Filing Compare · SOUTHERN NATURAL GAS COMPANY, L.L.C.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________

Form 10-K

(Mark One)

R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2009
	For the fiscal year ended December 31, 2010
	OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to

Commission File Number 1-2745

Southern Natural Gas Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware	63-0196650
(State or Other Jurisdiction of	(I.R.S. Employer
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
Incorporation or Organization)	Identification No.)
El Paso Building
1001 Louisiana Street
Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

Telephone Number: (713) 420-2600

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R

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 £ No R

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 R No £

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 £ No £

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. R

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 £

Accelerated filer £

Non-accelerated filer R

(Do not check if a smaller reporting company)

Smaller Reporting Company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No R

State the aggregate market value of the voting equity held by non-affiliates of the registrant: None

Documents Incorporated by Reference: None

SOUTHERN NATURAL GAS COMPANY

TABLE OF CONTENTS

	Caption	Page
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	5
Item 1B.	Unresolved Staff Comments	1213
Item 2.	Properties	1213
Item 3.	Legal Proceedings	1213
Item 4.	~~Submission~~(Removed ofand ~~Matters to a Vote of Security Holders~~Reserved)	1213
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	1314
Item 6.	Selected Financial Data	1314
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1415
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	24
Item 8.	Financial Statements and Supplementary Data	25
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	4744
Item 9A.	Controls and Procedures	4744
Item 9A(T).	Controls and Procedures	47
Item 9B.	Other Information	44
Item 9B.	Other Information	47
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	4845
Item 11.	Executive Compensation	4947
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	5047
Item 13.	Certain Relationships and Related Transactions, and Director Independence	5048
Item 14.	Principal Accountant Fees and Services	5148
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	5249
	Signatures	7950

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

/d = per day LNG = liquefied natural gas BBtu = billion British thermal units MMcf = million cubic feet Bcf = billion cubic feet Tonne = metric ton Bcfe = billion cubic feet of natural gas equivalents

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

When we refer to “us”, “we”, “our”, “ours”, or “SNG”, we are describing Southern Natural Gas Company and/or our subsidiaries.

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PART I

ITEM 1. BUSINESS

Overview and Strategy

We are a Delaware general partnership, originally formed in 1935 as a corporation. We are owned ~~75 percent~~60 ~~indirectly through a wholly owned subsidiary of El Paso Corporation (El Paso) and 25~~ percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership of El Paso. ~~EPB~~Corporation ~~was formed~~(El inPaso), ~~November~~and ~~2007~~40 atpercent ~~which time~~ by El Paso ~~contributed~~SNG 10Holding ~~percent~~Company, ofL.L.C., ~~its interest~~a inwholly usowned tosubsidiary ~~EPB.~~of El Paso. In ~~September 2008~~2010, EPB acquired an additional 1535 percent ~~ownership~~ interest (20 percent in June and 15 percent in November) in us from El Paso.

In November 2007, in conjunction with the formation of EPB, we distributed our 50 percent interest in Citrus Corp. (Citrus) and our wholly owned subsidiaries, Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba Express), to El Paso. Citrus owns the Florida Gas Transmission Company, LLC pipeline system and SLNG owns the Elba Island LNG facility. SLNG and Elba Express have been reflected as discontinued operations in our financial statements for periods prior to their distribution. For a further discussion of these discontinued operations, see Part II, Item 8, Financial Statements and Supplementary Data, Note 2. In addition, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes. Accordingly, we settled our then existing current and deferred tax balances through El Paso’s cash management program pursuant to our tax sharing agreement with El Paso.

Our pipeline system and storage facilities operate under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.

Our strategy is to enhance the value of our transportation and storage business by:

•

providing outstanding customer service;

• ~~executing~~ successfully executing on time and on budget for our ~~backlog of~~ committed expansion projects;

•

developing new growth projects in our market and supply areas;

•

maintaining the integrity and ensuring the safety of our pipeline system and other assets;

• ~~successfully~~optimizing ~~recontracting~~our ~~expiring~~contract ~~contracts for transportation capacity or contracting available capacity~~portfolio; and

• focusing on increasing utilization, efficiency and ~~synergies~~cost ~~across~~control in our ~~system~~operations.

Pipeline System. Our pipeline system consists of approximately 7,600 miles of pipeline with a design capacity of 3,700 MMcf/d. During ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008, average throughput was 2,~~322~~ 505 BBtu/d, 2,~~339~~322 BBtu/d and 2,~~345~~339 BBtu/d. This system extends from 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. We are the principal natural gas transporter to the southeastern markets in Alabama, Georgia and South Carolina. Our system is also connected to the Elba Island LNG terminal near Savannah, Georgia. This terminal is owned by EPB and has a peak send-out capacity of approximately 1.28 Bcf/d and a storage capacity of 11.5 Bcfe.

FERC Approved Projects. As of December 31, 2009, we had the following FERC-approved expansion projects on our system. For a further discussion of our other expansion projects, see Item 7, Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Project	Capacity (MMcf/d)		Description	Anticipated Completion or In-Service Date
South System III		370	To add 81 miles of pipe and 17,310 of horsepower compression on our pipeline facilities.		2011-2012
Southeast Supply Header Phase II		350	To add 26,000 of horsepower compression to the jointly owned pipeline facilities.		2011

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~~Storage Facilities.~~FERC ~~Along~~Approved ~~our~~Projects. ~~pipeline~~As ~~system, we own and operate 100 percent~~ of ~~the~~ ~~Muldon~~December ~~storage~~31, ~~facility in Monroe County~~2010, ~~Mississippi~~we ~~and~~had ~~own a 50 percent interest in and operate~~ the ~~Bear~~following ~~Creek~~FERC ~~Storage~~approved ~~Company,~~expansion ~~LLC (Bear~~projects ~~Creek)~~on ~~in Bienville~~our ~~Parish, Louisiana~~system. ~~Bear~~For ~~Creek~~a ~~provides~~further ~~storage~~discussion ~~services~~of ~~pursuant~~these ~~to firm~~expansion ~~contracts~~projects, tosee usPart ~~and Tennessee Gas Pipeline Company~~II, aItem ~~subsidiary of El Paso~~7, ~~which~~Management’s ~~owns~~Discussion ~~the remaining 50 percent interest. Our interest in Bear Creek~~ and ~~the~~Analysis ~~Muldon storage facilities have a combined working natural gas storage capacity~~ of 60Financial ~~Bcf~~Conditions and ~~peak~~Results ~~withdrawal capacity~~ of 1Operations.~~2 Bcf/d. We provide storage services to our customers utilizing the Bear Creek and the Muldon storage facilities at our FERC tariff rate.~~

Project	Capacity (MMcf/d)	Description	Anticipated Completion or In-Service Date
South System III	370	To add 81 miles of pipeline and 17,310 of horsepower compression; each phase will add an additional 122 MMcf/d of capacity	2011-2012(1)

Southeast Supply Header Phase II(2)	350	To add approximately 26,000 of horsepower compression to the jointly owned pipeline facilities	June 2011

____________

(1) This project will be completed in three phases. We placed Phase I of the project in service in January 2011 and anticipate to place Phase II and III in service in June 2011 and June 2012.

(2) This project is operated by Spectra Energy Corp.

Storage Facilities. We own and operate 100 percent of the Muldon storage facility in Monroe County, Mississippi. We also own a 50 percent interest in and operate Bear Creek Storage Company, LLC (Bear Creek) in Bienville Parish, Louisiana. Bear Creek is a joint venture equally owned by us and our affiliate, Tennessee Gas Pipeline Company (TGP). Our interest in Bear Creek and the Muldon storage facilities have a combined working natural gas storage capacity of 60 Bcf and peak withdrawal capacity of 1.2 Bcf/d. We provide storage services to our customers utilizing the Bear Creek and the Muldon storage facilities at our FERC tariff rate. The working storage capacity at the Bear Creek facility is committed equally to TGP and us.

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 system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.

The southeastern market served by our pipeline is the fastest growing natural gas demand region in the United States. Demand for deliveries from our pipeline is characterized by two peak delivery periods, the winter heating season and the summer cooling season.

The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as ~~shale~~shales, ~~tight sands, and coal bed methane,~~ is rapidly increasing. This shift will ~~change~~affect the supply patterns, ~~and~~the flows and the rates that can be charged on ~~pipelines~~pipeline systems. The impact will vary among pipelines according to the ~~proximity~~location ofand the number of competitors attached to these new supply sources. Our pipeline is directly connected to the Haynesville Shale formation in northern Louisiana. Our pipeline is also indirectly connected, through new interconnecting pipelines, to the Barnett Shale, Bossier Sands, Woodford Shale and Fayetteville Shale. It is ~~likely~~possible that ~~natural~~ gas from these sources will ~~increase~~increasingly displace receipts over time. ~~This~~and ~~will~~could ~~affect~~impact the flows on the system and ~~the~~our ~~array of~~ shipper contracts.

~~Imported~~ Imports of LNG ~~has been~~have afluctuated ~~growing~~in ~~supply~~the ~~sector~~past ofin ~~the~~response ~~natural~~to changing gas ~~market~~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 may compete with us for transportation of gas into market areas we serve.

Electric power generation has been athe ~~growing~~source ~~demand~~of ~~sector~~most of the growth in demand for natural gas ~~market.~~over ~~The growth~~the oflast ~~natural~~10 ~~gas-fired~~years, ~~electric~~and ~~power~~this ~~benefits~~trend ~~the~~is ~~natural~~expected ~~gas~~to ~~industry~~continue ~~by creating~~in ~~more~~the ~~demand~~future. ~~for~~The growth of natural gas. ~~This~~in ~~potential~~this ~~benefit~~sector is ~~offset,~~influenced ~~in varying~~by ~~degrees,~~competition bywith coal and increased ~~generation~~consumption ~~efficiency,~~of ~~the~~electricity ~~more~~as ~~effective~~a ~~use~~result of ~~surplus~~ ~~electric~~recent ~~capacity,~~economic ~~increased~~growth. ~~natural~~Short-term ~~gas~~market ~~prices~~shifts ~~and~~have ~~the~~been ~~use~~driven ~~and availability~~by ofrelative ~~other~~costs ~~fuel~~of ~~sources~~coal-fired ~~for~~generation ~~power~~versus gas-fired generation. InA ~~addition,~~long-term inmarket ~~several regions~~shift ofin the ~~country,~~use ~~new~~of ~~additions~~coal in ~~electric~~power ~~generating~~generation ~~capacity~~could ~~have exceeded~~be ~~load~~driven ~~growth~~by ~~and~~environmental ~~electric~~regulations. ~~transmission~~The ~~capabilities~~future ~~out~~demand offor ~~those regions~~natural gas could be increased by regulations limiting or discouraging coal use. ~~These~~However, ~~developments~~natural ~~may~~gas ~~inhibit~~demand ~~owners~~could ofpotentially ~~new~~be ~~power~~adversely ~~generation facilities~~affected ~~from~~by ~~signing~~laws ~~firm~~mandating ~~transportation~~or ~~contracts~~encouraging ~~with~~renewable ~~natural~~power ~~gas pipelines~~sources.

Growth of the natural gas market has been adversely affected by the current economic slowdown in the U.S. and global economies. The decline in economic activity reduced industrial demand for natural gas and electricity, which affected natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. We expect the demand and growth for natural gas to return as the economy recovers. Natural gas has a favorable competitive position as an electric generation fuel because it is a clean and abundant fuel with lower capital requirements compared with other alternatives. The lower demand and the credit restrictions on investments in the recent past may slow development of supply projects. While our pipeline could experience some level of reduced throughput and revenues, or slower development of expansion projects as a result of these factors, we generate a significant (greater than 80 percent) portion of our revenues through fixed monthly reservation or demand charges on long-term contracts at rates stipulated under our tariff or in our contracts.

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~~Our~~We ~~existing transportation~~face ~~and~~competition ~~storage~~in ~~contracts~~a ~~mature~~number atof ~~various~~our ~~times~~key markets and inwe ~~varying amounts~~compete ofwith ~~throughput~~other ~~capacity.~~interstate ~~Our~~and ~~ability~~intrastate pipelines for deliveries to ~~extend~~multiple-connection ~~our~~customers ~~existing~~who ~~customer contracts~~can ortake ~~remarket~~deliveries ~~expiring~~at ~~contracted~~alternative ~~capacity~~points. isNatural ~~dependent~~gas delivered on ~~competitive alternatives,~~our ~~the~~system ~~regulatory~~competes ~~environment~~with atalternative ~~the~~energy ~~federal,~~sources ~~state~~used ~~and~~to ~~local~~generate ~~levels and~~electricity ~~market~~such ~~supply~~as ~~and~~hydroelectric ~~demand~~power, ~~factors~~coal atand ~~the~~fuel ~~relevant~~oil. ~~dates~~Our ~~these~~four ~~contracts~~largest customers are ~~extended~~ orable ~~expire.~~to ~~The~~obtain ~~duration~~a ofsignificant ~~new~~portion orof ~~renegotiated~~their ~~contracts~~natural ~~will~~gas ~~be affected~~requirements bythrough ~~current~~transportation ~~prices,~~from ~~competitive~~other ~~conditions~~pipelines and ~~judgments~~we ~~concerning future~~compete ~~market~~with ~~trends~~several ~~and~~pipelines ~~volatility~~for the transportation business of our other customers. ~~Subject~~We toalso ~~regulatory~~compete ~~requirements,~~with ~~we attempt~~pipelines and gathering systems for connection to ~~recontract~~new orsupply ~~remarket~~sources. ~~our~~Our ~~capacity~~most atdirect ~~the~~competitor ~~maximum~~is ~~rates~~Transcontinental ~~allowed under~~Gas ~~our~~Pipe ~~tariffs~~Line Company, ~~although~~L.L.C., atwhich ~~times~~owns an approximately 10,500 wemile ~~enter~~pipeline ~~into~~extending from Texas to New York. It has firm transportation contracts atwith ~~amounts~~some ~~that~~of ~~are~~our ~~less~~largest ~~than~~customers, ~~these~~including ~~maximum~~Atlanta ~~allowable~~Gas ~~rates~~Light toCompany, ~~remain competitive~~Alabama Gas Corporation, Southern Company Services, and SCANA Corporation.

WeFor ~~face competition in~~ a ~~number~~further discussion of ~~our~~factors ~~key~~impacting ~~markets and we compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on~~ our ~~system competes~~markets ~~with alternative energy sources used to generate electricity, such as hydroelectric power, coal~~ and ~~fuel oil. Our four largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines. Also~~competition, wesee ~~compete~~Item ~~with several pipelines for the transportation business of our other customers. In addition~~1A, weRisk ~~compete with pipelines and gathering systems for connection to new supply sources~~Factors.

~~Our~~Customers most direct competitor is Transco, which owns an approximately 10,500-mile pipeline extending from Texas to New York. It has firm transportation contracts with some of our largest customers, including Atlanta Gas Light Company, Alabama Gas Corporation, Southern Company Services, and ~~SCANA Corporation.~~Contracts

~~The~~Our ~~following~~existing ~~table details~~transportation ~~our~~and ~~customer~~storage ~~and~~contracts ~~contract~~expire ~~information~~at ~~related~~various totimes ~~our~~and ~~pipeline~~in ~~system~~varying as amounts of ~~December~~ ~~31,~~throughput ~~2009~~capacity. ~~Firm~~Our ~~customers~~ability ~~reserve~~to extend our existing customer contracts or remarket expiring contracted capacity is dependent on ~~our pipeline~~competitive ~~system~~alternatives, the regulatory environment at the federal, state and ~~storage~~local ~~facilities~~levels and ~~are~~market ~~obligated~~supply toand ~~pay~~demand afactors ~~monthly reservation~~at the relevant dates these contracts are extended or ~~demand~~expire. ~~charge,~~The ~~regardless~~duration of ~~the~~new ~~amount~~or ofrenegotiated ~~natural~~contracts ~~gas~~will ~~they transport~~be oraffected ~~store~~by current prices, ~~for~~competitive ~~the~~conditions ~~term~~and ofjudgments ~~their~~concerning ~~contracts.~~future ~~Interruptible~~market ~~customers~~trends ~~are customers~~and ~~without~~volatility. ~~reserved~~Although ~~capacity~~we ~~that~~attempt ~~pay~~to ~~usage~~recontract ~~charges~~or ~~based~~remarket onour capacity at the ~~volume of~~maximum ~~gas~~rates ~~they~~allowed ~~transport,~~under ~~store~~our tariffs, ~~inject~~we orfrequently ~~withdraw~~enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

Customer Information	Contract Information
Approximately 270 firm and interruptible customers.	Approximately 200 firm transportation contracts. Weighted average remaining contract term of approximately six years.
Major Customers: Atlanta Gas Light Company(1) (1,063 BBtu/d)
	Expire in 2013-2024.
Southern Company Services
(433 BBtu/d)	Expire in 2011-2018.
Alabama Gas Corporation
(372 BBtu/d)	Expire in 2010-2013.
SCANA Corporation
(315 BBtu/d)	Expire in 2013-2019.

The following table details our customer and contract information related to our pipeline system as of December 31, 2010. Firm customers reserve capacity on our pipeline system and 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. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.

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(1) (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.

____________

(1) Atlanta Gas Light Company isreleases ~~currently~~on ~~releasing~~a monthly basis a significant portion of its firm capacity to a subsidiary of SCANA Corporation ~~under terms allowed by our tariff~~.

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Regulatory Environment

Our interstate natural gas transmission system and storage operations 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. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority also extends to:

•

rates and charges for natural gas transportation and storage;

•

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 service;

•

depreciation and amortization policies;

•

acquisition and disposition of facilities; and

•

initiation and discontinuation of services.

Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation 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 system is 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.

Environmental

A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.

Employees

We do not have employees. Following our reorganization in 2007, our former employees continue to provide services to us through an affiliated service company owned by our general partner, El Paso. We are managed and operated by officers of El Paso~~, our general partner~~. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf.

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ITEM 1A. RISK FACTORS

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and ~~differences~~such ~~between~~variances ~~assumed facts and actual results~~ can be material~~, depending upon the circumstances~~. Where~~, based~~ ~~on assumptions,~~ we ~~or our management~~ express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur~~, be achieved or accomplished~~. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these ~~cautionary statements~~ and ~~any~~ other cautionary statements ~~that may accompany such forward-looking statements~~. InWe ~~addition, we~~ disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.

With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf.

Risks Related to Our Business

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

The ~~financial~~ results of our ~~transportation~~business ~~and~~are ~~storage~~impacted ~~operations~~in ~~are~~the ~~impacted~~long term by the volumes of natural gas we transport or store and the prices we are able to charge for ~~doing~~ sothese services. The volumes ~~of natural gas~~ we ~~are able to~~ transport and store ~~depends~~ depend on the actions of third parties ~~and~~that are based on factors beyond our control. Such ~~actions~~factors include ~~factors~~ events that negatively impact our customers’ demand ~~and~~for ~~producers’~~natural ~~supply,~~gas ~~including factors~~and ~~that~~could ~~negatively~~expose ~~impact~~ our ~~customers’~~pipeline ~~need~~to ~~for~~the ~~natural~~risk ~~gas~~that ~~from~~we ~~us,~~will ~~as well~~not asbe ~~the~~able ~~continued~~to ~~availability~~renew ofcontracts ~~natural~~at ~~gas~~expiration ~~production~~or ~~and~~that ~~reserves connected~~we will be required to discount our ~~pipeline~~rates ~~system~~significantly upon renewal. ~~Further,~~We ~~the~~are ~~following~~also ~~factors, most~~highly ofdependent ~~which~~on ~~are~~our ~~also~~customers ~~beyond~~and downstream pipelines to attach new and increased loads on their system in order to grow our ~~control~~business. Further, ~~may~~state ~~unfavorably~~agencies ~~impact~~that regulate our ~~ability~~local ~~to maintain~~distribution orcompany ~~increase~~customers ~~current~~could ~~throughput,~~impose orrequirements tothat ~~remarket~~could ~~unsubscribed~~impact ~~capacity~~demand on for our ~~pipeline system:~~services.

•The ~~service~~volume ~~area~~of ~~competition;~~gas that we transport and store also depends on the availability of natural gas supplies that are attached to our pipeline system, including the need for producers to continue to develop additional gas supplies to offset the natural decline from existing wells connected to our system. 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 system. 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. 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 transmission and storage through our system.

•Furthermore, ~~price~~our ~~competition;~~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.

•The ~~expiration~~agencies orthat ~~turn~~regulate ~~back~~our ofbusiness ~~significant~~and ~~contracts;~~our customers could affect our profitability.

•Our ~~changes~~business inis ~~regulation~~extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior, the U.S. Department of Homeland Security and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. The FERC regulates most aspects of ~~regulatory~~our ~~bodies;~~business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipeline (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. 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, our profitability 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 we can file and obtain rate increases.

• weather conditions that impact natural gas throughput and storage levels;

• weather fluctuations or warming or cooling trends that may impact demand in the markets in which we do business, including trends potentially attributed to climate change;

• drilling activity and decreased availability of conventional gas supply sources and the availability and timing of other gas supply sources, such as LNG;

• continued development of additional sources of gas supply that can be accessed;

• decreased natural gas demand due to various factors, including economic recession (as further discussed below), availability of alternate energy sources and increases in prices;

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•Our ~~legislative,~~existing ~~regulatory~~rates ormay ~~judicial~~be ~~actions,~~challenged ~~such~~by ascomplaint. ~~mandatory~~The ~~renewable~~FERC ~~portfolio~~commenced ~~standards~~several ~~and~~complaint ~~greenhouse~~proceedings ~~gas~~in ~~(GHG)~~2009 ~~regulations~~ and~~/or~~ ~~legislation~~2010 ~~that~~against ~~could~~unaffiliated ~~result~~pipeline insystems ~~(i)~~to ~~changes~~reduce in the ~~demand~~rates ~~for~~they ~~natural~~were ~~gas~~charging ~~and~~their ~~oil,~~customers. There ~~(ii)~~is ~~changes~~a inrisk that the ~~availability~~FERC of or ~~demand~~our ~~for~~customers ~~alternative~~could ~~energy~~file ~~sources~~similar ~~such~~complaints ason ~~hydroelectric~~us and ~~nuclear~~that ~~power,~~a successful ~~wind~~complaint ~~and~~against ~~solar~~our ~~energy~~rates ~~and/or~~could ~~(iii)~~have ~~changes~~an inadverse ~~the~~impact ~~demand~~on ~~for~~us. ~~less~~For ~~carbon~~a ~~intensive~~discussion ~~energy~~of ~~sources;~~our rate case, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

•Certain ~~availability~~of ~~and~~our ~~cost~~transportation services are subject to ~~fund~~negotiated ~~ongoing~~rate ~~maintenance~~contracts ~~and~~that ~~growth~~may ~~projects,~~not ~~especially~~allow inus ~~periods~~to recover our costs of ~~prolonged~~providing ~~economic~~the ~~decline;~~services.

•Under ~~opposition~~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 ~~energy~~adjustment ~~infrastructure~~for ~~development~~increased costs which could occur due to inflation, ~~especially~~increases in ~~environmentally~~the ~~sensitive~~cost ~~areas;~~of capital or 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.

•Our ~~adverse~~revenues ~~general~~are ~~economic~~generated ~~conditions~~under ~~including~~contracts ~~prolonged recessionary periods~~ that ~~might~~must ~~negatively~~be ~~impact~~renegotiated ~~natural gas demand and the capital markets;~~periodically.

•Our 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 system could decrease over time and thereby negatively impact our ability to ~~achieve~~renew ~~targeted~~contracts ~~annual~~at ~~operating~~rates that were previously in place. Our ability to extend and ~~administrative~~replace ~~expenses~~contracts ~~primarily~~could be adversely affected by ~~reducing~~factors ~~internal~~we ~~costs~~cannot ~~and~~control, as ~~improving~~discussed ~~efficiencies~~above. ~~from~~In ~~leveraging~~addition, achanges ~~consolidated~~in ~~supply~~state ~~chain~~regulation ~~organization;~~of ~~and~~local distribution companies may cause us to negotiate short-term contracts or turn back their capacity when our contracts expire.

•The ~~unfavorable~~expansion ~~movements~~of inour ~~natural~~pipeline ~~gas~~system ~~prices~~by inconstructing ~~certain~~new ~~supply~~facilities subjects us to construction and ~~demand~~other ~~areas~~risks that may adversely affect us.

AWe ~~substantial portion~~frequently expand the capacity of our ~~revenues~~existing ~~are~~pipeline ~~generated~~and ~~from~~storage ~~transportation~~facilities ~~contracts~~by ~~that~~constructing ~~must~~additional ~~be renegotiated periodically~~facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

~~Our~~● ~~revenues~~our ~~are generated~~ability ~~under~~to ~~transportation~~obtain ~~and~~necessary ~~storage~~approvals ~~contracts which expire periodically~~ and ~~must~~permits befrom ~~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~~FERC ~~contracts, we could suffer a material reduction in our revenues, earnings~~ and ~~cash~~other ~~flows.~~regulatory ~~Currently,~~agencies on a ~~substantial~~timely ~~portion~~basis ofthat ~~our firm transportation contacts~~ are ~~subscribed through 2013. For additional information~~ on ~~the~~terms ~~expiration~~that ofare ~~our~~acceptable ~~contract~~to ~~portfolio~~us, ~~see~~including ~~Part~~the ~~II,~~potential ~~Item~~negative 7,impact ~~Management’s Discussion and Analysis~~ of ~~Financial~~delays ~~Condition~~ and ~~Results~~increased ofcosts ~~Operations.~~caused ~~In particular,~~by ~~our~~general ~~ability~~opposition to ~~extend~~energy ~~and~~infrastructure ~~replace~~development, ~~contracts~~especially ~~could be adversely affected by factors we cannot control as discussed~~ in ~~more detail above. In addition~~environmentally, ~~changes~~culturally insensitive ~~state~~and ~~regulation~~more ofheavily ~~local~~populated ~~distribution companies may cause us to negotiate short-term contracts or turn back our capacity when our contracts expire.~~areas;

In● ~~2009,~~the ~~our contracts~~ability ~~with~~to ~~Atlanta~~access ~~Gas~~sufficient ~~Light~~capital ~~Company,~~at ~~Southern~~reasonable ~~Company~~rates ~~Services,~~to ~~Alabama~~fund ~~Gas Corporation~~expansion ~~and SCANA Corporation represented approximately 28 percent~~projects, ~~11 percent,~~especially 10in ~~percent~~periods ~~and 8 percent~~ of ~~our~~prolonged ~~firm~~economic ~~transportation capacity. For additional information regarding our major customers, see Item 1, Business — Markets and Competition. The loss of one of these customers or a~~ decline ~~in their~~when ~~creditworthiness~~we ~~could~~may ~~adversely~~be ~~affect~~unable ~~our~~to ~~results~~access ofthe ~~operations, financial~~capital ~~position and cash flows.~~markets;

~~We are~~● ~~exposed to~~ the ~~credit~~availability ~~risk~~ of ~~our~~skilled ~~customers~~labor, equipment, and ~~our~~materials ~~credit risk management may not be adequate~~ to ~~protect~~complete ~~against~~expansion ~~such risk.~~projects;

We● ~~are~~potential ~~subject~~changes ~~to the risk of delays~~ in ~~payment as well as losses resulting from nonpayment and/or nonperformance by our customers~~federal, ~~including~~state ~~default risk associated with adverse economic conditions. Our credit procedures~~ and ~~policies~~local ~~may not be adequate to fully eliminate customer credit risk. In addition~~statutes, ~~in certain situations~~regulations, ~~we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future customers fail to pay~~ and~~/or perform~~ and we are unable to remarket the capacity, our business, the results of our operations and our financial condition could be adversely affected. We may not be able to effectively remarket capacity during and after insolvency proceedings involving a shipper.orders;

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

●

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 the return on our investments or could result in financial impairments;

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

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

●	the lack of transportation, storage or throughput commitments.

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~~A portion~~Any of ~~our~~these ~~transportation~~risks ~~services~~could ~~are~~prevent ~~provided~~a ~~pursuant~~project tofrom ~~long-term~~proceeding, ~~fixed-price~~ ~~“negotiated~~delay ~~rate”~~its ~~contracts~~completion or increase its anticipated costs. There is also the risk that ~~are~~a ~~not~~downturn ~~subject~~in tothe ~~adjustment,~~economy ~~even if~~and ~~our~~its ~~cost~~negative toimpact ~~perform~~upon ~~such~~natural ~~services~~gas ~~exceeds~~demand may result in either slower development in the ~~revenues~~potential ~~received~~for ~~from~~future expansion projects or adjustments in the contractual commitments supporting such ~~contracts,~~ ~~and,~~projects. asAs a result, ~~our~~new ~~costs~~facilities ~~could~~may ~~exceed~~be ~~our~~delayed ~~revenues~~or ~~received~~may ~~under such~~not ~~contracts~~achieve our expected investment return.

ItWe isdepend ~~possible~~on ~~that costs~~certain tokey ~~perform~~customers ~~services under “negotiated rate” contracts will exceed the negotiated rates. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract~~ for ~~service at~~ a ~~“negotiated~~significant ~~rate”~~portion ~~which may~~of beour ~~above~~revenues orand ~~below~~ the ~~FERC~~loss regulated “recourse rate” for that service, and that contract must be filed and accepted by FERC. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation, cost of ~~capital,~~any ~~taxes or other factors relating to the specific facilities being used to perform the services. Any shortfall~~ of ~~revenue,~~ ~~representing~~these ~~the~~key ~~difference~~customers ~~between~~could ~~“recourse~~result ~~rates”~~in ~~(if~~a ~~higher)~~decline ~~and negotiated~~in ~~rates,~~our ~~under current FERC policy is generally not recoverable from other shippers~~revenues.

~~Fluctuations~~We ~~in energy~~rely ~~commodity~~on ~~prices~~a ~~could~~limited ~~adversely~~number ~~affect~~of customers for a significant portion of our ~~business~~revenues. For the year ended December 31, 2010, our contracts with Atlanta Gas Light Company, Southern Company Services, Alabama Gas Corporation and SCANA Corporation represented approximately 25 percent, 19 percent, 8 percent and 8 percent, respectively of our firm transportation capacity. The loss of any material 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.

~~Revenues~~The ~~generated by~~costs ~~our~~to ~~transportation~~maintain, ~~and~~repair ~~storage contracts depend on volumes~~ and ~~rates,~~replace ~~both of which can be affected by the price of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by~~ our ~~customers, including~~pipeline ~~power~~system ~~companies that~~ may ~~not~~exceed dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our ~~transmission and~~expected storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our system, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelineslevels. ~~A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transporation and storage through our system.~~

WeMuch ~~retain~~of aour ~~fixed percentage~~pipeline infrastructure was originally constructed many years ago. The age of ~~natural~~these ~~gas~~assets ~~received~~may ~~for~~result ~~transportation~~in them being more costly to maintain and ~~storage~~repair. asWe ~~provided~~may ~~in our~~also ~~tariff~~be required to replace certain facilities over time. ~~This~~ In ~~retained~~addition, ~~natural~~our ~~gas~~pipeline isassets ~~used~~may asbe ~~fuel~~subject ~~and~~to the risk of failures or other incidents due to ~~replace~~factors ~~lost and~~outside ~~unaccounted~~of ~~for~~our ~~natural~~control ~~gas. As~~(including ~~calculated~~due into athird ~~manner~~party ~~set~~excavation ~~forth~~near in our ~~tariff~~pipeline system, ~~volumes~~unexpected ~~from~~degradation ~~any~~of ~~excess~~our ~~natural~~pipeline ~~gas~~system, ~~retained~~as ~~and~~well ~~not~~as ~~used~~design, construction or manufacturing defects) that could result in ~~operations~~ ~~are~~personal toinjury beor ~~given~~property ~~back~~damages. toMuch of our ~~customers~~pipeline ~~through~~system ~~lower~~is ~~retention percentages~~located ~~determined~~in onpopulated anareas ~~annual~~which ~~basis~~increases the level of such risks. ~~Any~~Such ~~under-recoveries~~incidents ~~will~~could bealso ~~returned to~~result usin ~~through~~unscheduled ~~higher~~outages ~~percentages~~or ~~determined~~periods onof anreduced ~~annual~~operating ~~basis.~~flows Ifwhich ~~natural~~could ~~gas prices~~result in ~~the~~a ~~supply~~loss ~~basins~~of ~~connected~~our ability to serve our ~~pipeline~~customers ~~system~~and ~~are~~a ~~higher~~loss ~~than prices~~of inrevenues. ~~other~~Although ~~natural~~we ~~gas~~are ~~producing~~targeted ~~regions,~~to complete our ~~ability~~pipeline tointegrity ~~compete~~program ~~with~~which ~~other transporters~~includes ~~may~~the bedevelopment ~~negatively~~and ~~impacted~~use onof ~~a short~~in-~~term~~line ~~basis,~~inspection astools ~~well~~in ashigh ~~with respect~~consequence toareas ~~our~~by ~~long-term~~its ~~recontracting~~required ~~activities.~~completion ~~Furthermore~~date at the end of 2012, ~~fluctuations~~we ~~in pricing~~will ~~between~~continue ~~supply~~to ~~sources~~incur ~~and~~substantial ~~market~~expenditures ~~areas~~beyond ~~could~~2012 ~~negatively~~relating ~~impact~~to the integrity and safety of our ~~transportation~~ ~~revenues~~pipeline. ~~Consequently~~In addition, as indicated above there is a ~~significant~~risk ~~prolonged~~that ~~downturn~~new ~~in natural~~regulations ~~gas~~associated ~~prices~~with ~~could~~pipeline ~~have~~safety aand ~~material~~integrity ~~adverse~~issues ~~effect~~will onbe ~~our~~adopted ~~financial condition,~~that ~~results~~could ofrequire ~~operations~~us ~~and~~to ~~liquidity.~~incur ~~Fluctuations~~additional material expenditures in ~~energy~~the ~~prices~~ future. We are ~~caused~~also bysubject ato ~~number~~inherent ofrisks ~~factors,~~associated with operating gas storage facilities including: potential gas losses and field degradation.

•We ~~regional,~~do ~~domestic~~not ~~and~~own ~~international~~all ~~supply~~the ~~and~~land ~~demand,~~on ~~including~~which ~~changes~~our inpipeline ~~supply~~system and ~~demand~~facilities ~~due~~are tolocated, ~~general~~which ~~economic~~could ~~conditions~~disrupt ~~and~~our ~~weather;~~operations.

•We ~~availability~~do ~~and~~not ~~adequacy~~own all of ~~gathering,~~the ~~processing~~land on which our pipelines and ~~transportation~~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, our facilities; may not be properly located within the boundaries of such rights-of-way or the landowners otherwise interfere with our operations. Our loss of or interference with these rights could have a material adverse effect on us.

•There ~~energy~~are ~~legislation~~accounting ~~and~~principles ~~regulation,~~that ~~including~~are ~~potential~~unique ~~changes~~to ~~associated~~regulated ~~with~~interstate ~~GHG~~pipeline ~~emissions~~assets ~~and~~that ~~renewable~~could ~~portfolio~~materially ~~standards;~~impact our recorded earnings.

•Accounting ~~federal~~policies ~~and~~for ~~state~~FERC ~~taxes~~regulated pipelines are in certain instances different from U.S. general accepted accounting principles (GAAP) for nonregulated entities. For example, ifFERC ~~any~~accounting policies permit certain regulatory assets to be recorded on our balance sheet that would not typically be recorded for nonregulated entities. In determining whether to account for regulatory assets on our pipeline, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these assets. Currently, we have regulatory assets recorded on our balance sheet. If we determine that future recovery is no longer probable, then we could be required to write off the ~~sale~~regulatory orassets ~~transportation~~in ~~and~~the ~~storage~~future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of ~~natural~~long-lived ~~gas;~~assets. Equity amounts capitalized are included as other income on our income statement. To the extent that one of our expansion projects is not fully subscribed when it goes into service, we may experience a reduction in our earnings once the pipeline is placed into service.

• the price and availability of supplies of alternative energy sources; and

• the level of imports, including the potential impact of political unrest among countries producing oil and LNG, as well as the ability of certain foreign countries to maintain natural gas and oil prices, production and export controls.

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The ~~agencies~~supply ~~that regulate~~and usdemand ~~and~~for natural gas could be adversely affected by many factors outside of our ~~customers~~control which could negatively affect ~~our profitability~~us.

Our success depends on the supply and demand for natural gas. The degree to which our business is ~~regulated~~ impacted by ~~the~~changes ~~FERC,~~in ~~the~~supply ~~U.S.~~or ~~Department~~demand ofvaries. ~~Transportation~~For example, ~~the~~we ~~U.S. Department~~are ofnot significantly impacted in the ~~Interior~~short-term ~~and~~by ~~various~~reductions ~~state~~in ~~and~~the ~~local~~supply ~~regulatory~~or ~~agencies~~demand ~~whose actions~~for ~~have~~natural ~~the~~gas ~~potential~~since towe ~~adversely~~recover ~~affect~~most of our ~~profitability.~~revenues Infrom ~~particular, the~~reservation ~~FERC~~charges ~~regulates~~under ~~the~~longer-term ~~rates~~contracts wethat are ~~permitted~~not todependent ~~charge~~on ~~our~~the ~~customers~~supply ~~for~~and ~~our services~~demand ~~and~~of ~~sets~~natural ~~authorized~~gas ~~rates~~in ofthe ~~return~~short-term. InHowever, ~~January~~our ~~2010,~~business ~~the~~can ~~FERC~~be ~~approved our~~negatively ~~settlement~~impacted inby ~~which~~sustained wedownturn ~~(i)~~in ~~increased~~supply ~~our~~and ~~base~~demand ~~tariff~~for ~~rates~~natural ~~effective September~~gas. 1,One ~~2009,~~of ~~(ii)~~the ~~implemented~~major afactors ~~volume~~that ~~tracker~~will ~~for~~impact natural gas ~~used~~demand will be the potential growth of natural gas in ~~operations~~the power generation market, ~~(iii)~~ ~~agreed~~particularly todriven ~~file~~by ~~our~~the ~~next~~speed ~~general~~and ~~rate~~level ~~case~~of tocoal-fired bepower ~~effective~~generation ~~after~~that ~~August~~is ~~31, 2012~~replaced ~~but~~with nonatural ~~later~~gas-fired ~~than~~power ~~September~~generation. In 1addition, ~~2013,~~the supply and ~~(iv)~~demand ~~extended~~for ~~the~~natural ~~vast~~gas ~~majority~~for of our ~~firm~~business ~~transportation~~will ~~contracts~~depend ~~until~~on ~~August~~many 31other factors outside of our control, ~~2013.~~which include, among others:

We● ~~periodically file~~adverse ~~with~~changes the FERC to adjust the rates charged to our customers. In establishing those rates, the FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in ~~companies~~global ~~with~~economic corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. Depending on the specific risks faced by us and the companies included in the proxy groupconditions, ~~the~~including ~~FERC~~changes ~~may establish rates~~ that ~~are~~negatively ~~not acceptable to us and have a negative~~ impact ongeneral ~~our~~demand ~~cash~~for ~~flows,~~power ~~profitability~~generation and ~~results~~ ofindustrial ~~operations. In~~loads ~~addition,~~for ~~pursuant~~natural to laws and regulations, our existing rates may be challenged by complaint. The FERC commenced several complaint proceedings in 2009 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on our pipeline system and that a successful complaint against our rates could have an adverse impact on our cash flows and results of operations.gas;

In● ~~addition,~~adverse ~~the FERC~~changes ~~currently~~in ~~allows~~geopolitical ~~partnerships~~factors and ~~other~~unexpected ~~pass~~wars, ~~through~~terrorist ~~entities~~activities ~~to include in their cost-of-service an income tax allowance. Any changes to the FERC’s treatment of income tax allowances in cost-of-service~~ and toothers ~~potential adjustment~~acts ~~in a future rate case~~ of ~~our equity rate of return may cause our rates to be set at a level that is different from those currently in place and in some instances lower than the level otherwise in effect.~~aggression;

~~Increased regulatory~~● ~~requirements~~technological ~~relating~~advancements tothat ~~the~~may ~~integrity~~drive offurther ~~our~~increases ~~pipeline requires additional spending~~ in ~~order~~production tofrom ~~maintain~~natural ~~compliance~~gas with the FERC’s requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.shales;

~~Environmental compliance~~● ~~and~~competition ~~remediation~~from ~~costs~~imported LNG and ~~the~~alternate ~~costs of environmental liabilities could exceed our estimates.~~fuels;

~~Our~~● ~~operations~~increased ~~are subject~~prices to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation or clean-up of contaminated properties (some of which have been designated as Superfund sites by the U.S. Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act), as well as damage claims arising out of the contamination of properties or impact on natural ~~resources.~~gas ~~Although~~that we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could benegatively ~~required to set aside additional amounts which could significantly~~ impact ~~our future consolidated results of operations, financial position or cash flows. See Part II, Item 8, Financial Statements and Supplementary Data, Note 7.~~demand;

In● ~~estimating~~increased ~~our environmental~~costs ~~liabilities,~~to wetransport ~~face~~natural ~~uncertainties that include:~~gas;

•● ~~estimating~~adoption ~~pollution~~of ~~control~~various ~~and~~energy ~~clean~~efficiency upand ~~costs,~~conservation ~~including sites where preliminary site investigation or assessments have been completed~~measures; and

•● ~~discovering~~perceptions ~~new~~of ~~sites~~customers oron ~~additional~~the ~~information~~availability atand ~~existing~~price ~~sites;~~volatility of natural gas prices over the longer-term.

•The ~~forecasting~~price ~~cash~~for ~~flow~~natural ~~timing~~gas tocould ~~implement~~be ~~proposed~~adversely ~~pollution~~affected by many factors outside of our control ~~and~~which ~~cleanup~~could ~~costs;~~negatively affect us.

Natural gas 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. The degree to which our business is impacted by lower commodity prices varies. For example, we are not significantly impacted in the short-term by changes in natural gas prices. However, we can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas, including reductions in our ability to renew transportation contracts on favorable terms, as well as to construct new pipeline infrastructure. The price for natural gas is subject to a variety of additional factors that are outside of our control, which include, among others:

●	changes in regional and domestic supply and demand;

●

changes in basis differentials among different supply basins that can negatively impact our ability to compete with supplies from other basins, including our ability to maintain our transportation revenues and renew transportation contracts in supply basins that are not as competitive as other alternatives;

●	changes in the costs of transporting natural gas;

●	increased federal and state taxes, if any, on the transportation of natural gas;

●	the price and availability of supplies of alternative energy sources;

●	the amount of capacity available to transport natural gas.

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

The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies and storage companies in the transportation and storage of natural gas, as well as 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. There have also been various proposals over time to construct new pipelines into our market area.

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•Our ~~receiving~~operations ~~regulatory~~are ~~approval~~subject ~~for~~to ~~remediation~~operational ~~programs;~~hazards and uninsured risks which could negatively affect us.

•Our ~~quantifying~~operations ~~liability~~are ~~under~~subject to a number of 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 pipeline by third party excavation or construction); explosions, pipeline failures, mechanical and process safety failures; events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental ~~laws~~hazards. ~~that~~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 ~~impose~~encounter ~~joint~~additional marine perils, including hurricanes and ~~several~~other ~~liability~~adverse weather conditions, damage from collisions with vessels, and governmental regulations. In addition, although the potential effects of climate change on ~~potentially~~our ~~responsible~~operations ~~parties~~(such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) 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 ~~managing~~other ~~allocation~~coastal ~~responsibilities;~~regions.

•While ~~evaluating~~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 ~~understanding~~do not cover all risks. For example, we do not carry or are unable to obtain insurance coverage on terms that we find acceptable for certain exposures including, but not limited to certain environmental ~~laws~~exposures (including potential environmental fines and ~~regulations~~penalties), ~~including~~business ~~their~~interruption, ~~interpretation~~named windstorm/hurricane exposures, and ~~enforcement;~~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.

•We ~~interpreting~~are ~~whether~~subject ~~various~~to ~~maintenance~~a ~~activities~~complex ~~performed~~set inof ~~the~~laws ~~past~~ and ~~currently~~regulations ~~being~~that ~~performed~~regulate ~~required~~the ~~pre-construction~~energy ~~permits~~industry ~~pursuant~~for towhich ~~the~~we ~~Clean~~have ~~Air~~to ~~Act;~~incur substantial compliance and remediation costs.

•Our ~~changing~~operations ~~environmental~~are subject to a complex set of federal, state and local laws and regulations that ~~may~~tend ~~increase~~to change from time to time and generally are becoming increasingly more stringent. In addition to the 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 and the FERC to impose penalties for violations of laws or regulations 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 discharge 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 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 or local lands are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands both onshore and offshore, which are regulated by the Department of the Interior, particularly by the Bureau of Land Management and the Bureau of Ocean Energy Management, Regulation and Enforcement.

InThe ~~addition to potentially increasing the cost of our environmental liabilities, changing environmental~~ laws and regulations ~~may~~(and ~~increase our future compliance costs, such as~~ the ~~costs of~~interpretations ~~complying~~thereof) ~~with~~that ~~ozone~~are ~~standards,~~applicable ~~emission standards with regard~~ to our ~~reciprocating~~ ~~internal~~business ~~combustion~~could ~~engines~~materially onchange ~~our~~in ~~pipeline~~the ~~system, GHG reporting~~future and ~~potential~~increase ~~mandatory~~the ~~GHG~~cost ~~emissions~~of ~~reductions. Future environmental compliance costs relating to GHGs associated with~~ our ~~operations~~operation ~~are~~or ~~not~~otherwise ~~yet clear. For~~negatively ~~a further~~impact ~~discussion on GHGs, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies~~us.

~~Although~~The ~~it is uncertain what impact legislative,~~ regulatory, ~~and~~framework ~~judicial~~affecting ~~actions~~our ~~might~~business ~~have on us until further definition~~ is ~~provided~~frequently insubject ~~those~~to ~~forums~~change, ~~there~~with isthe a risk that ~~such~~ ~~future~~either ~~measures~~new ~~could~~laws ~~result~~and inregulations ~~changes~~may tobe ~~our~~enacted ~~operations~~or ~~and~~existing tolaws ~~the consumption~~ and ~~demand~~regulation ~~for~~may ~~natural~~be ~~gas~~amended. ~~Changes~~Such tonew ~~our~~or ~~operations~~amended ~~could~~laws ~~include increased~~and ~~costs~~regulations tocan ~~(i)~~materially ~~operate~~affect ~~and maintain~~ our ~~facilities,~~operations ~~(ii)~~and ~~install new emission controls on~~ our ~~facilities,~~financial ~~(iii)~~results. In ~~construct~~this ~~new facilities~~regard, ~~(iv) acquire~~there ~~allowances~~have orbeen ~~pay~~proposals ~~taxes related~~ to ~~our~~implement ~~GHG~~or ~~and~~amend ~~other~~federal, ~~emissions~~state, and ~~(v) administer~~local ~~and~~laws ~~manage an emissions program for GHG~~ and ~~other emissions. Changes in~~ regulations, ~~including~~that ~~adopting~~could ~~new~~negatively ~~standards~~impact ~~for emission controls from certain of~~ our ~~facilities~~business, could also result in delays in obtaining required permits to construct our facilities. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipeline and in the prices at which ~~we sell~~includes ~~natural~~among gas, 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.others:

Our operations are subject to operational hazards and uninsured risks.

Our operations are subject to the inherent risks normally associated with pipeline operations, including pipeline failures, explosions, pollution, release of toxic substances, fires, adverse weather conditions (such as hurricanes and flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses. In addition, although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of GHG could have a negative impact on our operations in the future.

While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles as well as limits on our maximum recovery, and do not cover all risks. There is also the risk that our coverages will change over time in light of increased premiums or changes in the terms of the insurance coverages that could result in our decision to either terminate certain coverages, increase our deductibles or decrease our maximum recoveries. In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

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● 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 GHG emissions. The ~~expansion~~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 has 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 ~~business~~operations. byThis ~~constructing~~will ~~new~~largely ~~facilities~~depend ~~subjects~~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 us to ~~construction~~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 ~~risks~~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 system. 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 ~~adversely~~be ~~affect~~able to include some or all of the costs associated with our ~~financial~~environmental ~~results~~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.

We● ~~may~~Renewable/Conservation ~~expand~~Legislation. There have been various legislative and regulatory proposals at the ~~capacity~~ offederal ~~our~~and ~~existing~~state ~~pipeline~~levels to provide incentives and ~~storage~~subsidies ~~facilities~~to by(a) ~~constructing additional~~shift ~~facilities.~~more ~~Construction~~power ofgeneration ~~these~~to ~~facilities~~renewable isenergy ~~subject~~sources and (b) support technological advances to ~~various regulatory,~~drive ~~development~~less energy consumption. These incentives and ~~operational~~subsidies ~~risks,~~could ~~including:~~have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.

•● ~~our~~Pipeline ~~ability~~Safety. toVarious ~~obtain~~legislative ~~necessary~~and ~~approvals~~regulatory ~~and~~reforms ~~permits~~associated bywith ~~the~~pipeline ~~FERC~~safety and ~~other~~integrity ~~regulatory~~issues ~~agencies~~have onbeen arecently ~~timely~~proposed, ~~basis~~including reforms that would require increased periodic inspections, installation of additional valves and other equipment on ~~terms~~our ~~that~~pipeline ~~are~~and ~~acceptable~~subjecting toadditional ~~us,~~pipelines (including ~~the~~gathering ~~potential~~facilities) ~~impact~~to ofmore ~~delays~~stringent ~~and~~regulation. ~~increased~~It ~~costs~~is ~~caused~~uncertain bywhat ~~certain~~reforms, ~~environmental~~if ~~and~~any, ~~landowner~~will ~~groups~~be ~~with~~adopted ~~interests~~and ~~along~~what ~~the~~impact ~~route~~they ofmight ultimately have on our ~~pipeline;~~operations or financial results.

•We ~~the~~are ~~ability~~exposed to ~~access~~the ~~sufficient~~credit ~~capital~~risk atof ~~reasonable~~our ~~rates~~counterparties toand ~~fund~~our ~~expansion~~credit ~~projects,~~risk ~~especially~~management ~~in periods of prolonged economic decline when we~~ may not be ~~unable~~adequate to ~~access~~protect ~~the~~against ~~capital~~such ~~markets;~~risk.

•We are subject to the ~~availability~~risk ofthat ~~skilled~~our ~~labor~~counterparties fail to make payments to us within the time required under our contracts. Our current largest exposures are associated with shippers under long-term transportation contracts on our pipeline system. Our credit procedures and policies may not be adequate to fully eliminate counterparty credit risk. In addition, ~~equipment~~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 ~~materials~~perform, we could be adversely affected. For example, we may not be able to ~~complete~~effectively ~~expansion~~remarket ~~projects;~~capacity or enter into new contracts at similar terms during and after insolvency proceedings involving a customer.

•We ~~potential~~are ~~changes~~exposed into ~~federal,~~the ~~state~~credit and ~~local~~performance ~~statutes,~~risk ~~regulations~~of ~~and~~our ~~orders,~~key ~~such~~contractors asand ~~environmental requirements, including climate change requirements, that delay or prevent a project from proceeding or increase the anticipated cost of the project;~~suppliers.

•As ~~impediments~~an owner of energy infrastructure facilities with significant capital expenditures, we rely on ~~our~~contractors for certain construction, and we rely on suppliers for key materials, supplies and services, including steel mills and pipe and tubular manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to ~~acquire~~perform ~~rights-of-way~~their orcontractual ~~land~~obligations ~~rights~~with orus, toincluding ~~commence~~their performance and ~~complete~~warranty ~~construction~~obligations. onThis acould ~~timely~~result ~~basis~~in delays or ondefaults ~~terms~~in ~~that~~performing ~~are~~such ~~acceptable~~contractual obligations and increased costs to seek replacement contractors, each which could adversely impact us;.

• our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials, labor, contractor productivity, delays in construction or other factors beyond our control, that we may not be able to recover from our customers which may be material;

• the lack of future growth in natural gas supply and/or demand; and

• 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 the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or we may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

Adverse general domestic economic conditions could negatively affect our operating results, financial condition, or liquidity.

We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. The global economy is experiencing a recession and the financial markets have experienced extreme volatility and instability. In response, over the last year, El Paso announced certain actions designed to reduce its need to access such financial markets, including reductions in the capital programs of certain of its operating subsidiaries and the sale of several non-core assets.

If we or El Paso experience prolonged periods of recession or slowed economic growth in the U.S., demand growth from consumers for natural gas transported by us may continue to decrease, which could impact the development of our future expansion projects. Additionally, our or El Paso’s access to capital could be impeded and the cost of capital we obtain could be higher. Finally, we are subject to the risks arising from changes in legislation and regulation associated with any such recession or prolonged economic slowdown, including creating preference for renewables, as part of a legislative package to stimulate the economy. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.

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We have certain contingent liabilities that could exceed our estimates.

We have certain contingent liabilities associated with litigation, regulatory and environmental matters. In this regard, although we have greatly reduced our litigation, regulatory and environmental exposures over the last several years, we continued to have contingent liabilities (see Part II, Item 8, Financial Statements and Supplementary Data, Note 7). Although we believe that we have established appropriate reserves for our litigation and environmental matters, we could be required to accrue additional amounts in the future and these amounts could be material.

We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these retained liabilities, including a reduction in historical knowledge of the assets and business that is required to effectively manage these liabilities or defend any associated litigation or regulatory proceedings.

We are subject to financing and interest rate risks.

~~Our~~Although ~~future~~a ~~success, financial~~substantial ~~condition~~portion ~~and~~of ~~liquidity~~our ~~could~~debt becapital ~~adversely~~structure ~~affected~~has ~~based~~fixed oninterest ~~our ability~~rates, tochanges ~~access~~in ~~capital~~market ~~markets~~conditions, ~~and~~including ~~obtain~~potential ~~financing~~increases atin ~~cost~~the ~~effective~~deficits ~~rates. This~~of isforeign, ~~dependent~~federal onand state governments, could have a ~~number~~negative ofimpact ~~factors~~on ininterest ~~addition~~rates that could cause our financing costs to ~~general~~increase. ~~economic conditions~~Since ~~discussed~~interest ~~above~~rates are at historically low levels, ~~many~~it ofis ~~which~~anticipated wethat ~~cannot~~they ~~control,~~will ~~including~~increase ~~changes~~ in: the future.

• our credit ratings;

• the structured and commercial financial markets;

• market perceptions of us or the natural gas and energy industry; and

• market prices for hydrocarbon products.

Risks Related to Our Affiliation with El Paso and EPB

El Paso and EPB file reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not included herein or incorporated by reference into this report.

We are a ~~majority owned~~consolidated subsidiary of EPB and El Paso.

As a ~~majority~~consolidated ~~owned~~ subsidiary of EPB and El Paso, subject to limitations in our indentures, EPB and El Paso ~~has~~ have substantial control over:

• decisions on our financing and capital raising activities; • mergers or other business combinations; • our acquisitions or dispositions of assets; and • our participation in EPB’s cash management program.

•EPB ~~mergers~~and El Paso may exercise such control in its interests and not necessarily in the interests of us or ~~other~~the ~~business~~holders ~~combinations;~~of our long-term debt.

• our acquisitions or dispositions of assets; and

• our participation in El Paso’s cash management program.

El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.

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

Our business requires the retention and recruitment of a skilled workforce. If El Paso is unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.

Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our and El Paso’s leverage, liquidity, and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital.

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ElOur ~~Paso~~business ~~provides cash~~requires ~~management~~the retention and ~~other~~recruitment ~~corporate services for us. We are currently required to make distributions~~ of ~~available cash as defined in our partnership agreement on~~ a ~~quarterly~~skilled ~~basis~~workforce toand ~~our~~the ~~partners.~~loss ~~In addition, we conduct commercial transactions with some~~ of ~~our~~employees ~~affiliates.~~could Ifresult Elin ~~Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under~~ the ~~cash~~failure ~~management program, or our affiliates may not be able~~ to ~~pay their~~implement ~~obligations to us. However, we might still be required to satisfy any affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect~~ our ~~financial~~business ~~position and cash flows~~plan. ~~For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.~~

Our relationship with El Paso and EPB and their financial condition subjects us to potential risks that are beyond our control.

Due to our relationship with El Paso and EPB, adverse developments or announcements concerning them or their other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. El Paso, EPB and their subsidiaries, including us, are on a stable outlook with Moody’s Investor Service, Fitch Ratings and Standard & Poor’s rating agencies. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our, EPB’s and El Paso’s leverage, liquidity, and credit profile. Any reduction in our, El Paso’s or EPB’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital. Below are the ratings assigned to our, El Paso’s and EPB’s senior unsecured indebtedness at December 31, 2010.

	Rating Agency
	Moody’s Investor Service	Standard & Poor’s	Fitch Ratings
		Credit Rating

SNG	Baa3 (1)	BB (2)	BBB- (1)
EPB	Ba1 (2)	BB (2)	BBB- (1)
El Paso	Ba3 (2)	BB-(2)	BB+ (2)

____________

(1) Investment grade.

(2) Below investment grade.

EPB provides cash management services and El Paso provides other corporate services for us. We are currently required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. In addition, we conduct commercial transactions with some of our affiliates. If EPB, El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy any affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

Our relationship with El Paso and EPB subjects us to potential conflicts of interest and they may favor their interests to the detriment of us.

Although ElEPB ~~Paso~~ has majority control of most decisions affecting our business, there are certain decisions that require the approval of both El Paso and EPB, including material regulatory filings, any significant sale of our assets, mergers and certain changes in affiliated service agreements. Conflicts of interest or disagreements could arise between El Paso and EPB with regard to such matters requiring unanimous approval, which could negatively impact our future operations.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

We have not included a response to this item since no response is required under Item 1B of Form 10K.

ITEM 2. PROPERTIES

A description of our properties is included in Item 1, Business, and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, 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 interest in these properties, or the use of these properties in our business. 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 material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.

ITEM 4. ~~SUBMISSION~~(REMOVED OFAND ~~MATTERS TO A VOTE OF SECURITY HOLDERS~~RESERVED)

~~None.~~13

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of our partnership interests are held by El Paso and EPB and, accordingly, are not publicly traded. ~~Prior to converting into a general partnership effective November 1, 2007, all of our common stock was held by El Paso.~~

We are required to make distributions to our partners of available cash as defined in our partnership agreement on a quarterly basis from legally available funds that have been approved for payment by our Management Committee. We made cash distributions to our partners of ~~approximately~~$257 million in 2010, $171 million in 2009 and ~~approximately~~ $200 million in 2008. ~~No dividends or cash distributions were declared or paid in 2007.~~ Additionally, in January ~~2010~~2011, we made a cash distribution of approximately $8347 million to our partners.

ITEM 6. SELECTED FINANCIAL DATA

The following selected historical financial data is derived from our audited consolidated financial statements and is not necessarily indicative of results to be expected in the future. The selected financial data should be read together with Item 7, Management’s Discussion and Analysis and Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary Data included in this Report on Form 10-K.

	As of or for the Year Ended December 31,
	2009		2008		2007		2006		2005
	2010		2009		2008		2007		2006
	(In millions)
Operating Results Data:
Operating revenues	$	~~510~~548	$	~~540~~510	$	~~482~~540	$	~~462~~482	$	~~437~~462
Operating income		~~255~~308		~~271~~255		~~242~~271		~~218~~242		~~215~~218
Income from continuing operations		208		235		202		162		155
Net income		267		208		235		202		162
Financial Position Data:
Total assets	$	2,~~659~~687	$	2,~~629~~659	$	2,~~803~~629	$	32,~~395~~803	$	3,~~199~~395
Long-term debt, less current maturities		910		910		~~1,098~~910		1,~~096~~098		1,~~195~~096
Partners’ capital/stockholder’s equity		1,~~614~~624		1,~~577~~614		1,~~542~~577		1,~~644~~542		1,~~455~~644

1314

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 I, Item 1A, Risk Factors. We have included a discussion in this MD&A of our business, ~~growth~~expansion projects, results of operations, liquidity and capital resources, contractual obligations and critical accounting ~~policies and~~ estimates that may affect us as we operate in the future.

In November 2007, in conjunction with the formation of El Paso Pipeline Partners, L.P. (EPB), we distributed our 50 percent interest in Citrus Corp. (Citrus) and our wholly owned subsidiaries Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba Express), to El Paso Corporation (El Paso). Citrus owns the Florida Gas Transmission Company, LLC pipeline system and SLNG owns the Elba Island LNG facility. SLNG and Elba Express have been reflected as discontinued operations in our financial statements for periods prior to their distribution. Our continuing operating results include earnings from Citrus, but only through the date of its distribution to El Paso. For a further discussion of these discontinued operations, see Item 8, Financial Statements and Supplementary Data, Note 2. In addition, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes. Accordingly, we settled our then existing current and deferred tax balances through El Paso’s cash management program pursuant to our tax sharing agreement with El Paso.

Overview

Business. Our primary business consists of the interstate transportation and storage of natural gas. ~~Each~~ ofWe ~~these~~face ~~businesses faces~~ varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.

Type	Description	Percent of ~~Total~~2010 Revenues ~~in 2009~~
Reservation	Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline ~~system~~systems and storage ~~facilities~~facility. 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.	88
Usage and Other	Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.	12

The ~~Federal Energy Regulatory Commission (~~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. In January 2010, the FERC approved our settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our 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 our firm transportation contracts until August 31, 2013. 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.

14We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

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We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. We refer to the difference between the maximum rates allowed under our tariff and the contractual rate we charge as discounts.

Our existing contracts mature at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately six years as of December 31, 2009. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2009, including those with terms beginning in 2010 or later.

	Contracted Capacity		Percent of Total Contracted Capacity		Reservation Revenue		Percent of Total Reservation Revenue
	(BBtu/d)				(In millions)
2010		118		3	$	16		4
2011		124		3		6		1
2012		—		—		—		—
2013		2,127		56		255		58
2014 and beyond		1,473		38		161		37
Total		3,842		100	$	438		100

Growth Projects. We expect to spend approximately $403 million on contracted organic growth projects from 2010 through 2014. Of this amount, we expect to spend $249 million in 2010 primarily on our South System III and the Southeast Supply Header projects described below:

• South System III. The South System III expansion project will expand our pipeline system in Mississippi, Alabama and Georgia by adding approximately 81 miles of pipeline looping and replacement on our south system and 17,310 horsepower of compression to serve an existing power generation facility owned by the Southern Company in the Atlanta, Georgia area that is being converted from coal-fired to cleaner burning natural gas. This expansion project will be completed in three phases, at an estimated total cost of $352 million, with each phase expected to add an additional 122 MMcf/d of capacity. In August 2009, we received a certificate of authorization from the FERC on this project. The project has estimated in-service dates of January 2011 for Phase I, June 2011 for Phase II and June 2012 for Phase III. We have entered into a precedent agreement with Southern Company Services as agent for its affiliated operating companies, Georgia Power Company, Alabama Power Company, Mississippi Power Company, Southern Power Company and Gulf Power Company to provide an incremental firm transportation service to such operating companies, commencing in phases beginning January 1, 2011, and ending May 31, 2032, which is 20 years after the estimated in-service date for Phase III.

• Southeast Supply Header. We own an undivided interest in the northern portion of the Southeast Supply Header project jointly owned by Spectra Energy Corp (Spectra) and CenterPoint Energy, which added 115-mile supply line to the western portion of our system. This project is expected to provide access through pipeline interconnects to several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale basins. The estimated cost to us for Phase II is $69 million and is expected to provide us with an additional 350 MMcf/d of supply capacity. In August 2009, we received a certificate of authorization from the FERC to construct Phase II, which is anticipated to be placed in service in June 2011.

We believe that cash flows from operating activities, combined with amounts available to us under El Paso’s cash management program and capital contributions from our partners, will be adequate to meet our capital requirements and our existing operating needs.

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Our existing contracts expire at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately seven years as of December 31, 2010. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2010, including those with terms beginning in 2011 or later.

	Contracted Capacity			Percent of Contracted Capacity		Reservation Revenue		Percent of Reservation Revenue
		(BBtu/d)	(In millions)
2011		140			3	$	8		2
2012		2			—		—		—
2013		2,065			49		249		50
2014		36			1		6		1
2015		360			9		46		9
2016 and beyond		1,617			38		192		38
Total		4,220			100	$	501		100

Expansion Projects. During 2011, we plan to spend approximately $125 million in capital on our backlog of expansion projects. Our most significant FERC approved projects are described below.

	•	South System III. This expansion project will be completed in three phases, at an estimated total cost of approximately $300 million, 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 Phase II. We own 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 our system. This project provides us 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 us for Phase II of this project is approximately $60 million and is expected to provide us with an additional 350 MMcf/d of supply capacity. We expect to place Phase II of the project in service in June 2011.

In addition to our backlog of contracted organic growth projects, we have other projects that are in various phases of commercial development. Many of the potential projects involve expansion capacity to serve increased natural gas-fired generation loads and would have in-service dates for 2015 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.

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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 business, which consists of both consolidated operations and an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. We define EBIT as net income adjusted for items such as (i) interest and debt expense, and (ii) affiliated interest income, ~~and (iii) income taxes~~net. ~~We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods.~~ EBIT may not be comparable to measures 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 ~~our~~ net income, our throughput volumes and an analysis and discussion of our results in ~~2009~~2010 compared with ~~2008~~2009 and ~~2008~~2009 compared with ~~2007~~2008.

Operating Results:

	2009			2008			2007
	2010			2009			2008
	(In millions, except for volumes)
Operating revenues	$	~~510~~548		$	~~540~~510		$	~~482~~540
Operating expenses		(~~255~~240	)		(~~269~~255	)		(~~240~~269	)
Operating income		~~255~~308			~~271~~255			~~242~~271
Earnings from unconsolidated affiliates		1114			1311			8813
Other income, net		27			102			1310
EBIT(1)		268			294			343
EBIT		329			268			294
Interest and debt expense		(6263	)		(7262	)		(9172	)
Affiliated interest income		2			13			19
Affiliated interest income, net		1			2			13
Income tax expense		—			—			(69	)
Net income	$	267		$	208		$	235
Income from continuing operations		208			235			202
Throughput volumes (BBtu/d) (1)		2,505			2,322			2,339
Discontinued operations, net of income taxes		—			—			19
Net income	$	208		$	235		$	221
Throughput volumes (BBtu/d)(2)		2,322			2,339			2,345

____________

(1) ~~2007~~Throughput ~~EBIT~~volumes ~~represents~~include ~~EBIT~~billable ~~from~~transportation ~~continuing~~throughput ~~operations~~volumes for storage injection.

(2) Throughput volumes include billable transportation throughput volumes for storage injection.

EBIT Analysis:

	2009 to 2008												2008 to 2007
	2010 to 2009												2009 to 2008
	Revenue			Expense			Other			Total			Revenue			Expense			Other			Total
	Operating Revenue			Operating Expense			Other			Total			Operating Revenue			Operating Expense			Other			Total
	Favorable/(Unfavorable)
	(In millions)
Expansions	$	2		$	(3	)	$	(12	)	$	(13	)	$	14		$	(2	)	$	(2	)	$	10
Reservation and other services revenues	$	47		$	—		$	—		$	47		$	24		$	(3	)	$	—		$	21
Service revenues		22			—			—			22			2			—			—			2
AFUDC on expansions		—			—			9			9			—			—			(12	)		(12	)
Gas not used in operations and other natural gas sales		(15	)		22			—			7			9			(12	)		—			(3	)
Gas not used in operations and other natural gas activities		(8	)		7			—			(1	)		(15	)		22			—			7
Calpine bankruptcy		~~(35~~—	)		—			—			~~(35~~—	)		33(35	)		—			—			33(35	)
Operating and general and administrative expenses		—			—10			—			—10			—			~~(10~~—	)		—			~~(10~~—	)
Earnings from Citrus		—			—			—			—			—			—			(75	)		(75	)
Other(1)		(1	)		(2	)		(1	)		(4	)		(4	)		(5	)		2			(7	)
Other(1)		(4	)		(5	)		2			(7	)		—			(5	)		(1	)		(6	)
Total impact on EBIT	$	38		$	15		$	8		$	61		$	(30	)	$	14		$	(10	)	$	(26	)
Total impact on EBIT	$	(30	)	$	14		$	(10	)	$	(26	)	$	58		$	(29	)	$	(78	)	$	(49	)

____________

(1) Consists of individually insignificant items.

16Reservation and Other Services Revenues. In January 2010, the FERC approved our rate case settlement which among other factors, increased our base tariff rates effective September 1, 2009 which resulted in higher reservation and other services revenues for the years ended December 31, 2010 and 2009.

AFUDC on Expansions. We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on equity funds related to our construction of long-lived assets that is recorded as other income on our income statements. For the year ended December 31, 2010 when compared to 2009, we benefitted from an increase in other income of approximately $9 million associated with the equity portion of AFUDC primarily on our South System III and Southeast Supply Header Phase II projects. Other income for the year ended December 31, 2009 was reduced by approximately $12 million associated with the equity portion of AFUDC due to lower capital expenditures as compared to 2008 primarily due to the completion of the Cypress Phase II and Southeast Supply Header Phase I projects which were placed in service in May 2008 and September 2008.

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~~Expansions~~Gas Not Used in Operations and Other Natural Gas Activities. ~~During~~ Prior to September 1, 2009, the ~~allowance~~financial ~~for~~impacts ~~funds~~ of gas not used ~~during~~in ~~construction~~operations ~~(AFUDC)~~were ~~has~~based ~~been~~on ~~reduced~~the byprice ~~approximately~~of ~~$12~~natural ~~million due~~gas toand ~~lower~~the ~~capital~~amount ~~expenditures~~of asnatural ~~compared~~gas we were allowed to ~~2008.~~retain ~~This~~according ~~decrease~~to ~~is primarily~~our ~~attributable~~tariff, relative to the ~~completion~~amounts of ~~the~~natural ~~Cypress~~gas ~~Phase~~we IIused for operating purposes and ~~Southeast Supply~~the ~~Header~~cost ~~Phase~~of Ioperating ~~projects~~our ~~placed~~electric ~~into~~compression ~~service~~facilities. inVolumes ~~May~~from ~~2008~~any excess natural gas retained and ~~September 2008.~~not ~~Since~~used wein ~~placed~~operations ~~Phase~~were Ishared ofwith ~~the~~our ~~Cypress~~customers. Effective ~~project~~September in1, ~~service~~2009, inwe ~~May~~implemented ~~2007~~a ~~and Phase~~volume IItracker as part of ~~the~~our ~~project~~rate incase ~~May~~settlement ~~2008,~~and therefore we ~~experienced~~no anlonger ~~increased~~share ~~level~~retained ~~of revenue~~gas ~~throughout~~not ~~2008~~used ~~and~~in aoperations ~~decrease~~with inour ~~AFUDC~~customers. onFor ~~this~~the ~~project~~year inended ~~2008~~December as 31, 2010 when compared towith ~~2007.~~2009, ~~The~~our ~~reduction~~EBIT inwas ~~AFUDC~~favorably onimpacted by $5 million due to the ~~Cypress~~implementation ~~project~~of ~~during~~the ~~2008~~gas ~~was~~ volumetric tracker, partially offset by ~~higher~~$7 ~~AFUDC~~million ~~related~~due to the ~~construction~~elimination of ~~Phase~~our Ifuel sharing mechanism. Additionally, we experienced favorable impacts to our EBIT in 2010 compared to 2009 due to higher costs of ~~the Southeast~~$4 ~~Supply~~million ~~Header,~~associated ~~which~~with ~~was~~replacement ~~placed~~of ~~into~~depleted ~~service~~storage volumes in ~~September 2008~~2009.

~~During~~We ~~2009,~~periodically BGperform ~~LNG Services~~an ~~(BG)~~assessment ~~informed us~~ of ~~their~~our ~~intent~~natural ~~not~~gas tovolumes ~~exercise~~in ~~their~~our ~~option~~storage tofields, ~~have us construct~~ the ~~Cypress~~results ~~Phase~~of ~~III~~which ~~expansion.~~may ~~However,~~have BGnegative ~~has~~impacts ~~made alternative commitments~~ to ~~subscribe~~our toresults ~~certain other firm capacity on another~~ of Eloperations ~~Paso’s pipeline~~if ~~systems~~we ~~and~~determine toa ~~provide~~storage ~~certain~~loss ~~rate~~has ~~considerations on its existing transportation contract for Cypress Phases I and II~~occurred. InDuring ~~August 2009~~2010, weour ~~received certificates~~EBIT ofwas ~~authorization~~unfavorably ~~from~~impacted ~~the~~by ~~FERC~~$2 onmillion ~~the~~due ~~South~~to ~~System~~a ~~III~~gas ~~and Southeast~~loss ~~Supply~~at ~~Header~~one ~~Phase~~of IIour ~~projects~~storage facilities.

InFor ~~addition~~the toyear ~~our backlog~~ended ofDecember ~~contracted~~31, ~~organic growth projects~~2009, weour ~~have~~EBIT ~~other~~was ~~projects~~favorably ~~that~~impacted ~~are in~~$22 ~~various~~million ~~phases~~due ofto ~~commercial~~favorable ~~development.~~revaluation ~~Many~~ of ~~the~~retained ~~potential~~volumes ~~projects involve~~on ~~expansion~~our ~~capacity~~system tocompared ~~serve~~with ~~increased~~2008, ~~natural~~offset ~~gas-fired~~by ~~generation loads.~~lower ~~Although~~revenues ~~we pursue the development~~ of ~~these~~approximately ~~potential~~$15 ~~projects~~million ~~from~~due ~~time~~ to ~~time,~~favorable ~~there~~sales ~~can~~of beexcess nogas ~~assurance~~not ~~that~~used ~~we will be successful~~ in ~~negotiating~~operations ~~the definitive binding contracts necessary for such projects to be included~~ in ~~our backlog of contracted organic growth projects~~2008.

Service Revenues. During 2009, our service revenue increased primarily due to higher tariff rates placed into service on September 1, 2009 pursuant to our rate case settlement which is further discussed above. During 2008, our service revenues increased primarily due to an increase in our firm transportation revenue offset by lower interruptible services and usage revenue as compared to 2007.

Gas Not Used in Operations and Other Natural Gas Sales and Purchases. Prior to September 1, 2009, the financial impacts of our operational gas, net of gas used in operations, was based on the price of natural gas and the amount of natural gas we were allowed to retain and dispose of according to our tariff, relative to the amounts of natural gas we used for operating purposes and the cost of operating our electric compression facilities. Effective September 1, 2009, a volume tracker was implemented as part of our rate case settlement as further discussed below, therefore we no longer share retained gas not used in operations. However, through August 31, 2009, our share of retained gas not used in operations resulted in revenues to us, which were impacted by volumes and prices during a given period. For the year ended December 31, 2009, our operating expense was $22 million lower than in 2008 primarily due to favorable revaluation of retained volumes on our system. Offsetting this favorable impact during the year ended December 31, 2009 was a $15 million reduction in revenue primarily related to favorable sales in 2008. During the year ended December 31, 2008, our EBIT was lower primarily due to higher cost of electric compression on our system and lower gas prices at year end.

Calpine Bankruptcy. During 2008, we recognized revenue related to distributions received under Calpine’s approved plan of reorganization.

Operating and General and Administrative Expenses. Our operating and general and administrative ~~costs~~expenses were ~~higher~~lower infor ~~2008~~the ~~than~~year ~~2007~~ended December 31, 2010 compared with 2009 primarily due to ~~higher repair~~lower ~~and~~benefits, ~~maintenance~~payroll ~~costs~~ and ~~higher~~contractor ~~allocated~~ costs ~~from El~~net ~~Paso based on the estimated level~~ of ~~resources~~reimbursements ~~devoted~~from ~~to us and the relative size of~~ our ~~EBIT,~~ ~~gross~~affiliates ~~property~~related ~~and payroll when compared~~ to Eltheir ~~Paso’s~~shared ~~other affiliates~~pipeline services.

Earnings from Citrus. Our operating results for 2007 reflect earnings from Citrus prior to its distribution to El Paso in November 2007 in conjunction with the formation of EPB.

Interest and Debt Expense

Interest and debt expense for the year ended December 31, 2009, was $10 million lower than in 2008 primarily due to lower average outstanding debt balances resulting from the retirement and repurchases of debt in June and September ~~2008~~2009. ~~Interest and debt expense for the year ended December 31, 2008, was $19 million lower than in 2007 primarily due to lower average outstanding debt balances.~~ For further information on our outstanding debt balances, see Item 8, Financial Statements and Supplementary Data, Note 6.

17Affiliated Interest Income, net

~~Table~~ Affiliated interest income, net for the year ended December 31, 2009 was $11 million lower compared to 2008 due to lower average advances due from El Paso under its cash management program and lower short-term interest rates. During 2009, the average advances due from El Paso decreased primarily due to debt retirement and repurchases in June and September 2008 funded with recoveries of ~~Contents~~our note receivable.

~~Affiliated Interest~~In ~~Income~~conjunction with EPB’s acquisition of an additional interest in us in November 2010, we terminated our participation in El Paso’s cash management program and began to participate in EPB’s cash management program. The following table shows the average advances due from El Paso and payable to EPB, and the average short-term interest rates for the year ended December 31:

Affiliated interest income for the year ended December 31, 2009 was $11 million lower than in 2008 and $6 million lower for the year ended December 31, 2008 as compared to 2007 due to lower average advances due from El Paso under its cash management program and lower short-term interest rates. During 2009, the average advances due from El Paso decreased primarily due to debt retirement and repurchases in June and September 2008 with recoveries of our note receivable. The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:

	2010			2009			2008
	(In millions, except for rates)
Average advance due from El Paso	$	88		$	85		$	300
Average advance due to EPB		1			—			—
Average short-term interest rate on affiliate note receivable		1.5	%		1.7	%		4.4	%
Average short-term interest rate on affiliate note payable		0.8	%		—			—

	2009			2008			2007
	(In millions, except for rates)
Average advance due from El Paso	$	85		$	300		$	315
Average short-term interest rate		1.7	%		4.4	%		6.2	%

Income Taxes

Effective November 1, 2007, we no longer pay income taxes as a result of our conversion into a partnership, which impacted our 2007 effective tax rate. Our effective tax rate of 25 percent for the year ended December 31, 2007, was lower than the statutory rate of 35 percent primarily due to the tax effect of earnings from unconsolidated affiliates that qualify for the dividends received deduction, 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 3.

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Liquidity and Capital Resources

Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities, amounts available ~~under~~to Elus ~~Paso~~under EPB’s cash management program and capital contributions from our partners. At December 31, ~~2009~~2010, we had a note ~~receivable~~payable ~~from~~to ElEPB ~~Paso~~ of approximately $~~154~~12 million of which ~~approximately $42 million~~ was classified as current ~~based~~ on ~~the~~our ~~net~~balance ~~amount we anticipate using in the next twelve months considering available cash sources and needs~~sheet. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of EPB’s and El Paso’s cash management ~~program~~programs. Our primary uses of cash are for working capital, capital expenditures and for required distributions to our partners.

Although ~~recent~~ financial conditions have ~~shown signs of improvement~~improved, continued volatility in ~~2010~~ ~~and beyond in~~ the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base 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.

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flow from operating activities, amounts available to us under ~~El Paso~~EPB’s cash management program and capital contributions from our partners. As of December 31, ~~2009~~2010, ElEPB ~~Paso~~ had approximately $~~1.8~~450 ~~billion~~million of capacity available ~~liquidity,~~to ~~including~~it ~~approximately~~under its $~~1.3 billion~~750 ofmillion ~~capacity~~revolving ~~available~~credit tofacility itand ~~under~~$69 ~~various~~million ~~committed~~of ~~credit facilities~~cash. While we do not anticipate a need to directly access the financial markets in ~~2010~~ 2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.

~~For~~2010 ~~further~~Cash ~~detail on~~Flow ~~our~~Activities. ~~risk~~Our ~~factors~~cash ~~including~~flows ~~potential~~for ~~adverse~~the ~~general~~year ~~economic~~ended ~~conditions including~~December ~~our ability to access financial markets which could impact our operations and liquidity~~31, ~~see~~2010 ~~Part~~are I,summarized ~~Item~~as ~~1A,~~follows ~~Risk~~(in ~~Factors.~~millions):

2009 Cash Flow Activities. Our cash flows for the year ended December 31, 2009 are summarized as follows (In millions):


Cash Flow from Operations
Net income	$	267
Non-cash income adjustments		64
Change in assets and liabilities		(24	)
Total cash flow from operations		307

Other Cash Inflows
Investing activities
Proceeds from the sale of assets		8
Net change in note receivable from affiliate		154
Return of capital from investment in unconsolidated affiliate		15
		177
Financing activities
Net change in note payable to affiliate		12

Total cash inflows		189

Cash Outflows
Investing activities
Capital expenditures		217
Acquisition		18
		235
Financing activities
Distributions to partners		257

Total cash outflows		492
Net change in cash and cash equivalents	$	4

Cash Flow from Operations
Net income	$	208
Non-cash income adjustments		56
Change in other assets and liabilities		22
Total cash flow from operations		286
Cash Inflows
Investing activities
Proceeds from sale of assets		41
Cash Outflows
Investing activities
Additions to property, plant and equipment		138
Net change in notes receivable from affiliate		18
		156
Financing activities
Distributions to partners		171
Total cash outflows		327
Net change in cash	$	—

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During ~~2009~~2010, we generated $~~286~~ 307 million of operating cash flow. We utilized these amounts to ~~fund~~maintain ~~maintenance of~~ our system as well as pay distributions to our partners. During the year ended December 31, ~~2009~~2010, we paid cash distributions of approximately $~~171~~257 million to our partners. In addition, in January ~~2010~~2011 we paid a cash distribution to our partners of approximately $8347 million. Our cash capital expenditures for the year ended December 31, ~~2009~~2010 and those planned for ~~2010~~2011 are listed below:

	2009			Expected 2010
	2010			Expected 2011
	(In millions)
Maintenance	$	6067		$	9564
Expansion/Other		84			249
Expansion		150			128
Hurricanes(1)		(6	)		—
Total	$	217		$	192
Total	$	138		$	344

~~____________~~Our expected 2011 expansion capital expenditures primarily relate to our South System III and Southeast Supply Header Phase II expansion projects. Our maintenance capital expenditures primarily relate to maintaining and improving the integrity of our pipeline, complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. While we expect to fund maintenance capital expenditures through internally generated funds, we intend to fund our expansion capital expenditures through amounts available to us under EPB’s cash management program and capital contributions from our partners.

~~(1) Amounts shown~~For ~~are~~further ~~net~~detail ofon ~~insurance~~our ~~proceeds~~risk offactors $9including ~~million~~potential inadverse ~~2009~~general economic conditions including our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A, Risk Factors.

Our expected 2010 expansion capital expenditures primarily relate to our South System III and Southeast Supply Header expansion projects. Our maintenance capital expenditures primarily relate to maintaining and improving the integrity of our pipeline, complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. While we expect to fund maintenance capital expenditures through internally generated funds, we intend to fund our expansion capital expenditures through amounts available under El Paso’s cash management program and capital contributions from our partners. We anticipate to receive approximately $150 million of capital contributions from our partners during 2010.20

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Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt ~~and other accrued liabilities~~, while other obligations, such as operating leases, ~~demand~~storage ~~charges under transportation~~ and ~~storage~~electric commitments, and capital commitments, are not reflected on our balance sheet. We have excluded from these amounts expected contributions to our other postretirement benefit plans, because these expected contributions are not contractually required. For further information on our expected contributions to our post retirement benefit plans, see Item 8, Financial Statements and Supplementary Data, Note 8. The following table and discussion summarizes our contractual cash obligations as of December 31, ~~2009~~2010, for each of the periods presented (all amounts are undiscounted):

	Due in less than 1 Year		Due in 1 to 3 Years		Due in 3 to 5 Years		Thereafter		Total
	(In millions)
Long-term debt:
Principal	$	—	$	—	$	—	$	911	$	911
Interest		61		123		123		~~620~~559		~~927~~866
Operating leases		3		6		6		85		2320
Other contractual commitments and purchase obligations:
Transportation and storage commitments		18		9		—		—		27
Capital commitments		27		—		—		—		27
Other commitments		5311		153		—		—		6814
Total contractual obligations	$	~~135~~102	$	~~153~~132	$	129	$	1,~~539~~475	$	1,~~956~~838

Long-Term Debt (Principal and Interest). Debt obligations included in the table above represent stated maturities. Interest payments are shown through the stated maturity date of the related fixed rate debt based on the contractual interest rate. For a further discussion of our debt obligations, see Item 8, Financial Statements and Supplementary Data, Note 6.

Operating Leases. For a further discussion of these obligations see Item 8, Financial Statements and Supplementary Data, Note 7.

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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~~Capital ~~and Storage~~ Commitments. Included in these amounts are commitments for purchasing pipe and related assets in our pipeline operations, and various other maintenance, engineering, procurement and construction contracts. • Other Commitments. Included in these amounts are commitments primarily for storage services. We have excluded asset retirement obligations, and reserves for litigation and environmental remediation as these liabilities are not contractually fixed as to ~~the~~ timing and amount.

· Other Commitments. Included in these amounts are commitments for electric service to provide power to certain of our compression facilities and contractual obligations related to our expansion projects. We have excluded asset retirement obligations and reserves for litigation and environmental remediation as these liabilities are not contractually fixed as to timing and amount.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 7, which is incorporated herein by reference.

Climate Change and Energy Legislation and Regulation. There are various legislative and regulatory measures relating to climate change and energy policies that have been proposed and, if enacted, will likely impact our business.

Climate Change Legislation and Regulation. Measures to address climate change and greenhouse gas (GHG) emissions are in various phases of discussions or implementation at international, federal, regional and state levels. Over 50 countries, including the U.S., have submitted formal pledges to cut or limit their emissions in response to the United Nations-sponsored Copenhagen Accord. It is reasonably likely that federal legislation requiring GHG controls will be enacted within the next few years in the United States. Although it is uncertain what legislation will ultimately be enacted, it is our belief that cap-and-trade or other market-based legislation that sets a price on carbon emissions will increase demand for natural gas, particularly in the power sector. We believe this increased demand will occur due to substantially less carbon emissions associated with the use of natural gas compared with alternate fuel sources for power generation, including coal and oil-fired power generation. However, the actual impact on demand will depend on the legislative provisions that are ultimately adopted, including the level of emission caps, allowances granted, offset programs established, cost of emission credits and incentives provided to other fossil fuels and lower carbon technologies like nuclear, carbon capture sequestration and renewable energy sources.

It is also reasonably likely that any federal legislation enacted would increase our cost of environmental compliance by requiring us to install additional equipment to reduce carbon emissions from our larger facilities as well as to potentially purchase emission allowances. Based on 2008 operational data we reported to the California Climate Action Registry our operations in the United States emitted approximately 1.8 million tonnes of carbon dioxide equivalent emissions during 2008. We believe that approximately 1.6 million tonnes of the GHG emissions that we reported to CCAR would be subject to regulations under the climate change legislation that passed in the U.S. House of Representatives (the House) in June 2009. Of these amounts that would be subject to regulation, we believe that approximately 21 percent would be subject to the cap-and-trade rules contained in the proposed legislation and the remainder would be subject to performance standards. As proposed by the House, the portion of our GHG emissions that would be subject to cap-and-trade rules could require us to purchase allowances or offset credits and the portion of our GHG emissions that would be subject to performance standards could require us to install additional equipment or initiate new work practice standards to reduce emission levels at many of our facilities. The costs of purchasing emission allowances or offset credits and installing additional equipment or changing work practices would likely be material. Increases in costs of our suppliers to comply with such cap-and-trade rules and performance standards, such as the electricity we purchase in our operations, could also be material and would likely increase our cost of operations. Although we believe that many of these costs should be recoverable in the rates we charge our customers, recovery is still uncertain at this time. A climate change bill was also voted upon favorably by the Senate Committee on Energy and Public Works (the Committee) in November 2009 and has been ordered to be reported out of the Committee. Any final bill passed out of the U.S. Senate will likely see further substantial changes, and we cannot yet predict the form it may take, the timing of when any legislation will be enacted or implemented or how it may impact our operations if ultimately enacted.

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~~The~~Commitments ~~Environmental Protection Agency (EPA) finalized regulations to monitor~~ and report GHG emissions on an annual basis. The EPA also proposed new regulations to regulate GHGs under the Clean Air Act, which the EPA has indicated could be finalized as early as March 2010. The effective date and substantive requirements of any EPA final rule is subject to interpretation and possible legal challenges. In addition, it is uncertain whether federal legislation might be enacted that either delays the implementation of any climate change regulations of the EPA or adopts a different statutory structure for regulating GHGs than is provided for pursuant to the Clean Air Act. Therefore, the potential impact on our operations and construction projects remains uncertain.Contingencies

InFor ~~addition, in March 2009, the EPA proposed~~ a ~~rule~~further ~~impacting~~discussion ~~emissions~~of ~~from reciprocating internal combustion engines, which would require us to install emission controls on~~ our ~~pipeline~~commitments ~~system.~~and ~~It is expected that the rule will be finalized in August 2010. As proposed~~contingencies, ~~engines~~see ~~subject~~Item ~~to the regulations would have to be in compliance by August 2013. Based upon that timeframe~~8, weFinancial ~~would~~Statements ~~expect~~and ~~that~~Supplementary ~~we would commence incurring expenditures in late 2010~~Data, ~~with~~Note ~~the majority of the work and expenditures incurred in 2011 and 2012. If the regulations are adopted as proposed~~7, wewhich ~~would~~is ~~expect~~incorporated toherein ~~incur~~by ~~approximately $12 million in capital expenditures over the period from 2010 to 2013~~reference.

Legislative and regulatory efforts are underway in various states and regions. These rules once finalized may impose additional costs on our operations and permitting our facilities, which could include costs to purchase offset credits or emission allowances, to retrofit or install equipment or to change existing work practice standards. In addition, various lawsuits have been filed seeking to force further regulation of GHG emissions, as well as to require specific companies to reduce GHG emissions from their operations. Enactment of additional regulations by federal and state governments, as well as lawsuits, could result in delays and have negative impacts on our ability to obtain permits and other regulatory approvals with regard to existing and new facilities, could impact our costs of operations, as well as require us to install new equipment to control emissions from our facilities, the costs of which would likely be material.

Energy Legislation. In conjunction with these climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint.” These proposals would establish renewable energy and efficiency standards at both the federal and state level, some of which would require a material increase in renewable sources, such as wind and solar power generation, over the next several decades. There have also been proposals to increase the development of nuclear power and commercialize carbon capture sequestration especially at coal-fired facilities. Other proposals would establish incentives for energy efficiency and conservation. Although it is reasonably likely that many of these proposals will be enacted over the next few years, we cannot predict the form of any laws and regulations that might be enacted, the timing of their implementation, or the precise impact on our operations or demand for natural gas. However, such proposals if enacted could negatively impact natural gas demand over the longer term.

Off-Balance Sheet Arrangements

We have no off-balance sheet financing entities or structures with third parties other than our equity investment in Bear Creek, our accounts receivable sales program, and our letter of credit associated with the construction costs related to our Southeast Supply Header project. For a discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Notes 7, 10 and 11, which ~~are~~is incorporated herein by reference.

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, revenue and 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.

Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standards Board’s accounting standards on rate-regulated operations. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of 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. As of December 31, 2010, we had accrued approximately $2 million for legal matters.

Accounting for Other Postretirement Benefits. We reflect an asset or liability for our postretirement benefit plan based on its over funded or under funded status. As of December 31, 2010, our postretirement benefit plan was under funded by $3 million. Our postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rates used in calculating our benefit obligation. We select our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.

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~~Critical Accounting~~Actual ~~Policies~~results may differ from the assumptions included in these calculations, and ~~Estimates~~as a result, our estimates associated with our postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligation, along with changes to the plan 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):

The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material impact on our results of operations. For additional information concerning our other accounting policies, see the notes to the financial statements included in Item 8, Financial Statements and Supplementary Data, Note 1.

	Change in Funded Status
One percentage point increase in:
Discount rates	$	5
Health care cost trends		(5	)
One percentage point decrease in:
Discount rates	$	(5	)
Health care cost trends		4

Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standards Board’s accounting standards on rate-regulated operations. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under U.S. generally accepted accounting principles for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of this standard, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.

Accounting for Other Postretirement Benefits. We reflect an asset or liability for our postretirement benefit plan based on its over funded or under funded status. As of December 31, 2009, our postretirement benefit plan was under funded by $7 million. Our postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rates used in calculating our benefit obligation. We select our discount rate by matching the timing and amount of our expected future benefit payments for our 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, our estimates associated with postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligation, along with changes to the plan and other items, are deferred and recorded as either a regulatory asset or liability. A one percent change in our 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, 2009 (in millions):

	Change in Funded Status
One percent increase in:
Discount rates	$	5
Health care cost trends		(5	)
One percent decrease in:
Discount rates	$	(5	)
Health care cost trends		4

New Accounting Pronouncements Issued But Not Yet Adopted

See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, ~~2009~~2010, we had a note ~~receivable~~ ~~from El~~payable ~~Paso~~to EPB of approximately $~~154~~12 million, with a variable interest rate of 10.58% that is ~~due~~payable upon demand. While we are exposed to changes in interest ~~income~~expense based on changes to the variable interest rate, the fair value of this note ~~receivable~~payable approximates the carrying value due to the note being ~~due~~payable upon demand and the market-based nature of the interest rate.

The table below shows the carrying value, related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities and the estimated fair value of these securities ~~estimated~~ based on quoted market prices for the same or similar issues.

December 31, 2009

December 31, 2008

December 31, 2010

December 31, 2009

Expected Fiscal Year of Maturity of

Expected Fiscal Year of Maturity of Carrying Amounts

Carrying Amounts

Fair

Carrying

Fair

2011-2015

Thereafter

Total

Fair Value

Carrying Amount

Fair Value

2009-2013

Thereafter

Total

Value

Amount

Value

(In millions, except for rates)

(In millions, except for rate)

Liabilities:

Long-term debt — fixed rate

—

910

~~977~~984

910

~~726~~977

Average effective interest rate

6.8

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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 the Securities and Exchange Commission (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~~pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• ~~Provide~~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~~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 President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, ~~2009~~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. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, ~~2009~~ 2010.

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Report of Independent Registered Public Accounting Firm

The Partners of Southern Natural Gas Company

We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company (the Company) as of December 31, ~~2009~~2010 and ~~2008~~2009, and the related consolidated statements of income ~~and comprehensive income~~, partners’ capital~~/stockholder’s equity~~, and cash flows for each of the three years in the period ended December 31, ~~2009~~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, ~~2009~~2010. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The consolidated financial statements of Citrus Corp. and Subsidiaries (a corporation in which the Company had a 50% interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included from Citrus Corp. and Subsidiaries, is based solely on the report of the other auditors, exclusive of the income adjustment related to the disposition of the equity interest in November 2007. In the consolidated financial statements, earnings from the Company’s investment in Citrus Corp. represent approximately 28% of income before income taxes for the year ended December 31, 2007.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits ~~and the report of other auditors~~ provide a reasonable basis for our opinion.

In our opinion, ~~based~~ ~~on our audits and~~ the ~~report of other auditors, the~~ financial statements referred to above present fairly, in all material respects, the consolidated financial position of Southern Natural Gas Company at December 31, ~~2009~~2010 and ~~2008~~ 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2009~~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 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted a new income tax accounting standard, and effective January 1, 2008, the Company adopted the provisions of an accounting standard update related to measurement date and changed the measurement date of its postretirement benefit plan.

/s/ Ernst & Young LLP

Houston, Texas

February 26 28, ~~2010~~ 2011

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SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME ~~AND COMPREHENSIVE INCOME~~

(In millions)

	Year Ended December 31,
	2009			2008			2007
	2010			2009			2008
Operating revenues	$	~~510~~548		$	~~540~~510		$	~~482~~540
Operating expenses
Operation and maintenance		~~173~~154			~~189~~173			~~160~~189
Depreciation and amortization		5559			5355			53
Taxes, other than income taxes		27			27			27
		255			269			240
		240			255			269
Operating income		~~255~~308			~~271~~255			~~242~~271
Earnings from unconsolidated affiliates		1114			1311			8813
Other income, net		27			102			1310
Interest and debt expense		(6263	)		(7262	)		(9172	)
Affiliated interest income		2			13			19
Affiliated interest income, net		1			2			13
Income before income taxes		208			235			271
Net income	$	267		$	208		$	235
Income tax expense		—			—			69
Income from continuing operations		208			235			202
Discontinued operations, net of income taxes		—			—			19
Net income		208			235			221
Other comprehensive income		—			—			1
Comprehensive income	$	208		$	235		$	222

See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31,
	2009		2008
	2010		2009
ASSETS
Current assets
Cash and cash equivalents	$	—4	$	—
Accounts and notes receivable
Accounts and note receivable
Customer		73		37
Affiliates		64—		7164
Other		226		2
Materials and supplies		1516		1415
Other		914		159
Total current assets		9763		~~105~~97
Property, plant and equipment, at cost		3,~~709~~885		3,~~636~~709
Less accumulated depreciation and amortization		1,~~411~~390		1,~~373~~411
Total property, plant and equipment, net		2,~~298~~495		2,~~263~~298
Other assets
Investment in unconsolidated affiliate		7956		8179
Note receivable from affiliate		~~112~~—		95112
Other		73		8573
		264		261
		129		264
Total assets	$	2,~~659~~687	$	2,~~629~~659
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable
Accounts and note payable
Trade	$	1925	$	2819
Affiliates		2728		1027
Other		1631		1816
Taxes payable		913		89
Accrued interest		18		18
Asset retirement obligation		14		—
Asset retirement obligations		1		14
Other		56		105
Total current liabilities		~~108~~122		92108
Long-term debt		910		910
Other liabilities		2731		5027
Commitments and contingencies (Note 7)
Partners’ capital		1,~~614~~624		1,~~577~~614
Total liabilities and partners’ capital	$	2,~~659~~687	$	2,~~629~~659

See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2009			2008			2007
	2010			2009			2008
Cash flows from operating activities
Net income	$	~~208~~267		$	~~235~~208		$	~~221~~235
Less income from discontinued operations, net of income taxes		—			—			19
Income from continuing operations		208			235			202
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		5559			5355			53
Deferred income tax expense		—			—			23
Earnings from unconsolidated affiliate, adjusted for cash distributions		8			2			3
Earnings from unconsolidated affiliates, adjusted for cash distributions		2			3			42
Other non-cash income items		(3	)		(1	)		(5	)
Other non-cash income items		(1	)		(5	)		(6	)
Asset and liability changes
Accounts receivable		428			134			(713	)
Accounts payable		9			7			(13	)
Change in deferred purchase price from accounts receivable sales		(26	)		—			—
Taxes payable		—			—			(21	)
Accounts payable		(9	)		9			7
Other current assets		18(7	)		(518	)		(5	)
Other current liabilities		102			(910	)		(49	)
Non-current assets		—(13	)		~~(11~~—	)		(511	)
Non-current liabilities		~~(19~~1	)		4(19	)		~~(320~~4	)
Cash provided by (used in) continuing activities		286			285			(51	)
Net cash provided by operating activities		307			286			285
Cash provided by discontinued activities		—			—			25
Net cash provided by (used in) operating activities		286			285			(26	)
Cash flows from investing activities
Capital expenditures		(~~138~~217	)		(138	)		(~~243~~138	)
Net change in notes receivable from affiliate		(18	)		289			(152	)
Net change in note receivable from affiliate		154			(18	)		289
Proceeds from the sale of assets		41			—			—
Acquisition		(18	)		—			—
Cash provided by (used in) continuing activities		(115	)		151			(395	)
Proceeds from the sale of assets		8			41			—
Cash used in discontinued activities		—			—			(25	)
Return of capital from investment in unconsolidated affiliate		15			—			—
Net cash provided by (used in) investing activities		(~~115~~58	)		~~151~~(115	)		~~(420~~151	)
Cash flows from financing activities
Payments to retire long-term debt		—			~~(236~~—	)		(~~584~~236	)
Distributions to partners		(~~171~~257	)		(~~200~~171	)		—(200	)
Net proceeds from issuance of long-term debt		—			—			494
Net change in note payable to affiliate		12			—			—
Contribution from parent		—			—			536
Net cash used in financing activities		(245	)		(171	)		(436	)
Net cash provided by (used in) financing activities		(171	)		(436	)		446
Net change in cash and cash equivalents		4			—			—
Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—
End of period	$	—4		$	—		$	—
Supplemental cash flow information related to continuing operations Interest paid, net of amounts capitalized	$	59		$	61		$	75

See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL~~/STOCKHOLDER’S EQUITY~~

(In ~~millions,~~ ~~except share amounts~~millions)

	Common Stock					Additional Paid-in			Retained			Accumulated Other Comprehensive			Total Stockholder’s			Total Partners’
January 1, 2008	$	1,542
	Shares			Amount		Capital			Earnings			Income (Loss)			Equity			Capital
Net income		235
January 1, 2007		1,000		$	—	$	340		$	1,304		$	—		$	1,644		$	—
Distributions		(200	)
Net income										187						187
December 31, 2008		1,577
Other comprehensive income													1			1			—
Net income		208
Adoption of new tax accounting standard, net of income tax of $(3)										(5	)					(5	)		—
Distributions		(171	)
Reclassification to regulatory liability (Note 8)													(5	)		(5	)		—
December 31, 2009		1,614
October 31, 2007		1,000			—		340			1,486			(4	)		1,822			—
Net income		267
Conversion to general partnership (November 1, 2007)		(1,000	)				(340	)		(1,486	)		4			(1,822	)		1,822
Distributions		(257	)
Contributions																			536
December 31, 2010	$	1,624
Distributions																			(850	)
Net income																			34
December 31, 2007		—			—		—			—			—			—			1,542
Net income																			235
Distributions																			(200	)
December 31, 2008		—			—		—			—			—			—			1,577
Net income																			208
Distributions																			(171	)
December 31, 2009		—		$	—	$	—		$	—		$	—		$	—		$	1,614

See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware general partnership, originally formed in 1935 as a corporation. We are owned 7560 percent by ~~El Paso SNG Holding Company, L.L.C., a subsidiary of El Paso Corporation (El Paso) and 25 percent by~~ EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (EPB), ~~which~~a ismaster ~~majority~~limited ~~owned~~partnership by of El Paso. InCorporation ~~conjunction with the formation of EPB in November 2007, we distributed our 50 percent interest in Citrus Corp.~~ (~~Citrus~~El Paso), ~~our wholly owned subsidiaries Southern LNG, Inc. (SLNG)~~ and ~~Elba~~40 ~~Express~~percent ~~Company,~~by ~~LLC (Elba Express) to~~ El Paso ~~effective~~SNG ~~November~~Holding 21Company, ~~2007~~L. ~~Citrus owns the Florida Gas Transmission Company~~L.C., ~~LLC~~a ~~(FGT)~~wholly ~~pipeline~~owned ~~system~~subsidiary ~~and~~of ~~SLNG~~El ~~owns our Elba Island LNG facility~~Paso. Our Weconsolidated ~~have reflected the SLNG and Elba Express operations as discontinued operations in our~~ financial statements ~~for~~are ~~periods~~prepared ~~prior~~in toaccordance ~~their distribution~~with U.S. ~~Additionally,~~generally ~~effective~~accepted ~~November~~accounting 1,principles ~~2007,~~(GAAP) ~~we converted to a general partnership~~ and ~~are~~include nothe ~~longer~~accounts ~~subject~~of toall ~~income~~consolidated ~~taxes~~subsidiaries ~~and~~after ~~settled~~the ~~our current~~elimination ~~and deferred income tax balances through El Paso’s cash management program. For a further discussion~~ of ~~these~~intercompany ~~and~~accounts ~~other related transactions, see Notes 2, 3~~ and 11transactions.

~~Our~~We ~~consolidated~~ consolidate entities when we have the ability to control or direct the operating and financial ~~statements~~decisions ~~are~~of ~~prepared~~the entity or when we have a significant interest in ~~accordance~~the ~~with~~entity Uthat gives us the ability to direct the activities that are significant to that entity.S The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. ~~generally~~We ~~accepted~~ apply the equity method of accounting ~~principles~~where ~~(GAAP)~~we ~~and~~can ~~include~~exert significant influence over, but do not control or direct the ~~accounts~~policies, decisions or activities of ~~all~~an ~~consolidated subsidiaries~~entity. ~~after~~We use the ~~elimination~~cost method of ~~intercompany~~accounting ~~accounts~~where ~~and~~we ~~transactions~~are unable to exert significant influence over the entity.

We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Regulated Operations

Our interstate natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) ~~under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978~~ and ~~the Energy Policy Act of 2005. We~~ follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded ~~under GAAP~~ for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, loss on reacquired debt, taxes related to an equity return component on regulated capital projects in periods prior to 2007 when we changed our legal structure to a general partnership, and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents.

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Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Materials and Supplies

We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.

Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas delivered from or received onby a ~~customer’s contract~~pipeline atsystem ~~the~~or ~~supply~~storage ~~point~~facility differs from the contractual amount ofto ~~natural~~be ~~gas~~ delivered ~~under~~ ~~the~~or ~~customer’s transportation contract at the delivery point~~received. We value these imbalances due to or from shippers and operators at specified index prices ~~set forth in our tariff based on the production month in which the imbalances occur~~. Imbalances ~~Customer imbalances~~ are ~~aggregated~~settled ~~and~~either ~~netted~~as oncash aouts ~~monthly~~or ~~basis, and settled~~ in ~~cash~~-kind, subject to the terms of our tariff. For differences in value between the amounts we pay or receive for the purchase or sale of natural gas used to resolve shipper imbalances over the course of a year, we have the right under our tariff to recover applicable losses or refund applicable gains through a storage cost reconciliation charge. This charge is applied to volumes as they are transported on our system. Annually, we true-up any losses or gains obtained during the year by adjusting the following years’ storage cost reconciliation charge.

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Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect to settle them within a year.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the ~~FERC-accepted~~ depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. ~~Currently,~~ ~~our~~We re-evaluate depreciation rates ~~vary~~each ~~from~~time ~~less~~we ~~than~~file ~~one~~with ~~percent to 20 percent per year. Using these rates,~~ the ~~remaining~~FERC ~~depreciable~~for ~~lives~~an ofincrease ~~these~~or ~~assets range~~decrease ~~from~~in ~~two~~our totransportation 43and ~~years~~storage rates. Currently, Weour ~~re-evaluate~~ depreciation rates ~~each~~vary ~~time~~from weless ~~file with~~than ~~the~~one ~~FERC~~percent ~~for~~to a20 ~~change~~percent inper ~~our transportation and storage rates~~year.

When we retire property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize a gain or loss unless we sell ~~or retire~~ an entire operating unit, as defined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements.

AtIncluded ~~December~~in ~~31, 2009~~our property balances are base gas and ~~2008~~working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we ~~had~~recognize ~~$34~~a ~~million~~loss ~~and~~in ~~$48~~our ~~million~~income ofstatement ~~construction~~or ~~work~~defer ~~in progress~~the ~~included~~loss inas a regulatory asset on our ~~property,~~balance ~~plant~~sheet ~~and~~if ~~equipment~~deemed probable of recovery through future rates charged to our customers.

32We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to interest and debt expense on our income statements. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.

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We capitalize a carrying cost (an allowance for funds used during construction) on debt and equity funds related to our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs capitalized during the years ended December 31, 2009, 2008 and 2007, were $1 million, $3 million and $4 million. These debt amounts are included as a reduction to interest and debt expense on our income statement. The equity portion is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized (exclusive of taxes) during the years ended December 31, 2009, 2008 and 2007, were $3 million, $7 million and $8 million. These equity amounts are included in other income on our income statement.

Asset and Investment Divestitures/Impairments

We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. ~~When~~If an event occurs, we evaluate the recoverability of our carrying value based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. ~~The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sale, among other factors.~~

We reclassify assets to be sold in our financial statements as either held-for-sale or from discontinued operations when it becomes probable that we will dispose of the assets within the next twelve months and when they meet other criteria, including whether we will have significant long-term continuing involvement with those assets after they are sold. We cease depreciating assets in the period that they are reclassified as either held for sale or from discontinued operations, and reflect the results of our discontinued operations in our income statement separtely from those of continuing operations.

Cash flows from our discontinued businesses are reflected as discontinued operating, investing, and financing activities in our statement of cash flows. Cash provided by discontinued activities in the operating activities section of our cash flow statement includes all operating cash flows generated by our discontinued businesses during the period. Proceeds from the sale of our discontinued operations are classified in cash provided by discontinued activities in the cash flows from investing activities section of our cash flow statement. To the extent that these operations participated in El Paso’s cash management program, we reflected transactions related to El Paso’s cash management program as financing activities in our cash flow statement. We cease depreciating assets in the period that they are reclassified as either held for sale or as discontinued operations.

Revenue Recognition

Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period ~~regardless of the amount of natural gas that is transported or stored~~. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. ~~Gas~~For ~~not~~contracts ~~used~~with instep-up ~~operations~~or isstep-down ~~based~~rate onprovisions ~~the~~that ~~volumes of natural gas we~~ are ~~allowed~~not torelated ~~retain and dispose of relative~~ to ~~the~~changes ~~amounts we use for operating purposes. As calculated~~ in alevels ~~manner~~of ~~set forth in our tariff~~service, ~~volumes~~ ~~from~~we ~~any excess natural gas retained and not used in operations are to be given back to our customers through lower retention percentages determined on an annual basis. We~~ recognize ~~our~~reservation ~~share of~~ revenues onratably ~~gas~~over ~~not used in operations from our shippers when we retain~~ the ~~volumes~~ atcontract ~~the market prices required under our tariffs~~life. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

3332

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Environmental Costs and Other Contingencies

Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.

Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that, ~~when fully analyzed,~~ indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Income Taxes

Effective November 1, 2007, we converted to a general partnership in conjunction with the formation of EPB and accordingly, we are no longer subject to income taxes. As a result of our conversion to a general partnership, we settled our then existing current and deferred tax balances with recoveries of note receivables from El Paso under its cash management program pursuant to our tax sharing agreement with El Paso (see Notes 3 and 11). Prior to that date, we recorded current income taxes based on our taxable income and provided for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represented the income tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We accounted for tax credits under the flow-through method, which reduced the provision for income taxes in the year the tax credits first became available. We reduced deferred tax assets by a valuation allowance when, based on our estimates, it was more likely than not that a portion of those assets would not be realized in a future period.

On January 1, 2007, we adopted a new income tax accounting standard. The adoption of the standard did not have a material impact on our financial statements.

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is ~~also~~ recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid under the plan. These contributions are invested until the benefits are paid to plan participants. The net benefit cost of this plan is recorded in our income statement and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 8.

In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.

Income Taxes

We are a partnership for income tax purposes and are not subject to either federal income taxes or generally to state income taxes. Our partners are responsible for income taxes on their allocated share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities. We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because information regarding each partner’s tax attributes in us is not available to us.

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2. Acquisition/Divestiture

In 2010, we purchased certain pipeline assets from Elba Express Company, L.L.C. (Elba Express), our affiliate, for $18 million and sold certain pipeline assets to Elba Express for net proceeds of $8 million. We recorded both the purchase and sale at their historical cost and accordingly, we recognized no gain or loss on these transactions.

3. Fair Value of Financial Instruments

At December 31, 2010 and 2009, the carrying amounts of cash and cash equivalents and trade receivables and payables represented their fair value because of the short-term nature of these instruments. At December 31, 2010, we had a note payable to EPB of approximately $12 million with a variable interest rate of 0.8%. At December 31, 2009, we had an interest bearing note receivable from El Paso of approximately $154 million due upon demand, with a variable interest rate of 1.5%. While we are exposed to changes in interest expense based on changes to the variable interest rate, the fair value of our note payable approximates the carrying value due to the note being payable on demand and the market-based nature of the interest rate.

In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:

	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt	$	910	$	984	$	910	$	977

4. Regulatory Assets and Liabilities

Our regulatory assets are included in other current and non-current assets on our balance sheets. Our regulatory liabilities are included in other non-current liabilities on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:

	2010		2009
	(In millions)
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	13	$	—
Other		1		4
Total current regulatory assets		14		4
Non-current regulatory assets
Taxes on capitalized funds used during construction		28		29
Unamortized loss on reacquired debt		29		32
Other		6		1
Total non-current regulatory assets		63		62
Total regulatory assets	$	77	$	66
Non-current regulatory liabilities
Postretirement benefits	$	9	$	5
Other		6		3
Total non-current regulatory liabilities	$	15	$	8

The significant regulatory assets and liabilities include:

Difference Between Gas Retained and Gas Consumed in Operations. These amounts reflect the value of the volumetric difference between the gas retained and consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers in subsequent fuel filing periods.

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WeTaxes ~~have~~on ~~legal obligations~~Capitalized ~~associated~~Funds ~~with~~Used ~~the~~During ~~retirement~~Construction. ofRegulatory ~~our~~asset ~~natural~~balance established ~~gas~~in ~~pipeline, transmission~~periods ~~facilities~~prior ~~and~~to ~~storage~~2007 ~~wells.~~when ~~Our~~we changed our legal ~~obligations~~structure ~~primarily involve~~to ~~purging~~a ~~and~~general ~~sealing~~partnership, to offset the ~~pipeline~~deferred iftax itfor isthe ~~abandoned.~~equity Wecomponent ~~also~~of ~~have obligations~~the toallowance ~~remove~~for ~~hazardous~~funds ~~materials~~used ~~associated~~during ~~with~~the ~~our~~construction ~~natural~~of ~~gas transmission~~long-lived ~~facilities~~assets. Taxes ifon ~~they~~capitalized ~~are~~funds ~~replaced.~~used Weduring ~~continue~~construction toand ~~evaluate~~the ~~our~~offsetting ~~asset retirement~~deferred ~~obligations~~income taxes are included in the rate base and ~~future~~recovered ~~developments~~over ~~could~~the ~~impact~~depreciable lives of the ~~amounts~~long ~~we record~~lived asset to which they relate.

~~Where~~Unamortized weLoss ~~can reasonably estimate the asset retirement obligation, we accrue a liability based~~ on anReacquired ~~estimate of the timing and amount of settlement~~Debt. WeAmount ~~record~~represents ~~changes in estimates based on changes in~~ the ~~expected~~deferred ~~amount~~ and ~~timing~~unamortized portion of losses ~~payments to settle our asset retirement obligations. We intend~~ on ~~operating~~reacquired ~~and~~debt ~~maintaining our natural gas pipeline and storage system as long as supply and demand for natural gas exists,~~ which weare ~~expect~~recovered ~~for~~over the ~~foreseeable~~original ~~future.~~life ~~Therefore,~~of ~~we believe that we cannot reasonably estimate~~ the ~~asset~~debt ~~retirement~~issue ~~obligation~~through ~~for~~ the ~~substantial~~cost ~~majority~~ of ~~our natural gas pipeline and storage system assets because these assets have indeterminate lives~~service.

Postretirement Benefits. Represents unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recovered in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.

5. Property, Plant and Equipment

Capitalized Costs During Construction. Interest costs capitalized were $2 million, $1 million and $3 million during the years ended December 31, 2010, 2009 and 2008. Equity amounts capitalized were $7 million, $3 million and $7 million during the years ended December 31, 2010, 2009 and 2008.

Construction Work-In Progress. At December 31, 2010 and 2009, we had approximately $212 million and $34 million of construction work in progress included in our property, plant and equipment.

Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transportation facilities primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. In estimating our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount rates that currently range from five to 12 percent based on when the liabilities were recorded. We record changes in estimates based on changes in the expected amount and timing of payments to settle our obligations. We intend on operating and maintaining our natural gas pipeline and storage systems as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.

The net asset retirement obligation as of December 31 reported on our balance sheets in current and other non-current liabilities and the changes in the net liability for the years ended December 31 were as follows:

	2009			2008
	2010			2009
	(In millions)
Net asset retirement obligation at January 1	$	2019		$	—20
Accretion expense		2			—
Liabilities settled		(12	)		—
Changes in estimate		(3	)		20
Accretion expense		1			2
Net asset retirement obligation at December 31(1)	$	19		$	20
Changes in estimate		—			(3	)
Net asset retirement obligation at December 31(1)	$	8		$	19

____________

(1) For the year ended December 31, 2010 and 2009, approximately $1 million and $14 million of this amount isare reflected in current liabilities.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. We record the net benefit cost related to this plan in our income statement. This net benefit cost is a function of many factors including benefits earned during the year by plan participants (which is a function of the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 8.

In accounting for our postretirement benefit plan, we record an asset or liability for our postretirement benefit plan based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.

Effective January 1, 2008, we adopted the provisions of an accounting standard update related to measurement date and changed the measurement date of our postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements.

Effective December 31, 2009, we expanded our disclosures about postretirement benefit plan assets as a result of new disclosure requirements. See Note 8 for these expanded disclosures.

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~~New Accounting~~6. ~~Pronouncements Issued But Not Yet Adopted~~Debt

AsOur oflong-term ~~December~~debt ~~31, 2009,~~consisted of the following ~~accounting~~at ~~standards~~December ~~had not yet been adopted by us.~~31:

Transfers of Financial Assets. In June 2009, the FASB updated accounting standards on financial asset transfers. Among other items, this update eliminated the concept of a qualifying special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated or not. The changes are effective for existing QSPEs as of January 1, 2010 and for transactions entered into on or after January 1, 2010. The adoption of this accounting standard in January of 2010 did not have a material impact on our financial statements as we amended our existing accounts receivable sales program in January 2010 (see Note 11).

	2010		2009
	(In millions)
5.90% Notes due April 2017	$	500	$	500
7.35% Notes due February 2031		153		153
8.0% Notes due March 2032		258		258
		911		911
Less: Unamortized discount		1		1
Total long-term debt	$	910	$	910

~~Variable~~Under ~~Interest~~our ~~Entities. In June 2009~~indentures, ~~the~~we ~~FASB~~are ~~updated~~subject ~~accounting~~to ~~standards~~a ~~for~~number ~~variable~~of ~~interest entities~~restrictions toand ~~revise~~covenants. ~~how~~The ~~companies~~most ~~determine~~restrictive ~~the~~of ~~primary~~these ~~beneficiaries~~include oflimitations ~~these entities,~~on ~~among~~the ~~other~~incurrence ~~changes~~of liens. ~~Companies~~Our ~~will~~long-term ~~now~~debt becontains ~~required~~cross-acceleration toprovisions, ~~use~~the ~~a qualitative~~most ~~approach~~restrictive ~~based~~of onwhich ~~their~~is ~~responsibilities~~a ~~and~~$10 ~~power~~million ~~over~~cross-acceleration ~~the entities’~~clause. ~~operations~~If triggered, ~~rather~~repayment ~~than~~of athe ~~quantitative~~long-term ~~approach~~debt inthat ~~determining~~contains ~~the primary~~these ~~beneficiary~~provisions ascould ~~previously~~be ~~required~~accelerated. ~~The~~For ~~adoption~~the ofyear ~~this accounting~~ended ~~standard~~December in31, ~~January of~~ 2010, ~~did~~we ~~not~~were ~~have~~in acompliance ~~material~~with ~~impact on~~ our ~~financial~~ ~~statements~~debt-related covenants.

2. Divestitures

In November 2007, in conjunction with the formation of EPB, we distributed our wholly owned subsidiaries, SLNG and Elba Express, to El Paso. We have reflected these operations as discontinued operations in our financial statements for periods prior to their distribution. We classify assets (or groups of assets) to be disposed of as held for sale or, if appropriate, from discontinued operations when they have received appropriate approvals to be disposed of by our management when they meet other criteria. We also distributed our investment in Citrus to El Paso which is not reflected in discontinued operations. The table below summarizes the operating results of our discontinued operations for the year ended December 31, 2007.

	(In millions)
Revenues	$	61
Costs and expenses		(35	)
Other income, net		4
Interest and debt expense		1
Income before income taxes		31
Income taxes		12
Income from discontinued operations, net of income taxes	$	19

3. Income Taxes

In conjunction with the formation of EPB, we converted our legal structure into a general partnership effective November 1, 2007 and are no longer subject to income taxes. We also settled our then existing current and deferred income tax balances pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program.

Components of Income Tax Expense. The following table reflects the components of income tax expesne included in income from continuing operations for the year ended December 31, 2007:

	(In millions)
Current
Federal	$	40
State		6
		46
Deferred
Federal		19
State		4
		23
Total income taxes	$	69

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Effective Tax Rate Reconciliation. Our income tax expense, included in income from continuing operations differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for the year ended December 31, 2007:

	(In millions, except for rates)
Income taxes at the statutory federal rate of 35%	$	95
Increase (decrease)
Pretax income not subject to income tax after conversion to partnership		(11	)
State income taxes, net of federal income tax benefit		6
Earnings from unconsolidated affiliates where we anticipate receiving dividends		(21	)
Income taxes	$	69
Effective tax rate		25	%

4. Fair Value of Financial Instruments

At December 31, 2009 and 2008, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term nature of these instruments. At December 31, 2009 and 2008, we had an interest bearing note receivable from El Paso of approximately $154 million and $136 million due upon demand, with a variable interest rate of 1.5% and 3.2%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:

	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt, including current maturities	$	910	$	977	$	910	$	726

5. Regulatory Assets and Liabilities

Our current and non-current regulatory assets are included in other current and non-current assets on our balance sheets. Our non-current regulatory liabilities are included in other non-current liabilities on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:

	2009		2008
	(In millions)
Current regulatory assets	$	4	$	1
Non-current regulatory assets
Taxes on capitalized funds used during construction		29		34
Unamortized loss on reacquired debt		32		36
Other		1		4
Total non-current regulatory assets		62		74
Total regulatory assets	$	66	$	75
Non-current regulatory liabilities
Postretirement benefits	$	5	$	—
Other		3		4
Total non-current regulatory liabilities	$	8	$	4

The significant regulatory assets and liabilities include:

Taxes on Capitalized Funds Used During Construction: These regulatory asset balances were established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction are amortized and the offsetting deferred income taxes are included in the rate base. Both are recovered over the depreciable lives of the long lived asset to which they relate.

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Unamortized Net Loss on Reacquired Debt: These amounts represent the deferred and unamortized portion of losses on reacquired debt which are not included in the rate base, but are recovered over the original life of the debt issue through the authorized rate of return.

Postretirement Benefits: These balances represent deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recoverable in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as the benefits are funded.

6. Debt and Credit Facilities

Debt. Our long-term debt consisted of the following at December 31:

	2009		2008
	(In millions)
5.90% Notes due April 2017	$	500	$	500
7.35% Notes due February 2031		153		153
8.0% Notes due March 2032		258		258
		911		911
Less: Unamortized discount		1		1
Total long-term debt, less current maturities	$	910	$	910

In March 2009, we, Southern Natural Issuing Corporation (SNIC), El Paso and certain other El Paso subsidiaries filed a registration statement on Form S-3 under which we and SNIC may co-issue debt securities in the future. SNIC is a wholly owned finance subsidiary of us and is the co-issuer of certain of our outstanding debt securities. SNIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of our debt securities. Accordingly, it has no ability to service obligations on our debt securities.

Under our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. For the year ended December 31, 2009, we were in compliance with our debt-related covenants. Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $10 million cross-acceleration clause. If triggered, repayment of the long-term debt that contains these provisions could be accelerated.

7. Commitments and Contingencies

Legal Proceedings

~~Gas Measurement Cases.~~ We and a ~~number of~~ our affiliates ~~were~~are named defendants in ~~actions~~numerous legal proceedings and claims that ~~generally allege~~arise ~~mismeasurement~~in the ordinary course of ~~natural~~our ~~gas~~business. ~~volumes~~For ~~and/or~~each ~~heating~~of ~~content~~these ~~resulting~~matters, in we evaluate the ~~underpayment~~merits of ~~royalties.~~the ~~These~~case, ~~cases~~our ~~were~~exposure ~~filed~~to inthe ~~1997~~matter, bypossible anlegal ~~individual under~~or settlement strategies and the ~~False~~likelihood ~~Claims~~of ~~Act~~an ~~and~~unfavorable ~~have~~outcome. ~~been~~If ~~consolidated~~we ~~for~~determine ~~pretrial~~that ~~purposes~~an ~~(In re:~~unfavorable ~~Natural~~outcome ~~Gas~~is ~~Royalties~~probable ~~Qui~~and ~~Tam~~can ~~Litigation~~be estimated, ~~U.S.~~ ~~District~~we ~~Court~~establish ~~for~~the necessary accruals. While the ~~District~~outcome of ~~Wyoming).~~these ~~These~~matters, ~~complaints~~including ~~allege an~~those ~~industry-wide~~discussed ~~conspiracy~~above, tocannot ~~underreport~~be ~~the~~predicted ~~heating~~with ~~value~~certainty, asand ~~well~~there asare ~~the volumes~~still ofuncertainties related to the ~~natural~~costs ~~gas~~we ~~produced~~may ~~from~~incur, ~~federal~~based upon our evaluation and ~~Native~~experience ~~American~~to ~~lands~~date, we believe we have established appropriate reserves for these matters. ~~In October~~It ~~2006~~is possible, ~~the~~however, ~~U.S.~~that ~~District~~new ~~Judge~~information ~~issued~~or anfuture ~~order~~developments ~~dismissing~~could ~~all~~require ~~claims against~~us ~~all~~to ~~defendants.~~reassess Inour ~~March~~potential ~~2009,~~exposure ~~the~~related ~~Tenth~~to ~~Circuit~~these ofmatters ~~Appeals~~and ~~affirmed~~adjust ~~the dismissals~~our accruals accordingly, and inthese ~~October~~adjustments ~~2009~~could be material. At December 31, ~~the~~2010, ~~plaintiff’s~~we ~~appeal~~had toapproximately ~~the~~$2 ~~United~~million ~~States Supreme~~accrued ~~court~~for ~~was~~our ~~denied~~outstanding legal matters.

In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2009, we accrued approximately $2 million for our outstanding legal matters.

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Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect ~~on the environment~~ of the disposal or release of specified substances at current and former operating sites. At ~~both~~ December 31, ~~2009~~2010, we had no accrual for our environmental matters, and ~~2008~~at December 31, 2009, we ~~had~~ accrued approximately $1 million for expected remediation costs and associated onsite, offsite and groundwater technical studies.

Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will spend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for one active site. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities.

We expect to make capital expenditures for environmental matters of approximately $3 million in the aggregate for 2011 through 2015, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations with which we have to be in compliance by October 2013.

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It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

Rates and Regulatory ~~Matters~~Matter

~~Notice~~Rate ~~of Proposed Rulemaking~~Case. In ~~October~~January ~~2007~~2010, the ~~Minerals~~FERC ~~Management~~approved ~~Service~~our ~~(MMS)~~settlement ~~issued a~~in ~~notice~~which ofwe ~~proposed~~(i) ~~rulemaking~~increased ~~that~~our isbase ~~applicable~~tariff torates ~~pipelines~~effective ~~located~~September in1, ~~the Outer~~2009, ~~Continental Shelf~~ (~~OCS~~ii). Ifimplemented ~~adopted,~~a ~~the~~volume ~~proposed~~tracker ~~rules~~for ~~would substantially~~gas ~~revise~~used ~~MMS~~in ~~OCS~~operations, ~~pipeline~~(iii) ~~and~~agreed ~~rights-of-way~~to ~~regulations.~~file ~~The proposed~~our ~~rules~~next ~~would~~general ~~have~~rate ~~the~~case ~~effect~~to ofbe ~~(i)~~effective ~~increasing~~after ~~the~~August ~~financial obligations of entities~~31, ~~like us~~2012, but ~~which~~no ~~have~~later ~~pipelines~~than ~~and~~September ~~pipeline~~1, ~~rights-of-way~~2013, inand ~~the OCS;~~ (iiiv) ~~increasing~~extended the ~~regulatory~~vast ~~requirements~~majority ~~imposed on the operation and maintenance~~ of ~~existing~~our ~~pipelines~~firm ~~and~~transportation ~~rights~~contracts ofuntil ~~way~~August in31, ~~the OCS; and (iii) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS~~2013.

Rate Case. In January 2010, the FERC approved our settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our 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 our firm transportation contracts until August 31, 2013.

Other Commitments

~~Commercial~~Capital Commitments. At December 31, ~~2009~~2010, we ~~entered~~had ~~into~~capital ~~unconditional~~commitments ~~purchase obligations~~of ~~for products and services totaling~~ approximately $9527 million primarily related to ~~the~~our South System III ~~project~~ and ~~the~~Southeast ~~Southest~~Supply Header Phase II projects, all of which is expected to be spent in 2011. During 2009, we entered into an approximately $57 million letter of credit associated with our estimated construction costs related to our Southeast Supply Header project. ~~Our~~ ~~annual~~As ~~obligations~~invoices are paid under ~~these~~the ~~agreements~~contract, we are ~~$71 million~~ inable ~~2010~~to ~~and~~reduce ~~$24~~the ~~million~~value inof ~~2011~~the letter of credit. InAt ~~addition~~December 31, we2010, the letter of credit has been reduced to approximately $31 million. 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.

~~Operating~~Other ~~Leases~~Commitments. We ~~lease property~~have entered into unconditional commitments primarily for storage services, ~~facilities~~totaling ~~and~~approximately ~~equipment~~$14 ~~under~~million ~~various~~at ~~operating~~December ~~leases~~31, 2010. Our ~~primary commitment~~annual obligations under ~~operating~~these ~~leases~~purchase isobligations ~~the~~are ~~lease~~$11 ofmillion ~~our~~in ~~office~~2011, ~~space~~$1 million in ~~Birmingham~~ 2012, ~~Alabama~~and $2 million in 2013. ElWe ~~Paso~~also ~~guarantees~~hold ~~our~~cancelable ~~obligations~~easements ~~under~~or ~~these~~rights-of-way ~~lease agreements.~~arrangements ~~Future~~from ~~minimum~~landowners ~~annual~~permitting ~~rental~~the ~~commitments~~use ~~under~~of ~~our~~land ~~operating~~for ~~leases at~~the ~~December~~construction ~~31,~~and ~~2009~~operation of our pipeline system. Currently, ~~were~~our asobligations ~~follows:~~under these easements are not material to the results of our operations.

Year Ending December 31,
	(In millions)
2010	$	3
2011		3
2012		3
2013		3
2014		3
Thereafter		8
Total	$	23

Operating Leases. We lease property, facilities and equipment under various operating leases. Our primary commitment under operating leases is the lease of our office space in Birmingham, Alabama. El Paso guarantees our obligations under these lease agreements. Future minimum annual rental commitments under our operating leases at December 31, 2010, were as follows:

Rent expense on our lease obligations for the years ended December 31, 2009, 2008 and 2007 was less than $1 million, $4 million, and less than $1 million. These amounts include our share of rent allocated to us from El Paso.

Year Ending December 31,	(In millions)
2011	$	3
2012		3
2013		3
2014		3
2015		3
Thereafter		5
Total	$	20

39Rent expense on our lease obligations for each of the years ended December 31, 2010, 2009 and 2008 was $4 million. These amounts include our share of rent allocated to us from El Paso.

Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of performance guarantees that are not recorded in our financial statements. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. As of December 31, 2009, we had performance guarantees related to construction contracts held by Southern LNG Company, L.L.C and Elba Express our affiliates. These guarantees expired in 2010, upon completion of the construction projects.

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Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Currently, our obligations under these easements are not material to the results of our operations. During 2009, we entered into a $57 million letter of credit associated with our projected construction costs related to the Southeast Supply Header project.

Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of performance guarantees that are not recorded in our financial statements. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. As of December 31, 2009, we have a performance guarantee related to contracts held by SLNG, an entity formerly owned by us, with a maximum exposure of $225 million and a performance guarantee related to contracts held by Elba Express, an entity formerly owned by us, with no stated maximum limit. We estimate our potential exposure related to these guarantees is approximately $93 million, which is based on their remaining estimated obligations under the contracts.

8. Retirement Benefits

Pension and Retirement Savings Plans. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on ~~its~~ El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits Plan. We provide postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. Employees in this group who retire after June 30, 2000 continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $41 million to our postretirement benefit plan in ~~2010~~2011.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan ~~under the accounting standards related to other postretirement plans~~, we record an asset or liability ~~for our postretirement benefit plan~~ based on ~~its~~the over funded or under funded status. InAny ~~March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any~~ deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions ~~that~~are ~~would otherwise be~~ recorded ineither ~~accumulated~~as ~~other~~a ~~comprehensive~~regulatory ~~income~~asset ~~for~~or ~~non-regulated~~liability ~~entities. Upon~~as ~~adoption~~allowed ofby ~~this~~the FERC. ~~guidance,~~These weamounts ~~reclassified~~would $5otherwise ~~million~~be ~~from~~recorded in accumulated other comprehensive income tofor anon-regulated ~~regulatory liability~~entities.

40The table below provides information about our postretirement benefit plan:

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	December 31,
	2010			2009
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation - beginning of period	$	59		$	61
Interest cost		3			4
Participant contributions		1			1
Actuarial gain		(1	)		(1	)
Benefits paid(1)		(4	)		(6	)
Accumulated postretirement benefit obligation - end of period	$	58		$	59
Change in plan assets:
Fair value of plan assets - beginning period	$	52		$	46
Actual return on plan assets		5			8
Employer contributions		1			4
Participant contributions		1			—
Benefits paid		(4	)		(6	)
Fair value of plan assets - end of period	$	55		$	52
Reconciliation of funded status:
Fair value of plan assets	$	55		$	52
Less: accumulated postretirement benefit obligation		58			59
Net liability at December 31	$	(3	)	$	(7	)

The table below provides information about our postretirement benefit plan. In 2008, we adopted the FASB’s revised measurement date provisions for other postretirement benefit plans and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008. For 2009, the information is presented and computed as of and for the twelve months ended December 31, 2009.

	December 31, 2009			December 31, 2008
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation - beginning of period	$	61		$	62
Interest cost		4			4
Participant contributions		1			1
Actuarial (gain) loss		(1	)		1
Benefits paid(1)		(6	)		(7	)
Accumulated postretirement benefit obligation - end of period	$	59		$	61
Change in plan assets:
Fair value of plan assets - beginning period	$	46		$	66
Actual return on plan assets		8			(17	)
Employer contributions		4			4
Participant contributions		—			1
Benefits paid		(6	)		(8	)
Fair value of plan assets - end of period	$	52		$	46
Reconciliation of funded status:
Fair value of plan assets	$	52		$	46
Less: accumulated postretirement benefit obligation		59			61
Net liability at December 31	$	(7	)	$	(15	)

____________

(1) Amounts shown net of a subsidy of less than $1 million ~~and approximately $1 million~~ for the years ended December 31, ~~2009~~2010 and ~~2008~~2009 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. We may invest plan assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.

We use various methods to determine the fair values of the assets in our other postretirement benefit plans, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2009, our assets are comprised of an exchange-traded mutual fund with a fair value of $2 million and common/collective trusts with a fair value of $50 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common/collective trusts are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. We may adjust the fair value of our common/collective trusts, when necessary, for factors such as liquidity or risk of nonperformance by the issuer. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2009 and 2008.38

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~~Expected~~We ~~Payment~~use various methods to determine the fair values of ~~Future~~the ~~Benefits~~assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $3 million and common collective trust funds with a fair value of $52 million. As of December 31, 2009, weassets ~~expect~~were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $50 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the ~~following~~price ~~benefit~~quoted ~~payments~~for ~~under our~~the ~~plan:~~fund in actively traded markets. Our common collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common collective trust funds where the issuer reserves the right to temporarily delay withdrawal in certain situations such as market conditions or at the issuer’s discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2010 and 2009.

Year Ending December 31,	Expected Payments(1)
	(In millions)
2010	$	5
2011		5
2012		5
2013		5
2014		5
2015 - 2019		22

Expected Payment of Future Benefits. As of December 31, 2010, we expect the following benefit payments under our plan:

_______

Year Ending December 31,	Expected Payments(1)
	(In millions)
2011	$	4
2012		4
2013		4
2014		4
2015		4
2016 – 2020		21

(1) Includes a reduction of approximately $1 million in each of the years 2010 – 2014 and approximately $4 million in aggregate for 2015 – 2019 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.____________

~~Actuarial~~(1) Includes ~~Assumptions~~a ~~and Sensitivity~~reduction ~~Analysis.~~of ~~Accumulated~~less ~~postretirement~~than ~~benefit~~$1 ~~obligations~~million ~~and net~~in ~~benefit~~each ~~costs~~of ~~are~~the ~~based~~years on2011 ~~actuarial~~– ~~estimates~~2015 and ~~assumptions.~~approximately ~~The following~~$4 ~~table~~million ~~details~~in ~~the~~aggregate ~~weighted~~for ~~average~~2016 ~~actuarial~~– ~~assumptions~~2020 ~~used~~for ~~in determining~~an ~~our~~expected ~~postretirement~~subsidy ~~plan~~related ~~obligations~~to ~~and~~the ~~net~~Medicare ~~benefit~~Prescription ~~costs~~Drug, ~~for 2009~~Improvement, ~~2008~~ and ~~2007:~~Modernization Act of 2003.

	2009		2008		2007
	(Percent)
Assumptions related to benefit obligations at December 31, 2009 and 2008 and September 30, 2007 measurement dates:
Discount rate		5.51		6.00		6.05
Assumptions related to benefit costs at December 31:
Discount rate		6.00		6.05		5.50
Expected return on plan assets(1)		8.00		8.00		8.00

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2010, 2009 and 2008:

_______

	2010		2009		2008
	(Percent)
Assumptions related to benefit obligations at December 31:
Discount rate		4.92		5.51		6.00
Assumptions related to benefit costs for the year ended December 31:
Discount rate		5.51		6.00		6.05
Expected return on plan assets(1)		7.75		8.00		8.00

____________

(1) The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 8.0 percent, gradually decreasing to 5.0 percent by the year 2015. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change would not have had a significant effect on interest costs in 2009 or 2008. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31, 2009 and 2008:39

	2009			2008
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	5		$	5
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(4	)	$	(5	)

Components of Net Benefit Cost. For each of the years ended December 31, the components of net benefit cost are as follows:

	2009			2008			2007
	(In millions)
Interest cost	$	3		$	4		$	4
Expected return on plan assets		(2	)		(3	)		(3	)
Amortization of net actuarial gain		—			(1	)		—
Net benefit cost	$	1		$	—		$	1

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Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.4 percent, gradually decreasing to 5.0 percent by the year 2016. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change would not have had a significant effect on interest costs in 2010 or 2009. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31, 2010 and 2009:

	2010			2009
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	5		$	5
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(4	)	$	(4	)

Components of Net Benefit Cost. For each of the years ended December 31, the components of net benefit cost are as follows:

	2010			2009			2008
	(In millions)
Interest cost	$	3		$	3		$	4
Expected return on plan assets		(2	)		(2	)		(3	)
Amortization of net actuarial gain		—			—			(1	)
Net benefit cost	$	1		$	1		$	—

9. Transactions with Major Customers

The following table shows revenues from our major customers for each of the three years ended December 31:

	2009		2008		2007
	2010		2009		2008
	(In millions)
SCANA Corporation(1)	$	8392	$	7983	$	7779
Southern Company Services		5862		5558		5455

_______

(1) A significant portion of revenues received from a subsidiary of SCANA Corporation resulted from firm capacity released by Atlanta Gas Light Company under terms allowed by our tariff.

10. Supplemental Cash Flow Information

The following table contains supplemental cash flow information from continuing operations for each of the three years ended December 31:

	2009		2008		2007
	(In millions)
Interest paid, net of capitalized interest	$	61	$	75	$	97
Income tax payments		—		—		374	(1)

(1) Includes amounts related to the settlement of current and deferred tax balances due to the conversion to a partnership in November 2007 (see Notes 3 and 11).

11. Investments in Unconsolidated Affiliates and Transactions with Affiliates

Investments in Unconsolidated Affiliates

Citrus. Prior to its transfer to El Paso in November 2007 in conjunction with the formation of EPB, we had a 50 ownership percent interest in Citrus, which owns the FGT pipeline system. CrossCountry Energy, LLC, a subsidiary of Southern Union Company, owns the other 50 percent of Citrus. During 2007, we received $103 million in dividends from Citrus.

Bear Creek Storage Company, LLC (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Tennessee Gas Pipeline Company, our affiliate. We account for our investment in Bear Creek using the equity method of accounting. During 2009, 2008 and 2007, we received $13 million, $16 million and $27 million in dividends from Bear Creek.

Summarized financial information of our proportionate share of our unconsolidated affiliates as of and for the years ended December 31 is presented as follows:

	2009		2008		2007
	(In millions)
Operating results data:(1)
Operating revenues	$	18	$	20	$	267
Operating expenses		7		8		115
Income from continuing operations and net income		11		13		92	(2)

	2009		2008
	(In millions)
Financial position data:
Current assets	$	28	$	27
Non-current assets		52		55
Other current liabilities		1		1
Equity in net assets		79		81

____________

(1) A ~~Includes~~significant ~~Citrus~~portion ~~results~~of ~~for~~revenues ~~the~~received ~~entire~~from ~~year~~a ~~ended~~subsidiary ~~December 31, 2007. Our share~~ of ~~Citrus’~~SCANA ~~net~~Corporation ~~income~~resulted ~~prior~~from tofirm ~~the~~capacity ~~distribution~~released ofby ~~this~~Atlanta ~~investment~~Gas inLight ~~November~~Company ~~2007~~under ~~was~~terms ~~$75~~allowed ~~million,~~by ~~adjusted~~our ~~for the excess purchase price amortization~~tariff.

~~(2)~~10. ~~The~~Accounts ~~difference~~Receivable ~~between~~Sales our proportionate share of our equity investments’ net income and our earnings from unconsolidated affiliates in 2007 is due primarily to the excess purchase price amortization related to Citrus and differences between the estimated and actual equity earnings on our investments.Program

43During 2009, we had an agreement to sell a senior interest in certain accounts receivable (which are short-term assets that generally settle within 60 days) to a third party financial institution (through a wholly-owned special purpose entity), and we retained subordinated interest in those receivables. The sale of the senior interest qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital. During the years ended December 31, 2009 and 2008, we received $299 million and $280 million of cash related to the sale of the senior interest, collected $228 million and $275 million from the subordinated interest we retained in the receivables, and recognized a loss of less than $1 million in both periods on these transactions. At December 31, 2009, the third party financial institution held $30 million of senior interest and we held $19 million of subordinated interest. Our subordinated interest was reflected in accounts receivable on our balance sheet. In January 2010, we terminated this accounts receivable sales program and paid $30 million to acquire the senior interest. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interest, and cash paid to terminate the program, as operating cash flows on our statement of cash flows.

In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to the third party financial institution that qualifies for sale accounting under the updated accounting standards related to financial asset transfers. Under this program, we sell receivables in their entirety to the third party financial institution (through a wholly-owned special purpose entity). At December 31, 2010, the third party financial institution held $56 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. During the year ended December 31, 2010, we sold approximately $629 million of accounts receivable to the third party financial institution, for which we received approximately $395 million of cash up front and had a deferred purchase price of approximately $234 million. We received approximately $208 million of cash related to the deferred purchase price when the underlying receivables were collected during 2010. As of December 31, 2010, we had not collected approximately $26 million of deferred purchase price related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value). We recognized a loss of less than $1 million on our accounts receivable sales for the year ended December 31, 2010. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales program as operating cash flows on our statement of cash flows.

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Under both the prior and current accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2010, 2009 and 2008.

The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.

11. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

Bear Creek Storage Company, LLC (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Tennessee Gas Pipeline Company (TGP), our affiliate. We account for our investment in Bear Creek using the equity method of accounting. During 2010, 2009 and 2008, we received $14 million, $13 million and $16 million in cash distributions from Bear Creek. Also, during 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a cash distribution to its partners, including $23 million to us. Included in this amount was a return of capital of $15 million.

Summarized financial information of our proportionate share of Bear Creek as of and for the years ended December 31 is presented as follows:

	2010		2009
	(In millions)
Financial position data:
Current assets	$	5	$	28
Non-current assets		52		52
Other current liabilities		2		1
Equity in net assets		55		79

Transactions with Affiliates

~~Contributions/~~Distributions. On ~~November~~We ~~21,~~are ~~2007,~~required into ~~conjunction~~make ~~with~~distributions ~~the formation~~ of ~~EPB,~~available wecash ~~made~~as ~~a distribution~~defined ofin our 50partnership ~~percent~~agreement ~~ownership~~on ina ~~Citrus~~quarterly ~~and~~basis to our ~~wholly~~partners. ~~owned subsidiaries~~During ~~SLNG~~2010, 2009 and ~~Elba~~2008, ~~Express~~we ~~(described~~paid incash ~~Note~~distributions 1)of ~~with~~approximately a$257 ~~book~~million, ~~value~~$171 ~~of approximately~~million and $~~850~~200 million to Elour ~~Paso~~partners. ~~and~~In Eladdition, ~~Paso~~in ~~made~~January 2011 we paid a ~~capital~~cash ~~contribution~~distribution to our partners of approximately $~~536~~47 million ~~to us~~.

We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During 2009 and 2008, we paid cash distributions of approximately $171 million and $200 million to our partners. We did not make any distributions to our partners during 2007. In addition, in January 2010 we paid a cash distribution to our partners of approximately $83 million.41

Cash Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2009 and 2008, we had a note receivable from El Paso of $154 million and $136 million. We classified $42 million and $41 million of this receivable as current on our balance sheets at December 31, 2009 and 2008, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on our note at December 31, 2009 and 2008 was 1.5 % and 3.2%.

Income Taxes. Effective November 1, 2007, we converted into a general partnership as discussed in Note 1 and settled our then existing current and deferred tax balances of approximately $334 million pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program. During 2007, we also settled $20 million with El Paso through its cash management program for certain tax attributes previously reflected as deferred income taxes in our financial statements. These settlements are reflected as operating activities in our statement of cash flows.

Accounts Receivable Sales Program. We sell certain accounts receivable to a QSPE whose purpose is solely to invest in our receivables, which are short-term assets that generally settle within 60 days. During the year ended December 31, 2009 and 2008, we received net proceeds in both periods of $0.5 billion related to sales of receivables to the QSPE and changes in our subordinated beneficial interests, and recognized losses of less than $1 million on these transactions. As of December 31, 2009 and 2008, we had approximately $50 million and $48 million of receivables outstanding with the QSPE, for which we received cash of approximately $30 million and $24 million and received subordinated beneficial interests of approximately $19 million and $23 million. The QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $30 million and $25 million as of December 31, 2009 and 2008. We reflect the subordinated interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections), are recorded as accounts receivable from affiliate in our balance sheets. Our ability to recover our carrying value of our subordinated beneficial interests is based on the collectability of the underlying receivables sold to the QSPE. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under these agreements, we earn a fee for servicing the receivables and performing all administrative duties for the QSPE which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2009 and 2008.

In January 2010, we ceased selling accounts receivable to the QSPE and began selling those receivables directly to a third party financial institution. In return, the third party financial institution pays a certain amount of cash up front for the receivables, and pays the remaining amount owed over time as cash is collected from the receivables.

Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to affiliates under long-term contracts.

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WeCash doManagement ~~not have employees~~Programs. ~~Following~~In ~~our~~conjunction ~~reorganization~~with inEPB’s ~~November~~acquisition ~~2007,~~of ~~our~~an ~~former~~additional ~~employees continue~~interest toin ~~provide services to~~ us ~~through~~in anNovember ~~affiliated service company owned by our general partner~~2010, Elwe ~~Paso.~~began Weto ~~are~~participate ~~managed~~in ~~and~~EPB’s ~~operated~~cash bymanagement ~~officers~~program ofwhich ~~El Paso,~~matches ~~our~~short-term ~~general~~cash ~~partner.~~surpluses ~~We have an omnibus agreement with El Paso~~ and ~~its affiliates~~needs ~~under which we reimburse El Paso for the provision~~ of ~~various~~participating ~~general and~~affiliates, ~~administrative~~thus ~~services~~minimizing ~~for~~ our ~~benefit~~total ~~and~~borrowings ~~for~~from ~~direct~~outside ~~expenses~~sources. EPB ~~incurred~~uses ~~by El~~the ~~Paso~~cash onmanagement ~~our~~program ~~behalf.~~to Elsettle ~~Paso~~intercompany ~~bills~~transactions usbetween ~~directly~~participating ~~for~~affiliates. At ~~certain~~December ~~general~~31, ~~and administrative~~2010, ~~costs~~we ~~and~~had ~~allocates~~ a ~~portion~~note ofpayable ~~its general and administrative costs~~ to ~~us.~~EPB Inof ~~addition~~approximately to$12 ~~allocations~~million ~~from~~which Elwas ~~Paso,~~classified weas ~~are~~current ~~allocated~~on ~~costs from Tennessee Gas Pipeline Company,~~ our ~~affiliate,~~balance ~~associated with our pipeline services~~sheet. ~~These~~The ~~allocations~~interest ~~are~~rate ~~based~~ on ~~the~~this ~~estimated~~variable ~~level~~rate ofnote ~~effort~~was ~~devoted to~~0.8% ~~our~~at ~~operations~~December ~~and the relative size of our EBIT~~31, ~~gross property and payroll~~2010.

~~The~~Also, ~~following~~in ~~table shows~~conjunction ~~overall~~with ~~revenues~~EPB’s acquisition of the additional interest in us as described above, we terminated our participation in El Paso’s cash management program and ~~charges~~received cash of approximately $5 million from ~~our~~El ~~affiliates~~Paso ~~for~~in ~~each~~settlement of the ~~three years~~final ~~ended~~note receivable balance. At December 31, 2009, we had a $154 million note receivable from El Paso of which $42 million was classified as current on our balance sheet. The interest rate on this variable rate note was 1.5% at December 31:, 2009.

	2009		2008		2007
	(In millions)
Revenues from affiliates	$	6	$	6	$	7
Operation and maintenance expenses from affiliates		125		120		69
Reimbursement of operating expenses charged to affiliates		14		13		—

We do not have employees and we are managed and operated by officers of El Paso, our general partner. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are allocated costs from TGP, our affiliate, associated with our pipeline services. These allocations are based on the estimated level of effort devoted to our operations and the relative size of our earnings before interest expense and income taxes, gross property and payroll.

The following table shows overall revenues, expenses and reimbursements from our affiliates for each of the three years ended December 31:

	2010		2009		2008
	(In millions)
Revenues	$	8	$	6	$	6
Operation and maintenance expenses		115		125		120
Reimbursement of operating expenses		4		14		13

12. Supplemental Selected Quarterly Financial Information (Unaudited)

Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.

	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In millions)
2010
Operating revenues	$	145	$	131	$	134	$	138	$	548
Operating income		86		72		71		79		308
Net income		76		60		60		71		267
2009
Operating revenues	$	126	$	119	$	124	$	141	$	510
Operating income		64		57		57		77		255
Net income		48		48		45		67		208
2008
Operating revenues	$	163	$	125	$	123	$	129	$	540
Operating income		101		61		54		55		271
Net income		95		53		44		43		235

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SCHEDULE II

SOUTHERN NATURAL GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008

(In millions)

Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions			Charged to Other Accounts			Balance at End of Period
2010
Legal reserves	$	2	$	—	$	—		$	—		$	2
Environmental reserves		1		—		(1	)		—			—
2009
Legal reserves	$	2	$	—	$	—		$	—		$	2
Environmental reserves		1		—		—			—			1
2008
Legal reserves	$	2	$	—	$	—		$	—		$	2
Environmental reserves		1		—		—			—			1
2007(1)
Valuation allowance on deferred tax assets	$	1	$	—	$	—		$	(1	)	$	—
Legal reserves		2		—		—			—			2
Environmental reserves		1		—		—			—			1

~~____________~~43

(1) Amounts reflect the reclassification of certain entities as discontinued operations.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, ~~2009~~ 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the ~~SEC~~U.S. Security and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and ~~Chief Financial Officer~~CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within aour company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and ~~Chief~~CFO ~~Financial Officer~~ concluded that our disclosure controls and procedures (as defined in ~~the~~ Exchange Act Rules 13a-15(e) and 15d-15 (e)) were effective as of December 31, ~~2009~~2010. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control ~~Over~~ over Financial Reporting.

Changes in Internal Control ~~Over~~over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of ~~2009~~2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report. See Item 8, Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control Over Financial Reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management Committee and Executive Officers

We are a Delaware general partnership with two partners, the first of which is a wholly owned subsidiary of El ~~Paso~~EPB (the “ElEPB ~~Paso~~ Partner”), and the second of which is a wholly owned subsidiary of ~~EPB~~El Paso (the “~~EPB~~El Paso Partner”). The ElEPB ~~Paso~~ Partner owns a 75 60 percent interest in our partnership, and the ~~EPB~~El Paso Partner owns our remaining 25 40 percent interest. A general partnership agreement governs our ownership and management. Although our management is vested in our partners, the partners have agreed to delegate our management to a management committee. Decisions of or actions taken by the management committee are binding on us. The management committee is composed of four representatives, with three representatives being designated by the ElEPB ~~Paso~~ Partner and one representative being designated by the ~~EPB~~ El Paso Partner. Each member of the management committee has full authority to act on behalf of the partner that designated such member with respect to matters pertaining to us. Each member of the management committee is entitled to one vote on each matter submitted for a vote of the management committee, and the vote of a majority of the members of the management committee constitutes action of the management committee, except for certain actions specified in the general partnership agreement that require unanimous approval of the management committee. Our officers are appointed by the management committee.

The following provides biographical information for each of our ~~executive officers and~~ management committee members, including the experience, qualifications, attributes or skills of such individuals, as well as information regarding our executive officers, as of February 2625, ~~2010~~2011.

There are no family relationships among any of our executive officers or management committee members, and, unless described herein, no arrangement or understanding exists between any executive officer and any other person pursuant to which he was or is to be selected as an officer.

Name	~~Age~~	~~Position~~Age	Position
James C. Yardley	58	President and Management Committee Member
Norman G. Holmes		54	President, and Management Committee Member
John R. Sult	50	~~Senior Vice President and Chief Financial Officer~~51	Executive Vice President and Chief Financial Officer
Daniel B. Martin	53	Senior Vice President and Management Committee Member
James C. Yardley		59	Management Committee Member
Norman G. Holmes	53	Senior Vice President, Chief Commercial Officer and Management Committee Member
Daniel B. Martin		54	Senior Vice President and Management Committee Member
Michael J. Varagona	54	~~Vice President, Business Development and Management Committee Member~~55	Vice President, Business Development and Management Committee Member

~~James~~Norman CG. ~~Yardley~~Holmes. Mr. ~~Yardley~~ Holmes has been aPresident ~~member~~ of ~~the Management Committee of~~ Southern Natural Gas Company ~~since~~ ~~November 2007 and President~~ since ~~May~~August ~~1998.~~2010, ~~Mr. Yardley~~a ~~previously served~~member ~~as Chairman~~ of the ~~Board~~Management ofCommittee ~~Southern~~since ~~Natural~~November ~~Gas~~2007, ~~Company~~and ~~from~~Senior ~~May~~Vice ~~2005~~President ~~to November 2007~~ and aChief ~~director~~Commercial Officer from ~~November~~August ~~2001~~2006 to ~~November~~August ~~2007~~2010. HeMr. Holmes has ~~been Executive~~served ~~Vice~~as President of ~~our~~Tennessee ~~parent~~Gas ElPipeline ~~Paso~~Company ~~with~~and ~~responsibility~~as ~~for~~a ~~the regulated~~member ~~pipeline~~of ~~business~~its ~~unit~~Board of Directors since August ~~2006~~2010. ~~Mr.~~He ~~Yardley~~previously isserved ~~currently~~as a ~~member~~ Director of ~~the~~Southern ~~board~~Natural ofGas ~~directors~~Company offrom ~~Scorpion~~November ~~Offshore~~2005 ~~Ltd~~to November 2007. HeMr. ~~also~~Holmes ~~serves~~served onas ~~the Board~~Vice President, Business Development of ~~Interstate~~Southern Natural Gas ~~Association~~Company offrom ~~America~~1999 ~~and~~to ~~previously~~2006 ~~served~~and as ~~its~~ ~~chairman.~~Vice President and Controller from 1995 to 1999. Mr. ~~Yardley~~ Holmes also serves as ~~Director,~~Senior Vice President ~~and Chief Executive Officer~~ of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

~~John R. Sult.~~ Mr. ~~Sult~~Holmes’ ~~has been~~day Senior Vice President and Chief Financial Officer of Southern Natural Gas Company since November 2009. Mr. Sult previously served as Senior Vice President, Chief Financial Officer and Controller from November 2005 to ~~November 2009.~~day ~~Mr.~~leadership ~~Sult also serves~~ as ~~Senior~~our ~~Vice~~ President ~~and~~provides ~~Chief~~him ~~Financial~~with ~~Officer of~~an ~~our~~intimate ~~parent~~knowledge ~~El Paso and as Senior Vice President and Chief Financial Officer~~ of our ~~affiliates El Paso Natural Gas Company~~partnership, ~~Colorado~~including ~~Interstate~~its ~~Gas Company~~strategies, ~~and~~ ~~Tennessee~~operations ~~Gas Pipeline Company. Mr. Sult previously served as Senior Vice President~~ and ~~Controller of El Paso from November 2005 to November 2009~~markets. ~~Mr.~~ ~~Sult~~In ~~held~~addition, ~~the~~his ~~position~~experience ~~of Vice President and Controller at Halliburton Energy Services Company from August 2004 until joining El Paso in October 2005. Mr. Sult also serves~~ as ~~Director, Senior Vice~~ President ~~and Chief Financial Officer~~ of ElTennessee ~~Paso~~Gas Pipeline GP Company~~, L.L.C.,~~ provides the ~~general~~Management ~~partner~~Committee ofwith Elimportant ~~Paso~~operational ~~Pipeline~~and ~~Partners,~~management Lexperience.P.

48John R. Sult. Mr. Sult has been Executive Vice President and Chief Financial Officer of Southern Natural Gas Company since March 2010 and Senior Vice President and Chief Financial Officer from November 2009 to March 2010. Mr. Sult previously served as Senior Vice President, Chief Financial Officer and Controller from November 2005 to November 2009. Mr. Sult also serves as Executive Vice President and Chief Financial Officer of our parent El Paso and as Executive Vice President and Chief Financial Officer of our affiliates El Paso Natural Gas Company, Colorado Interstate Gas Company, and Tennessee Gas Pipeline Company. Mr. Sult previously served as Senior Vice President and Controller of El Paso from November 2005 to November 2009. Mr. Sult held the position of Vice President and Controller at Halliburton Energy Services Company from August 2004 until joining El Paso in October 2005. Mr. Sult also serves as Director, Executive Vice President and Chief Financial Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

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~~Daniel B.~~James ~~Martin~~C. Yardley. Mr. ~~Martin~~ Yardley has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and ~~Senior~~served ~~Vice~~as President ~~since~~ ~~June~~from ~~2000~~May 1998 to August 2010. HeMr. Yardley previously served as aChairman ~~director~~of the Board of Southern Natural Gas Company from May 2005 to November 2007. ~~Mr.~~and ~~Martin has been~~ a ~~director~~Director offrom ~~our affiliates~~November El2001 ~~Paso~~to ~~Natural~~November ~~Gas Company and Tennessee Gas Pipeline Company since May 2005~~2007. ~~Mr.~~He ~~Martin~~ has been ~~Senior~~Executive Vice President of ~~Tennessee~~our ~~Gas~~parent ~~Pipeline Company~~El ~~since~~Paso ~~June~~with ~~2000~~responsibility ~~and~~for ~~Senior~~the ~~Vice~~regulated ~~President~~pipeline ofbusiness Elunit ~~Paso Natural Gas Company~~ since ~~February~~August ~~2000~~2006. HeMr. ~~served~~Yardley asserves aon ~~director~~the board of ~~ANR~~Interstate ~~Pipeline~~Natural ~~Company~~Gas ~~from~~Association ~~May 2005~~of ~~through~~America ~~February 2007~~ and ~~Senior~~previously ~~Vice~~served ~~President~~as ofits ~~ANR Pipeline Company from January 2001 to February 2007~~chairman. Mr. ~~Martin~~Yardley also serves as ~~Senior~~Director, ~~Vice~~ President ofand Chief Executive Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

~~Norman G.~~As ~~Holmes.~~Executive ~~Mr. Holmes has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Senior~~ Vice President ~~and Chief~~of ~~Commercial~~El ~~Officer~~Paso ~~since~~Corporation’s ~~August~~Pipeline ~~2006~~Group, Mr. HeYardley ~~previously~~brings ~~served as~~ a ~~director~~ wealth of ~~Southern~~operating ~~Natural~~experience ~~Gas Company from November 2005~~ to ~~November~~our ~~2007. Mr. Holmes~~Management ~~served~~Committee as ~~Vice~~well ~~President,~~as ~~Business~~an ~~Development~~extensive understanding of ~~Southern~~the ~~Natural~~pipeline ~~Gas Company~~industry ~~from~~overall. ~~1999~~In toaddition, ~~2006~~Mr. Yardley’s ~~and~~experience as ~~Vice~~ President and ~~Controller~~Chief ~~from~~Executive ~~1995~~Officer ~~to 1999. Mr. Holmes also serves as Senior Vice President~~ of El Paso Pipeline ~~GP Company~~Partners, L.LP.~~C.,~~ ~~the~~further ~~general~~augments ~~partner~~his ofknowledge Eland ~~Paso Pipeline Partners, L~~experience.P.

Daniel B. Martin. Mr. Martin has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Senior Vice President since June 2000. He previously served as a Director of Southern Natural Gas Company from May 2005 to November 2007. Mr. Martin has been a Director of our affiliates El Paso Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. Mr. Martin has been Senior Vice President of Tennessee Gas Pipeline Company since June 2000 and Senior Vice President of El Paso Natural Gas Company since February 2000. He served as a Director of ANR Pipeline Company from May 2005 through February 2007 and Senior Vice President of ANR Pipeline Company from January 2001 to February 2007. Mr. Martin also serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P. Mr. Martin is currently a member of the board of directors of Citrus Corp., a joint venture between El Paso Citrus Holdings, Inc. and Cross Country Citrus, LLC.

With his years of experience with El Paso’s pipeline subsidiaries, Mr. Martin brings comprehensive knowledge and understanding of the pipeline industry. In particular, Mr. Martin provides the Management Committee with valuable leadership and experience in pipeline safety, compliance and emergency response.

Michael J. Varagona. Mr. Varagona has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Vice President of Business Development since January 2007. Mr. Varagona served as Director, Business Development from January 2004 to December 2006.

Mr. Varagona has over 32 years experience in the natural gas industry, including significant experience in marketing and business development, transmission and liquefied natural gas infrastructure. In particular, he was a major participant in the reactivation of the Elba Island LNG Terminal in Savannah, Georgia, and has worked with numerous LNG suppliers and markets to develop more than $1.2 billion in LNG-related infrastructure.

Audit Committee, Compensation Committee and Code of Ethics

As a majority owned subsidiary of ~~El Paso~~EPB, we rely on ElEPB ~~Paso~~ for certain support services. As a result, we do not have a separate corporate audit committee or audit committee financial expert, or a separate compensation committee. Also, we have not adopted a separate code of ethics. However, our executives are subject to El Paso’s code of ethics, referred to as the “Code of ~~Business~~ Conduct”. The Code of ~~Business~~ Conduct is a value-based code that is built on five core values: stewardship, integrity, safety, accountability and excellence. In addition to other matters, the Code of ~~Business~~ Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of ~~Business~~ Conduct. A copy of the Code of ~~Business~~ Conduct is available for your review at El Paso’s website, www.elpaso.com.

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ITEM 11. EXECUTIVE COMPENSATION

All of our executive officers are officers or employees of El Paso or one of its non-SNG subsidiaries and devote a substantial portion of their time to El Paso or such other subsidiaries. None of these executive officers receives any compensation from SNG or its subsidiaries. The compensation of our executive officers is set by El Paso, and we have no control over the compensation determination process. Our executive officers and former employees participate in employee benefit plans and arrangements sponsored by El Paso. We have not established separate employee benefit plans and we have not entered into employment agreements with any of our executive officers.

The members of our management committee are also officers or employees of El Paso or one of its non-SNG subsidiaries and do not receive additional compensation for their service as a member of our management committee.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

~~SNG~~We isare a Delaware general partnership. ~~SNG~~We isare owned 7560 percent ~~indirectly~~by ~~through~~EPPP SNG GP Holdings, L.L.C., a wholly-owned subsidiary of ~~El Paso~~EPB, and is40 ~~owned 25~~ percent by EPPP SNG GP Holdings, L.L.C., a wholly-owned subsidiary of ~~EPB~~El Paso. The address of each of El Paso and EPB is 1001 Louisiana Street, Houston, Texas 77002.

The following table sets forth, as of February 1217, ~~2010~~2011, the number of shares of common stock of El Paso owned by each of our executive officers and management committee members and all of our management committee members and executive officers as a group.

Name of Beneficial Owner

~~Shares of Common Stock Owned Directly or Indirectly~~

Shares of Common Stock Owned Directly or Indirectly

Shares Underlying Options Exercisable Within 60 Days(1)

Total Shares of Common Stock Beneficially Owned

~~Total Shares of Common Stock Beneficially Owned~~

Percentage of Total Shares of Common Stock Beneficially Owned(2)

~~Percentage of Total Shares of Common Stock Beneficially Owned(2)~~

James C. Yardley

274,233

477,421

751,654

Norman G.Holmes

65,934

163,210

229,144

John R. Sult

85116,~~588~~131

209,897

~~149,985~~

326,028

~~235,573~~

Daniel B. Martin

151,068

242,662

393,730

James C. Yardley

306,991

559,203

866,194

Norman G. Holmes

57,989

164,512

222,501

Daniel B. Martin

162,099

227,670

389,769

Michael J. Varagona

3843,~~076~~316

77,636

~~66,874~~

120,952

~~104,950~~

All management committee members and executive officers as a group (5 persons)

~~606~~694,~~954~~471

1,237,616

~~1,101,454~~

1,932,087

~~1,708,408~~

~~____________~~___________________

* Less than 1%.

*	Less than 1%.

(1)	The shares indicated represent stock options granted under El Paso’s current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 17, 2011. Shares subject to options cannot be voted.
(2)	Based on 704,734,612 shares outstanding as of February 17, 2011.

~~(1)~~ The ~~shares~~following ~~indicated~~table ~~represent~~sets ~~stock~~forth, ~~options~~as ~~granted~~of ~~under~~February El17, ~~Paso’s~~2011, ~~current~~the ornumber ~~previous~~of ~~stock~~common ~~option~~units ~~plans,~~of ~~which~~EPB ~~are~~owned ~~currently~~by ~~exercisable~~each orof ~~which~~our ~~will~~executive ~~become~~officers ~~exercisable~~and ~~within~~management 60committee ~~days~~members and all of ~~February~~our ~~12,~~management ~~2010.~~committee ~~Shares~~members ~~subject~~and toexecutive ~~options~~officers ~~cannot~~as bea ~~voted~~group.

(2) Based on 701,314,549 shares outstanding as of February 12, 2010.

Name of Beneficial Owner	Total Common Units Beneficially Owned	Percentage of Total Common Units Beneficially Owned(1)
Norman G. Holmes	—	—
John R. Sult	10,000	*
James C. Yardley	10,000	*
Daniel B. Martin	—	—
Michael J. Varagona	—	—
All management committee members and executive officers as a group (5 persons)	20,000	*

___________________

*	Less than 1%.

(1)	Based on 177,167,863 shares outstanding as of February 17, 2011.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

~~We are a general partnership presently owned 75 percent indirectly through a wholly owned subsidiary of~~ El Paso ~~and~~Pipeline 25Partners ~~percent through a wholly owned subsidiary of EPB~~L.P.

~~SNG Guarantee~~We are a general partnership presently owned 60 percent indirectly through a wholly owned subsidiary of EPB ~~Elba~~and ~~Island~~40 ~~Expansion~~percent through a wholly owned subsidiary of El Paso.

We formerly owned Southern LNG Inc. (SLNG), which owns and operates a LNG receiving and regasification terminal on Elba Island near Savannah, Georgia. SLNG is now a subsidiary of El Paso. In connection with an ongoing expansion of the Elba Island LNG terminal (Elba III), we have guaranteed necessary funds (up to a defined limit) to permit the construction of the Elba III expansion.

SNG Guarantee of Elba Express Expansion

SNG formerly owned Elba Express Pipeline Company, LLC (EEC), which is in the process of constructing a 191-mile pipeline primarily in Georgia that is expected to be placed into service in March 2010. EEC is now a subsidiary of El Paso. We have agreed to provide, at our election, either all necessary funds to Elba Express (up to a defined limit) or a guarantee in the form of a performance bond (up to a defined limit) to permit the construction of the Elba Express pipeline.

El Paso Guarantee of SNG Lease

El Paso has guaranteed our obligations with respect to our leased headquarters.

Other Agreements and Transactions

In addition, we currently have and will have in the future other routine agreements with El Paso or one of its subsidiaries that arise in the ordinary course of business, including agreements for services and other transportation and exchange agreements and interconnection and balancing agreements with other El Paso pipelines.

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For a description of certain additional affiliate transactions, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, ~~2009~~2010 and ~~2008~~2009 of $~~792~~982,000 and $~~751~~792,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Southern Natural Gas Company and its subsidiaries as well as the review of documents filed with the SEC and related consent.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, ~~2009~~2010 and ~~2008~~ 2009.

Policy for Approval of Audit and Non-Audit Fees

We are ~~substantially~~ a majority owned bysubsidiary of both El Paso and ~~its~~EPB ~~subsidiaries~~ and do not have a separate audit committee. El Paso’s and EPB’s Audit ~~Committee~~Committees ~~has~~have adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its ~~2010~~2011 Annual Meeting of Stockholders. For a description of EPB’s pre-approval policies for audit and non-audit related services, see EPB’s Annual Report on Form 10-K for the year ended December 31, 2010.

5148

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

~~(a)~~ The following ~~consolidated~~ ~~financial~~documents ~~statements~~ are ~~included~~filed inas ~~Part~~a ~~II, Item 8~~ part of this report:

1. Financial statements

	Page
Southern Natural Gas Company
The following consolidated financial statements are included in Part II, Item 8 of this report:
Report of Independent Registered Public Accounting Firm	26
Consolidated Statements of Income and Comprehensive Income	27
Consolidated Statements of Income	27
Consolidated Balance Sheets	28
Consolidated Statements of Cash Flows	29
Consolidated Statements of Partners’ Capital/Stockholder’s Equity	30
Consolidated Statements of Partners’ Capital	30
Notes to Consolidated Financial Statements	31

2. Financial statement schedules
Schedule II — Valuation and Qualifying Accounts	46
All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.
3. and (b). Exhibits
The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and: • should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; • may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement; • may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and • were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. Undertaking We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. SEC upon request all constituent instruments defining the rights of holders of our long-term debt and our consolidated subsidiaries not filed as an exhibit hereto for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

2. Financial statement schedules

52Schedule II — Valuation and Qualifying Accounts 43

All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.

3. Exhibits

The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•	may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•	may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and our consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

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(c) Financial Statements of 50-Percent-Or-Less-Owned Investees:
Citrus Corp.
Report of Independent Registered Public Accounting Firm	54
Consolidated Balance Sheets	55
Consolidated Statements of Income	56
Consolidated Statements of Stockholders’ Equity	57
Consolidated Statements of Comprehensive Income	57
Consolidated Statements of Cash Flows	58
Notes to Consolidated Financial Statements	59

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Citrus Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity, of comprehensive income and of cash flows present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the “Company”) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with the accounting principles generally accepted in the United States of America. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 2 and 6 to the consolidated financial statements, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158 “Employers’ Accounting for Defined Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” as of December 31, 2006.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 25, 2008

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2007			December 31, 2006
	(In thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	3,572		$	15,267
Accounts receivable, billed and unbilled, less allowances of $18 and $282, respectively		39,350			45,049
Materials and supplies		12,745			2,954
Exchange gas receivable		1,729			—
Other		2,248			1,025
Total Current Assets		59,644			64,295
Property, Plant and Equipment
Plant in service		4,265,844			4,163,082
Construction work in progress		150,742			85,746
		4,416,586			4,248,828
Less accumulated depreciation and amortization		1,401,638			1,304,133
Property, Plant and Equipment, Net		3,014,948			2,944,695
Other Assets
Unamortized debt expense		4,221			4,687
Regulatory assets		19,207			31,007
Other		10,838			76,429
Total Other Assets		34,266			112,123
Total Assets	$	3,108,858		$	3,121,113
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	44,000		$	84,000
Accounts payable — trade and other		33,422			25,070
Accounts payable — affiliated companies		8,416			2,823
Accrued interest		14,251			14,805
Accrued income taxes		7,599			2,375
Accrued taxes, other than income		5,437			9,332
Exchange gas payable		22,547			24,225
Capital accruals		22,636			22,185
Dividends payable		42,600			—
Other		7,600			6,526
Total Current Liabilities		208,508			191,341
Deferred Credits
Deferred income taxes, net		763,364			777,404
Regulatory liabilities		14,842			14,256
Other		9,202			8,129
Total Deferred Credits		787,408			799,789
Long-Term Debt		909,810			836,882
Commitments and contingencies (Note 14)
Stockholders’ Equity
Common stock, $1 par value; 1,000 shares authorized, issued and outstanding		1			1
Additional paid-in capital		634,271			634,271
Accumulated other comprehensive loss		(7,885	)		(10,524	)
Retained earnings		576,745			669,353
Total Stockholders’ Equity		1,203,132			1,293,101
Total Liabilities and Stockholders’ Equity	$	3,108,858		$	3,121,113

The accompanying notes are an integral part of these consolidated financial statements.

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005
	(In thousands)
Operating Revenues
Transportation of natural gas	$	495,513		$	485,189		$	476,049
Total Operating Revenues		495,513			485,189			476,049
Operating Expenses
Operations and maintenance		82,058			77,941			78,829
Depreciation and amortization		100,634			98,653			91,125
Taxes, other than income taxes		29,618			34,765			34,306
Total Operating Expenses		212,310			211,359			204,260
Operating Income		283,203			273,830			271,789
Other Income (Expenses)
Interest expense and related charges, net		(73,871	)		(76,428	)		(79,290	)
Other, net		39,984			4,633			6,531
Total Other Income (Expenses), net		(33,887	)		(71,795	)		(72,759	)
Income Before Income Taxes		249,316			202,035			199,030
Federal and State Income Tax Expense		92,224			75,960			75,086
Net Income	$	157,092		$	126,075		$	123,944

The accompanying notes are an integral part of these consolidated financial statements.

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005
	(In thousands)
Common Stock
Balance, beginning and end of period	$	1		$	1		$	1
Additional Paid-in Capital
Balance, beginning and end of period		634,271			634,271			634,271
Accumulated Other Comprehensive Loss
Balance, beginning of period		(10,524	)		(13,162	)		(15,800	)
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,639			2,638			2,638
Balance, end of period		(7,885	)		(10,524	)		(13,162	)
Retained Earnings
Balance, beginning of period		669,353			668,678			665,934
Net income		157,092			126,075			123,944
Dividends (1)		(249,700	)		(125,400	)		(121,200	)
Balance, end of period		576,745			669,353			668,678
Total Stockholders’ Equity	$	1,203,132		$	1,293,101		$	1,289,788

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31, 2007		Year Ended December 31, 2006		Year Ended December 31, 2005
	(In thousands)
Net income	$	157,092	$	126,075	$	123,944
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,639		2,638		2,638
Total Comprehensive Income	$	159,731	$	128,713	$	126,582

____________

(1) Includes $42.6 million in Dividends Payable, declared in December 2007, payable in January, 2008 and which was paid on January 18, 2008. (See Note 7 — Related Party Transaction)

The accompanying notes are an integral part of these consolidated financial statements.

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CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005
	(In thousands)
Cash flows provided by operating activities
Net income	$	157,092		$	126,075		$	123,944
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		100,634			98,653			91,125
Amortization of hedge loss in other comprehensive income		2,639			2,638			2,638
Amortization of discount and swap hedge loss in long term debt		528			527			530
Amortization of regulatory assets and other deferred charges		1,250			3,274			3,380
Amortization of debt costs		994			1,048			1,053
Deferred income taxes		(12,277	)		18,629			12,740
Allowance for funds used during construction		(4,683	)		(1,630	)		(1,441	)
Gain on sale of assets		—			—			(1,236	)
Changes in operating assets and liabilities:
Accounts receivable		5,699			(3,327	)		403
Accounts payable		11,950			(3,316	)		(10,567	)
Accrued interest		(554	)		(286	)		(324	)
Accrued income tax		5,224			3,247			(7,204	)
Other current assets and liabilities		(8,944	)		18,749			3,234
Other long-term assets and liabilities		74,668			(24,627	)		36,140
Net cash provided by operating activities		334,220			239,654			254,415
Cash flows used in investing activities
Capital expenditures		(175,370	)		(106,023	)		(37,610	)
Allowance for funds used during construction		4,683			1,630			1,441
Proceeds from sale of assets		—			—			1,715
Net cash used in investing activities		(170,687	)		(104,393	)		(34,454	)
Cash flows used in financing activities
Dividends paid		(207,100	)		(125,400	)		(121,200	)
Net (payments) borrowings on the revolving credit facilities		76,400			(2,000	)		(75,000	)
Long-term debt finance costs		(528	)		—			—
Payments on long-term debt		(44,000	)		(14,000	)		(14,000	)
Net cash used in financing activities		(175,228	)		(141,400	)		(210,200	)
Net increase (decrease) in cash and cash equivalents		(11,695	)		(6,139	)		9,761
Cash and cash equivalents, beginning of period		15,267			21,406			11,645
Cash and cash equivalents, end of period	$	3,572		$	15,267		$	21,406
Supplemental disclosure of cash flow information
Interest paid (net of amounts capitalized)	$	72,439		$	72,067		$	74,714
Income tax paid	$	103,589		$	56,814		$	66,954

The accompanying notes are an integral part of these consolidated financial statements.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Corporate Structure

Citrus Corp. (Citrus, the Company), a holding company formed in 1986, owns 100 percent of the membership interest in Florida Gas Transmission Company, LLC (Florida Gas), and 100 percent of the stock of Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company. At December 31, 2007, the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly-owned subsidiary of El Paso Corporation (El Paso), and 50 percent by CrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry Energy, LLC (CrossCountry). In November 2007, Southern Natural Gas Company (Southern), whose parent is El Paso, distributed EPCH to El Paso. CrossCountry was a wholly-owned subsidiary of Enron Corp. (Enron) and certain of its subsidiary companies. Effective November 17, 2004, CrossCountry became a wholly-owned subsidiary of CCE Holdings, LLC (CCE Holdings), which was a joint venture owned by subsidiaries of Southern Union Company (Southern Union) (50 percent), GE Commercial Finance Energy Financial Services (GE) (approximately 30 percent) and four minority interest owners (approximately 20 percent in the aggregate).

On December 1, 2006, a series of transactions were completed which resulted in Southern Union increasing its indirect ownership interest in Citrus from 25 percent to 50 percent. On September 14, 2006, Energy Transfer Partners, L.P. (Energy Transfer), an unaffiliated company, entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings from GE and other investors. At the same time, Energy Transfer and CCE Holdings entered into a definitive redemption agreement, pursuant to which Energy Transfer’s 50 percent ownership interest in CCE Holdings would be redeemed in exchange for 100 percent of the equity interest in Transwestern Pipeline Company, LLC (TW) (Redemption Agreement). Upon closing of the Redemption Agreement on December 1, 2006, Southern Union became the indirect owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus, with the remaining 50 percent of Citrus continuing to be owned by EPCH.

Florida Gas, an interstate natural gas pipeline extending from South Texas to South Florida, is engaged in the interstate transmission of natural gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

On September 1, 2006, Florida Gas converted its legal entity type from a corporation to a limited liability company, pursuant to the Delaware Limited Liability Company Act.

(2) Significant Accounting Policies

Basis of Presentation — The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

Regulatory Accounting — Florida Gas’ accounting policies generally conform to Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71). Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under GAAP for non-regulated entities.

Revenue Recognition — Revenues consist primarily of fees earned from gas transportation services. Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly. For interruptible or volumetric based services, commodity revenues are recorded upon the delivery of natural gas to the agreed upon delivery point. Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a rate specified in the contract.

Because Florida Gas is subject to FERC regulations, revenues collected during the pendency of a rate proceeding may be required by the FERC to be refunded in the final order. Florida Gas establishes reserves for such potential refunds, as appropriate. There were no reserves for potential rate refund at December 31, 2007 and 2006, respectively.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Instruments — The Company follows FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (Statement No. 133) to account for derivative and hedging activities. In accordance with this statement, all derivatives are recognized on the Consolidated Balance Sheets at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or non-hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used. Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument. For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated Other Comprehensive Loss until the related hedge items impact earnings. Any ineffective portion of a cash flow hedge is reported in current period earnings. For derivatives treated as trading or non-hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon quoted market prices and mathematical models using current and historical data. As of December 31, 2007, the Company does not have any hedges in place as it is only amortizing previously terminated hedges.

Property, Plant and Equipment — Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities and is recorded at its original cost. Florida Gas capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and cost of funds, both interest and an equity return component (see third following paragraph). Costs of replacements and renewals of units of property are capitalized. The original cost of units of property retired are charged to accumulated depreciation, net of salvage and removal costs. Florida Gas charges to maintenance expense the costs of repairs and renewal of items determined to be less than units of property.

The Company amortized that portion of its investment in Florida Gas property which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percent based upon the estimated remaining useful life of the pipeline system.

Florida Gas has provided for depreciation of assets, on a straight-line basis, at an annual composite rate of 2.77 percent, 2.78 percent and 2.56 percent for the years ended December 31, 2007, 2006 and 2005, respectively.

The recognition of an allowance for funds used during construction (AFUDC) is a utility accounting practice with calculations under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of capital invested in construction work-in-progress. AFUDC has been segregated into two component parts — borrowed funds and equity funds. The allowance for borrowed and equity funds used during construction, including related gross up, totaled $10.3 million, $3.4 million and $1.4 million for the years ended December 31, 2007, 2006 and 2005, respectively. AFUDC borrowed is included in Interest Expense and AFUDC equity is included in Other Income in the accompanying statements of income.

Asset Retirement Obligations — The Company applies the provisions of FASB Statement No. 143, Accounting for Asset Retirement Obligations to record a liability for the estimated removal costs of assets where there is a legal obligation associated with removal. Under this standard, the liability is recorded at its fair value, with a corresponding asset that is depreciated over the remaining useful life of the long-lived asset to which the liability relates. An ongoing expense will also be recognized for changes in the value of the liability as a result of the passage of time.

FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN No. 47) issued by the FASB in March 2005 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation (ARO) when incurred, if the fair value of the liability can be reasonably estimated. FIN No. 47 provides guidance for assessing whether sufficient information is available to record an estimate. This interpretation was effective for the Company beginning on December 31, 2005. Upon adoption of FIN No. 47, Florida Gas recorded an increase in plant in service and a liability for an ARO of $0.5 million. This new asset and liability related to obligations associated with the removal and disposal of asbestos and asbestos containing materials on Florida Gas’ pipeline system. The ARO asset at December 31, 2007 had a net book value of $0.5 million.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides a reconciliation of the carrying amount of the ARO liability for the period indicated:

	Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005
	(In thousands)
Beginning balance	$	481		$	493		$	—
Incurred		—			—			493
Settled		(37	)		(36	)		—
Accretion Expense		27			24			—
Ending balance	$	471		$	481		$	493

Asset Impairment — The Company applies the provisions of FASB No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, to account for impairments on long-lived assets. Impairment losses are recognized for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying value. The amount of impairment is measured by comparing the fair value of the asset to its carrying amount.

Exchange Gas — Gas imbalances occur as a result of differences in volumes of gas received and delivered by a pipeline system. These imbalances due to or from shippers and operators are valued at an appropriate index price. Imbalances are settled in cash or made up in-kind subject to terms of Florida Gas’ tariff, and generally do not impact earnings.

Environmental Expenditures (Note 12) — Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future generation, are expensed. Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate based on the nature of the cost incurred. Liabilities are recorded when environmental assessments and/or clean ups are probable and the cost can be reasonably estimated. Remediation obligations are not discounted because the timing of future cash flow streams is not predictable.

Cash and Cash Equivalents — Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.

Materials and Supplies — Materials and supplies are valued at the lower of cost or market value. Materials transferred out of warehouses are priced at average cost. Materials and supplies include spare parts which are critical to the pipeline system operations and are valued at the lower of cost or market.

Fuel Tracker — A liability is recorded for net volumes of gas owed to customers collectively. Whenever fuel is due from customers from prior under recovery based on contractual and specific tariff provisions an asset is recorded. Gas owed to or from customers is valued at market. Changes in the balances have no effect on the consolidated income of the Company.

Income Taxes (Note 4) — Income taxes are accounted for under the asset and liability method in accordance with the provisions of FASB Statement No. 109, Accounting for Income Taxes. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The determination of the Company’s provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts are circumstances change, these reserves are adjusted through the provision for income taxes.

Accounts Receivable — The Company establishes an allowance for doubtful accounts on accounts receivable based on the expected ultimate recovery of these receivables. The Company considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility. Unrecovered accounts receivable charged against the allowance for doubtful accounts were $0.3 million, nil and nil in the years ended December 31, 2007, 2006 and 2005, respectively.

Pensions and Postretirement Benefits — Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (Statement No. 158). Statement No. 158 requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation. Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated Other Comprehensive Loss in stockholders’ equity. Effective for years beginning after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date. The Company has not yet adopted the measurement provisions of Statement No. 158.

Prior to adoption of the recognition provisions of Statement No. 158, the Company accounted for its defined benefit postretirement plans under FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement No. 106).” Statement No. 106 required that the liability recorded should represent the actuarial present value of all future benefits attributable to an employee’s service rendered to date. Under Statement No. 106, changes in the funded status were not immediately recognized; rather they were deferred and recognized ratably over future periods. Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its postretirement benefit plans. The Company’s plan is in an overfunded position as of December 31, 2007. As the plan assets are derived through rates charged to customers, under Statement No. 71, to the extent the Company has collected amounts in excess of what is required to fund the plan, the Company has an obligation to refund the excess amounts to customers through rates. As such, the Company recorded the previously unrecognized changes in the funded status (i.e., actuarial gains) as a regulatory liability and not as an adjustment to Accumulated Other Comprehensive Loss.

Use of Estimates — The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

New Accounting Principles

Accounting Principles Not Yet Adopted.

FIN 48,” Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement 109” (FIN 48 or the Interpretation): Issued by the FASB in June 2006, this Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006, for public enterprises and December 15, 2007, for nonpublic enterprises, such as Citrus. The Company has determined the implementation of this Statement will not have a material impact on its consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FSP No. FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48” (FIN 48-1): Issued by the FASB in May 2007, FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.

FASB Statement No. 157, “Fair Value Measurements” (FASB Statement No. 157 or the Statement): Issued by the FASB in September 2006, this Statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Where applicable, this Statement simplifies and codifies related guidance within GAAP. Except for certain non financial assets and liabilities more fully discussed in FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP No. FAS 157-2) which was issued by the FASB in February 2008, this Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. For those non financial assets and liabilities deferred pursuant to FSP No. FAS 157-2, this Statement is effective for financial statements for fiscal years beginning after November 15, 2008. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”: Issued by the FASB in February 2007, this Statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. The Statement does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. The Statement is effective for fiscal years beginning after November 15, 2007. At January 1, 2008, the Company did not elect the fair value option under the Statement and, therefore, there was no impact to the Company’s consolidated financials statements.

FASB Statement No. 141 (revised), “Business Combinations”. Issued by the FASB in December 2007, this Statement changes the accounting for business combinations including the measurement of acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for preacquisition gain and loss contingencies, the recognition of capitalized in-process research and development costs, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.

FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”. Issued by the FASB in December 2007, this Statement changes the accounting for noncontrolling (minority) interests in consolidated financial statements including the requirements to classify noncontrolling interests as a component of consolidated stockholders’ equity, and the elimination of minority interest accounting in results of operations with earnings attributable to noncontrolling interests reported as part of consolidated earnings. Additionally, the Statement revises the accounting for both increases and decreases in a parent’s controlling ownership interest. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited. The Company is currently evaluating the impact of this statement on its consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3) Long Term Debt

The table below sets forth the long-term debt of the Company as of the dates indicated:

	Years		December 31, 2007					December 31, 2006
	Due		Book Value			Fair Value		Book Value			Fair Value
	(In thousands)
Citrus
8.490% Senior Notes		2007-2009	$	60,000		$	63,572	$	90,000		$	95,011
Revolving Credit Agreement Citrus		2012		62,400			62,400		—			—
FGT
9.750% Senior B Notes		1999-2008		6,500			6,736		13,000			13,663
10.110% Senior C Notes		2009-2013		70,000			82,282		70,000			82,773
9.190% Senior Notes		2005-2024		127,500			158,843		135,000			167,004
7.625% Senior Notes		2010		325,000			353,352		325,000			348,137
7.000% Senior Notes		2012		250,000			277,281		250,000			271,893
Revolving Credit Agreement FGT		2007		—			—		40,000			40,000
Revolving Credit Agreement FGT		2012		54,000			54,000		—			—
Total debt outstanding			$	955,400		$	1,058,466	$	923,000		$	1,018,481
Current portion of long-term debt				(44,000	)				(84,000	)
Unamortized Debt Discount and Swap Loss				(1,590	)				(2,118	)
Total long-term debt			$	909,810				$	836,882

Annual maturities of long-term debt outstanding as of the date indicated were as follows:

	December 31, 2007
Year	(In thousands)
2008	$	44,000
2009		51,500
2010		346,500
2011		21,500
2012		387,900
Thereafter		104,000
	$	955,400

On August 13, 2004 Florida Gas entered into a Revolving Credit Agreement (“2004 Revolver”) with an initial commitment level of $50 million, subsequently increased by $125 million to $175 million. Since that time, Florida Gas has routinely utilized the 2004 Revolver to fund working capital needs. On December 31, 2006, the amount drawn under the 2004 Revolver was $40 million, with a weighted average interest rate of 6.08 percent (based on LIBOR plus 0.70 percent). Additionally, a commitment fee of 0.15 percent is payable quarterly on the unused portion of the commitment balance. The 2004 Florida Gas Revolver terminated in August 2007 and was replaced by a new revolving credit agreement at Florida Gas in the amount of $300 million (“2007 Florida Gas Revolver”), which will mature on August 16, 2012. The 2007 Florida Gas Revolver requires interest based on LIBOR plus a margin tied to the debt rating of the Company’s senior unsecured debt, currently 0.28 percent, and has a facility fee of 0.07 percent. As of December 31, 2007, the amount drawn under the 2007 Florida Gas Revolver was $54 million with a weighted average interest rate of 5.30 percent (based on LIBOR plus 0.28 percent).

Also on August 16, 2007, Citrus entered into a revolving credit facility in the amount of $200 million (“2007 Citrus Revolver”), which will mature on August 16, 2012. This facility will enable Citrus to meet its funding needs and repay its debt maturities. As of December 31, 2007, the amount drawn under the 2007 Citrus Revolver was $62.4 million with a weighted average interest rate of 5.22 percent (based on LIBOR plus 0.28 percent), and has a facility fee of 0.07 percent. Issuance costs for the 2007 Florida Gas Revolver and 2007 Citrus Revolver were $0.3 million and $0.2 million, respectively at December 31, 2007.

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The book value of the 2004 Revolver, 2007 Florida Gas Revolver, and 2007 Citrus Revolver approximates their market value given the variable rate of interest. Estimated fair value amounts of other long-term debt were obtained from independent parties, and are based upon market quotations of similar debt at interest rates currently available. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2007 and 2006 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

The agreements relating to Florida Gas’ debt include, among other things, restrictions as to the payment of dividends and maintaining certain restrictive financial covenants, including a required ratio of consolidated funded debt to total capitalization.

Under the terms of its debt agreements, Florida Gas may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and Florida Gas’ consolidated debt does not exceed specific debt to total capitalization ratios, as defined in certain debt instruments. Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.

All of the debt obligations of Citrus and Florida Gas have events of default that contain commonly used cross-default provisions. An event of default by either Citrus or Florida Gas on any of their borrowed money obligations, in excess of certain thresholds which is not cured within defined grace periods, would cause the other debt obligations of Citrus and Florida Gas to be accelerated.

(4) Income Taxes

The principal components of the Company’s net deferred income tax liabilities as of the dates indicated were as follows:

	December 31,		December 31,
	2007		2006
	(In thousands)
Deferred income tax asset
Regulatory and other reserves	$	5,554	$	8,595
		5,554		8,595
Deferred income tax liabilities
Depreciation and amortization		759,576		742,566
Deferred charges and other assets		—		27,981
Regulatory costs		4,717		9,298
Other		4,625		6,154
		768,918		785,999
Net deferred income tax liabilities	$	763,364	$	777,404

Total income tax expense for the periods indicated was as follows:

	Year Ended December 31, 2007			Year Ended December 31, 2006		Year Ended December 31, 2005
	(In thousands)
Current Tax Provision
Federal	$	99,083		$	52,135	$	53,526
State		5,418			5,196		8,820
		104,501			57,331		62,346
Deferred Tax Provision
Federal		(14,531	)		15,863		11,079
State		2,254			2,766		1,661
		(12,277	)		18,629		12,740
Total income tax expense	$	92,224		$	75,960	$	75,086

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CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The differences between taxes computed at the U.S. federal statutory rate of 35 percent and the Company’s effective tax rate for the periods indicated are as follows:

	Year Ended December 31, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005
	(In Thousands)
Statutory federal income tax provision	$	87,261		$	70,712		$	69,661
State income taxes, net of federal benefit		4,986			5,176			6,813
Other		(23	)		72			(1,388	)
Income tax expense	$	92,224		$	75,960		$	75,086
Effective Tax Rate		37.0	%		37.6	%		37.7	%

The Company files a consolidated federal income tax return separate from that of its stockholders.

(5) Employee Benefit Plans

The employees of the Company were covered under Enron’s employee benefit plans until November 2004.

Enron maintained a pension plan that was a noncontributory defined benefit plan, the Enron Corp. Cash Balance Plan (the Cash Balance Plan), covering certain Enron employees in the United States and certain employees in foreign countries. The basic benefit accrual was 5 percent of eligible annual base pay. In 2003 the Company recognized its portion of the expected Cash Balance Plan settlement by recording a $9.6 million current liability, which was cash settled in 2005 (Note 7), and a charge to operating expense. In 2004, with the settlement of the rate case (Note 8), Florida Gas recognized a regulatory asset for its portion, $9.3 million, with a reduction to operating expense. Per the rate case settlement Florida Gas will amortize, over five years retroactive to April 1, 2004, its allocated share of costs to fully fund and terminate the Cash Balance Plan. Amortization recorded was $1.9 million, $1.8 million and $1.9 million for the years ended December 31, 2007, 2006 and 2005, respectively. At December 31, 2007 and 2006 the remaining regulatory asset balance was $2.3 million and $4.2 million, respectively (Note 10).

Effective November 1, 2004 all employees of the Company were transferred to an affiliated entity, CrossCountry Energy Services, LLC (CCES) and during November 2004, employee insurance coverage migrated (without lapse) from Enron plans to new CCES welfare and benefit plans. Effective March 1, 2005 essentially all such employees were transferred to Florida Gas and became eligible at that time to participate in employee welfare and benefit plans adopted by Florida Gas.

Effective March 1, 2005 Florida Gas adopted the Florida Gas Transmission Company 401(k) Savings Plan (the Plan). All employees of Florida Gas are eligible to participate and, within one Plan, may contribute up to 50 percent of pre-tax compensation, subject to IRS limitations. This Plan allows additional “catch-up” contributions by participants over age 50, and allows Florida Gas to make discretionary profit sharing contributions for the benefit of all participants. Florida Gas matched 50 percent of participant contributions under this Plan up to a maximum of four percent of eligible compensation through December 31, 2007. The matching was increased effective January 1, 2008 to 100 percent of the first two percent and 50 percent of the next three percent of the participant’s compensation paid into the Plan. Participants vest in such matching and any profit sharing contributions at the rate of 20 percent per year, except that participants with five years of service at the date of adoption of the Plan were immediately vested. Administrative costs of the Plan and certain asset management fees are paid from Plan assets. Florida Gas’ expensed its contribution of $0.3 million, $0.4 million, and $0.3 million for the years ended December 31, 2007, 2006, and 2005 respectively.

	Pre-FASB 158			FASB 158 adoption adjustment			Post-FASB 158
	(In Thousands)
Prepaid postretirement benefit cost (non-current) (Note 10)	$	(721	)	$	3,423		$	2,702
Regulatory asset		1,951			(1,951	)		—
Regulatory liability		—			(1,472	)		(1,472	)

	One Percentage Point Increase		One Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	15	$	(13	)
Effect on postretirement benefit obligation	$	240	$	(215	)

	December 31, 2007			December 31, 2006
Equity securities		31	%		0	%
Debt securities		69	%		0	%
Cash and cash equivalents		0	%		100	%
Total		100	%		100	%

Years	Expected Benefits Before Effect of Medicare Part D		Payments Medicare Part D		Net
	(In thousands)
2008	$	551	$	96	$	455
2009		594		99		495
2010		614		101		513
2011		625		101		524
2012		624		100		524
2013 — 2017		2,935		454		2,481

	Termination Date	Amortization Period	Original Gain/(Loss)			December 31, 2007			December 31, 2006
						(In thousands)
Interest rate swap loss on 7.625% $325 million note due 2010	December 2000	10 years	$	(18,724	)	$	(5,461	)	$	(7,334	)
Interest rate swap loss on 7.0% $250 million note due 2012	July 2002	10 years		(12,280	)		(5,579	)		(6,807	)
Interest rate swap gain on 9.19% $150 million note due 2005-2024	November 1994	20 years		9,236			3,155			3,617
Total						$	(7,885	)	$	(10,524	)

Signature	~~Title~~	~~Date~~Title	Date
/s/James C. Yardley	President and Management Committee	February 26, 2010
/s/ Norman G. Holmes		President and Management Committee Member	February 28, 2011
James C. Yardley	Member (Principal Executive Officer)
Norman G. Holmes		(Principal Executive Officer)
/s/John R. Sult	Senior Vice President and	February 26, 2010
/s/ John R. Sult		Executive Vice President and	February 28, 2011
John R. Sult	~~Chief Financial Officer~~	Chief Financial Officer
	~~(Principal Financial Officer)~~	(Principal Financial Officer)
/s/ Rosa P. Jackson	~~Vice President and Controller~~	~~February~~Vice ~~26,~~President ~~2010~~and Controller	February 28, 2011
Rosa P. Jackson	~~(Principal Accounting Officer)~~	(Principal Accounting Officer)
/s/Daniel B. Martin	Senior Vice President and Management	February 26, 2010
/s/ Daniel B. Martin		Management Committee Member	February 28, 2011
Daniel B. Martin	~~Committee Member~~
/s/Norman G. Holmes	Senior Vice President,	February 26, 2010
/s/ Michael J. Varagona		Management Committee Member	February 28, 2011
Norman G. Holmes	Chief Commercial Officer and Management Committee Member
Michael J. Varagona
/s/Michael J. Varagona	Vice President and	February 26, 2010
/s/ James C. Yardley		Management Committee Member	February 28, 2011
Michael J. Varagona	Management Committee Member
James C. Yardley

Exhibit
Exhibit Number		Description
Number		Description
3.A		Certificate of Conversion (incorporated by reference to Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.A		Certificate of Conversion (Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.B		Statement of Partnership Existence (incorporated by reference to Exhibit 3.B to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.B		Statement of Partnership Existence (Exhibit 3.B to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.C		General Partnership Agreement dated November 1, 2007 (incorporated by reference to Exhibit 3.C to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.C		General Partnership Agreement dated November 1, 2007 (Exhibit 3.C to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.D		First Amendment to the General Partnership Agreement of Southern Natural Gas Company, dated September 30, 2008 (incorporated by reference to Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on October 6, 2008).
3.D		First Amendment to the General Partnership Agreement of Southern Natural Gas Company, dated September 30, 2008 (Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on October 6, 2008).
3.E		Second Amendment to General Partnership Agreement of Southern Natural Gas Company, dated June 23, 2010 (incorporated by reference to Exhibit 3.A to our Quarterly Report on Form 10-Q for the period ended June 30, 2010, filed with the SEC on August 6, 2010).
4.A		Indenture dated June 1, 1987 between Southern Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); First Supplemental Indenture, dated as of September 30, 1997, between Southern Natural Gas Company and the Trustee (Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); Second Supplemental Indenture dated as of February 13, 2001, between Southern Natural Gas Company and the Trustee (Exhibit 4.A.2 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); Third Supplemental Indenture dated as of March 26, 2007 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on March 28, 2007); Fourth Supplemental Indenture dated as of May 4, 2007 among Southern Natural Gas Company, Wilmington Trust Company (solely with respect to certain portions thereof) and The Bank of New York Trust Company, N.A. (Exhibit 4.C to our quarterly report on Form10-Q for the period ended March 31, 2007, filed with the SEC on May 8, 2007); Fifth Supplemental Indenture dated October 15, 2007 by and among SNG, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on October 16, 2007); Sixth Supplemental Indenture dated November 1, 2007 by and among SNG, Southern Natural Issuing Corporation, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.F		Third Amendment to General Partnership Agreement of Southern Natural Gas Company, dated June 30, 2010 (incorporated by reference to Exhibit 3.B to our Quarterly Report on Form 10-Q for the period ended June 30, 2010, filed with the SEC on August 6, 2010).
4.B		Form of 5.90% Note due 2017 (included as Exhibit A to Exhibit 4.A of our Current Report on Form 8-K filed with the SEC on March 28, 2007).
3.G		Fourth Amendment to the General Partnership Agreement of Southern Natural Gas Company, dated November 19, 2010 (incorporated by reference to Exhibit 3 to our Current Report on Form 8-K filed with the SEC on November 24, 2010).
*4.C		Indenture dated as of March 5, 2003 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., successor to The Bank of New York, as Trustee.
4.A		Indenture dated June 1, 1987 between Southern Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); First Supplemental Indenture, dated as of September 30, 1997, between Southern Natural Gas Company and the Trustee (incorporated by reference to Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); Second Supplemental Indenture dated as of February 13, 2001, between Southern Natural Gas Company and the Trustee (incorporated by reference to Exhibit 4.A.2 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); Third Supplemental Indenture dated as of March 26, 2007 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on March 28, 2007); Fourth Supplemental Indenture dated as of May 4, 2007 among Southern Natural Gas Company, Wilmington Trust Company (solely with respect to certain portions thereof) and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.C to our quarterly report on Form10-Q for the period ended March 31, 2007, filed with the SEC on May 8, 2007); Fifth Supplemental Indenture dated October 15, 2007 by and among SNG, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on October 16, 2007); Sixth Supplemental Indenture dated November 1, 2007 by and among SNG, Southern Natural Issuing Corporation, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).

10.D		Registration Rights Agreement, dated as of March 26, 2007, among Southern Natural Gas Company and Banc of America Securities LLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, BNP Paribas Securities Corp., HVB Capital Markets, Inc., Greenwich Capital Markets, Inc., Scotia Capital (USA) Inc., and SG Americas Securities, LLC (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on March 28, 2007).
4.B		Form of 5.90% Note due 2017 (included as Exhibit A to Exhibit 4.A of our Current Report on Form 8-K filed with the SEC on March 28, 2007).
4.C		Indenture dated as of March 5, 2003 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., successor to The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.C to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010).
*12		Ratio of Earnings to Fixed Charges.
*21		Subsidiaries of Southern Natural Gas Company.
*23.A		Consent of Independent Registered Public Accounting Firm Ernst & Young, LLP.
*23.B		Consent of Independent Registered Public Accounting Firm PricewaterhouseCoopers, LLP.
*31.A		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.B		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.A		Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.B		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(In millions)

Operating results data:

Operating revenues

Operating expenses

Income from continuing operations and net income