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

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

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 (Address of Principal Executive Offices)		77002 (Zip Code)

Telephone Number: (713) 420-2600
Internet Website: www.eppipelinepartners.com

Title of Each Class		Name of Each Exchange on which Registered
Common Units Representing Limited Partnership Interests		New York Stock Exchange

     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 þ 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 $1,825,084,894 on June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, based on the price of $28.67 per unit, the closing price of the common units as reported on the New York Stock Exchange on such date.

     There were 177,167,863 Common Units and 3,615,578 General Partner Units outstanding as of February 22, 2011:

Documents Incorporated by Reference: None.

 

 

EL PASO PIPELINE PARTNERS, L.P.
TABLE OF CONTENTS

Caption		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			9
Item 1B. Unresolved Staff Comments			26
Item 2. Properties			26
Item 3. Legal Proceedings			26
Item 4. (Removed and Reserved)			26
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			27
Item 6. Selected Financial Data			29
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			43
Item 8. Financial Statements and Supplementary Data			44
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			79
Item 9A. Controls and Procedures			79
Item 9B. Other Information			79
PART III
Item 10. Directors, Executive Officers and Corporate Governance			80
Item 11. Executive Compensation			86
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			88
Item 13. Certain Relationships and Related Transactions, and Director Independence			91
Item 14. Principal Accountant Fees and Services			98
PART IV
Item 15. Exhibits and Financial Statement Schedules			99
Signatures			100
EX-12
EX-21
EX-23.A
EX-31.A
EX-31.B
EX-32.A
EX-32.B
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

     Below is a list of terms that are common to our industry and used throughout this document:

/d		= per day		NGL		= natural gas liquid
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		GAAP		=Generally Accepted Accounting Principles
LNG		= liquefied natural gas		FERC		=Federal Energy Regulatory Commission

     When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

     When we refer to “EPB”, “us”, “we”, “our”, or “ours”, we are describing El Paso Pipeline Partners, L.P. and/or our subsidiaries.

ITEM 1.		BUSINESS

Overview and Strategy

     We are a Delaware master limited partnership (MLP) formed in 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, L.L.C. (WIC) system, the Southern LNG Company, L.L.C. (SLNG) storage facility, the Elba Express Company, L.L.C. (Elba Express) system, a 58 percent general partner interest in the Colorado Interstate Gas Company (CIG) system, and a 60 percent general partner interest in the Southern Natural Gas Company (SNG) system. 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. In July 2009, we acquired an additional 18 percent general partner interest in CIG from El Paso. In March 2010, we acquired a 51 percent member interest in each of SLNG and Elba Express from El Paso. In June 2010, we acquired an additional 20 percent general partner interest in SNG from El Paso. In November 2010, we acquired the remaining 49 percent member interest in each of SLNG and Elba Express and an additional 15 percent general partner interest in SNG.

     Our pipeline systems, storage facilities and LNG receiving terminal operate under tariffs approved by the 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 cost 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.

Our Assets

     The table below and discussion that follows provide detail on our pipeline systems as of December 31, 2010:

		As of December 31, 2010
Transmission		Ownership				Miles of				Design				Storage				Average Throughput(1)
System		Interest				Pipeline				Capacity				Capacity				2010				2009				2008
		(Percent)								(MMcf/d)				(Bcf)								(BBtu/d)
WIC			100				800				3,538				—				2,472				2,652				2,543
CIG (2)(3)			58				4,300				4,592				37				2,131				2,299				2,225
SNG (2)(4)			60				7,600				3,700				60				2,505				2,322				2,339
Elba Express (5)			100				200				945				—				—				—				—

     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 37 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 and the 164-mile High Plains pipeline (High Plains) both of which are in northeast Colorado. Totem and High Plains were placed in service in June 2009 and November 2008, respectively, and are operated by CIG. Totem consists of a 6 Bcf natural gas storage field that services and interconnects with High Plains. WYCO also owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain’s electric generation plant, which CIG does not operate, and a compressor station in Wyoming leased by WIC.

     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 100 percent of the Muldon storage facility and a 50 percent interest in Bear Creek. The storage facilities have a combined working natural gas storage capacity of 60 Bcf and peak withdrawal capacity of 1.2 Bcf/d. The SNG system is also connected to SLNG’s Elba Island LNG terminal near Savannah, Georgia.

     Elba Express. Elba Express owns the Elba Express pipeline, an approximately 200-mile pipeline with a design capacity of 945 MMcf/d that transports natural gas supplies from the Elba Island LNG terminal to markets in the southeastern and eastern U.S. Elba Express was placed into service in March 2010. Under a firm transportation service agreement, the entire capacity of Elba Express is contracted to Shell NA LNG LLC (Shell LNG) for 30 years at a fixed rate that will be reduced beginning on December 31, 2013. The firm transportation service agreement is supported

by a step-down parent guarantee from Shell Oil Company (Shell) that secures the timely performance of the obligations of the agreement. SNG operates Elba Express pursuant to a service agreement with Elba Express.

     SLNG. SLNG owns the Elba Island LNG receiving terminal, located near Savannah, Georgia. The Elba Island LNG terminal is one of eleven facilities in the United States capable of providing domestic storage and vaporization services to international producers of LNG. The Elba Island LNG terminal has approximately 11.5 equivalent Bcf of LNG storage capacity and 1.8 Bcf/d, of peak send-out capacity. The capacity of the Elba Island LNG terminal is fully contracted with subsidiaries of BG Energy Holdings Limited (BG) under a conventional recourse rate contract and Shell under a long-term step-down fixed rate contract (that will be reduced beginning on December 31, 2013 and remain flat thereafter). The Elba Island LNG terminal is directly connected to three interstate pipelines, indirectly connected to two others, and also connected by commercial arrangements to a major local distribution company; thus, is readily accessible to the southeast and mid-Atlantic markets. SNG operates the Elba Island LNG terminal pursuant to a service agreement with SLNG. The firm SLNG service agreements are supported by parent guarantees from BG and Shell that secure the timely performance of the obligations of those agreements.

     FERC Approved Pipeline Projects. As of December 31, 2010, we had the following significant FERC approved pipeline expansion projects on our systems. For a further discussion of other expansion projects, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

										Anticipated
		Existing		Capacity						Completion or
Project		System		(MMcf/d)				Description		In-Service Date
South System III (Phases I — III)		SNG			370			To add 81 miles of pipeline and 17,310 of horsepower compression; each phase will add an additional 122 MMcf/d of capacity		2011 and 2012(1)
Southeast Supply Header Phase II (2)		SNG			350			To add approximately 26,000 of horsepower compression to the jointly owned pipeline facilities		June 2011

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 shales, is rapidly increasing. This shift will affect the supply patterns, the flows, and the rates that can be charged on pipeline systems. The impacts will vary among pipelines according to the location and the number of competitors attached to these new supply sources.

     Another change in the supply patterns is the reduction in imports from Canada. This decrease has been the result of declining production and increasing demand in Canada. This reduction in imports has led to increased demand for domestic supplies and related transportation services over the last several years, a trend which is expected to continue in the future. On the other border, exports to Mexico are increasing and are expected to increase further over time as demand growth exceeds production growth in that country. The increase in demand for gas and transportation caused by these trends in Canada and Mexico could be partially offset by imports of LNG. Imports of LNG have fluctuated in the past in response to changing gas prices within North America, Europe and Asia. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems may also compete with our pipelines for transportation of gas into the market areas we serve.

     Electric power generation has been the source of most of the growth in demand for natural gas over the last ten years, and this trend is expected to continue in the future. The growth of natural gas in this sector is influenced by competition with coal and increased consumption of electricity as a result of recent economic growth. Short-term market shifts have been driven by relative costs of coal-fired generation versus gas-fired generation. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources.

     For a further discussion of factors impacting our markets and competition, See Item 1A, Risk Factors.

     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), Bison Pipeline LLC (Bison) and CIG. With the decline in drilling in the Powder River Basin and the commissioning of Bison in early 2011, WIC may have difficulty renewing expiring contracts on the WIC Medicine Bow laterals. 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.

     CIG. Our 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 us with incremental demand for transportation services. In late 2010, the Colorado Public Utility Commission approved a proposal for PSCo to convert approximately 900 megawatts (MW) of older coal generation to natural gas fired generation by 2017. This approval remains under review and is being protested by the coal industry. 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 Rockies Express. Competition from Rockies Express and Bison could result in additional discounting on the CIG system.

     SLNG. Elba Island’s LNG terminal capacity is completely subscribed under long term contracts with subsidiaries of BG and Shell. Because revenue from these contracts is predominantly based on reservation charges, changes in throughput at the terminal driven by domestic or global competition will have relatively little effect on our revenue stream or profitability. Since the Elba Island LNG terminal is directly connected to three interstate pipelines, and indirectly connected to two others, it is readily accessible to markets in the southeast U.S., Florida, and the mid-Atlantic. We believe that this connectivity well positions the Elba Island LNG terminal to compete for any global LNG supplies against any other U.S. LNG terminal.

     Elba Express. The full pipeline capacity of Elba Express is completely subscribed under a long term contract with a subsidiary of Shell. Because revenue from this contract is entirely based on reservation charges, changes in throughput on Elba Express driven by competitive forces will have little or no effect on our revenue stream or profitability. Elba Express competes for receipts into its system within the worldwide LNG market given its existing configuration to provide south to north takeaway capacity from the Elba LNG terminal to downstream markets in the mid-Atlantic and northeast.

     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 Transcontinental Gas Pipeline Company (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 and storage facility as of December 31, 2010. Our firm customers reserve capacity on our pipeline systems 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 seven years.
Major Customers:
Williams Gas Marketing, Inc.
(353 BBtu/d)		Expire in 2013-2015.
(414 BBtu/d)		Expire in 2017-2018.
(610 BBtu/d)		Expire in 2019-2021.
Anadarko Petroleum Corporation
(323 BBtu/d) (406 BBtu/d) (665 BBtu/d)		Expire in 2011-2015. Expire in 2016-2018. Expire in 2020-2023.

CIG
Customer Information		Contract Information
Approximately 110 firm and interruptible customers.		Approximately 160 firm transportation contracts. Weighted average remaining contract term of approximately seven years.
Major Customers:
PSCo
(905 BBtu/d)		Expire in 2012-2019.
(874 BBtu/d)		Expire in 2025-2029.
(200 BBtu/d)(1)		Expires in 2040.
Williams Gas Marketing, Inc.
(395 BBtu/d)		Expire in 2011-2014.
Pioneer Natural Gas Resources USA, Inc.
(109 BBtu/d)		Expire in 2014-2015.
(202 BBtu/d)		Expire in 2020-2022.

SLNG
Customer Information		Contract Information
Two firm customers.		Two firm storage contracts. Weighted average remaining contract term of approximately 21 years.
Major Customers:
BG LNG Services, LLC		Expires in 2027.
Shell NA LNG, LLC		Expire in 2035 — 2036.

Elba Express
Customer Information		Contract Information
Four firm and interruptible customers.		One firm transportation contract. Remaining contract term of approximately 29 years.
Major Customers:
Shell N A LNG, LLC		Expires in 2040.
(965 BBtu/d)

SNG
Customer Information		Contract Information
Approximately 260 firm and interruptible customers.		Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately seven years.
Major Customers:
Atlanta Gas Light Company(2)
(979 BBtu/d)		Expire in 2013-2015.
(84 BBtu/d)		Expires in 2024.
Southern Company Services
(43 BBtu/d)		Expire in 2011-2013.
(390 BBtu/d)		Expire in 2017-2018.
(375 BBtu/d)		Expires in 2032.
Alabama Gas Corporation
(352 BBtu/d)		Expires in 2013.
SCANA Corporation
(315 BBtu/d)		Expire in 2013-2019.

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 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 extends to:

•

rates and charges for natural gas transportation, storage and related services;

•

certification and construction of new facilities;

•

extension or abandonment of services and facilities;

•

maintenance of accounts and records;

•

relationships between pipelines and certain affiliates;

•

terms and conditions of services;

•

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 48.9 percent limited partner interest in us and the remaining 42 percent general partner interest in CIG and 40 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 remediation activities is included in Part II, Item 8 Financial Statements and Supplementary Data, Note 9.

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, SLNG and Elba Express are operated by SNG and CIG and SNG are 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 14.

Available Information

     Our website is 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.

ITEM 1A.		RISK FACTORS

     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 such variances can be material. Where we 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. 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 and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. 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 of our forward-looking statements.

     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 and the trading price of our common units could decline materially. The risks referred to herein refer to risks inherent to our wholly-owned operations through WIC, SLNG and Elba Express and our general partner interests in CIG and SNG.

Risks Inherent in Our Business

The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.

     Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for natural gas, including reductions in our ability to renew pipeline transportation contracts on favorable terms and to construct new pipeline infrastructure. One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:

•

Adverse changes in general global economic conditions. The level and speed of the recovery from the recent recession remains uncertain and could impact the supply and demand for natural gas and our future rate of growth in our business;

•

Adverse changes in geopolitical factors, including the ability of the Organization of the Petroleum Exporting Countries (OPEC) to agree upon and maintain certain production levels, political unrest and changes in foreign governments in production regions of the world and unexpected wars, terrorist activities and others acts of aggression;

•

Technological advancements that may drive further increases in production from natural gas shales;

•

Competition from imported LNG and Canadian supplies and alternate fuels;

•

Increased prices of natural gas or NGLs that could negatively impact demand for these products;

•

Increased costs to explore for, develop, produce, gather, process and transport natural gas or NGLs.

•

Adoption of various energy efficiency and conservation measures; and

•

Perceptions of customers on the availability and price volatility of our services, particularly customers’ perceptions on the volatility of natural gas prices over the longer-term.

The agencies that regulate our pipeline businesses and their customers could affect our profitability.

     Our pipeline businesses are extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior, the U.S. Coast Guard, the U.S. Department of Homeland Security and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipelines (including establishing authorized rates of return). Our pipelines periodically file to adjust their rates charged to their customers. CIG will file a rate case that will establish new rates in 2011. There is a risk that the FERC may establish rates that are not acceptable to us or have a negative impact on us. In addition, the profitability of our pipeline systems is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before the pipeline can file and obtain rate increases.

The prices for natural gas and NGLs could be adversely affected by many factors outside of our control which could negatively affect us.

     Our success depends in part upon the prices we receive for our natural gas and NGLs. Natural gas and NGL prices historically have been volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices will remain depressed for sustained periods, especially in relation to natural gas prices which are at relatively low levels at this time. Our business can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas and NGLs including reductions in our ability to enter into or renew pipeline transportation contracts on favorable terms and to construct new pipeline infrastructure. The prices for natural gas and NGLs are subject to a variety of additional factors that are outside of our control, which include, among others:

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Changes in regional, domestic and international supply and demand;

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Volatile trading patterns in commodity-futures markets;

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Changes in basis differentials among different supply basins that can negatively impact the ability of our business to compete with supplies from other basins, including our ability to maintain pipeline transportation revenues and to enter into or renew transportation contracts in any supply basins that are not as competitive with other alternatives;

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Changes in the costs of exploring for, developing, producing, transporting, processing and marketing natural gas;

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Increased federal and state taxes, if any, on the sale or transportation of natural gas and NGLs; and

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The price and availability of supplies of alternative energy sources.

Our business is subject to competition from third parties which could negatively affect us.

     The natural gas pipeline business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies in the transportation and storage of natural gas. We also compete with suppliers of alternate sources of energy, including electricity, coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes new large pipeline systems that have recently been constructed from supply basins in which one or more of our pipelines are located (including Bison and Rockies Express) and growing competition in many of the markets that we serve. There have also been various proposals over time to construct LNG terminals and new pipelines that could also negatively impact the demand and the transportation rates that several of our pipeline systems could charge to the extent the LNG terminals were constructed. This competition could result in our inability to renew contracts and to maintain rates and transportation volumes, any of which could have a material adverse effect on our business.

The success of our pipeline business depends on many factors beyond our control.

     The results of our pipeline business are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for these services. The volumes of natural gas we are able to transport and store depend on the actions of third parties that are beyond our control. Such actions include factors that negatively impact our customers’ demand for natural gas and could expose our pipelines to the risk that we will not be able to renew contracts at expiration or that will require us to discount our rates significantly upon renewal. In addition, some of our pipeline systems are not fully subscribed. We are also highly dependent on our customers and downstream pipelines to attach new and increased loads on their systems in order to grow our pipeline business. Further, state agencies that regulate our pipelines’ local distribution company customers could impose requirements that could impact demand for our pipelines’ services.

     The volume of gas that we are able to transport and store also depends on the availability of natural gas supplies that are attached to our pipeline systems, including the need for producers to continue to develop additional natural gas supplies to offset the natural decline from existing wells connected to our systems. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our systems. There have been major shifts in supply basins over the last few years, especially with regard to the development of new natural gas shale plays and declining production from conventional sources of supplies as well as declining deliveries from Canada. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transportation and storage through our systems.

     Furthermore, our ability to deliver gas to our shippers is dependent upon their ability to purchase and deliver gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the gas delivered by our shippers at the receipt points into our system is less than the gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand.

     Our operations are subject to operational hazards and uninsured risks which could negatively affect us.

     Our operations are subject to inherent risks including fires, earthquakes, adverse weather conditions (such as extreme cold or heat, hurricanes, tornadoes, lightning and flooding) and other natural disasters; terrorist activity or acts of aggression; the collision of equipment of third parties on our infrastructure (such as damage caused to our underground pipelines by third party excavation or construction); explosions, pipeline failures, mechanical and process safety failures, well blowouts, formations with abnormal pressures and collapses of wellbore casing or other tubular events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, oil, brine or well fluids, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards. Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. Our offshore operations may encounter additional marine perils, including hurricanes and other adverse weather conditions, damage from collisions with vessels, and governmental regulations. 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, particularly with regard to any of our facilities that are located in or near the Gulf of Mexico and other coastal regions.

     While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, we do not carry or are unable to obtain insurance coverage on terms we find acceptable for certain environmental exposures, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption, named windstorm / hurricane exposures and, in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.

Certain of our pipeline systems’ transportation services are subject to “negotiated rate” contracts that may not allow us to recover our costs of providing the services.

     Under FERC policy, interstate pipelines and their customers may execute contracts at a negotiated rate which may be above or below the FERC-regulated recourse rate for that service. These negotiated rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increase in cost of capital, taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, representing the difference between recourse rates and negotiated rates could result in either losses or lower rates of return in providing such services.

     The revenues of our pipeline business are generated under contracts that must be renegotiated periodically.

     Substantially all of our pipeline revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we 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 example, basis differentials between receipt and delivery points on our pipeline systems could decrease over time and thereby negatively impact our ability to renew contracts at rates that were previously in place. Our ability to extend and replace contracts could be adversely affected by factors we cannot control. In addition, changes in state regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.

The expansion of our pipeline systems by constructing new facilities subjects us to construction and other risks that may adversely affect us.

     We frequently expand the capacity of our existing pipeline, storage or LNG facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

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our ability to obtain necessary approvals and permits from the FERC and other regulatory agencies on a timely basis that are on terms that are acceptable to us, including the potential negative impact of delays and increased costs caused by general opposition to energy infrastructure development, especially in environmentally and culturally sensitive areas and more heavily populated areas;

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the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;

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the availability of skilled labor, equipment, and materials to complete expansion projects;

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potential changes in federal, state and local statutes, regulations, and orders;

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impediments on our ability to acquire rights-of-way or land rights on terms that are acceptable to us;

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our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel), labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact our return on our investments;

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our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;

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the failure of suppliers and contractors to meet their performance and warranty obligations; and

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the lack of transportation, storage or throughput commitments.

     Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its negative impact upon natural gas demand may result in either slower development in the potential for future 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.

We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.

     Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trade Commission (FTC), FERC and U.S. Commodity Futures Trading Commission (CFTC) to impose penalties for violations in these areas has generally increased over the last few years. In addition, our business is subject to laws and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain

pollution controls and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we operate pipeline facilities that are located on federal lands located both onshore and offshore, which are regulated by the Department of the Interior, particularly by the Bureau of Land Management (BLM) and the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE). In addition, we also have pipeline operations on Native American tribal lands, which are regulated by the Department of the Interior, particularly by the Bureau of Indian Affairs, as well as local tribal authorities. Operations on these properties are often subject to additional regulations and compliance obligations, which can delay our access to such lands and impose additional compliance costs.

     In addition, the FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipelines (including establishing authorized rates of return). Many of our pipelines periodically file to adjust their rates charged to their customers. CIG will file a rate case that will establish new rates in 2011. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, the profitability of our pipeline systems is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before the pipeline can file and obtain rate increases, such events can have a negative impact upon our operating results. Our existing rates may also be challenged by complaint. The FERC commenced several proceedings in 2009 and 2010 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 us. The FERC currently allows publicly traded partnerships to include in their cost-of-service an income tax allowance. Any changes to FERC’s treatment of income tax allowances in cost of service could result in lower recourse rates that could negatively impact our unitholders’ investment in us.

The laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operations or otherwise negatively impact us.

     The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws or regulations may be enacted or existing laws and regulation may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to implement or amend federal, state, local and tribal laws and regulations that could negatively impact our business, which includes among others:

•

Climate Change and other Emissions. There have been various legislative and regulatory proposals at the federal and state levels to address climate change and to regulate greenhouse gas (GHG) emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have already adopted regulations to regulate GHG emissions. Although natural gas as a fuel supply for power generation results in the least GHG emissions of any fossil fuel, it is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted, including the level of any emission standards; the amount and costs of allowances, offsets and credits granted; and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject many of our larger facilities to regulation prior to 2016. There have also been various legislative and regulatory proposals at the federal and state levels to address various emissions from coal-fired power plants. Although such proposals will generally favor the use of natural gas fired power plants over coal fired power plants, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been other various environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs.

For example, the EPA has proposed more stringent ozone standards, as well as implemented more stringent emission standards with regard to certain combustion engines on our pipeline systems. It is uncertain what impact new environmental regulations might have on us until further definition is provided in the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by requiring us to monitor emissions, install additional equipment to reduce carbon emissions and possibly to purchase emission credits, as well as potentially delay the receipt of permits and other regulatory approvals. 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.

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Renewable / Conservation Legislation. There have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.

•

Pipeline Safety. Various legislative and regulatory reforms associated with pipeline safety and integrity issues have been recently proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipelines or otherwise subject our pipelines to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.

•

Tax Policies. Various federal legislation has been proposed to materially revise the tax provisions associated with the energy industry. For example, previous proposed changes have included changes to the taxation of carried interests, which could potentially change the taxation of sales or exchange of partnership interests such as ours. There have also been proposals to simplify the tax code by generally eliminating deductions and reducing the effective corporate and individual tax rates, which could negatively impact the tax allowance in our FERC-approved pipeline rates and impact the return and yield expectations of our investors. It is unclear whether these or other changes will be enacted and if enacted when they will become effective. Any such changes could negatively impact us.

Our pipeline systems depend on certain key customers for a significant portion of their revenues and the loss of any of these key customers could result in a decline in our revenues. In addition, we are exposed to the credit risk of our counterparties and our credit risk management may not be adequate to protect against such risk.

     We are subject to the risk of our counterparties failing to make payments to us, which may include payments not being received within the time required under our contracts. Our current largest exposures are associated with shippers under long-term transportation contracts on our pipeline systems. For example, our systems rely on a limited number of customers for a significant portion of our systems’ revenues. For the year ended December 31, 2010, the four largest customers for each of WIC, CIG, SNG, SLNG and Elba Express accounted for approximately 66 percent, 60 percent, 36 percent, 100 percent and 100 percent of their respective operating revenues. The loss of all or 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 us. Our credit procedures and policies that are governed by the FERC may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we may not be able to effectively remarket capacity during and after insolvency proceedings involving a customer.

We are exposed to the credit and performance risk of our key contractors and suppliers.

     As an owner of large energy infrastructure facilities with significant capital expenditures in our business, we rely on contractors for certain construction and on suppliers for key materials, supplies and services, including steel mills, pipe and other 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, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each of which could adversely impact us.

The costs to maintain, repair and replace our pipeline systems may exceed our expected levels.

     Much of our pipeline infrastructure was constructed many years ago. The age of these assets may result in them being more costly to maintain and repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or other incidents due to factors outside of our control (including due to third party excavation near our pipelines, unexpected degradation of our pipelines, as well as design, construction or manufacturing defects) that could result in personal injury or property damages. Much of our pipeline system is located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and use of in-line inspection tools in high consequence areas by its required completion date at the end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipelines. Also, there is a risk of gas loss and field degradation for our storage operations. In addition, there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future.

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 are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way may lapse or terminate or our facilities may not be properly located within the boundaries of such rights-of-way. Our loss of or interference with these rights could have a material adverse effect on us.

There are accounting principles that are unique to regulated interstate pipeline assets that could materially impact our recorded earnings.

     Accounting policies for FERC regulated pipelines are in certain instances different from nonregulated entities. For example, regulated operations accounting policies permit certain regulatory assets to be recorded on our balance sheet that would not be recorded for nonregulated entities. In determining whether to account for regulatory assets on each of our pipelines, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these assets. Currently, all of our pipeline systems have regulatory assets recorded on their balance sheets. If we determine that future recovery is no longer probable for any of our pipeline systems, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of long-lived assets. To the extent that one or more of our pipeline expansion projects is not fully subscribed when it goes into service, we could experience a reduction in our earnings once the pipeline is placed into service.

Our business requires the retention and recruitment of a skilled workforce and the loss of such workforces could result in the failure to implement our business plans.

     We are managed and operated by El Paso and its affiliates. Such operations and management require the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. El Paso competes with other companies in the energy industry for this skilled workforce. In addition, many of El Paso’s current employees are retirement eligible, which have significant institutional knowledge that must be transferred to other employees. If El Paso is unable to (a) retain their current employees, (b) successfully complete the knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.

We have certain contingent liabilities that could exceed our estimates.

     We have certain contingent liabilities associated with litigation. We are involved in various lawsuits in which we or our subsidiaries have been sued (see Part II, Item 8, Financial Statements and Supplementary Data, Note 9). Although we believe that we have established appropriate reserves for these litigation liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.

Risks Related to Our Liquidity

We depend on distributions from our subsidiaries to meet our needs.

     We have no significant assets other than our ownership interests in our operating subsidiaries. We are dependent on the earnings and cash flows, dividends, loans or other distributions from our subsidiaries to generate the funds necessary to meet our obligations. Applicable law and contractual restrictions (including restrictions in certain of our subsidiaries’ credit facilities and the rights of certain creditors of our subsidiaries that would often be superior to our interests) may negatively impact our ability to obtain such distributions from our subsidiaries.

     The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may increase cash distributions during periods when we experience reductions in net income for financial accounting purposes and may reduce cash distributions during periods when we experience increases in net income for financial accounting purposes.

We have significant existing debt which requires us to dedicate a substantial portion of our cash flows to service our debt payment obligations, as well as reduces our flexibility to respond to changed circumstances.

     We have significant debt, debt service and debt maturity obligations. This requires us to dedicate a material portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions or general partnership purposes, as well as distributions to our unitholders. In addition, these debt levels expose us to liquidity and default risks, especially during times of financial volatility and reduced commodity prices.

We have significant capital programs in our business that require us to access capital markets frequently and any inability to obtain access to the capital markets in the future at competitive rates could have a negative impact on us.

     We have extensive capital programs in our business, which requires us to frequently access the capital markets. Although the markets have become less volatile than they were in recent years, volatility in the financial market remains. We are rated investment grade by Fitch (BBB-) and below investment grade by Moody’s (Ba1) and Standard & Poor’s (BB) Rating services at this time, thus our ability to access the capital markets and the cost of capital could be negatively impacted in the future. This could require us to forego capital opportunities, make those opportunities less attractive to us or make us less competitive in our pursuit of growth opportunities.

Our current and future debt and associated borrowing costs can be negatively impacted by the ratings assigned to our debt facilities and securities, the credit and risk profile of our general partner and its owner, El Paso, which could have a negative impact upon us.

     Our credit ratings may be adversely affected by the leverage of our general partner or El Paso, as credit rating agencies 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. El Paso is rated below investment grade by Moody’s (Ba3), Standard & Poor’s (BB-) and Fitch (BB+). The ratings assigned to both CIG’s and SNG’s senior unsecured indebtedness by Moody’s Investor Services (Baa3) and Fitch (BBB-) are currently investment grade. Standard & Poor’s Rating services currently has both CIG and SNG at non-investment grade (BB). Moody’s Investor Services, Standard & Poor’s Investor, and Fitch services both provide a stable outlook. These ratings have increased our cost of capital and our operating costs in comparison to some of our peers. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies review their general credit requirements as well as review our leverage, liquidity and credit profile. Any reduction in our credit rating could also impact our cost of capital. Any reduction in our credit rating could also negatively impact the credit rating of our subsidiaries, which could also increase their cost of capital. It could also impact our ability, as well as the ability of our subsidiaries, to access the capital markets. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our debt instruments, as well as the market value of our units.

We will be negatively impacted if we are unable to renew our revolving credit facility that expires November 2012.

     We have a corporate revolving credit facility that is due to expire November 2012. Prior to its maturity, we plan to renew or extend this credit facility. However, many other companies have similar expiration and renewal requirements, and we will be competing for available credit capacity of the financial institutions, many of which are in the process of deleveraging their balance sheets. It is likely that the cost of such credit facilities (spreads over LIBOR) will increase above current levels. The amount of credit capacity we are able to obtain and the ultimate cost of such credit could have a negative impact upon our liquidity, cost of capital and financial results.

A breach of the covenants applicable to our debt and other financing obligations could affect our ability to borrow funds, could accelerate our debt and other financing obligations and those of our subsidiaries, and reduce our cash available for distribution to our unitholders.

     Our debt and other financing obligations contain restrictive covenants, including debt to earnings before interest, income taxes, depreciation and amortization (EBITDA) and EBITDA to interest expense in our note purchase agreements, and contain cross default provisions. Volatility in the financial markets and a reduction in access to capital could cause these covenants to become more restrictive during refinancing. A breach of any of these covenants could preclude us or our subsidiaries from issuing letters of credit, from borrowing under our credit agreements and could accelerate our debt and other financing obligations and those of our subsidiaries. If this were to occur, we might not be able to repay such debt and other financing obligations. 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.

Restrictions in our credit facility and note purchase agreement could limit our ability to make distributions to our unitholders.

     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. Our payment of principal and interest on any future indebtedness will reduce our cash available for distribution on our units.

     We are subject to interest rate risks.

     Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future. Rising interest rates could also negatively impact our unitholders’ investment in us, as changes in interest rates may affect the yield requirements of investors in our units. It may also negatively impact our ability to issue additional equity to make acquisitions, to incur debt or for other purposes.

Risks Inherent in Our Structure and Relationship with El Paso

Our ability to continue to acquire interests in interstate pipelines from El Paso could be negatively impacted by various factors that would reduce our growth opportunities.

     An important source of our growth in the past and potentially in the future is the purchase of interests in interstate pipelines from El Paso. As our general partner, El Paso is entitled to incentive distribution rights (IDRs). El Paso is currently entitled to receive the maximum level of IDRs. Our ability to purchase additional interests on an accretive basis to the limited partner unitholders may be negatively impacted by such IDRs unless El Paso elects to reduce the level of the IDRs as provided for in the partnership agreement. In addition, as the general partner of the partnership, El Paso could also be subject to claims associated with conflicts of interest and breach of fiduciary duties. Although the partnership agreements expressly define and limit its obligations as the general partner, if any conflicts of interest or breach of fiduciary duties are found, then our ability to purchase additional interests in interstate pipeline assets from El Paso could be negatively impacted.

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service the notes or to repay them at maturity.

     Unlike a corporation, EPB’s partnership agreement requires EPB to distribute, on a quarterly basis, 100 percent of its available cash to its unitholders of record and its general partner. Available cash is generally defined as all of EPB’s cash-on-hand as of the end of a fiscal quarter, adjusted for cash distributions and net changes to reserves. EPB’s general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to its reserves or the reserves of EPB’s operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:

	•		to provide for the proper conduct of our business and the businesses of EPB’s operating subsidiaries (including reserves for future capital expenditures and for EPB’s anticipated future credit needs);
	•		to reimburse EPB’s general partner for all expenses it has incurred on EPB’s behalf;
	•		to provide funds for distributions to EPB’s unitholders and its general partner for any one or more of the next four calendar quarters; or
	•		to comply with applicable law or any of EPB’s loan or other agreements.

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.

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), Bear Creek Storage Company, LLC (Bear Creek), Ruby Pipeline, L.L.C. and Tennessee Gas Pipeline (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 us.

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.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common 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 40 percent general partner interest in CIG and SNG, and we own a 58 percent and 60 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 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 66 ⅔ percent of all outstanding common units voting together as a single class is required to remove our general partner. 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. 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.

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.

     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, SLNG and Elba Express, a 58 percent general partner interest in CIG and a 60 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 or SNG or other assets acquired in the future 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. 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.

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;
	•		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, 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 49 percent of our outstanding common units at December 31, 2010.

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.

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 February 17, 2011, we had 177,167,863 common units outstanding, which includes 88,400,059 common units held by affiliates of our general partner. Upon payment of the quarterly cash distribution payment for the fourth quarter of 2010, the financial tests required for the conversion of all subordinated units into common units were satisfied. As a result, the 27,727,411 subordinated units held by affiliates of El Paso Corporation were converted on February 15, 2011 on a one-for-one basis into common units effective January 3, 2011. 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.

Risks Related to our Senior Unsecured Notes

The notes are unsecured obligations of El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC) and not guaranteed by any of its subsidiaries. As such, the notes are effectively junior to EPPOC’s existing and future secured debt and to all debt and other liabilities of its subsidiaries.

     The notes are EPPOC’s unsecured obligations and rank equally in right of payment with all of its other existing and future unsubordinated debt. All of EPPOC’s operating assets are in subsidiaries of EPPOC, and none of these subsidiaries guarantee EPPOC’s obligations with respect to the notes. Creditors of EPPOC’s subsidiaries have claims with respect to the assets of those subsidiaries that rank effectively senior to the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of those creditors would be satisfied prior to making any such distribution or payment to EPPOC in respect of its direct or indirect equity interests in such subsidiaries. Consequently, after satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of the notes. As of December 31, 2010, the notes were effectively subordinated to approximately $2.0 billion of outstanding indebtedness of EPPOC’s subsidiaries. Furthermore, such subsidiaries are not prohibited under the indenture from incurring additional indebtedness.

     In addition, because the notes and the guarantee of the notes by EPB are unsecured, holders of any secured indebtedness of EPPOC or EPB would have claims with respect to the assets constituting collateral for such indebtedness that are senior to the claims of the holders of the notes. Currently, neither EPPOC nor EPB have any secured indebtedness. Although the indenture governing the notes places some limitations on the ability of EPPOC to create liens securing debt, there are significant exceptions to these limitations, which allow us to secure significant amounts of indebtedness without equally and ratably securing the notes. If EPPOC or EPB incur secured indebtedness and such indebtedness is either accelerated or becomes subject to a bankruptcy, liquidation or reorganization, the assets of EPPOC or EPB would be used to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made on the notes. Consequently, any such secured indebtedness would effectively be senior to the notes and the guarantee of the notes by EPB, to the extent of the value of the collateral securing the secured indebtedness. In that event, the noteholders may not be able to recover all the principal or interest that is due under the notes.

We may not be able to repurchase the notes upon a change of control.

     Upon the occurrence of a change of control trigger event, we will be required to offer to repurchase all outstanding notes at 101 percent of their principal amount plus accrued and unpaid interest. We may not be able to repurchase the notes upon a change of control trigger event because we may not have sufficient funds. Further, we may be contractually restricted under the terms of our revolving credit facility or other future senior indebtedness from repurchasing all of the notes tendered by holders upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase your notes unless we are able to refinance or obtain waivers under our credit facilities. Our failure to repurchase the notes upon a change of control would cause a default under the indenture and a cross-default under our revolving credit facility. Our revolving credit facility provides that a change of control, as defined in such agreement, will be a default that permits lenders to accelerate the maturity of borrowings thereunder and limiting our ability to purchase the notes, and reducing the practical benefit of the offer to purchase provisions to the holders of the notes. Any of our future debt agreements may contain similar provisions. In addition, the change of control provisions in the indenture may not protect the noteholders from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction.

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes and our indebtedness under our revolving credit facility, and we may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

     Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure the noteholders that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure the noteholders that we would be able to take any of these actions, that these actions would be successful and would permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements, including our credit agreement and the indenture that will govern the notes. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our revolving credit facility contains restrictions on our ability to dispose of assets. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them, and any proceeds may not be adequate to meet any debt service obligations then due.

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 (IRS) 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 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. 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.

     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. During the last session of Congress, the House of Representatives passed the Tax Extenders Act of 2009, H.R. 4213, a bill which included 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. The carried interest portion of this bill did not pass the Senate during the Congressional session. The legislation could be re-introduced in the new Congress. Although we do not believe that this provision would apply to us as it was previously drafted, we are unable to predict whether it will be re-introduced in its previous form, or with any changes to the provision or whether carried interest legislation will ultimately be enacted. Moreover, it is possible that the efforts regarding current carried interests 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 IRS challenge of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS 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 challenge by 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.

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 to 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.

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 9, and is incorporated herein by reference.

     Natural Buttes. In May 2004, the 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 U.S. 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 $1.0 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. Pursuant to the 2009 FERC order approving the sale of the compressor station and gas processing plant, we filed for FERC approval of the proposed accounting entries associated with the sale which utilized a technical obsolescence valuation methodology for determining the portion of the composite accumulated depreciation attributable to the plant which resulted in us recording a gain on the sale in the fourth quarter of 2009. In September 2010, the FERC issued an order that utilized a different depreciation allocation methodology to estimate the net book value of the facilities. Based on the order, we recorded a non-cash adjustment as an increase of operation and maintenance expense of approximately $20.8 million in September 2010 to write down the net property, plant and equipment associated with the sale of the Natural Buttes facilities since it is no longer probable of recovery. We have filed a request for rehearing and clarification of the order.

     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. (REMOVED AND RESERVED)

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 22, 2011, we had 30 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
2010
Fourth Quarter		$	35.74			$	31.34			$	0.4100
Third Quarter		$	33.84			$	27.40			$	0.4000
Second Quarter		$	30.77			$	23.62			$	0.3800
First Quarter		$	28.31			$	23.35			$	0.3600
2009
Fourth Quarter		$	26.52			$	19.98			$	0.3500
Third Quarter		$	21.30			$	17.14			$	0.3300
Second Quarter		$	19.80			$	16.53			$	0.3250
First Quarter		$	20.00			$	14.91			$	0.3200

     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 15, 2011, we paid a distribution of $0.4400 per unit to all unitholders of record at the close of business on February 1, 2011. 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 $8.0 million in 2010. In February 2011, our general partner received incentive distributions of $6.1 million.

     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 of any quarter beginning after December 31, 2010 after (i) 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 on/or after December 31, 2008, or (ii) 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, or (iii) 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. Upon payment of the quarterly cash distribution payment for the fourth quarter of 2010, the financial tests required for the conversion of all subordinated units into common units were satisfied. As a result, the 27,727,411 subordinated units held by affiliates of El Paso were converted on February 15, 2011 on a one-for-one basis into common units effective January 3, 2011. The conversion does not impact the amount of cash distribution paid or the total number of the Partnership’s outstanding units.

ITEM 6. SELECTED FINANCIAL DATA

     The operating results data for each of the three years ended December 31, 2010 and the financial position data as of December 31, 2010 and 2009 were derived from our audited financial statements. We derived the operating results data for each of the two years ended December 31, 2007 and the financial position data as of December 31, 2008, 2007 and 2006 from our accounting records. Our historical results are not necessarily indicative of results to be expected in the future. We had various acquisitions as discussed in Note 2. Subsequent to the July 2009, March 2010 and November 2010 acquisitions, we have the ability to control CIG’s, SLNG’s, Elba Express’ and SNG’s operating and financial decisions and policies. Accordingly, we have consolidated the entities and retrospectively adjusted our historical financial statements in all periods to reflect the changes in reporting entity. Because the November 2010 acquisition of the remaining interest in SLNG and Elba Express was the acquisition of additional non-controlling interests in a consolidated entity, this acquisition was accounted for on a prospective basis. For a further discussion of each of these acquisitions and the retrospective adjustment of our historical financial statements, see Item 8, Financial Statements and Supplementary Data, Note 2.

     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,
		2010				2009				2008				2007				2006
		(In millions, except per unit amounts)
Operating Results Data:
Operating revenues		$	1,344.1			$	1,119.3			$	1,064.4			$	968.0			$	921.7
Operating income			747.1				582.8				532.3				483.7				464.7
Earnings from unconsolidated affiliates			15.7				12.4				15.9				89.8				78.0
Net income from continuing operations			605.1				497.2				474.5				393.0				338.2
Net income			605.1				497.2				474.5				396.0				342.8
Net income attributable to El Paso Pipeline Partners, L.P.			378.5				317.6				300.8				257.1				227.5
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit-basic and diluted
Common units(1)		$	1.90			$	1.64			$	1.26			$	0.11			$	—
Subordinated units(1)			1.78				1.56				1.12				0.11				—
Distributions declared per common unit(2)		$	1.55			$	1.33			$	1.01			$	—			$	—
Financial Position Data:
Property, plant and equipment, net		$	5,691.5			$	5,408.3			$	4,796.2			$	4,112.4			$	3,594.9
Investment in unconsolidated affiliates			71.7				93.5				98.4				102.0				711.1
Total assets			6,177.2				6,164.2				5,618.7				5,069.8				5,707.0
Long-term debt and other financing obligations, less current maturities			3,400.3				2,536.2				2,266.9				2,136.0				1,704.6
Total partners’ capital			2,410.0				3,181.6				2,813.8				3,052.0				2,882.1

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 initial public offering, 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. In September 2008, we acquired a 15 percent general partner interest in SNG and 30 percent general partner interest in CIG from El Paso. In July 2009, we acquired an 18 percent general partner interest in CIG from El Paso. In March 2010 we acquired a 51 percent member interest in each of SLNG and Elba Express from El Paso at which point we had the ability to control SLNG’s and Elba Express’ operating and financial decisions and policies, thus have consolidated these entities in our financial statements. We have retrospectively adjusted our historical financial statements in all periods to reflect the reorganization of entities under common control and the change in reporting entity. In June 2010, we acquired an additional 20 percent general partner interest in SNG. In November 2010, we acquired the remaining 49 percent member interest in each of SLNG and Elba Express and an additional 15 percent general partner interest in SNG. Subsequent to the 2009 and 2010 acquisitions, we have the ability to control CIG’s and SNG’s operating and financial decisions and policies. Accordingly, we have consolidated CIG and SNG and retrospectively adjusted our historical financial statements. Because the acquisition of the remaining 49 percent member interest in SLNG and Elba Express was an acquisition of additional non-controlling interest in a consolidated entity, we accounted for the acquisition prospectively. We have reflected El Paso’s 42 percent general partner interest in CIG and El Paso’s 40 percent general partner interest in SNG as non-controlling interest in our financial statements for all periods presented. As a result of the retrospective consolidation of CIG, SLNG, Elba Express and SNG, earnings prior to the acquisition of the incremental interests have been allocated solely to our general partner.

     For a further discussion of each of these acquisitions and the retrospective adjustment of our historical financial statements, see Item 8, Financial Statements and Supplementary Data, Note 2.

     We have included a discussion in this MD&A of items that may affect us and how we 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 3.5 Bcf/d and an average daily throughput of 2,472 BBtu/d in 2010. We also hold a 100 percent ownership interest in each of SLNG and Elba Express. SLNG owns the Elba Island LNG receiving terminal, one of eleven facilities in the United States capable of providing domestic storage and vaporization services to international producers of LNG. The Elba Island LNG terminal has storage capacity of 11.5 Bcf equivalent and has peak send-out capacity of approximately 1.8 Bcf/d. Elba Express is an interstate natural gas pipeline system with approximately 200 miles of pipeline with a design capacity of 945 MMcf/d. Elba Express was placed in service in March 2010.

     We also own a 58 percent general partner interest in CIG and a 60 percent general partner interest in SNG whose operations are summarized below:

CIG. CIG is an interstate natural gas pipeline system with approximately 4,300 miles of pipeline with a design capacity of approximately 4.6 Bcf/d and an average daily throughput of 2,131 BBtu/d in 2010. It has associated storage facilities with 37 Bcf of underground working natural gas storage capacity, which includes 6 Bcf of storage capacity from Totem 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 of 2,505 BBtu/d in 2010. 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 Tennessee Gas Pipeline Company (TGP), our affiliate.

     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:

				Percent of Total Revenues in 2010(2)
																Elba
Type		Description		WIC				CIG				SLNG				Express(1)				SNG				Total
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	%			92	%			92	%			100	%			88	%			91	%
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.			2	%			8	%			8	%			—				12	%			9	%

     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. We also experience earnings volatility when amounts of natural gas used in our operations differs from the amount received for that purpose.

     SNG Rate Case. In January 2010, the FERC approved SNG’s rate case 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 but no later than September 1, 2013, and (iv) extended the vast majority of SNG’s firm transportation contracts until August 31, 2013.

     CIG Rate Case. Under the terms of the 2006 rate case settlement, CIG must file a new general rate case to be effective no later than October 1, 2011. In February 2011, FERC approved an amendment of the 2006 settlement, which is unopposed by all of CIG’s shippers, to provide for a modification allowing the effective date of the required new rate case to be moved to December 1, 2011.

The purpose of the delay in filing date is to allow CIG and its shippers the opportunity to reach a settlement of the rate proceeding before it is formally filed at FERC. At this time, the outcome of the pre-filing settlement negotiations and the outcome of the upcoming general rate case, in the event pre-filing settlement cannot be reached, cannot be known with certainty.

     Growth Projects. During 2010, we generated significant earnings and continued to focus on delivering on our remaining backlog of expansion projects. During 2010, we placed approximately $1 billion of expansion projects into service, all on time and in total approximately $100 million under budget. We intend to grow our business through organic expansion opportunities and through strategic asset acquisitions from third parties, El Paso or both. Listed below are significant updates to our backlog of projects:

     WIC. In November 2010, both portions of the WIC system expansion project were placed in service. The first portion of the WIC system expansion project added compression on the Kanda Lateral and increased capacity to 595 MDth/d. The second portion of the WIC expansion project installed three miles of pipeline and reconfigured one compressor at the Wamsutter station. Such expansion provided 155 MDth/d of additional natural gas deliveries from WIC mainline into a third party pipeline and onto the Opal Hub and El Paso’s Ruby Pipeline that is currently under construction.

     CIG. In December 2010, CIG placed in service the Raton 2010 expansion project. This project provides additional capacity of approximately 130 MMcf/d from Raton Basin in southern Colorado to the Cheyenne Hub in northern Colorado.

     SLNG/Elba Express. In March and July 2010, SLNG placed in service vaporization facilities and additional storage facilities, at the Elba Island LNG terminal as part of the Elba III Phase A Expansion. In March 2010, the Elba Express Phase A expansion was placed in service.

•

SLNG Elba III Expansion. The Elba III Phase A Expansion increased SLNG’s peak send-out capacity to 1.8 Bcf/d equivalent from 1.2 Bcf/d in March 2010 and increased storage capacity at the Elba Island LNG terminal to approximately 11.5 Bcf in July 2010.

•

Elba Express Expansion. In 2010, the Elba Express Phase A Expansion added an approximate 200-mile pipeline with a design capacity of 945 MMcf/d that transports natural gas supplies from the Elba Island LNG terminal to markets in the southeastern and eastern U.S.

     SNG. SNG expects to spend approximately $125 million in 2011. These expenditures are 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, with each phase expected to add an additional 122 MMcf/d of capacity. Phase I of the project was placed in service in January 2011 on time and under budget. The estimated in-service dates are June 2011 for Phase II and June 2012 for Phase III. Construction agreements have been finalized for Phase II.

•

Southeast Supply Header (SESH). SNG owns an undivided interest in the northern portion (Phase I) of the Southeast Supply Header project jointly owned by Spectra Energy Corp and CenterPoint Energy, which added a 115-mile supply line to the western portion of the SNG system. This project provides SNG access through pipeline interconnects to several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale basins. Phase I of the project was placed in service in September 2008. The estimated cost to SNG for Phase II of this project is approximately $60 million and is expected to provide SNG with an additional 350 MMcf/d of supply capacity. We expect to place Phase II of the project in service in June 2011.

     Total consolidated capital expenditures for 2011 are expected to be approximately $260 million, including approximately $110 million of maintenance capital and approximately $150 million of expansion capital. The partnership’s growth capital is primarily for SNG’s South System III expansion.

     We continue to evaluate additional expansion opportunities around our well-positioned assets. We have other projects that are in various phases of commercial development. Many of these potential projects involve expansion capacity to serve increased natural gas-fired generation loads and 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. The development projects are in various phases of commercial development.

Results of Operations

     Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our businesses, which consists of both consolidated operations and investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to evaluate more effectively our operating performance using the same performance measure analyzed internally by El Paso so that investors may evaluate our operating results without regard to our financing methods or capital structure. We define EBIT as net income adjusted for items such as (i) interest and debt expense, net, (ii) affiliated interest income and expense, net, (iii) income tax expense, and (iv) net income attributable to noncontrolling interest. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT 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 to net income, our throughput volumes and an analysis and discussion of our operating results for each of the three years ended December 31, 2010, which reflects the retrospective adjustment of our historical financial statements discussed in Item 8, Financial Statements and Supplementary Data, Note 2.

		2010				2009				2008
		(in millions, except volumes)
Operating revenues		$	1,344.1			$	1,119.3			$	1,064.4
Operating expenses			(597.0	)			(536.5	)			(532.1	)
Operating income			747.1				582.8				532.3
Earnings from unconsolidated affiliates			15.7				12.4				15.9
Other income, net			29.2				47.8				33.8
EBIT before adjustment for noncontrolling interests			792.0				643.0				582.0
Net income attributable to noncontrolling interests			226.6				179.6				173.7
EBIT			565.4				463.4				408.3
Interest and debt expense, net			(186.6	)			(129.0	)			(129.3	)
Affiliated interest income, net			2.1				4.4				40.1
Income tax expense			(2.4	)			(21.2	)			(18.3	)
Net income attributable to El Paso Pipeline Partners, L.P.			378.5				317.6				300.8
Net income attributable to noncontrolling interests			226.6				179.6				173.7
Net income		$	605.1			$	497.2			$	474.5
Throughput volumes (BBtu/d) (1)			6,925				7,142				6,926

     Below is a discussion of factors impacting EBIT in 2010 compared with 2009 and 2009 as compared with 2008.

		2010 to 2009																2009 to 2008
		Revenue				Expense				Other				Total				Revenue				Expense				Other				Total
		Favorable/(Unfavorable)
		(In millions)
Expansion		$	156.8			$	(23.7	)		$	(14.9	)		$	118.2			$	94.7			$	(22.4	)		$	10.8			$	83.1
Transportation revenues and expenses			65.3				(13.6	)			—				51.7				14.5				(4.0	)			—				10.5
Operational gas, revaluations and processing revenues			1.4				9.3				—				10.7				(16.3	)			9.6				—				(6.7	)
(Non-cash asset write down)/ Gain on sale of assets			—				(28.5	)			—				(28.5	)			—				7.8				—				7.8
Calpine Bankruptcy			—				—				—				—				(38.7	)			—				—				(38.7	)
Other(1)			1.3				(4.0	)			(0.4	)			(3.1	)			0.7				4.6				(0.3	)			5.0
Total impact on EBIT before adjustment for noncontrolling interests			224.8				(60.5	)			(15.3	)			149.0				54.9				(4.4	)			10.5				61.0
Net income attributable to noncontrolling interests			—				—				(47.0	)			(47.0	)			—				—				(5.9	)			(5.9	)
Total impact on EBIT		$	224.8			$	(60.5	)		$	(62.3	)		$	102.0			$	54.9			$	(4.4	)		$	4.6			$	55.1

     Expansions. Our EBIT increased during the years ended December 31, 2010 and 2009 primarily due to expansion projects placed into service during 2008, 2009 and 2010. This increase was driven by higher revenues partially offset by an increase in operating expenses and lower non-cash allowance for equity funds used during construction (AFUDC equity) from expansion projects, as follows:

		2010 to 2009				2009 to 2008
		(In millions)
WIC
Piceance lateral		$	10.1			$	9.9
Medicine Bow lateral			0.7				9.3
Kanda lateral			2.8				1.1
Other			0.2				—
CIG
Raton Expansion			6.2				0.8
High Plains pipeline			—				28.0
Totem Gas Storage			9.7				14.4
Other			—				3.2
SLNG
Elba III Phase A Expansion			54.4				14.6
Elba Express
Elba Express Pipeline			24.5				15.0
SNG
South System III			6.5				0.5
SESH I			—				(12.7	)
Other			3.1				(1.0	)
Total impact on EBIT		$	118.2			$	83.1

     Transportation Revenues and Expenses. During 2010 and 2009, our SNG system experienced higher revenues of $53.9 million and $22.7 million when compared to prior years as a result of higher tariff rates which became effective September 1, 2009 pursuant to its rate case settlement as discussed below. Additionally, our revenues increased during 2010 when compared to 2009 due to higher reservation revenue of $16.1 million on WIC’s mainline system which was offset by $16.4 million in higher expenses as a result of an increased third party capacity commitment. During 2009, our EBIT was negatively impacted by a $3.5 million transportation contract buy-out cost on CIG and $7.7 million decreased usage revenues on CIG and WIC.

     In January 2010, the FERC approved SNG’s rate case 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 but no later than September 1, 2013, and (iv) extended the vast majority of SNG’s firm transportation contracts until August 31, 2013.

     Operational Gas, Revaluations and Processing Revenues. During 2010, we experienced $8.9 million favorable gas balance revaluations on CIG and WIC when compared to 2009. We also benefited from implementation of SNG’s fuel volumetric tracker of $5.0 million in 2010 as part of its rate case settlement which was partially offset by a $7.3 million unfavorable impact due to the elimination of SNG’s fuel sharing mechanism. During 2009, WIC recorded a $9.6 million unfavorable fuel tracker adjustment which was partially offset by CIG’s $7.2 million favorable fuel tracker adjustment pursuant to the 2009 FERC orders as further discussed below. In 2008, CIG recorded a favorable fuel tracker adjustment of $9.7 million offset by a $4.2 million favorable gas balance revaluation variance on WIC and CIG when compared to 2009. Additionally, SNG experienced $21.6 million favorable revaluation of retained volumes during 2009 when compared to 2008 which was partially offset by costs of $4.5 million associated with condensate replacement. During 2008, SNG’s EBIT was favorably impacted by $15.2 million due to sale of excess gas not used in operations.

     On July 31, 2009 and October 1, 2009, the FERC issued orders to CIG and WIC, respectively, which retroactively unwound the non-volumetric provisions of the fuel and gas cost recovery mechanisms, which exposes us to both positive and negative fluctuations in gas prices related to fuel imbalance revaluations and related gas balance items. This price volatility impacts our earnings through the monthly non-cash revaluation of our gas balance items including fuel trackers, imbalances and operational inventories. We continue to seek options with the FERC and shippers to minimize the price volatility associated with these operational activities.

     In addition, our processing revenues at CIG were largely offset by expenses associated with the gas consumed in processing the liquids. CIG experienced $8.1 million higher processing revenues in 2010 compared to 2009 due to increased demand and favorable prices of natural gas liquids partially offset by $6.8 million higher gas processing expenses as a result of unfavorable gas prices. During 2009, CIG experienced $3.5 million lower processing revenues due to lower prices for natural gas liquids partially offset by $4.6 million lower gas processing expenses due to lower gas prices as compared to 2008.

     Non-cash Asset Write Down /Gain on Sale of Assets. 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. In the third quarter of 2010, we recorded a $20.8 million non-cash write down as an increase of operation and maintenance expense based on a FERC order related to the 2009 sale of the Natural Buttes facilities. For a further discussion of Natural Buttes, see Item 8, Financial Statements and Supplementary Data, Note 2.

     Calpine Bankruptcy. During 2008, SNG received $39 million related to Calpine Corporation’s (Calpine’s) rejection of its transportation contracts with us primarily associated with distributions received under Calpine’s approved plan of reorganization.

     Net Income Attributable to Noncontrolling Interests. We have reflected El Paso’s 42 percent general partner interest in CIG and 40 percent general partner interest in SNG as noncontrolling interest in our financial statements in all periods presented. We reflected the 49 percent member interest in each of SLNG and Elba Express as noncontrolling interest for 2008, 2009, and through November 2010, when EPB acquired the remaining 49 percent interest and they became 100 percent owned by EPB. For the year ended December 31, 2010, 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 Totem Gas Storage expansion project, an increase in SLNG’s net income from its Elba III Phase A Expansion project which was placed in service in March and July 2010, an increase in Elba Express’ net income from placing the Elba Express Pipeline in service in March 2010, and an increase in SNG’s net income primarily from its higher tariff rates effective September 1, 2009 pursuant to their rate case settlement.

Interest and Debt Expense

     For the year ended December 31, 2010, interest and debt expense was $57.6 million higher than in 2009 primarily due to significantly higher average debt outstanding used to partially fund acquisitions and organic expansion projects. The increase in our average debt outstanding was attributable to the debt issuance of $1.3 billion by EPPOC in 2010, see Item 8, Financial Statements and Supplementary Data, Note 7. These increases were partially offset by a decrease in the average balance outstanding under our credit facility from approximately $565 million to $511 million.

     During 2009, our interest and debt expense decreased $0.3 million as compared to 2008 primarily due to lower average interest rates under our credit facility, the repurchase of approximately $290 million of senior notes by CIG and SNG and an increase in AFUDC from Elba Express and the Elba III Expansion project on SLNG. These decreases were partially offset by EPPOC’s September 2008 issuance of $175.0 million of senior unsecured notes, the $165 million nonrecourse project financing agreement entered into by Elba Express in May 2009, the $135 million debt issuance by SLNG in February 2009 and the financing obligations to WYCO. For a further discussion of our long-term financing obligations, see Item 8, Financial Statements and Supplementary Data, Note 7.

     The following table shows the average balance outstanding and the average interest rates under our credit facility for the years ended December 31, 2010 and 2009:

		2010				2009
		(In millions, except for rates)
Average credit facility balance outstanding		$	511			$	565
Average interest rate on credit facility borrowings			0.8	%			0.8	%

Affiliated Interest Income, Net

     CIG, SNG, SLNG and Elba Express participated in El Paso’s cash management program. After we acquired additional interests in each of CIG, SLNG and SNG which required consolidation, their participation in El Paso’s cash management program was terminated. In 2010, SLNG and SNG received $7.5 million and $5.4 million, respectively, in cash from El Paso in settlement of their note receivable balances related to the termination of their participation in El Paso’s cash management program. Elba Express participated in El Paso’s cash management program until May 2009, when, as a result of a restriction in its project financing agreement, it terminated its participation in the cash management program and received a capital contribution from El Paso of its outstanding notes payable. CIG converted its note receivable with El Paso under its cash management program into a demand note receivable, which was repaid in June 2010.

     Affiliated interest income decreased $2.3 million for the year ended December 31, 2010 as compared to 2009 and decreased $35.7 million for the year ended December 31, 2009 as compared to 2008 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:

		2010				2009				2008
		(In millions, except for rates)
Average advance due from El Paso		$	175			$	306			$	927
Average short-term interest rate			1.5	%			1.7	%			4.4	%

Income Taxes

     Effective November 1, 2007, CIG and SNG no longer pay income taxes as a result of their conversion into partnerships. Effective February 4, 2010, SLNG converted into a limited liability company and is no longer subject to income taxes. Our effective tax rates of less than 1 percent for the year ended December 31, 2010, 4 percent for the year ended December 31, 2009 and 4 percent for the year ended December 31, 2008 were lower than the statutory rate of 35 percent due to income associated with non-taxpaying 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 15.

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, pre-acquisition undistributed earnings from consolidated subsidiaries and other income and expenses, net, which primarily includes deferred revenue, 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) income tax expense (ii) interest and debt expense, net of interest income, (iii) affiliated interest income, net of affiliated interest expense, (iv) depreciation and amortization expense, (v) the partnership’s share of distributions declared by unconsolidated affiliates for the applicable period, (vi) earnings from unconsolidated affiliates, and (vii) distributions declared by majority owned subsidiaries to El Paso for the applicable period.

     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. 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 $390.0 million and $236.7 million for the years ended December 31, 2010 and 2009. The increase in distributable cash flow in 2010 was due primarily to higher expansion revenues and our increased ownership interest in SLNG, Elba Express and SNG. The tables below provide our reconciliations of Distributable Cash Flow and Adjusted EBITDA for the years ended December 31, 2010 and 2009 and reflect the retrospective adjustment of our historical financial statements discussed in Item 8, Financial Statements and Supplementary Data, Note 2. :

Reconciliation of Distributable Cash Flow to Net Income.

		Year Ended December 31,
		2010				2009
		(In millions)
Net income		$	605.1			$	497.2
Net income attributable to noncontrolling interests			(226.6	)			(179.6	)
Net income attributable to El Paso Pipeline Partners, L.P.			378.5				317.6
Add: Income tax expense			2.4				21.2
Add: Interest and debt expense, net			186.6				129.0
Less: Affiliated interest income, net			(2.1	)			(4.4	)
EBIT (1)			565.4				463.4
Add:
Depreciation and amortization			152.7				129.2
Distributions declared by unconsolidated affiliates			13.4				16.7
Net income attributable to noncontrolling interests			226.6				179.6
Less:
Earnings from unconsolidated affiliates			(15.7	)			(12.4	)
Declared distributions by majority owned subsidiaries to El Paso (2)			(247.6	)			(232.5	)
Adjusted EBITDA			694.8				544.0
Less:
Cash interest expense, net			(184.9	)			(141.3	)
Maintenance capital expenditures			(94.0	)			(81.0	)
Pre-acquisition undistributed earnings from consolidated subsidiaries(3)			(19.7	)			(30.8	)
Other, net (4)			(6.2	)			(54.2	)
Distributable Cash Flow		$	390.0			$	236.7

Reconciliation of Distributable Cash Flow to Net Cash Provided by Operating Activities.

		Year Ended December 31,
		2010				2009
		(In millions)
Net cash provided by operating activities		$	671.7			$	638.5
Income tax expense			2.4				21.2
Interest and debt expense, net			186.6				129.0
Affiliated interest income, net			(2.1	)			(4.4	)
Declared distributions by majority-owned subsidiaries to El Paso (1)			(247.6	)			(232.5	)
SLNG pre-acquisition taxes payable			12.1				(2.8	)
SLNG pre-acquisition accumulated deferred taxes			58.2				—
Changes in working capital and other			13.5				(5.0	)
Adjusted EBITDA			694.8				544.0
Less:
Cash interest expense, net			(184.9	)			(141.3	)
Maintenance capital expenditures			(94.0	)			(81.0	)
Pre-acquisition undistributed earnings from consolidated subsidiaries (2)			(19.7	)			(30.8	)
Other, net (3)			(6.2	)			(54.2	)
Distributable Cash Flow		$	390.0			$	236.7

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 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, 2010, we had approximately $519 million of liquidity, consisting of $450 million of availability under the credit facility and $69 million of cash on hand. As part of our determination of available borrowing 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, 2010, our available borrowing capacity noted above was reduced to reflect the potential exposure to a loss of available borrowing capacity of $30.4 million assuming this lender continues to fail to fund the facility.

     We are primarily relying on cash flows from operating activities and availability under our credit facility to meet our operating needs, our anticipated cash distributions to our partners and our planned capital expenditure requirements for the foreseeable future. Our exposure to changes in our operating cash flows as the result of changes in natural gas consumption and demand is largely mitigated by a revenue base at WIC, CIG, SLNG, Elba Express 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. In addition, we believe the current equity and debt capital markets will support potential acquisition opportunities.

     We expect current liquidity and operating cash flow to be sufficient to fund our estimated 2011 capital program. In 2012, we will be required to renew our revolving credit facility. As a result of our current liquidity, we believe we are well positioned to meet our 2011 obligations. We will continue to assess and take further actions where prudent to meet our long-term objectives and capital requirements as well as address further changes in the financial and commodity markets. However, there are a number of factors that could impact our plans, including our ability to access the financial markets to fund our long-term capital needs if the financial markets are restricted. For further detail on our operations including risk factors, 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.

Overview of Cash Flow Activities. Our cash flows for the year ended December 31, 2010 are summarized as follows:

		2010				2009
		(In millions)
Cash Flow from Operations
Net income		$	605.1			$	497.2
Non-cash income adjustments			175.3				123.4
Change in other assets and liabilities			(108.7	)			17.9
Total cash flow from operations		$	671.7			$	638.5
Other Cash Inflows
Investing activities
Net change in notes receivable from affiliates		$	322.3			$	112.7
Return of capital on investment in unconsolidated affiliates			15.6				2.4
Other			1.5				51.1
			339.4				166.2
Financing activities
Net proceeds from issuance of common and general partner units			1,368.4				216.4
Net proceeds from issuance of long term debt			1,287.4				264.1
Cash contributions from El Paso			18.8				308.0
			2,674.6				788.5
Total other cash inflows		$	3,014.0			$	954.7
Cash Outflows
Investing activities
Capital expenditures		$	(412.1	)		$	(846.1	)
Cash paid to acquire additional interests in CIG, SNG, SLNG and Elba Express			(1,024.8	)			(143.2	)
Other			—				(0.4	)
			(1,436.9	)			(989.7	)
Financing activities
Payments on borrowings under credit facility			(250.0	)			(64.9	)
Payments to retire long-term debt, including capital lease obligations			(163.2	)			(4.1	)
Cash distributions to unitholders and general partner			(243.5	)			(161.5	)
Cash distributions to El Paso			(300.7	)			(276.3	)
Excess of cash paid for CIG, SNG, SLNG and Elba Express interests over contributed book value			(500.6	)			(71.3	)
Cash paid to acquire additional interests in SLNG and Elba Express			(758.0	)			—
Other			(0.4	)			—
			(2,216.4	)			(578.1	)
Total cash outflows		$	(3,653.3	)		$	(1,567.8	)
Net change in cash and cash equivalents		$	32.4			$	25.4

     For the year ended December 31, 2010, we generated cash flow from operations of $671.7 million compared with $638.5 million in the same period in 2009. Our operating cash flow in 2010 increased due to our expansion projects placed in service including Piceance Lateral Expansion, Totem Gas Storage, Elba III Phase A Expansion and Elba Express Pipeline. Also, contributing to the increase were higher reservation revenues on WIC’s mainline system and SNG’s rate case settlement. This increase was partially offset by SLNG’s conversion into a limited liability company and the related pre-acquisition settlement of its current and deferred tax balances of approximately

$71.7 million with amounts recovered from its note receivable from El Paso under the cash management program. In 2010, we received approximately $1.4 billion in net proceeds from the issuance of additional common and general partner units (see Note 3) and $1.3 billion net proceeds from the issuance of senior notes (see Note 7) which were used to partially fund acquisitions. In December 2010, we also received $45.5 million net proceeds from the underwriters’ exercise of their overallotment option and issuance of related general partner units from the November 2010 equity offering.

     During 2010, we utilized our cash inflows to pay distributions, including CIG, SLNG, Elba Express and SNG distributions to El Paso of their share of available cash (see Item 8, Financial Statements and Supplementary Data, Note 14), 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 SLNG, Elba Express, and SNG.

     We made cash distributions to our unitholders of $243.5 million during 2010 compared with $161.5 million in 2009, reflecting a greater number of partnership units outstanding and an increase in our cash distributions per unit. As of December 31, 2010, our cash capital expenditures for the year ended December 31, 2010 and those planned for 2011 were as follows:

						Expected
		2010				2011
		(In millions)
Maintenance		$	94.0			$	110
Expansion			318.1				150
Total		$	412.1			$	260

     Total consolidated capital expenditures for 2011 are expected to be approximately $260 million, including approximately $110 million of maintenance capital and approximately $150 million of expansion capital. The partnership’s growth capital is primarily for SNG’s South System III expansion. EPB continues to evaluate additional expansion opportunities around its well-positioned assets. 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 capital contributions from El Paso.

Off-Balance Sheet Arrangements

     We have no off-balance sheet financing entities or structures with third parties other than our equity investments in WYCO and Bear Creek, our accounts receivable sales program and a letter of credit associated with construction costs on SNG. For a further discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Note 9, 13 and 14.

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, 2010 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		$	42.0			$	428.0			$	831.0			$	2,145.3			$	3,446.3
Interest			236.7				457.4				416.5				1,957.4				3,068.0
Other contractual liabilities			2.5				3.5				1.0				2.4				9.4
Operating leases			5.2				10.6				9.2				5.3				30.3
Capital commitments			27.1				—				—				—				27.1
Other contractual commitments and purchase obligations:
Transportation and storage			42.3				65.6				65.1				176.5				349.5
Other			1.1				2.5				—				—				3.6
Total		$	356.9			$	967.6			$	1,322.8			$	4,286.9			$	6,934.2

     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 CIG’s unconsolidated investment in 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 7.

     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 9.

     Capital Commitments. Included in this amount are capital commitments related to our expansion projects. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures. For a further discussion of these obligations, see Financial Statements and Supplementary Data, Note 9.

     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 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.

Critical Accounting Estimates

     Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues, expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of our Board of Directors.

     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 a nonregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded 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 evaluate the applicability of accounting standards related to regulated operations, 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 and Legal Reserves. We accrue environmental and legal 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, and in the case of environmental reserves, 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.

     Accounting for Other Postretirement Benefits. We reflect an asset or liability for SNG’s and CIG’s postretirement benefit plans based on the over funded or under funded status. As of December 31, 2010, the postretirement benefit plans were over funded by $7.0 million. The postretirement benefit obligation and net benefit cost are primarily based on actuarial calculations. Various assumptions are used in performing these calculations, including those related to the return that the plans’ assets are expected to return, the estimated cost of health care when benefits are provided under the plans and other factors. A significant assumption utilized is the discount rate used in calculating the benefit obligation. The discount rate is selected by matching the timing and amount of expected future benefit payments for the 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 the postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on the related benefit obligation, along with changes to the plans and other items, are deferred and recorded as either a regulatory asset or liability. A one-percentage point change in the primary assumptions would not have had a significant effect on net postretirement benefit cost. The following table shows the impact of a one percent change to the funded status for the year ended December 31, 2010 (in millions):

		Change in Funded
		Status
One percent increase in:
Discount rates		$	5.2
Health care cost trends			(4.7	)
One percent decrease in:
Discount rates		$	(5.6	)
Health care cost trends			4.1

     Asset and Investment Impairments. The accounting rules on asset and investment impairments require us to continually monitor our businesses, the business environment and the performance of our investments to determine if an event has occurred that indicates that a long-lived asset or investment may be impaired. Such 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. If an event occurs, we evaluate the recoverability of our 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. The assessment of project level cash flows requires significant judgment to make projections and assumptions for many years into the future for pricing, demand, competition, operating costs, legal and regulatory issues and other factors that are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates. 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.

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, 2010																																December 31, 2009
		Expected Fiscal Year of Maturity of Carrying Amounts																												Fair				Carrying				Fair
		2011				2012				2013				2014				2015				Thereafter				Total				Value				Amounts				Value
		(In millions)
Long-term debt and other financing obligations, including current portion — fixed rate		$	42.0			$	20.0			$	93.0			$	76.0			$	754.6			$	2,141.7			$	3,127.3			$	3,329.8			$	1,842.4			$	1,968.5
Average interest rate			8.6	%			9.8	%			8.4	%			9.9	%			5.5	%			7.6	%
Long-term debt and other financing obligations, including current portion — variable rate		$	—			$	315.0			$	—			$	—			$	—			$	—			$	315.0			$	308.0			$	703.0			$	667.1
Average interest rate							1.7	%

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
Management’s Annual Report on Internal Control over Financial Reporting			45
Reports of Independent Registered Public Accounting Firm			46
Consolidated Statements of Income			48
Consolidated Balance Sheets			49
Consolidated Statements of Cash Flows			50
Consolidated Statements of Partners’ Capital and Comprehensive Income			51
Notes to Consolidated Financial Statements			52
1. Basis of Presentation and Significant Accounting Policies			52
2. Contribution of Assets, Acquisitions and Divestitures			56
3. Partners’ Capital			57
4. Earnings Per Unit and Cash Distributions			58
5. Regulatory Assets and Liabilities			61
6. Property, Plant and Equipment			62
7. Long-Term Debt and Other Financing Obligations			63
8. Fair Value of Financial Instruments			67
9. Commitments and Contingencies			67
10. Retirement Benefits			69
11. Transactions with Major Customers			72
12. Supplemental Cash Flow Information			72
13. Accounts Receivable Sales Program			72
14. Investments in Unconsolidated Affiliates and Transactions with Affiliates			73
15. Income Taxes			76
16. Supplemental Selected Quarterly Financial Information (Unaudited)			77

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, 2010. 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, 2010. The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report included herein.

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, 2010 and 2009, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. 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, 2010. 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, and 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, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, 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 2 to the consolidated financial statements, the consolidated financial statements have been retrospectively adjusted for a change in reporting entity.

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, 2010, 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 28, 2011 expressed an unqualified opinion thereon.

Houston, Texas
February 28, 2011

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, 2010, 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, 2010, 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, 2010 and 2009, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010 of El Paso Pipeline Partners, L.P. and our report dated February 28, 2011 expressed an unqualified opinion thereon.

Houston, Texas
February 28, 2011

El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per unit amounts)

		Year Ended December 31,
		2010				2009(1)				2008(1)
Operating revenues		$	1,344.1			$	1,119.3			$	1,064.4
Operating expenses
Operation and maintenance			385.2				352.7				361.5
Depreciation and amortization			152.7				129.2				118.5
Taxes, other than income taxes			59.1				54.6				52.1
			597.0				536.5				532.1
Operating income			747.1				582.8				532.3
Earnings from unconsolidated affiliates			15.7				12.4				15.9
Other income, net			29.2				47.8				33.8
Interest and debt expense, net			(186.6	)			(129.0	)			(129.3	)
Affiliated interest income, net			2.1				4.4				40.1
Income before income taxes			607.5				518.4				492.8
Income tax expense			2.4				21.2				18.3
Net income			605.1				497.2				474.5
Net income attributable to noncontrolling interests			(226.6	)			(179.6	)			(173.7	)
Net income attributable to El Paso Pipeline Partners, L.P.		$	378.5			$	317.6			$	300.8
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit — Basic and Diluted:
Common units		$	1.90			$	1.64			$	1.26
Subordinated units		$	1.78			$	1.56			$	1.12

See accompanying notes.