospectively adjusted our historical financial statements for the consolidation of CIG following the acquisition of an additional 18 percent interest in CIG from El Paso on July 24, 2009. As a result of the retrospective consolidation of CIG, earnings prior to the acquisition of the incremental interests in CIG (“pre-acquisition earnings”) in historical periods have been allocated solely to our general partner in all periods presented. Accordingly, our allocation of pre-acquisition earnings to our general partner reflects 58 percent of CIG’s earnings prior to November 21, 2007, 48 percent of CIG’s earnings between November 21, 2007 and September 30, 2008 and 18 percent of CIG’s earnings between September 30, 2008 and July 24, 2009.
     Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit is computed by dividing the limited partners’ interest in net income attributable to El Paso Pipeline Partners, L.P. by the weighted average number of limited partner units outstanding. Diluted earnings per limited partner unit reflects the potential dilution that could occur if securities or other agreements to issue common units were exercised, settled or converted into common units. As of December 31, 2009 and 2008, we had 8,429 and 21,101 restricted units outstanding, a portion of which were dilutive for the years ended December 31, 2009 and 2008. No potentially dilutive securities existed as of December 31, 2007.
     The tables below show the (i) allocation of net income attributable to El Paso Pipeline Partners, L.P. and the (ii) net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit based on the number of basic and diluted limited partner units outstanding for the years ended December 31, 2009, 2008 and 2007.
     Allocation of Net Income Attributable to El Paso Pipeline Partners, L.P.
                         
    2009     2008     2007  
    (In Millions)  
Net income attributable to El Paso Pipeline Partners, L.P
  $ 213.5     $ 171.6     $ 127.9  
Less: CIG preacquisition earnings allocated to general partner subsequent to initial public offering
    (14.6 )     (57.1 )     (10.0 )
Earnings prior to initial public offering
                (108.0 )
 
                 
Income subject to 2% allocation of general partner interest
    198.9       114.5       9.9  
Less: General partner’s interest in net income attributable to El Paso Pipeline Partners, L.P
    (4.0 )     (2.3 )     (0.2 )
General partner’s incentive distribution
    (1.0 )            
 
                 
Limited partners’ interest in net income attributable to El Paso Pipeline Partners, L.P. — common and subordinated
  $ 193.9     $ 112.2     $ 9.7  
 
                 

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Net Income Attributable to El Paso Pipeline Partners, L.P. per Limited Partner Unit
                                                 
    2009     2008     2007  
    Common     Subordinated     Common     Subordinated     Common     Subordinated  
    (In millions, except for per unit amounts)  
Distributions (1)
  $ 132.7     $ 37.8     $ 86.0     $ 33.3     $ 7.3     $ 3.6  
Undistributed earnings (losses)
    18.0       5.4       (4.9 )     (2.2 )     (0.8 )     (0.4 )
 
                                   
Limited partners’ interest in net income attributable to El Paso Pipeline Partners, L.P.
  $ 150.7     $ 43.2     $ 81.1     $ 31.1     $ 6.5     $ 3.2  
 
                                   
 
                                               
Weighted average limited partner units outstanding — Basic and Diluted
    91.8       27.7       64.2       27.7       57.2       27.7  
 
                                               
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit — Basic and Diluted
  $ 1.64     $ 1.56     $ 1.26     $ 1.12     $ 0.11     $ 0.11  
 
(1)   Reflects distributions declared to our common and subordinated unitholders of $1.3650 per unit, $1.2025 per unit and $0.12813 per unit for the years ended December 31, 2009, 2008 and 2007.
     Subordinated units. All of the subordinated units are held by a wholly owned subsidiary of El Paso. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.28750 per common unit, which is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
     The subordination period will end and the subordinated units will convert to common units, on a one-for-one basis, on the first business day after we have earned and paid at least $0.43125 (150 percent of the minimum quarterly distribution) on each outstanding limited partner unit and general partner unit for each quarter in any four quarter period ending or after December 31, 2008, or on the first business day after we have earned and paid at least $0.28750 on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods ending on or after December 31, 2010. The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.
     Incentive distribution rights. The general partner holds incentive distribution rights in accordance with the partnership agreement. These rights pay an increasing percentage interest in quarterly distributions of cash based on the level of distribution to all unitholders. Additionally, our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. During the year ended December 31, 2009, our general partner received incentive distributions of $0.4 million. In February 2010, our general partner received incentive distributions of $0.6 million.

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     Cash Distributions to Unitholders. Our common and subordinated unitholders and general partner are entitled to receive quarterly distributions of available cash as defined in our partnership agreement. The table below shows the quarterly distributions to our unitholders and general partner (in millions, except for per unit amounts):
                                 
    Total Quarterly            
    Distribution Per   Total Cash   Date of   Date of
Quarters Ended   Unit   Distribution   Declaration   Distribution
2007
                               
December 31, 2007(1)
  $ 0.12813     $ 11.1     January 2008   February 2008
2008
                               
March 31, 2008
    0.28750       24.9     April 2008   May 2008
June 30, 2008
    0.29500       25.6     July 2008   August 2008
September 30, 2008
    0.30000       34.5     October 2008   November 2008
December 31, 2008
    0.32000       36.8     January 2009   February 2009
2009
                               
March 31, 2009
    0.32500       37.4     April 2009   May 2009
June 30, 2009
    0.33000       42.2     July 2009   August 2009
September 30, 2009
    0.35000       45.1     October 2009   November 2009
December 31, 2009
    0.36000       50.3     January 2010   February 2010
 
(1)   The December 31, 2007 distribution of $0.12813 per unit was prorated for the period beginning with the closing of our initial public offering through December 31, 2007.
     The distribution for the quarter ended December 31, 2009 was paid to all outstanding common and subordinated units on February 12, 2010 to unitholders of record at the close of business on February 1, 2010.
5. Regulatory Assets and Liabilities
     Our non-current regulatory assets and liabilities are included in other non-current assets and liabilities on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities as of December 31:
                 
    2009     2008  
    (In millions)  
Current regulatory assets
               
Difference between gas retained and consumed in operations
  $ 1.7     $ 26.3  
Other
    2.5       2.1  
 
           
Total current regulatory assets
    4.2       28.4  
 
           
Non-current regulatory assets
               
Taxes on capitalized funds used during construction
    17.7       18.2  
Unamortized loss on reacquired debt
    5.5       6.4  
Postretirement benefits
    1.4       2.2  
Other
    2.5       2.5  
 
           
Total non-current regulatory assets
    27.1       29.3  
 
           
Total regulatory assets
  $ 31.3     $ 57.7  
 
           
 
               
Current regulatory liabilities
               
Difference between gas retained and consumed in operations
  $ 14.7     $ 29.2  
 
           
Non-current regulatory liabilities
               
Property and plant depreciation
    17.8       19.0  
Postretirement benefits
    9.7       6.1  
Other
    0.2       0.3  
 
           
Total non-current regulatory liabilities
    27.7       25.4  
 
           
Total regulatory liabilities
  $ 42.4     $ 54.6  
 
           

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The significant regulatory assets and liabilities include:
     Difference between gas retained and gas consumed in operations: These amounts reflect the value of the volumetric difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent fuel filing periods.
     Taxes on capitalized funds used during construction: These regulatory asset balances were established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction are amortized and the offsetting deferred income taxes are included in the rate base. Both are recovered over the depreciable lives of the long lived asset to which they relate.
      Unamortized loss on reacquired debt: These amounts represent the deferred and unamortized portion of losses on reacquired debt which are not included in the rate base, but are expected to be recovered over the original life of the debt issue through the authorized rate of return.
     Postretirement Benefits: These balances represents deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plans and differences in the postretirement benefit related amounts expensed and the amounts recoverable in rates. Postretirement benefit amounts have been included in the rate base computations for CIG and are recoverable in such periods as the benefits are funded.
     Property and plant depreciation: Amount represents the deferral of customer-funded amounts for costs of future asset retirements. This amount is included in the rate base computations and the depreciation-related amounts are refunded over the lives of the long-lived assets to which they relate.

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6. Long-Term Debt and Other Financing Obligations
     Our long-term debt and other financing obligations are as follows:
                 
    As of December 31,  
    2009     2008  
    (in millions)  
El Paso Pipeline Partners, L.P.
               
Revolving credit facility, variable due 2012
  $ 520.0     $ 584.9  
Note payable to El Paso, variable due 2012, LIBOR plus 3.5%
    10.0       10.0  
Notes, variable due 2012, LIBOR plus 3.5%
    35.0       35.0  
Notes, 7.76%, due 2011
    37.0       37.0  
Notes, 7.93%, due 2012
    15.0       15.0  
Notes, 8.00%, due 2013
    88.0       88.0  
Colorado Interstate Gas Company
               
Senior Notes, 5.95%, due 2015
    35.0       35.0  
Senior Notes, 6.80%, due 2015
    339.9       339.9  
Senior Debentures, 6.85%, due 2037
    100.0       100.0  
 
           
Total long-term debt
    1,179.9       1,244.8  
Other financing obligations
    182.7       116.1  
 
           
Total long-term debt and other financing obligations
    1,362.6       1,360.9  
Less: Current maturities
    5.0       3.6  
 
           
Total long-term debt and other financing obligations, less current maturities
  $ 1,357.6     $ 1,357.3  
 
           
     Debt Maturities. Aggregate maturities of the principal amounts of long-term debt and other financing obligations as of December 31, 2009 for the next 5 years and in total thereafter are as follows (in millions):
         
2010
  $ 5.0  
2011
    42.0  
2012
    585.0  
2013
    93.0  
2014
    5.0  
Thereafter
    632.6  
 
     
Total long-term debt and other financing obligations
  $ 1,362.6  
 
     
     Credit Facility. In November 2007, we entered into an unsecured 5-year revolving credit facility (Credit Facility) with an initial aggregate borrowing capacity of up to $750 million expandable to $1.25 billion for certain expansion projects and acquisitions. Borrowings under the Credit Facility are guaranteed by certain of our subsidiaries. As of December 31, 2009 and 2008, we had $520.0 million and $584.9 million outstanding under our revolving credit facility. As of December 31, 2009, our remaining availability under the Credit Facility is approximately $215 million.
     The credit facility has two pricing grids, one based on credit ratings and the other based on leverage. As of December 31, 2009, the leverage pricing grid was in effect and our cost of borrowing was LIBOR plus 0.425 percent based on our leverage. We also pay an annual utilization and commitment fee of 0.225 percent. At December 31, 2009 and 2008, our all-in borrowing rates were 0.9 percent and 1.4 percent.
     The Credit Facility contains covenants and provisions that affect us, the borrowers and our other restricted subsidiaries, including, without limitation customary covenants and provisions:
    prohibiting the borrowers from creating or incurring indebtedness (except for certain specified permitted indebtedness) if such incurrence would cause a breach of the leverage ratio described below;
 
    prohibiting WIC from creating or incurring indebtedness in excess of $50 million (other than indebtedness under the Credit Facility);
 
    limiting our ability and that of the borrowers and our other restricted subsidiaries from creating or incurring certain liens on our respective properties (subject to enumerated exceptions);

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    limiting our ability to make distributions and equity repurchases (which shall be permitted if no insolvency default or event of default exists); and
 
    prohibiting consolidations, mergers and asset transfers by us, the borrowers and our other restricted subsidiaries (subject to enumerated exceptions).
     For the year ended December 31, 2009, we were in compliance with our debt-related covenants. The Credit Facility requires us to maintain, as of the end of each fiscal quarter, a consolidated leverage ratio (consolidated indebtedness to consolidated EBITDA (as defined in the Credit Facility)) of less than 5.00-to-1.00 for any four consecutive quarters; and 5.50-to-1.00 for any three consecutive quarters subsequent to the consummation of specified permitted acquisitions having a value greater than $25 million. We also have added additional flexibility to our covenants for growth projects. In case of a capital construction or expansion project in excess of $20 million, pro forma adjustments to consolidated EBITDA, approved by the lenders, may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments shall be limited to 25 percent of actual EBITDA.
     The Credit Facility contains certain customary events of default that affect us, the borrowers and our other restricted subsidiaries, including, without limitation, (i) nonpayment of principal when due or nonpayment of interest or other amounts within five business days of when due; (ii) bankruptcy or insolvency with respect to us, our general partner, the borrowers or any of our other restricted subsidiaries; (iii) judgment defaults against us, our general partner, the borrowers or any of our other restricted subsidiaries in excess of $50 million; or (iv) the failure of El Paso to directly or indirectly own a majority of the voting equity of our general partner and a failure by us to directly or indirectly own 100 percent of the equity of El Paso Pipeline Partners Operating Company, L.L.C.
     EPB Other Debt Obligations. In September 2008, we issued $175.0 million of senior unsecured notes and a $10.0 million note payable to El Paso as partial funding for the acquisition of additional interests in CIG and SNG as discussed in Note 2. Our restrictive covenants under these debt obligations are substantially the same as the restrictive covenants under our Credit Facility, with the exception of the requirement to maintain an interest coverage ratio (consolidated EBITDA (as defined in the Note Purchase Agreement) to interest expense) of greater than or equal to 1.50 to 1.00 for any four consecutive fiscal quarters.
     CIG Debt. In March 2009, CIG, Colorado Interstate Issuing Corporation (CIIC), El Paso and certain other El Paso subsidiaries filed a registration statement on Form S-3 under which CIG and CIIC may co-issue debt securities in the future. CIIC is a wholly owned finance subsidiary of CIG and is the co-issuer of CIG’s outstanding debt securities. CIIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of CIG’s debt securities. Accordingly, it has no ability to service obligations on CIG’s debt securities.
     For the year ended December 31, 2009, CIG was in compliance with its debt-related covenants. Under CIG’s various financing documents they are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions
     Other Financing Obligations. In June 2009 and November 2008, the Totem Gas Storage project and the High Plains pipeline were placed in service. Upon placing these projects in service, CIG transferred its title in the projects to WYCO Development LLC (WYCO), a joint venture with an affiliate of PSCo in which CIG has a 50 percent ownership interest. Although CIG transferred the title in these projects to WYCO, we continue to reflect the Totem Gas Storage facility and the High Plains Pipeline as property, plant and equipment in our financial statements as of December 31, 2009 due to CIG’s continuing involvement with the projects through WYCO.
     CIG constructed the Totem Gas Storage project and the High Plains pipeline and its joint venture partner in WYCO funded 50 percent of the construction costs of the projects, which we reflected as other non-current liabilities in our balance sheet during the construction period. Upon completion of the construction, CIG’s obligations to the affiliate of PSCo for these construction advances were converted into financing obligations to WYCO and accordingly, we reclassified the amounts from other non-current liabilities to debt and other financing obligations.

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     Totem Gas Storage financing obligation. The Totem Gas Storage obligation has a principal amount of $68.9 million as of December 31, 2009 and has monthly principal payments totaling $1.4 million each year through 2060. CIG also makes monthly interest payments on this obligation that are based on 50 percent of the operating results of the Totem Gas Storage facility, which is currently estimated at a 15.5% rate as of December 31, 2009.
     High Plains Pipeline financing obligation. The High Plains Pipeline obligation has a principal amount of $106.4 million as of December 31, 2009, and has monthly principal payments totaling $3.1 million each year through 2043. CIG also makes monthly interest payments on this obligation that are based on 50 percent of the operating results of the High Plains pipeline, which is currently estimated at a 15.5% rate as of December 31, 2009.
     Capital Lease. Effective December 1, 1999, WIC leased a compressor station under a capital lease from WYCO. The compressor station lease expires in November 2029. The total original capitalized cost of the lease was $12.0 million. As of December 31, 2009, we had a net book value of approximately $7.4 million related to this capital lease. Minimum future lease payments under the capital lease together with the present value of the net minimum lease payments as of December 31, 2009 are as follows:
         
Year Ending December 31,   (In millions)  
2010
  $ 1.3  
2011
    1.2  
2012
    1.1  
2013
    1.1  
2014
    1.0  
Thereafter
    7.9  
 
     
Total minimum lease payments
    13.6  
Less: amount representing interest
    (6.2 )
 
     
Present value of net minimum lease payments
  $ 7.4  
 
     
7. Fair Value of Financial Instruments
                                 
    As of December 31,
    2009   2008
    Carrying   Fair   Carrying   Fair
    Amount   Value   Amount   Value
    (In millions)
Long-term financing obligations, including current maturities
  $ 1,362.6     $ 1,374.7     $ 1,360.9     $ 1,126.3  
     As of December 31, 2009 and 2008, the carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables represented fair value because of the short-term nature of these instruments. At December 31, 2009 and 2008, we had notes receivable from El Paso of $93.2 million and $199.0 million due upon demand, with variable interest rates of 1.5% and 3.2%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of these notes receivable approximates their carrying value due to the market-based nature of the interest rate and the fact that they are demand notes. We estimate the fair value of our debt based on quoted market prices for the same or similar issues.
8. Commitments and Contingencies
Legal Proceedings
     WIC Line 124A Rupture. On November 11, 2006, a bulldozer driver ran into and ruptured WIC’s Line 124A near Cheyenne, Wyoming resulting in an explosion and fire, and the subsequent death of the driver. The driver was working for a construction company hired by Rockies Express Pipeline, LLC to construct its new pipeline in a corridor substantially parallel to WIC’s Line 124A. The Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) conducted an investigation into the incident, with which we fully cooperated. In March 2008, we received from PHMSA a Notice of Probable Violation with a proposed fine of $3.4 million. In October 2008, a hearing was held at which we contested the proposed fine. In December 2009, PHMSA issued its order, imposing a fine of $2.3 million, which has been paid.

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     Gas Measurement Cases. CIG and a number of its affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an order dismissing all claims against all defendants. In March 2009, the Tenth Circuit Court of Appeals affirmed the dismissals and in October 2009, the plaintiff’s appeal to the United States Supreme Court was denied.
     Similar allegations were filed in a second set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. The plaintiffs seek an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. In September 2009, the court denied the motions for class certification. The plaintiffs have filed a motion for reconsideration. CIG’s costs and legal exposure related to this lawsuit and claim are not currently determinable.
     In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2009, we had no accruals for our outstanding legal matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and establish accruals accordingly.
Environmental Matters
     We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2009, we had accrued approximately $10.8 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $35 million. Our accrual includes $7.7 million for environmental contingencies related to properties CIG previously owned. Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.
     Below is a reconciliation of our accrued liability from January 1, 2009 to December 31, 2009 (in millions):
         
Balance at January 1, 2009
  $ 13.3  
Additions/adjustments for remediation activities
    1.0  
Payments for remediation activities
    (3.5 )
 
     
Balance at December 31, 2009
  $ 10.8  
 
     
     For 2010, we estimate that our total remediation expenditures will be approximately $2.4 million, which will be expended under government directed clean-up plans.

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     It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.
Regulatory Matter
     Fuel Recovery Mechanism. During the first quarter of 2008, the FERC issued an order approving a fuel and related gas cost recovery mechanism for CIG which was designed to recover all cost impacts, or flow through to shippers any revenue impacts, of all fuel imbalance revaluations and related gas balance items. Effective April 2008, WIC implemented a similar fuel and related gas cost recovery mechanism, subject to the outcome of a FERC proceeding. The implementation of these mechanisms was protested by a limited number of shippers. On July 31, 2009 and October 1, 2009, the FERC issued orders to CIG and WIC, respectively, directing us to remove the cost and revenue components from our fuel recovery mechanisms while preserving the historic volumetric-based tracking mechanism. Due to these orders, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to fuel imbalance revaluations, their settlement, and other gas balance related items. We continue to explore options to minimize the price volatility associated with these operational activities. Our tariffs continue to provide that the difference between the quantity of fuel retained and fuel used in operations and lost and unaccounted for will be flowed-through or charged to shippers. These fuel trackers remove the impact of over or under collecting fuel and lost and unaccounted for from our operational gas costs
Other Commitments
     Capital Commitments. At December 31, 2009, we had capital commitments of $38.9 million related primarily to CIG’s Raton 2010 expansion project, the majority of which will be paid in 2010. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
     Transportation and Storage Commitments. We have entered into transportation commitments and storage capacity contracts totaling $176.6 million at December 31, 2009, of which $59.0 million is related to storage capacity contracts with our affiliate, Young Gas Storage Company, Ltd. Our annual commitments under these agreements are $21.1 million in 2010, $22.6 million in 2011, $28.4 million in 2012, $25.9 million in each of 2013 and 2014 and $52.7 million in total thereafter.
     Operating Leases. We lease property, facilities and equipment under various operating leases. Our minimum future annual rental commitments under our operating leases at December 31, 2009, are as follows:
         
Year Ending December 31,   (In millions)  
2010
  $ 2.2  
2011
    2.3  
2012
    2.3  
2013
    2.4  
2014
    2.4  
Thereafter
    0.6  
 
     
Total minimum lease payments
    12.2  
 
     
     Rental expense on our operating leases for each of the three years ended December 31, 2009, 2008 and 2007 was $2 million. These amounts include our share of rent allocated to us from El Paso.
     Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Currently, our obligations under these easements are not material to our results of operations.

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9. Retirement Benefits
     Pension and Retirement Savings Plans. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including CIG’s former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on its performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.
     Postretirement Benefits Plan. CIG provides postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. In addition, certain former CIG employees continue to receive limited postretirement life insurance benefits. CIG’s postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. CIG does not expect to make any contributions to the postretirement benefit plan in 2010.
     Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for CIG’s postretirement benefit plan, we record an asset or liability based on the over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $5 million from accumulated other comprehensive income to a regulatory liability.
     The table below provides information about CIG’s postretirement benefit plan. In 2008, we adopted the FASB’s revised measurement date provisions for other postretirement benefit plans and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008. For 2009, the information is presented and computed as of and for the twelve months ended December 31, 2009.
                 
    December 31,     December 31,  
    2009     2008  
    (In millions)  
Change in accumulated postretirement benefit obligation:
               
Accumulated postretirement benefit obligation — beginning of period
  $ 7.6     $ 7.3  
Interest cost
    0.4       0.5  
Participant contributions
    0.4       0.5  
Actuarial (gain) loss
    (2.3 )     0.8  
Benefits paid(1)
    (0.8 )     (1.5 )
 
           
Accumulated postretirement benefit obligation — end of period
  $ 5.3     $ 7.6  
 
           
 
               
Change in plan assets:
               
Fair value of plan assets — beginning of period
  $ 12.5     $ 18.0  
Actual return on plan assets
    2.0       (4.3 )
Participant contributions
    0.4       0.5  
Benefits paid
    (1.0 )     (1.7 )
 
           
Fair value of plan assets — end of period
  $ 13.9     $ 12.5  
 
           
 
               
Reconciliation of funded status:
               
Fair value of plan assets
  $ 13.9     $ 12.5  
Less: accumulated postretirement benefit obligation
    5.3       7.6  
 
           
Net asset at December 31
  $ 8.6     $ 4.9  
 
           
 
(1)   Amounts shown net of a subsidy of approximately $0.2 million for each of the years ended December 31, 2009 and 2008 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

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     Plan Assets. The primary investment objective of CIG’s plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from the targeted allocations, the target allocations of CIG’s postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. The plan’s assets may be invested in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.
     We use various methods to determine the fair values of the assets in CIG’s other postretirement benefit plans, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate CIG’s plan’s assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2009, the assets are comprised of an exchange-traded mutual fund with a fair value of $1.2 million and common/collective trusts with a fair value of $12.7 million. The exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. The common/collective trusts are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. We may adjust the fair value of the common/collective trusts, when necessary, for factors such as liquidity or risk of nonperformance by the issuer. CIG’s plan does not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that many not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2009 and 2008.
     Expected Payment of Future Benefits. As of December 31, 2009, we expect the following benefit payments under CIG’s plan (in millions):
         
Year Ending   Expected
December 31,   Payments(1)
2010
  $ 0.7  
2011
    0.7  
2012
    0.6  
2013
    0.6  
2014
    0.5  
2015 - 2019
    2.0  
 
(1)   Includes a reduction of approximately $0.2 million in each of the years 2010 - 2014 and approximately $0.8 million in aggregate for 2015 – 2019 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
     Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining CIG’s postretirement plan obligations and net benefit costs for 2009, 2008 and 2007:
                         
    2009   2008   2007
    (Percent)
Assumptions related to benefit obligations at December 31, 2009 and 2008 and September 30, 2007 measurement dates:
                       
Discount rate
    5.06       5.82       6.05  
Assumptions related to benefit costs at December 31:
                       
Discount rate
    5.82       6.05       5.50  
Expected return on plan assets(1)
    8.00       8.00       8.00  
 
(1)   The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. CIG’s postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for CIG’s postretirement benefit plan is calculated using the after-tax rate of return.

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     Actuarial estimates for CIG’s postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 8.0 percent, gradually decreasing to 5.0 percent by the year 2015. Changes in the assumed health care cost trends do not have a material impact on the amounts reported for CIG’s interest costs or CIG’s accumulated postretirement benefit obligations as of and for the years ended December 31, 2009 and 2008.
     Components of Net Benefit Income. For each of the years ended December 31, the components of net benefit income are as follows:
                         
    2009     2008     2007  
    (In millions)  
Interest cost
  $ 0.4     $ 0.4     $ 0.6  
Expected return on plan assets
    (0.6 )     (0.9 )     (0.9 )
Other
    (0.3 )     (0.7 )     (0.5 )
 
                 
Net postretirement benefit income
  $ (0.5 )   $ (1.2 )   $ (0.8 )
 
                 
10. Transactions with Major Customers
     The following table shows revenues from major customers for each of the three years ended December 31:
                         
    2009   2008   2007
    (In millions)
PSCo
  $ 156.1     $ 92.4     $ 93.7  
Anadarko Petroleum Corporation and Subsidiaries
    70.6       62.6       39.5  
Williams Gas Marketing, Inc.
    62.8       41.9       46.3  
11. Supplemental Cash Flow Information
     The following table contains supplemental cash flow information from continuing operations for each of the three years ended December 31:
                         
    2009   2008   2007
    (In millions)
Interest paid, net of capitalized amounts
  $ 71.5     $ 56.1     $ 60.5  
Income tax payments
                277.0 (1)
 
(1)   Includes amounts related to the settlement of current and deferred tax balances due to CIG’s conversion to a partnership in November 2007 (see Note 12).
12. Investments in Unconsolidated Affiliates and Transactions with Affiliates
Investments in Unconsolidated Affiliates
     SNG. In conjunction with our initial public offering of common units in November 2007, El Paso contributed to us, at their historical cost, a 10 percent general partner interest in SNG. On September 30, 2008, we acquired an additional 15 percent general partner interest in SNG from El Paso, as further discussed in Note 2. Our proportionate share of the operating results of SNG has been reflected as earnings from unconsolidated affiliates in our financial statements since the date the respective interests were contributed to us. We account for our investment in SNG using the equity method of accounting.
     WYCO. CIG has a 50 percent investment in WYCO which we account for using the equity method of accounting. WYCO owns the High Plains pipeline (a FERC-regulated pipeline), the Totem Gas Storage facility (a FERC-regulated storage facility), a state regulated intrastate pipeline and a compressor station. CIG has other financing obligations payable to WYCO totaling $175.3 million and $108.2 million as of December 31, 2009 and 2008, which are described further in Note 6.

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     The information below related to our unconsolidated affiliates reflects our net investment and earnings we recorded from these investments and summarized financial information of our proportionate share of SNG.
Net Investment and Earnings
                                         
                    Earnings from  
    Investment     Unconsolidated Affiliates  
    December 31,     December 31,     Year Ended December 31,  
    2009     2008     2009     2008     2007(1)  
    (In millions)     (In millions)  
SNG
  $ 403.4     $ 393.8     $ 52.5     $ 29.8     $ 2.6  
Other
    14.1       17.0       0.9       3.1       1.5  
 
                             
Total
  $ 417.5     $ 410.8     $ 53.4     $ 32.9     $ 4.1  
 
                             
SNG Summarized Financial Information
Results of operations
                         
    Year Ended December 31,  
    2009     2008     2007(1)  
    (In millions)  
Operating results data:
                       
Operating revenues
  $ 127.4     $ 73.3     $ 5.9  
Operating expenses
    63.6       38.1       2.6  
Income from continuing operations and net income
  $ 52.5     $ 29.8     $ 2.6  
 
(1)   Amounts for 2007 are calculated from the date of the initial public offering to December 31, 2007.
Financial position data
                 
    December 31,     December 31,  
    2009     2008  
    (In millions)  
Current assets
  $ 23.5     $ 26.3  
Non-current assets
    640.7       630.9  
Current liabilities
    26.6       23.0  
Long-term debt
    227.4       227.4  
Other non-current liabilities
    6.8       13.0  
 
           
Net assets
  $ 403.4     $ 393.8  
 
           
Transactions with Affiliates
     Distributions/Contributions. As further discussed in Note 1, in conjunction with our initial public offering in November 2007, 10 percent interests in CIG and SNG were contributed to us at their book value of $253 million and we made distributions to El Paso and its subsidiaries of $737 million using proceeds from the initial public offering and borrowings under our credit facility. In addition, we repaid affiliated notes payable with El Paso of $225 million. We also made additional distributions to El Paso of $11 million in November 2007.
     Distributions Received from SNG. SNG is required to make distributions of available cash as defined in their partnership agreement on a quarterly basis to their partners, including us. We received cash distributions from SNG of $42.9 and $26.1 million during the years ended December 31, 2009 and 2008, with the 2008 distribution including $4.3 million of returns of capital from our investments. In January 2010, we received distributions from SNG of $20.7 million.

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     CIG Distributions to El Paso
     CIG Cash Distributions to El Paso. CIG is required to make distributions of available cash as defined in their partnership agreement on a quarterly basis to their partners, including us. Due to the retrospective consolidation of CIG, we have reflected 42 percent of CIG’s historical distributions paid to El Paso as distributions to its noncontrolling interest holder in our financial statements in all periods presented. CIG’s remaining historical distributions (excluding distributions paid to its noncontrolling interest holder) are reflected as distributions of pre-acquisition earnings and are allocated to our general partner. The following table shows CIG’s cash distributions to El Paso:
                 
    Year Ended December 31,  
    2009     2008  
    (In millions)  
Distributions to noncontrolling interest holder
  $ 60.7     $ 45.6  
Distributions of pre-acquisition earnings
    15.0       43.7  
 
           
Cash distributions to El Paso
  $ 75.7     $ 89.3  
 
           
     In January 2010, CIG paid cash distributions of $18.5 million to El Paso.
     CIG Non-Cash Distribution to El Paso. Prior to our acquisition of an additional 30 percent ownership interest in CIG on September 30, 2008, CIG distributed a portion of its notes receivable under its cash management program to its partners (including us). Approximately $270 million of this distribution was made to El Paso, which is reflected as a non-cash distribution to El Paso in our financial statements.
     Affiliate Revenues and Expenses. We entered into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to and from affiliates under long-term contracts and various operating agreements. CIG also contracts with an affiliate to process natural gas and sell extracted natural gas liquids.
     We do not have employees. Following our reorganization in November 2007, our former employees continue to provide services to us through an affiliated service company owned by our general partner, El Paso. We are managed and operated by officers of El Paso, our general partner. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are allocated costs from El Paso Natural Gas Company and Tennessee Gas Pipeline Company, our affiliates, associated with our pipeline services. We also allocate costs to Cheyenne Plains Gas Pipeline, our affiliate, for their share of our pipeline services. The allocations from El Paso and TGP are based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll.
     We also have entered into various operating and management agreements with El Paso related to the operation of our assets. The table below shows our affiliate revenues and expenses for the years ended December 31, 2009, 2008 and 2007.
                         
    Year Ended December 31,
    2009   2008   2007
    (in millions)
Revenues from affiliates
  $ 16.1     $ 21.9     $ 19.2  
Operation and maintenance expense from affiliates
    88.7       80.7       51.1  
Reimbursement of operating expenses charged to affiliates
    12.0       11.9       9.8  

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     Cash Management Program. Prior to our July 24, 2009 acquisition of an additional 18 percent interest in CIG, CIG participated in El Paso’s cash management program, which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. At December 31, 2009 and 2008, CIG had a note receivable from El Paso of $73.0 million and $178.8 million. We classified $73.0 million and $102.9 million of this receivable as current on our balance sheets at December 31, 2009 and 2008, based on the net amount CIG anticipates using in the next twelve months considering available cash sources and needs. The interest rate on our note at December 31, 2009 and 2008 was 1.5% and 3.2%.
     Notes Receivable and Payable with Affiliates. Prior to the acquisition of additional ownership interests in CIG and SNG, in September 2008, we received a non-cash distribution of $30.0 million from CIG in the form of a note receivable from El Paso. As of December 31, 2009 and 2008 we had $20.2 million remaining on our note receivable from El Paso. This note is due upon demand and was classified as current on our balance sheet. The interest rate on this variable rate loan was 1.5% and 3.2% at December 31, 2009 and 2008. As partial funding for the acquisition, we also issued a note payable to El Paso of $10.0 million. For a further discussion of the note payable, see Note 2 and Note 6.
     Income Taxes. Effective November 1, 2007, CIG converted into a general partnership as discussed in Note 1 and settled its existing current and deferred tax balances of approximately $216.4 million pursuant to its tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program. During 2007, CIG also settled $8.8 million with El Paso through its cash management program for certain tax attributes previously reflected as deferred income taxes in our financial statements. These settlements are reflected as operating activities in our statement of cash flows.
     Accounts Receivable Sales Program. CIG sells certain accounts receivable to a QSPE whose purpose is solely to invest in their receivables, which are short-term assets that generally settle within 60 days. During the years ended December 31, 2009 and 2008, CIG received net proceeds of approximately $0.4 billion and $0.3 billion related to sales of receivables to the QSPE and changes in our subordinated beneficial interests and recognized losses of $0.4 million and $0.6 million on these transactions. As of December 31, 2009 and 2008, CIG had approximately $37.2 million and $29.0 million of receivables outstanding with the QSPE, for which they received cash of $20.0 million in both periods and received subordinated beneficial interests of approximately $16.8 million and $8.4 million. The QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $20.4 million and $20.6 million as of December 31, 2009 and 2008. We reflect the subordinated beneficial interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections) are recorded as accounts receivable from affiliate in our balance sheets. Our ability to recover our carrying value of our subordinated beneficial interests is based on the collectability of the underlying receivables sold to the QSPE. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the accounts receivable and performing all administrative duties for the QSPE which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2009 and 2008.
     In January 2010, CIG ceased selling its accounts receivable to the QSPEs and began selling the receivables directly to the third party financial institution. In return, the third party financial institution pays a certain amount of cash up front for the receivables, and pays the remaining amount owed over time as cash is collected from the receivables.
     Other Affiliate Balances. We had net contractual, gas imbalance, and trade payables, as well as other liabilities with our affiliates arising in the ordinary course of business of approximately $26.9 million and $10.2 million at December 31, 2009 and 2008. Prior to November 2007, WIC participated in El Paso’s cash management program to settle intercompany transactions between participating affiliates. At December 31, 2009 and 2008, we had contractual deposits from our affiliates of $6.7 million and $6.4 million included in other current liabilities on our balance sheet.
     WIC leases a compressor station from CIG’s unconsolidated affiliate, WYCO, and made lease payments to WYCO of $1.3 million, $1.4 million and $1.5 million for the years ended December 31, 2009, 2008 and 2007.
      Indemnification. In connection with our initial public offering, El Paso indemnified us for three years against certain potential environmental and toxic tort claims, losses and expenses associated with the business conducted by WIC, CIG and SNG or the operations of their assets occurring before the closing date of our initial public offering. The maximum liability of El Paso for this indemnification obligation will not exceed $15 million.

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13. Income Taxes
     In conjunction with our formation, CIG converted its legal structure into a general partnership effective November 1, 2007 and settled its current and deferred tax balances pursuant to its tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program. The tables below reflect that these balances have been settled and that CIG no longer pays income taxes effective November 1, 2007.
     Components of Income Taxes. The following table reflects the components of income taxes included in income from continuing operations for the year ended December 31, 2007:
         
    2007  
    (In millions)  
Current
       
Federal
  $ 32.7  
State
    3.7  
 
     
 
    36.4  
 
     
 
       
Deferred
       
Federal
    6.9  
State
    0.8  
 
     
 
    7.7  
 
     
Total income taxes
  $ 44.1  
 
     
     Effective Tax Rate Reconciliation. CIG’s income taxes, included in income from continuing operations, differ from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for the year ended December 31, 2007:
         
    2007  
    (In millions,  
    except for rates)  
Income taxes at the statutory federal rate of 35%
  $ 74.7  
Increase (decrease)
       
Pretax income not subject to income taxes after conversion to partnership
    (11.9 )
State income taxes, net of federal income tax benefit
    3.1  
Income associated with non-taxable entities
    (21.8 )
 
     
Income tax expense
  $ 44.1  
 
     
Effective tax rate
    21 %
 
     

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14. Supplemental Selected Quarterly Financial Information (Unaudited)
     Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.
                                         
    Quarters Ended   Year to
    March 31   June 30   September 30   December 31 (1)   Date
    (in millions, except per unit amounts)
2009
                                       
Operating revenues
  $ 135.3     $ 122.4     $ 128.8     $ 151.1     $ 537.6  
Operating income
    72.8       64.5       67.0       88.2       292.5  
Earnings from unconsolidated affiliates
    12.8       12.3       11.9       16.4       53.4  
Net income
    70.8       62.5       60.3       85.9       279.5  
Net income attributable to noncontrolling interests
    (17.4 )     (13.6 )     (13.7 )     (21.3 )     (66.0 )
Net income attributable to El Paso Pipeline Partners, L.P.
    53.4       48.9       46.6       64.6       213.5  
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit-
                                       
Basic and Diluted
                                       
Common
    0.40       0.38       0.35       0.51       1.64  
Subordinated
    0.40       0.34       0.35       0.47       1.56  
2008
                                       
Operating revenues
  $ 121.8     $ 106.6     $ 103.3     $ 125.5     $ 457.2  
Operating income
    68.3       45.8       43.3       72.4       229.8  
Earnings from unconsolidated affiliates(2)
    9.6       5.6       4.8       12.9       32.9  
Net income
    72.5       46.2       43.9       71.4       234.0  
Net income attributable to noncontrolling interests
    (21.3 )     (10.5 )     (10.7 )     (19.9 )     (62.4 )
Net income attributable to El Paso Pipeline Partners, L.P.
    51.2       35.7       33.2       51.5       171.6  
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit-
                                       
Basic and Diluted
                                       
Common
    0.31       0.27       0.29       0.37       1.26  
Subordinated
    0.31       0.27       0.14       0.37       1.12  
 
(1)   The quarter ended December 31, 2009 includes a gain of $7.8 million related to the sale of the Natural Buttes compressor station and gas processing plant (see Note 2).
 
(2)   We acquired an additional 15 percent interest in SNG from El Paso on September 30, 2008.

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SCHEDULE II
EL PASO PIPELINE PARTNERS, L.P.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2009, 2008 and 2007
(In millions)
                                         
    Balance at   Charged to           Charged to   Balance
    Beginning   Costs and           Other   at End
Description   of Period   Expenses   Deductions   Accounts   of Period
2009
                                       
Allowance for doubtful accounts
  $ 0.5     $ (0.2 )   $     $ (0.3 )   $  
Legal reserves
    1.2       1.1       (2.3 )            
Environmental reserves
    13.3       1.0       (3.5 )           10.8  
 
                                       
2008
                                       
Allowance for doubtful accounts
  $ 1.1     $ (0.7 )   $     $ 0.1     $ 0.5  
Legal reserves
          1.2                   1.2  
Environmental reserves
    14.9       1.5       (3.1 )           13.3  
 
                                       
2007
                                       
Allowance for doubtful accounts
  $ 0.9     $ 0.1     $     $ 0.1     $ 1.1  
Legal reserves
          3.1       (3.1 )            
Environmental reserves
    17.1       0.9       (3.1 )           14.9  

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ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
     None.
ITEM 9A.   CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
     As of December 31, 2009, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of our general partner, as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of El Paso’s disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including the CEO and CFO of our general partner, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and the CEO and CFO of our general partner have concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2009. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.
Changes in Internal Control over Financial Reporting
     There were no changes in our internal control over financial reporting during the fourth quarter of 2009 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B.   OTHER INFORMATION
     None.

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PART III
ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Partnership Management
     El Paso Pipeline GP Company, L.L.C., our general partner, manages our operations and activities. Our general partner and its board of directors are not elected by our unitholders and are not subject to re-election on a regular basis. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.
     The directors of our general partner oversee our operations. We presently have seven directors, three of whom are independent as defined under the independence standards established by the New York Stock Exchange and under our corporate governance guidelines. El Paso appoints all members to the board of directors of our general partner. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and governance committee. However, the board of our general partner has a standing audit committee, described below.
     The independent board members comprise all of the members of the audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee. The members of the audit committee also serve as a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.
     We do not directly employ any of the persons responsible for our management or operation. Rather, El Paso personnel manage and operate our business. Officers of our general partner, who are also officers of El Paso, manage the day-to-day affairs of our business and conduct our operations. We also utilize a significant number of employees of El Paso to operate our business and provide us with general and administrative services. We reimburse El Paso for allocated expenses of operational personnel who perform services for our benefit and we reimburse El Paso for allocated general and administrative expenses.
     In order to maximize operational flexibility, we conduct our operations through subsidiaries. We have one direct operating subsidiary, El Paso Pipeline Partners Operating Company, L.L.C., a limited liability company that conducts business through itself and its subsidiaries.

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Directors and Executive Officers of Our General Partner
     The following table sets forth information with respect to the directors and executive officers of our general partner as of February 26, 2010.
             
Name   Age   Position with El Paso Pipeline GP Company, L.L.C.
Ronald L. Kuehn, Jr
    74     Chairman of the Board
James C. Yardley
    58     Director, President and Chief Executive Officer
John R. Sult
    50     Director, Senior Vice President and Chief Financial Officer
Robert W. Baker
    53     Executive Vice President and General Counsel
James J. Cleary
    55     Senior Vice President
Daniel B. Martin
    53     Senior Vice President
Norman G. Holmes
    53     Senior Vice President
Douglas L. Foshee
    50     Director
D. Mark Leland
    48     Director
Arthur C. Reichstetter
    63     Director
William A. Smith
    65     Director
     Ronald L. Kuehn, Jr. Mr. Kuehn has been Chairman of the Board of El Paso Pipeline GP Company, L.L.C. since August 2007. Mr. Kuehn previously served as Chairman of the Board of Directors for El Paso from March 2003 to May 2009 and Interim Chief Executive Officer from March 2003 to September 2003. From September 2002 to March 2003, Mr. Kuehn served as Lead Director of El Paso. From January 2001 to March 2003, he was a business consultant. Mr. Kuehn served as non-executive Chairman of the Board of El Paso from October 1999 to December 2000. Mr. Kuehn previously served as Chairman of the Board of Sonat Inc. from April 1986 and President and Chief Executive Officer from June 1984 until his retirement in October 1999. Mr. Kuehn formerly served on the Board of Directors of Praxair, Inc. until 2008, Dun & Bradstreet Corporation until 2007 and Regions Financial Corporation until 2007.
     James C. Yardley. Mr. Yardley has been Director, President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President of El Paso with responsibility for the regulated pipeline business unit since August 2006. He has served as President of Tennessee Gas Pipeline since February 2007 and Chairman of the Board since August 2006. Mr. Yardley has been Chairman of El Paso Natural Gas Company since August 2006 and has served as President of Southern Natural Gas Company since May 1998. Mr. Yardley has been a member of the Management Committees of both Colorado Interstate Gas Company and Southern Natural Gas Company since their conversion to general partnerships in November 2007. Mr. Yardley is currently a member of the board of directors of Scorpion Offshore Ltd. He also serves on the Board of Interstate Natural Gas Association of America and previously served as its Chairman.
     John R. Sult. Mr. Sult has been a Director of El Paso Pipeline GP Company, L.L.C. since June 2009. He has served as Senior Vice President and Chief Financial Officer of El Paso Pipeline GP Company, L.L.C. since November 2009 and served as Senior Vice President, Chief Financial Officer and Controller from August 2007 to November 2009. Mr. Sult has been Senior Vice President and Chief Financial Officer of El Paso since November 2009 and previously served as Senior Vice President and Controller from November 2005 to November 2009. He served as Senior Vice President, Chief Financial Officer and Controller of El Paso’s Pipeline Group from November 2005 to November 2009. Mr. Sult was Vice President and Controller for Halliburton Energy Services from August 2004 to October 2005.
     Robert W. Baker. Mr. Baker has been Executive Vice President and General Counsel of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President and General Counsel of El Paso since January 2004. From February 2003 to December 2003, he served as Executive Vice President of El Paso and President of El Paso Merchant Energy. Mr. Baker previously served as Senior Vice President and Deputy General Counsel of El Paso from January 2002 to February 2003.

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     James J. Cleary. Mr. Cleary has been Senior Vice President of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been a director and President of El Paso Natural Gas Company since January 2004. Mr. Cleary has been a member of the Management Committee of Colorado Interstate Gas Company since November 2007 and President since January 2004. He previously served as Chairman of the Board of both El Paso Natural Gas Company and Colorado Interstate Gas Company from May 2005 to August 2006. From January 2001 to December 2003, he served as President of ANR Pipeline Company.
     Daniel B. Martin. Mr. Martin has been Senior Vice President of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been a member of the Management Committees of both Colorado Interstate Gas Company and Southern Natural Gas Company since November 2007. Mr. Martin has been a director of El Paso Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. He previously served as a director of Colorado Interstate Gas Company and Southern Natural Gas Company from May 2005 to November 2007. Mr. Martin has been Senior Vice President of Colorado Interstate Gas Company since January 2001, Senior Vice President of Southern Natural Gas Company and Tennessee Gas Pipeline Company since June 2000 and Senior Vice President of Southern Natural Gas Company since February 2000. He served as a director of ANR Pipeline Company from May 2005 through February 2007 and Senior Vice President of ANR Pipeline Company from January 2001 to February 2007.
     Norman G. Holmes. Mr. Holmes has been Senior Vice President of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Senior Vice President and Chief Commercial Officer since August 2006. He previously served as a director of Southern Natural Gas Company from November 2005 to November 2007. Mr. Holmes served as Vice President, Business Development of Southern Natural Gas Company from 1999 to 2006.
     Douglas L. Foshee. Mr. Foshee has been a Director of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Chairman of the Board of El Paso since May 2009 and President, Chief Executive Officer and a director of El Paso since September 2003. Prior to joining El Paso, Mr. Foshee served as Executive Vice President and Chief Operating Officer of Halliburton Company having joined that company in 2001 as Executive Vice President and Chief Financial Officer. Several subsidiaries of Halliburton, including DII Industries and Kellogg Brown & Root, commenced prepackaged Chapter 11 proceedings to discharge current and future asbestos and silica personal injury claims in December 2003 and an order confirming a plan of reorganization became final effective December 31, 2004. Prior to assuming his position at Halliburton, Mr. Foshee served as President, Chief Executive Officer and Chairman of the Board of Nuevo Energy Company and Chief Executive Officer and Chief Operating Officer of Torch Energy Advisors Inc. Mr. Foshee presently serves as a director of Cameron International Corporation and is a trustee of AIG Credit Facility Trust. Mr. Foshee serves as Chairman of the Federal Reserve Bank of Dallas, Houston Branch. Mr. Foshee also serves on the Board of Trustees of Rice University and serves as a member of the Council of Overseers for the Jesse H. Jones Graduate School of Management. He is a member of various civic and community organizations.
     D. Mark Leland. Mr. Leland has been a Director of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President of El Paso and President of El Paso’s Midstream business unit since October 2009. Mr. Leland previously served as Executive Vice President and Chief Financial Officer of El Paso from August 2005 to November 2009. Mr. Leland served as Executive Vice President of El Paso Exploration & Production Company from January 2004 to August 2005, and as Chief Financial Officer and a director from April 2004 to August 2005. He served as Senior Vice President and chief operating officer of GulfTerra Energy Partners, L.P. and its general partner from January 2003 to December 2003, as Senior Vice President and Controller from July 2000 to January 2003, and as Vice President from August 1998 to July 2000.

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     Arthur C. Reichstetter. Mr. Reichstetter has been a Director of El Paso Pipeline GP Company, L.L.C. since November 2007. He has been a private investment manager since 2007. Mr. Reichstetter had been Managing Director of Lazard Freres from April 2002 until his retirement in June 2007. From February 1998 to January 2002, Mr. Reichstetter was a Managing Director with Dresdner Kleinwort Wasserstein, formerly Wasserstein Parella & Co. Mr. Reichstetter was a Managing Director with Merrill Lynch from March 1993 until his retirement in February 1996. Prior to that time, Mr. Reichstetter worked as an investment banker at The First Boston Corporation from 1974 until 1993, in various positions becoming a managing director with that company in 1982.
     William A. Smith. Mr. Smith has been a Director of El Paso Pipeline GP Company, L.L.C. since May 2008. Mr. Smith is Managing Director and partner in Galway Group, L.P., an investment banking/energy advisory firm headquartered in Houston, TX. In 2002, Mr. Smith retired from El Paso Corporation, where he was an Executive Vice President and Chairman of El Paso Merchant Energy’s Global Gas Group. Mr. Smith had a 29 year career with Sonat Inc. prior to its merger with El Paso in 1999. At the time of the merger, Mr. Smith was Executive Vice President and General Counsel. He previously served as Chairman and President of Southern Natural Gas Company and as Vice Chairman of Sonat Exploration Company. Mr. Smith is currently a director of Eagle Rock Energy G&P LLC, a midstream/upstream master limited partnership and serves on that company’s audit committee. Mr. Smith previously served on the Board of Directors of Maritrans Inc. until 2006.
     Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
Audit Committee
     The board of directors of our general partner has a standing audit committee. All of the members are independent as defined under the independence standards established by the New York Stock Exchange. The audit committee is presently comprised of Messrs. Kuehn, Reichstetter and Smith. The audit committee plays an important role in promoting effective accounting, financial reporting, risk management and compliance procedures and controls. Each member of the audit committee meets the financial literacy standard required by the New York Stock Exchange rules and at least one member qualifies as having accounting or related financial management expertise. The board of directors of our general partner has affirmatively determined that Mr. Reichstetter satisfies the definition of “audit committee financial expert,” as defined by SEC rules, and has designated him as an “audit committee financial expert.”
Corporate Governance Guidelines and Code of Ethics
     Our Corporate Governance Guidelines, provide the framework for the effective governance of our partnership. We adopted the Corporate Governance Guidelines, which apply to the board of directors of our general partner, as well as to persons performing services to us, to address matters including qualifications for directors, standards for independence of directors, responsibilities of directors, limitation on serving on other boards/committees, the composition and responsibility of committees, conduct and minimum frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, equity ownership guidelines, director orientation and continuing education, and annual self-evaluation of the board, its committees and directors. The board of directors of our general partner recognizes that effective corporate governance is an on-going process, and the board will review and revise as necessary our Corporate Governance Guidelines annually, or more frequently if deemed necessary. Our Corporate Governance Guidelines may be found on our website at www.eppipelinepartners.com.

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     We also adopted a code of ethics, referred to as our “Code of Business Conduct,” that applies to all directors and employees of our general partner, including its Chief Executive Officer, Chief Financial Officer and senior financial and accounting officers, as well as all El Paso employees working on behalf of us or our general partner. The Code of Business Conduct is a value-based code that is built on five core values: stewardship, integrity, safety, accountability and excellence. In addition to other matters, the Code of Business Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of Business Conduct. A copy of the Code of Business Conduct is available on our website at www.eppipelinepartners.com. We will post on our internet website all waivers to or amendments of the Code of Business Conduct, which are required to be disclosed by applicable law and the New York Stock Exchange listing standards. Currently, we do not have nor do we anticipate any waivers of or amendments to the Code of Business Conduct. We believe the Code of Business Conduct exceeds the requirements set forth in the applicable SEC regulations and the corporate governance rules of the New York Stock Exchange.
Executive Sessions of the Board and Communications by Interested Parties
     As set forth in our Corporate Governance Guidelines and in accordance with NYSE listing standards, the board of directors of our general partner holds executive sessions on a regular basis without management present. Mr. Ronald L. Kuehn, Jr., our independent chairman of the board, presides over all executive sessions of the board.
     The board of directors of our general partner has established a process for interested parties to communicate with the board or any individual member thereof. Such communications should be in writing, addressed to the board or an individual director, c/o Ms. Marguerite Woung-Chapman, Corporate Secretary, P.O. Box 2511, Houston, TX 77252. The corporate secretary will forward such correspondence to the addressee.
Web Access
     We provide access through our website to current information related to corporate governance, including a copy of the charter of the audit committee of the board, our Corporate Governance Guidelines, our Code of Business Conduct, biographical information concerning each director, and other matters regarding our corporate governance principles. We also provide access through our website to all filing submitted by El Paso Pipeline Partners, L.P. to the SEC. Our website is www.eppipelinepartners.com, and access to this information is free of charge to the user (except for any internet provider or telephone charges).
Reimbursement of Expenses of Our General Partner
     Our general partner does not receive any management fee or other compensation for its management of our partnership under the omnibus agreement with El Paso or otherwise. Under the terms of the omnibus agreement, we reimburse El Paso for the provision of various general and administrative services for our benefit. We also reimburse El Paso for direct expenses incurred on our behalf and expenses allocated to us as a result of our becoming a public entity. The partnership agreement provides that our general partner determines the expenses that are allocable to us.
Section 16(a) Beneficial Ownership Reporting Compliance
     Section 16(a) of the Securities Exchange Act of 1934, as amended, requires executive officers and directors of our general partner and persons who beneficially own more than 10 percent of a registered class of our equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies of all such reports. Based solely upon a review of the copies of the reports received by us, we believe that all such filing requirements were satisfied during 2009.

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ITEM 11.   EXECUTIVE COMPENSATION
     The executive officers of our general partner are also executive officers of El Paso or one of its pipeline subsidiaries. The compensation of the executive officers of our general partner is set by El Paso, and we have no control over the compensation determination process. The officers and employees of our general partner participate in employee benefit plans and arrangements sponsored by El Paso. Other than the Long-Term Incentive Plan described below, neither we nor our general partner have established any employee benefit plans and our general partner has not entered into employment agreements with any of its officers.
Compensation Discussion and Analysis
     We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, El Paso Pipeline GP Company, L.L.C., the executive officers of which are employees of El Paso. El Paso Pipeline GP Company, L.L.C. entered into the omnibus agreement with El Paso, pursuant to which, among other matters:
    El Paso makes available to El Paso Pipeline GP Company, L.L.C. the services of the El Paso employees who serve as the executive officers of El Paso Pipeline GP Company, L.L.C.; and
 
    El Paso Pipeline GP Company, L.L.C. is obligated to reimburse El Paso for any allocated portion of the costs that El Paso incurs in providing compensation and benefits to such El Paso employees.
     Although we bear an allocated portion of El Paso’s costs of providing compensation and benefits to the El Paso employees who serve as the executive officers of our general partner, we have no control over such costs and cannot establish or direct the compensation policies or practices of El Paso. Each of these executive officers performs services for our general partner, as well as El Paso and its affiliates.
     We bore substantially less than a majority of El Paso’s costs of providing compensation and benefits to the Chief Executive Officer of our general partner (the principal executive officer), and the Chief Financial Officer of our general partner (the principal financial officer) during 2009.
     Our general partner has adopted the El Paso Pipeline GP Company, L.L.C. Long-Term Incentive Plan, or LTIP, under which equity awards of our partnership may be granted. At this point in time, we do not anticipate that the officers and employees of our general partner (including those that also serve as directors of the general partner) will receive any grants under the LTIP. As indicated above, the compensation of such officers and employees shall be pursuant to El Paso’s incentive plans and reimbursed by us pursuant to the omnibus agreement. Non-employee directors of our general partner receive equity grants under the LTIP, as described below.
Long-Term Incentive Plan
     The LTIP was designed to promote the interests of our partnership by providing to employees, consultants, and directors of our general partner and employees and consultants of its affiliates who perform services for us or on our behalf incentive compensation awards for superior performance that are based on our common units. Employees, directors, and consultants of our general partner or an affiliate who perform services for us and who are selected from time to time by the board of our general partner may be granted awards under the LTIP.

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     The LTIP is administered by the board of our general partner or a committee thereof. The board of our general partner, subject to the terms of the LTIP, has authority to (i) select the persons to whom awards are to be granted, (ii) determine the size and type of awards, (iii) determine the terms and conditions of any award, including any performance conditions, (iv) determine whether, to what extent, and under what circumstances awards may be settled, exercised, canceled, or forfeited; (vi) interpret and administer the LTIP and any instrument or agreement relating to an award made under the LTIP; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the LTIP; and (viii) make any other determination and take any other action that the board of our general partner deems necessary or desirable for the administration of the LTIP. All decisions, interpretations and other actions of the board of our general partner are final and binding.
     The LTIP authorizes the granting of unit options, restricted common units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The maximum number of our common units that may at any time be delivered or reserved for delivery under the LTIP is 1,250,000 common units. If any award expires, is canceled, exercised, paid or otherwise terminates without the delivery of common units, then the units covered by such award shall again be units with respect to which awards may be granted.
     The board of our general partner may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The board of our general partner also has the right to alter or amend the LTIP or any part thereof from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (i) the date common units are no longer available under the LTIP for grants, (ii) termination of the LTIP by the board of our general partner or (iii) the date 10 years following its date of adoption.
Compensation of Directors
     Officers or employees of our general partner or its affiliates who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Directors who are not officers or employees of our general partner or its affiliates are compensated for their services on the board, as described below. In addition, each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law pursuant to a director indemnification agreement and our partnership agreement.
     Cash Retainer. Each non-employee director of our general partner receives an annual retainer of $50,000, paid in quarterly installments. In addition, the chairman of the audit committee receives an additional retainer of $8,000 per year.
     Initial Equity Grant. Each non-employee director, upon joining the board, receives an initial long-term equity grant of restricted common units with a value of $50,000. The restricted common units are granted pursuant to the terms and conditions of the LTIP and vest in three (3) equal installments commencing on the last day of the calendar year of the year in which the grant was made and each of the following two anniversaries thereof. As no non-employee directors joined the board during 2009, no initial equity grants were made in 2009.
     Annual Equity Grant. Each non-employee director who is serving on the board on December 1st will receive an annual grant of restricted common units with a value of $50,000. This annual award is granted pursuant to the terms and conditions of the LTIP and vests in full on the last day of the calendar year following the year in which the grant was made. Annual equity grants for Messrs. Kuehn, Reichstetter and Smith were made on December 1, 2009.

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Director Compensation Table
     The following table sets forth the aggregate dollar amount of all fees paid to each of the non-employee directors of our general partner during 2009 for their services on the board. The non-employee directors do not receive stock options or pension benefits.
Director Compensation
for the Year Ended December 31, 2009
(1)
                                 
    Fees Earned or           All Other    
Name   Paid in Cash(2)   Stock Awards(3)(4)   Compensation(5)   Total
Ronald L. Kuehn, Jr.
  $ 50,000     $ 64,020     $ 7,150     $ 121,170  
Arthur C. Reichstetter
    58,000       64,020       6,942       128,962  
William A. Smith
    50,000       66,564       7,081       123,645  
 
(1)   Employee directors do not receive any additional compensation for serving on the board of directors of our general partner; therefore no amounts are shown for Messrs. Foshee, Sult, Leland and Yardley. Amounts paid as reimbursable business expenses to each director for attending board functions are not reflected in this table. Our general partner does not consider the directors’ reimbursable business expenses for attending board functions and other business expenses required to perform board duties to have a personal benefit and thus be considered a perquisite.
 
(2)   This column reflects the value of a director’s annual retainer, as well as the additional retainer for the chairman of the audit committee.
 
(3)   The amount in this column represents the dollar amount recognized for financial reporting purposes for the fiscal year ended December 31, 2009 of restricted common units granted in 2009 and prior years.
 
(4)   The grant date fair value of the annual restricted unit grants made to Messrs. Kuehn, Reichstetter and Smith on December 1, 2009 was $50,002.
 
(5)   The amount in this column for Mr. Kuehn represents $6,942 in cash distributions received on unvested restricted common units and $208 for an airline ticket for an occasion when the director’s spouse accompanied him on a business-related flight using a commercial carrier. The amount in this column for Messrs. Reichstetter and Smith represent cash distributions received on unvested restricted common units.

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ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
     The following table sets forth the beneficial ownership of units of our partnership owned as of February 12, 2010 by:
    each person known by us to be a beneficial owner of more than 5% of the units;
 
    each of the directors of our general partner;
 
    each of the named executive officers of our general partner; and
 
    all directors and executive officers of our general partner as a group.
     The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
     The percentage of total units to be beneficially owned is based on 107,484,747 common units outstanding as of February 12, 2010.
                                         
            Percentage of           Percentage of   Percentage of
    Common   Common   Subordinated   Subordinated   Total Common
    Units   Units   Units   Units   and Subordinated
    Beneficially   Beneficially   Beneficially   Beneficially   Units Beneficially
Name of Beneficial Owner(1)   Owned   Owned   Owned   Owned   Owned
El Paso Corporation(2)
    55,326,397       51.5 %     27,727,411       100 %     61.4 %
Ronald L. Kuehn, Jr.
    67,347       *             %     *  
James C. Yardley
    10,000       *             %     *  
Robert W. Baker
    5,000       *             %     *  
John R. Sult
    10,000       *             %     *  
James J. Cleary
    2,000       *             %     *  
Daniel B. Martin
          *             %     *  
Norman G. Holmes
          *             %     *  
Douglas L. Foshee
    25,000       *             %     *  
D. Mark Leland
    13,200       *             %     *  
Arthur C. Reichstetter
    107,347       *             %     *  
William A. Smith
    7,452       *             %     *  
All directors and executive officers as a group (eleven persons)
    247,346       *             %     *  
 
*   Less than 1%.
 
(1)   Unless otherwise indicated, the address for all beneficial owners in this table is El Paso Building, 1001 Louisiana Street, Houston, Texas 77002.
 
(2)   El Paso Corporation is the ultimate parent company of El Paso Pipeline Holding Company, L.L.C., the sole owner of the member interests of our general partner and El Paso Pipeline LP Holdings, L.L.C., the owner of 55,326,397 common units and 27,727,411 subordinated units. El Paso Corporation may, therefore, be deemed to beneficially own the units held by El Paso Pipeline LP Holdings, L.L.C.

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     The following table sets forth, as of February 12, 2010, the number of shares of common stock of El Paso owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.
                                 
    Shares of   Shares           Percentage of
    Common   Underlying   Total Shares   Total Shares
    Stock   Options   of Common   of Common
    Owned   Exercisable   Stock   Stock
    Directly or   Within   Beneficially   Beneficially
Name of Beneficial Owner   Indirectly   60 Days(1)   Owned   Owned(2)
Ronald L. Kuehn, Jr.
    114,501 (3)     8,000       122,501       *  
James C. Yardley
    274,233       477,421       751,654       *  
Robert W. Baker
    316,512       670,141       986,653       *  
John R. Sult
    85,588       149,985       235,573       *  
James J. Cleary
    59,045       271,469       330,514       *  
Daniel B. Martin
    151,068       242,662       393,730       *  
Norman G. Holmes
    57,989       164,512       222,501       *  
Douglas L. Foshee
    1,073,374       2,854,192       3,927,566       *  
D. Mark Leland
    299,007       539,800       838,807       *  
Arthur C. Reichstetter
                      *  
William A. Smith
    (4)                 *  
All directors and executive officers as a group (eleven persons)
    2,431,317       5,378,182       7,809,499       1.1 %
 
*   Less than 1%.
 
(1)   The shares indicated represent stock options granted under El Paso’s current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 12, 2010. Shares subject to options cannot be voted.
 
(2)   Based on 701,314,549 shares outstanding as of February 12, 2010.
 
(3)   Excludes 28,720 shares owned by Mr. Kuehn’s wife or children. Mr. Kuehn disclaims any beneficial ownership in these 28,720 shares.
 
(4)   Excludes 8,562 shares owned by Mr. Smith’s wife. Mr. Smith disclaims any beneficial ownership in these 8,562 shares.
EQUITY COMPENSATION PLAN INFORMATION TABLE
     The following table provides information concerning securities that may be issued under the El Paso Pipeline GP Company, L.L.C. Long-Term Incentive Plan as of December 31, 2009. For more information regarding this plan, which did not require approval by our limited partners, please read “Executive Compensation — Long-Term Incentive Plan.”
                         
    (a)   (b)   (c)
                    Number of Securities
                    Remaining Available for
    Number of Securities           Future Issuance under
    to be Issued upon   Weighted-Average   Equity Compensation
    Exercise of   Exercise Price of   Plans (Excluding
    Outstanding Options,   Outstanding Options,   Securities Reflected in
Plan Category   Warrants and Rights   Warrants and Rights   Column (a))
Equity compensation plans approved by unitholders
        $        
Equity compensation plans not approved by unitholders(1)
        $       1,227,150  
 
                       
Total
        $       1,227,150  
 
                       
 
(1)   Please read “Executive Compensation — Long-Term Incentive Plan” for a description of the material features of the plan, including the awards that may be granted under the plan.

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ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
     El Paso owns 55,326,397 common units and 27,727,411 subordinated units representing a 60 percent limited partner interest in us. In addition, our general partner owns a two percent general partner interest in us and the incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
     The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with ongoing operation and liquidation of El Paso Pipeline Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
     
 
  Operational Stage
 
   
Distributions of available cash to our general partner and its affiliates
  We will generally make cash distributions 98 percent to unitholders, including our general partner and its affiliates as holders of an aggregate of 55,326,397 common units, all of the subordinated units and the remaining two percent to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50 percent of the distributions above the highest target level.
 
   
Payments to our general partner and its affiliates
  Our general partner does not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines the amount of these expenses. In addition we will reimburse El Paso and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit.
 
   
Withdrawal or removal of our general partner
  If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
 
   
 
  Liquidation Stage
 
   
Liquidation
  Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Omnibus Agreement
     We are a party to an omnibus agreement with El Paso, our general partner, and certain of their affiliates that governs our relationship with them regarding the following matters:
    reimbursement of certain operating and general and administrative expenses;
 
    indemnification for certain environmental contingencies, tax contingencies and right-of-way defects;
 
    reimbursement for certain expenditures; and
 
    the guaranty by El Paso of certain expenses under intercompany agreements related to the Elba Island LNG terminal expansion.

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Reimbursement of Operating and General and Administrative Expense
     Under the omnibus agreement we reimburse El Paso and its affiliates for the payment of certain operating expenses and for the provision of various operating expenses and general and administrative services for our benefit with respect to the assets contributed to us. The omnibus agreement further provides that we reimburse El Paso for our allocable portion of the premiums on insurance policies covering our assets.
     Pursuant to these arrangements, El Paso performs centralized corporate functions for us, such as legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. We reimburse El Paso and its affiliates for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.
     We also reimburse El Paso for any additional state income, franchise or similar tax paid by El Paso resulting from the inclusion of us (and our subsidiaries) in a combined state income, franchise or similar tax report with El Paso as required by applicable law. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with El Paso.
Competition
     Neither El Paso nor any of its affiliates are restricted, under either our partnership agreement or the omnibus agreement, from competing with us. El Paso and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Indemnification
     Under the omnibus agreement, El Paso will indemnify us for three years after the closing of our initial public offering against certain potential environmental and toxic tort claims, losses and expenses associated with the business conducted by WIC, CIG or SNG or the operation of their assets and occurring before the closing date of our initial public offering. The maximum liability of El Paso for this indemnification obligation will not exceed $15 million and El Paso will not have any obligation under this indemnification until our aggregate losses exceed $0.25 million. El Paso will have no indemnification obligations with respect to environmental or toxic tort claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of our initial public offering. We have agreed to indemnify El Paso against environmental liabilities related to our assets to the extent El Paso is not required to indemnify us.
     Additionally, El Paso will indemnify us for losses attributable to title defects, failures to obtain consents or permits necessary for the transfer of the contributed assets, retained assets and liabilities (including pre-closing litigation relating to contributed assets) and income taxes attributable to pre-closing operations or ownership of the assets contributed to us, including any such income tax liability of El Paso and its affiliates that may result from our formation transactions.
     In no event will El Paso be obligated to indemnify us for any claims, losses or expenses or income taxes referred to in either of the two immediately preceding paragraphs to the extent either (i) reserved for in our financial statements as of September 30, 2007, or (ii) we recover any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party or in the tariffs paid by the customers of our affected pipeline system. In addition, in no event will the amount required to be indemnified to us in respect of any such claims, losses or expenses or income taxes in respect of CIG or SNG exceed 10 percent of the gross amount of such claims, losses, expenses or income taxes, as the case may be.

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     El Paso has also agreed to indemnify us, CIG and SNG from any amounts that may become payable by such indemnified party in respect of any entity, investment or business that was owned or operated by WIC, CIG or SNG prior to the closing of our initial public offering but which are not so owned or operated by WIC, CIG or SNG immediately after the closing of our initial public offering.
     In addition, El Paso has agreed to reimburse us for a 10% share of any amounts that may be paid by SNG under (i) the performance guaranty entered into by SNG for the Elba Island LNG terminal, (ii) its obligations in respect of the Elba III expansion or (iii) its obligations in respect of the Elba Express pipeline expansion. Please read “— SNG Guaranty of Elba Island Expansion” and “— SNG Guaranty of Elba Express Pipeline” below.
     We are required to indemnify El Paso for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to El Paso’s indemnification obligations.
SNG Guarantee of Elba Island Expansion
     SNG formerly owned Southern LNG Inc. (SLNG), which owns and operates a liquefied natural gas receiving and regasification terminal on Elba Island near Savannah, Georgia. SLNG is now a subsidiary of El Paso. In connection with an ongoing expansion of the Elba Island LNG terminal (Elba III), SNG has guaranteed the performance by SLNG of its construction contract with CB&I Constructors, Inc. SNG is to provide, at its election, either all necessary funds (up to defined limit) or a guarantee in the form of a performance bond (up to a defined limit) to permit the construction of the Elba III expansion. Pursuant to the omnibus agreement, El Paso has agreed to reimburse us, our general partner and any of our majority owned subsidiaries for a 10% share of any amounts that may be paid by SNG under the Elba Island guaranty or obligations in respect of the Elba III expansion.
SNG Guarantee of Elba Express Expansion
     Elba Express is a large pipeline under construction primarily in Georgia that is expected to be placed into service in March 2010. It will not be a part of SNG. However, SNG has agreed to provide, at its election, either all necessary funds to Elba Express (up to a defined limit) or a guarantee in the form of a performance bond (up to a defined limit) to permit the construction of the Elba Express pipeline. Pursuant to the omnibus agreement, El Paso has agreed to reimburse us, our general partner and any of our majority owned subsidiaries for a 10% share of any amounts that may be paid by SNG pursuant to obligations in respect of the Elba Express pipeline expansion.
Contracts with Affiliates
Contribution Agreement
     On July 24, 2009, we entered into the Contribution Agreement with our operating company and El Paso and certain of its subsidiaries. Pursuant to the Contribution Agreement, on July 24, 2009 we acquired an additional 18% general partner interest in CIG in exchange for cash consideration of $214.5 million.
     The conflicts committee of the board of directors of the General Partner unanimously recommended approval of the terms of the acquisition of the additional general partner interest in CIG. The conflicts committee of the board of directors of our general partner retained independent legal and financial advisors to assist it in evaluating and negotiating the transaction. In recommending approval of the transaction, the conflicts committee based its decision in part on an opinion from the committee’s independent financial advisor that the consideration to be paid by us pursuant to the Contribution Agreement is fair, from a financial point of view, to the holders of our common units, other than our general partner and its affiliates. The board of directors of the general partner unanimously approved the terms of this acquisition.

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Note Receivable
     Prior to the acquisition of additional ownership interests in CIG and SNG, in September 2008, we received a non-cash distribution of $30 million from CIG in the form of a note receivable from El Paso. As of December 31, 2009 we had $20 million remaining on our note receivable from El Paso. This note is due upon demand. This note bears interest at a variable rate based upon LIBOR plus a margin determined by reference to El Paso’s Amended and Restated Credit Agreement dated July 31, 2006.
Note Payable
     On September 30, 2008, in connection with our acquisition of additional ownership interests in CIG and SNG, we, as guarantor, and our operating company, as issuer, entered into a Note Purchase Agreement with El Paso. Under the Note Purchase Agreement, our operating company issued a $10 million senior unsecured note to El Paso initially bearing interest at LIBOR plus 3.5% due September 2012. This note may be prepaid without premium or penalty.
     Our operating company’s obligations under the Note Purchase Agreement are guaranteed by us. The Note Purchase Agreement requires that we maintain, as of the end of each fiscal quarter, (i) a consolidated leverage ratio (consolidated indebtedness to consolidated EBITDA (as defined in the Note Purchase Agreement)) of less than or equal to 5.50 to 1.00 for any four consecutive fiscal quarters and (ii) an interest coverage ratio (consolidated EBITDA to interest expense) of greater than or equal to 1.50 to 1.00 for any four consecutive fiscal quarters. In case of a capital construction or expansion project costing more than $20 million, pro forma adjustments to consolidated EBITDA may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments shall be limited to 25% of actual consolidated EBITDA.
     The Note Purchase Agreement also contains certain customary events of default that affect us, our operating company and our other restricted subsidiaries, including, without limitation, (i) nonpayment of principal when due or nonpayment of interest or other amounts within five business days of when due; (ii) bankruptcy or insolvency with respect to us, our general partner, our operating company or any of our other restricted subsidiaries; or (iii) judgment defaults against us, our general partner, our operating company or any of our other restricted subsidiaries in excess of $50 million.
CIG and SNG General Partnership Agreements
     General. Prior to the closing of our initial public offering in November 2007, each of CIG and SNG converted to general partnerships. In connection with the closing of our initial public offering, El Paso contributed to us a 10 percent general partner interest in each of CIG and SNG. In September 2008, we acquired from El Paso an additional 30 percent interest in CIG and an additional 15 percent interest in SNG. In July 2009, we acquired from El Paso an additional 18 percent interest in CIG. After these transactions, we own indirectly a 58 percent and 25 percent general partner interest in CIG and SNG, and an El Paso subsidiary owns indirectly a 42 percent and 75 percent general partner interest in CIG and SNG. A general partnership agreement governs the ownership and management of each of CIG and SNG. The CIG and SNG partnership agreements are substantially identical to each other in nearly all material respects.
     Each of CIG and SNG is a Delaware general partnership, one partner of which is a wholly owned subsidiary of El Paso (the El Paso Partner) owning a 42 percent and 75 percent interest in CIG and SNG, and the other partner is a wholly owned subsidiary of the partnership (the Partnership Partner) owning a 58 percent and 25 percent general partner interest in CIG and SNG. The purposes of each partnership are generally to own and operate the interstate pipeline system and related facilities owned by such partnership and to conduct such other business activities as the management committee of that partnership may from time to time determine, provided that such activity either generates “qualifying income” (as defined in Section 7704 of the Internal Revenue Code of 1986, or the “Code”) or enhances operations that generate such qualified income.
     Under the partnership agreement each partner may engage in other business opportunities, including those that compete with the partnership’s business, free from any obligation to offer same to the other partner or the partnership. In addition, any affiliate of a partner is free to compete with the business operations or activities of the partnership or the other partner.

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     Governance. Although management of each partnership is vested in its partners, the partners of each partnership have agreed to delegate management of the partnership to a management committee. Decisions or actions taken by the management committee of CIG or SNG will bind that partnership. Each management committee is composed of four representatives. The CIG management committee has three representatives being designated by the Partnership Partner and one representative being designated by the El Paso Partner. The SNG management committee has three representatives being designated by the El Paso Partner and one representative being designated by the Partnership Partner. Each representative has full authority to act on behalf of the partner that designated such representative with respect to matters pertaining to that partnership. The partners of each partnership have agreed that each representative is an agent of the partner that designated that person and does not owe any duty (fiduciary or otherwise) to such partnership, any other partner or any other representative.
     The management committee of each partnership meets no less often than quarterly, with the time and location of, and the agenda for, such meetings to be as the management committee determines; provided that in lieu of a meeting the management committee may elect to act by written consent. Special meetings of the management committee may be called at such times as a partner or management committee representative determines to be appropriate. The presence in person, or by electronic communication, of a majority of representatives (including at least one representative of each partner) constitutes a quorum of the management committee. Each representative is entitled to one vote on each matter submitted for vote of the management committee, and except as noted below, the vote of a majority of the representatives at a meeting properly called and held at which a quorum is present constitutes the action of the management committee. Any action of the management committee may be taken by unanimous written consent.
     The following actions require the unanimous approval of the management committee:
    dissolution of the partnership;
 
    causing or permitting the partnership to take certain bankruptcy actions;
 
    mortgaging or pledging assets with a value exceeding $225 million in the case of CIG and any assets in the case of SNG;
 
    the commencement or the resolution before the FERC (or any U.S. Court of Appeals of an appeal of a FERC order) of certain actions under the Natural Gas Act, or any other proceeding before the FERC that would result in a $50 million or more (i) reduction in revenue or (ii) payment of penalties, refunds or interest;
 
    any amendment of the partnership agreement;
 
    the admission of any person as a partner (other than a permitted transferee of a partner);
 
    any proposal to dispose of assets of such partnership with a value exceeding $225 million in the case of CIG and $450 million in the case of SNG;
 
    the disposition of all or substantially all of the assets of the partnership, and any disposition of interests in the partnership that would result in a termination under Section 708 of the Code;
 
    any merger, consolidation or conversion of the partnership;
 
    entering into new lines of business, including but not limited to, those that do not generate “qualifying income” under Section 7704 of the Internal Revenue Code; and
 
    any amendment to the master services agreement to which the partnership is a party, other than any amendment that the management committee determines would not materially adversely affect such partnership.
     Quarterly Cash Distributions. Under the CIG and SNG partnership agreements, on or before the end of the calendar month following each quarter prior to the commencement of the partnership’s liquidation, the management committee of each partnership is required to review the amount of available cash with respect to that quarter and distribute 100 percent of the available cash to the partners of that partnership in accordance with their percentage interests, subject to limited exceptions. Available cash with respect to any quarter is generally defined in these partnerships as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from Working Capital Borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of the partnership’s business.

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     Capital Calls to the Partners. From time to time as determined to be appropriate by the management committee of a partnership, the management committee may issue a capital call notice to the partners of that partnership for capital contributions to be made to fund the partnership’s operations. The notice will specify the amount of the capital contribution from all partners collectively and each partner individually, the purpose for which the funds will be used and the date that the contributions are to be made. If a partner fails to make a capital contribution when required under a capital call notice, the partner(s) that have made their full contribution may elect to pay the unpaid contribution and elect to treat that additional contribution as either (a) resulting in a priority interest of such contributing partner(s) or (b) treated as a permanent capital contribution that results in an adjustment of each partner’s relative percentage interest. If priority interest treatment is elected, all distributions that would otherwise have been paid to the non-contributing partner will be paid to the contributing partner until the priority interest is terminated, which will occur when the total of additional distributions to the contributing partner(s) equal the sum of the additional contribution amount plus 12 percent per annum.
Cash Management Programs
     SNG participates in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing El Paso’s total borrowings from outside sources. SNG has historically provided cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2009, SNG had a note receivable from El Paso of $154 million. The balance due to SNG under the cash management program will be used for general partnership purposes, debt repurchase expenses and premiums and to pay for capital expenditures. The interest rate payable by El Paso under the cash management program will be equal to LIBOR plus the applicable margin in effect from time to time pursuant to El Paso Corporation’s Amended and Restated Credit Agreement dated July 31, 2006, as amended or replaced from time to time.
     In conjunction with our acquisition of the additional interest in CIG on July 24, 2009, CIG terminated its participation in El Paso’s cash management program. CIG converted its note receivable with El Paso under its cash management program into a demand note receivable from El Paso. At December 31, 2009, CIG had $73 million remaining under this note at an interest rate of 1.5%. We classified $73 million as current based on the net amount CIG anticipates using in the next twelve months considering available cash sources and needs.
CIG Operating Agreements
     CIG entered into a Construction and Operating Agreement with WIC, on March 12, 1982. This agreement was amended in 1984 and 1988. Under this agreement, CIG agreed to design and construct the WIC system and to operate WIC (including conducting WIC’s marketing and administering WIC’s service agreements) using the same practices that CIG adopts in the operation and administration of its own facilities. Under this agreement, CIG is entitled to be reimbursed by WIC for all costs incurred in the performance of the services, including both direct costs and allocations of general and administrative costs based on direct field labor charges. Included in CIG’s allocated expenses are a portion of El Paso’s general and administrative expenses and EPNG and TGP allocated payroll and other expenses. CIG is the operator of the WIC facilities, and is reimbursed by WIC for operation, maintenance and general and administrative costs allocated from CIG, in each case under the CIG Construction and Operating Agreement referred to above.
     CIG entered into a Construction and Operating Agreement with Young Gas Storage Company, Ltd. on June 30, 1992. This agreement was amended in 1994 and 1997. Under this agreement, CIG agreed to design and construct the Young storage facilities and to operate the facilities (including conducting Young’s marketing and administering Young’s service agreements) using the same practices that CIG adopts in the operation and administration of its own facilities. CIG is entitled to reimbursement of all costs incurred in the performance of the services, including both direct costs and allocations of general and administrative costs based on direct field labor charges (including any costs charged or allocated to CIG from other affiliates). The agreement is subject to termination only in the event of the dissolution or bankruptcy of CIG, or a material default by CIG that is not cured within certain permissible time periods. Otherwise the agreement continues until the termination of the Young partnership agreement.

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     CIG entered into a Construction and Operating Agreement with Cheyenne Plains Gas Pipeline Company, L.L.C. on November 14, 2003. Under this agreement, CIG agreed to design and construct the facilities and to operate the Cheyenne Plains facilities (including conducting marketing and administering the service agreements) using the same practices that CIG adopts in the operation and administration of its own facilities. CIG is entitled to reimbursement by Cheyenne Plains for all costs incurred in the performance of the services, including both direct field labor charges and allocations of general and administrative costs (including any costs charged or allocated to CIG from other affiliates) using a modified Massachusetts allocation methodology, a time and motion analysis or other appropriate allocation methodology. The agreement is subject to termination by Cheyenne Plains on 12 months’ prior notice and is subject to termination by CIG on 12 months’ prior notice given no earlier that 48 months following the commencement of service by Cheyenne Plains in December 2004.
Transportation Agreements
     CIG is a party to four transportation service agreements with WIC for transportation on the WIC system at maximum recourse rates. The total volume subject to these contracts is 176,971 Dth/d. These contracts extend for various terms with 57,950 Dth/d expiring on December 31, 2011; and the balance expiring thereafter. Under the service agreements, we are required to make minimum annual payments of $6 million in each of the years 2010-2011, $3 million in 2012 and $3 million in total thereafter. In response to a solicitation of offers to turn back capacity in a WIC open season, CIG relinquished 70,000 Dth/d of capacity effective January 1, 2008. WIC has remarketed this capacity along with off-system capacity acquired by WIC on a third party pipeline and other capacity on its pipeline to another affiliate, Cheyenne Plains, under a Firm Transportation Service Agreement for 125,000 Dth/d from the Opal Hub in western Wyoming to the Cheyenne Hub at maximum recourse rates for a term extending to 2020.
     WIC is also a party to a transportation service agreement with CIG pursuant to which CIG will acquire 75,600 Dth/day of firm transportation capacity on WIC from a Primary Point of Receipt at the Cheyenne Hub to a Primary Point of Delivery into El Paso’s Ruby Pipeline at Opal, Wyoming. The rate that CIG will pay for this service is WIC’s maximum recourse rates plus the cost of any off-system capacity on a third party pipeline that is acquired by WIC to provide this service. The service will commence on the in-service date of El Paso’s Ruby Pipeline and will continue until the later of July 1, 2021 or ten years from the commencement date.
     CIG is a party to a capacity release agreement with PSCo, whereby PSCo has released storage capacity in our affiliate, Young Gas Storage Company, Ltd., to us for a term expiring on April 30, 2025. PSCo simultaneously contracted for a corresponding quantity of transportation and storage balancing service (which utilizes the storage capacity acquired through the capacity release).
     In order to provide “jumper” compression service between the CIG system and the Cheyenne Plains pipeline system, CIG added compression at CIG’s existing compressor station in Weld County, Colorado. Cheyenne Plains entered into a 25-year contract that expires in 2030 for the full capacity of the additional compression pursuant to which CIG’s full cost of service is covered. The contract is for 119,500 Dth/d.
Interconnection and Operational Balancing Agreements and Other Inter-Affiliate Agreements
     Each of WIC and CIG is a party to an operational balancing agreement with each other and independently with Cheyenne Plains. These agreements require the interconnecting parties to use their respective reasonable efforts to cause the quantities of gas that are tendered/accepted at each point of interconnection to equal the quantities scheduled at those points. The agreements provide for the treatment and resolution of imbalances. The agreements are terminable by either party on 30 days’ advance notice.
     CIG and WIC are parties to a capacity lease agreement dated November 1, 1997. In 1998, WIC installed a compressor unit at WIC’s Laramie compressor station. The installation of this compressor unit allowed the interconnection of CIG’s Powder River lateral and WIC’s mainline transmission system and resulted in an increase of approximately 49 MDth/d of capacity on CIG’s Powder River lateral (the original capacity on the Powder River lateral was approximately 46 MDth/d). In connection with the installation of the compression by WIC, CIG leased the additional 49 MDth/d of capacity in the Powder River lateral to WIC. WIC, in turn, leased to CIG 46 MDth/d of capacity through the new WIC compressor unit. The initial term of the lease of the Powder River lateral capacity

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from CIG to WIC was 10 years from the November 15, 1998 in-service date of the additional compression. In November 2008, the term of the lease was extended for 10 years. The term of the lease of the compression unit capacity from WIC to CIG continues for as long as CIG has shipper agreements for service using the compressor unit capacity. The parties to this agreement have agreed that the reciprocal leases provide adequate compensation to each other so there is no rental fee for either lease other than an agreement by WIC to reimburse CIG for any increase in operating expense incurred by CIG (including increased taxes, insurance or other expenses).
     WIC is a party to an “Upstream Pipeline Capacity Agreement” with Ruby Pipeline, LLC, a wholly owned indirect subsidiary of El Paso Corporation. Pursuant to this agreement WIC agreed to offer gas transportation services to shippers desiring to move gas volumes to the inlet to the proposed Ruby pipeline at Opal, Wyoming. Ruby has agreed to reimburse WIC for any unrecovered costs associated with 200 MDth/day of off-system capacity that was acquired by WIC to provide the upstream transportation services (either through a direct payment or through the acquisition of capacity on WIC). The off-system capacity was acquired by WIC on the expansions of the Rockies Express Pipeline from the Piceance Basin to Wamsutter, and the expansion of the Overthrust Pipeline from Wamsutter to Opal.
Other Agreements
     In addition, each of WIC, CIG and SNG currently have and will have in the future other routine agreements with El Paso or one of its subsidiaries that arise in the ordinary course of business, including agreements for services and other transportation and exchange agreements and interconnection and balancing agreements with other El Paso pipelines.
     For a description of certain additional affiliate transactions, see Part II, Item 8, Financial Statements and Supplementary Data, Note 12.
Review, Approval or Ratification of Transactions with Related Persons
     Our partnership agreement contains specific provisions that address potential conflicts of interest between our general partner and its affiliates, including El Paso, on one hand, and us and our limited partners, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner, which, is required to be comprised of independent directors. The partnership agreement provides that our general partner will not be in breach its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is:
    approved by the conflicts committee;
 
    approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
 
    on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
    fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
     If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or its conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.

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Director Independence
     The board of directors of our general partner has affirmatively determined that Ronald L. Kuehn, Jr, Arthur C. Reichstetter and William A. Smith each satisfy the independence requirements under the New York Stock Exchange listing standards. In making this determination, the board reviewed information from each of these directors regarding all of their respective relationships with us and analyzed the materiality of those relationships. The audit committee of our general partner’s board of directors is also composed entirely of independent directors.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees
     We paid audit fees of $1,444,000 for the year ended December 31, 2009 (including $792,000 related to CIG, our consolidated subsidiary) and $384,000 for the year ended December 31, 2008. These fees were for professional services rendered by Ernst & Young LLP for the audit of the consolidated financial statements of El Paso Pipeline Partners, L.P., the review of documents filed with the Securities and Exchange Commission, and related consents.
All Other Fees
     For the years ended December 31, 2009 and 2008, fees of $214,000 and $296,000 were paid to Ernst & Young LLP for professional services related to tax compliance and tax planning. No tax related services were provided for the year ended December 31, 2007.
     No audit-related services were provided by our independent registered public accounting firm for the years ended December 31, 2009 and 2008.
     During 2009, the Audit Committee approved all the types of audit and permitted non-audit services which our independent auditors were to perform during the year, as required under applicable law, and the cap on fees for each of these categories. The Audit Committee’s current practice is to consider for pre-approval annually all categories of audit and permitted non-audit services proposed to be provided by our independent auditors for a fiscal year. Pre-approval of tax services requires that the principal independent auditor provide the Audit Committee with written documentation of the scope and fee structure of the proposed tax services and discuss with the Audit Committee the potential effects, if any, of providing such services on the independent auditor’s independence. The Audit Committee will also consider for pre-approval annually the maximum amount of fees and the manner in which the fees are determined for each type of pre-approved audit and non-audit services proposed to be provided by our independent auditors for the fiscal year. The Audit Committee must separately pre-approve any service that is not included in the approved list of services or any proposed services exceeding pre-approved cost levels. The Audit Committee has delegated pre-approval authority to the Chairman of the Audit Committee for services that need to be addressed between Audit Committee meetings. The Audit Committee is then informed of these pre-approval decisions, if any, at the next meeting of the Audit Committee.

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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
     (a) The following consolidated financial statements are included in Part II, Item 8 of this report:
1. Financial Statements.
         
    Page
El Paso Pipeline Partners, L.P.    
Reports of Independent Registered Public Accounting Firm
    48  
Consolidated Statements of Income
    50  
Consolidated Balance Sheets
    51  
Consolidated Statements of Cash Flows
    52  
Consolidated Statements of Partners’ Capital
    53  
Notes to Consolidated Financial Statements
    54  
 
2. Financial Statement Schedules.
       
Schedule II — Valuation and Qualifying Accounts
    79  
     All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.
3. and (b). Exhibits
     The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 (b)(10)(iii) of Regulation S-K.
     The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
  should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
 
  may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
 
  may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and
 
  were made only as of the date of the applicable agreement or such other date or dates as maybe specified in the agreement and are subject to more recent developments.
     Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
Undertaking
     We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.
(c)   Financial Statements of 50-Percent-Or-Less-Owned Investees
1. Financial Statements.
Southern Natural Gas Company
 
Reports of Independent Registered Public Accounting Firms
  101       
Consolidated Statements of Income and Comprehensive Income
  103       
Consolidated Balance Sheets
  104       
Consolidated Statements of Cash Flows
  105       
Consolidated Statements of Partners’ Capital/Stockholder’s Equity
  106       
Notes to Consolidated Financial Statements
  107       
 
2. Financial Statement Schedules.
 
Schedule II — Valuation and Qualifying Accounts
  122       

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Report of Independent Registered Public Accounting Firm
The Partners of Southern Natural Gas Company
We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of income and comprehensive income, partners’ capital/stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(c) for each of the three years in the period ended December 31, 2009. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The consolidated financial statements of Citrus Corp. and Subsidiaries (a corporation in which the Company had a 50% interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included from Citrus Corp. and Subsidiaries, is based solely on the report of the other auditors, exclusive of the income adjustment related to the disposition of the equity interest in November 2007. In the consolidated financial statements, earnings from the Company’s investment in Citrus Corp. represent approximately 28% of income before income taxes for the year ended December 31, 2007.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Southern Natural Gas Company at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted the new income tax accounting standard, and effective January 1, 2008, the Company adopted the provisions of an accounting standard update related to the measurement date and changed the measurement date of its postretirement benefit plan.
/s/ Ernst & Young LLP
Houston, Texas
February 26, 2010

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Citrus Corp.:
In our opinion, the consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity, of comprehensive income and of cash flows (not presented separately herein) present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the “Company”) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with the accounting principles generally accepted in the United States of America. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 2 and 6 to the consolidated financial statements, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158 “Employers’ Accounting for Defined Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” as of December 31, 2006.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2008

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SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In millions)
                         
    Year Ended December 31,  
    2009     2008     2007  
Operating revenues
  $ 510     $ 540     $ 482  
 
                 
Operating expenses
                       
Operation and maintenance
    173       189       160  
Depreciation and amortization
    55       53       53  
Taxes, other than income taxes
    27       27       27  
 
                 
 
    255       269       240  
 
                 
Operating income
    255       271       242  
Earnings from unconsolidated affiliates
    11       13       88  
Other income, net
    2       10       13  
Interest and debt expense
    (62 )     (72 )     (91 )
Affiliated interest income
    2       13       19  
 
                 
Income before income taxes
    208       235       271  
Income tax expense
                69  
 
                 
Income from continuing operations
    208       235       202  
Discontinued operations, net of income taxes
                19  
 
                 
Net income
    208       235       221  
Other comprehensive income
                1  
 
                 
Comprehensive income
  $ 208     $ 235     $ 222  
 
                 
See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions)
                 
    December 31,  
    2009     2008  
ASSETS
               
Current assets
               
Cash and cash equivalents
  $     $  
Accounts and notes receivable
               
Customer
    7       3  
Affiliates
    64       71  
Other
    2       2  
Materials and supplies
    15       14  
Other
    9       15  
 
           
Total current assets
    97       105  
 
           
Property, plant and equipment, at cost
    3,709       3,636  
Less accumulated depreciation and amortization
    1,411       1,373  
 
           
Total property, plant and equipment, net
    2,298       2,263  
 
           
Other assets
               
Investment in unconsolidated affiliate
    79       81  
Note receivable from affiliate
    112       95  
Other
    73       85  
 
           
 
    264       261  
 
           
Total assets
  $ 2,659     $ 2,629  
 
           
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities
               
Accounts payable
               
Trade
  $ 19     $ 28  
Affiliates
    27       10  
Other
    16       18  
Taxes payable
    9       8  
Accrued interest
    18       18  
Asset retirement obligation
    14        
Other
    5       10  
 
           
Total current liabilities
    108       92  
 
           
Long-term debt
    910       910  
 
           
Other liabilities
    27       50  
 
           
Commitments and contingencies (Note 7)
               
Partners’ capital
    1,614       1,577  
 
           
Total liabilities and partners’ capital
  $ 2,659     $ 2,629  
 
           
See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
                         
    Year Ended December 31,  
    2009     2008     2007  
Cash flows from operating activities
                       
Net income
  $ 208     $ 235     $ 221  
Less income from discontinued operations, net of income taxes
                19  
 
                 
Income from continuing operations
    208       235       202  
Adjustments to reconcile net income to net cash from operating activities
                       
Depreciation and amortization
    55       53       53  
Deferred income tax expense
                23  
Earnings from unconsolidated affiliates, adjusted for cash distributions
    2       3       42  
Other non-cash income items
    (1 )     (5 )     (6 )
Asset and liability changes
                       
Accounts receivable
    4       13       (7 )
Accounts payable
    9       7       (13 )
Taxes payable
                (21 )
Other current assets
    18       (5 )     5  
Other current liabilities
    10       (9 )     (4 )
Non-current assets
          (11 )     (5 )
Non-current liabilities
    (19 )     4       (320 )
 
                 
Cash provided by (used in) continuing activities
    286       285       (51 )
Cash provided by discontinued activities
                25  
 
                 
Net cash provided by (used in) operating activities
    286       285       (26 )
 
                 
Cash flows from investing activities
                       
Capital expenditures
    (138 )     (138 )     (243 )
Net change in notes receivable from affiliate
    (18 )     289       (152 )
Proceeds from the sale of assets
    41              
 
                 
Cash provided by (used in) continuing activities
    (115 )     151       (395 )
Cash used in discontinued activities
                (25 )
 
                 
Net cash provided by (used in) investing activities
    (115 )     151       (420 )
 
                 
Cash flows from financing activities
                       
Payments to retire long-term debt
          (236 )     (584 )
Distributions to partners
    (171 )     (200 )      
Net proceeds from issuance of long-term debt
                494  
Contribution from parent
                536  
 
                 
Net cash provided by (used in) financing activities
    (171 )     (436 )     446  
 
                 
Net change in cash and cash equivalents
                 
Cash and cash equivalents
                       
Beginning of period
                 
 
                 
End of period
  $     $     $  
 
                 
See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL/STOCKHOLDER’S EQUITY
(In millions, except share amounts)
                                                         
                                    Accumulated              
                    Additional             Other     Total     Total  
    Common Stock     Capital     Retained     Comprehensive     Stockholder’s     Partner’  
    Shares     Amount     Paid-in     Earnings     Income (Loss)     Equity     Capital  
January 1, 2007
    1,000     $     $ 340     $ 1,304     $  <