e10vk

Percent of Total

Description

Revenues in 2006

Reservation

Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system, storage facility or LNG terminalling facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.

Usage
and Other

Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) who pay charges based on the volume of gas actually transported, stored, injected or withdrawn.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


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

For the fiscal year ended December 31, 2006


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

For the transition period from to

Commission File Number 1-2745

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
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 o No þ

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 þ No o

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ

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

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Common Stock, par value $1 per share. Shares outstanding on February 21, 2007: 1,000

SOUTHERN NATURAL GAS COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

Documents Incorporated by Reference: None

SOUTHERN NATURAL GAS COMPANY

TABLE OF CONTENTS


	Caption	Page

	PART I

Item 1.	Business	3
Item 1A.	Risk Factors	6
Item 1B.	Unresolved Staff Comments	10
Item 2.	Properties	10
Item 3.	Legal Proceedings	10
Item 4.	Submission of Matters to a Vote of Security Holders	*

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	11
Item 6.	Selected Financial Data	*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	16
Item 8.	Financial Statements and Supplementary Data	17
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	37
Item 9A.	Controls and Procedures	37
Item 9B.	Other Information	37

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	*
Item 11.	Executive Compensation	*
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	*
Item 13.	Certain Relationships and Related Transactions, and Director Independence	*
Item 14.	Principal Accountant Fees and Services	37

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	38
	Signatures	69
Indenture
First Supplemental Indenture
Second Supplemental Indenture
Amendment No.1 to Receivables Purchase Agreement
Certification of PEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of PEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


*		We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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

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.

PART I

ITEM 1. BUSINESS

Overview and Strategy

Each of our pipeline systems and storage facilities operates under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms, and other terms and conditions of service to our customers. The fees or 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.

Our strategy is to protect and enhance the value of our transmission, storage and LNG terminalling business by:

	•		Seeking to expand our systems by attracting new customers, markets or supply sources while leveraging our existing assets to the extent possible;

	•		Investing in maintenance and pipeline integrity projects to maintain the value and ensure the safety of our pipeline systems and assets; and

	•		Recontracting or contracting expiring or available capacity.

Below is a further discussion of our pipeline systems, storage facilities and LNG terminal.

The SNG System. The SNG pipeline system consists of approximately 7,500 miles of pipeline with a design capacity of approximately 3,450 MMcf/d. During 2006, 2005 and 2004, average throughput was 2,168 BBtu/d, 1,984 BBtu/d and 2,163 BBtu/d. This system extends from natural gas fields in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to markets 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 growing southeastern markets in Alabama, Georgia and South Carolina.

In June 2006, we received permission from the FERC to construct approximately 177 miles of pipeline to connect our Elba Island LNG facility to markets in Georgia and Florida. The project will consist of three phases with a total capital cost of approximately $321 million and a total contract level of 500 MMcf/d. Phase I has an estimated in service date of May 2007.

The FGT System. We have a 50 percent ownership interest in Citrus Corp. (Citrus), a Delaware corporation. Citrus owns 100 percent of the FGT pipeline system, which consists of approximately 4,868 miles of pipeline with a design capacity of 2,090 MMcf/d. During 2006, 2005 and 2004, average throughput was 2,018 BBtu/d, 1,916 BBtu/d and 2,014 BBtu/d. This system extends from south Texas to south Florida. For more information regarding our investment in Citrus and the FGT system, see Part II, Item 8, Financial Statement and Supplementary Data, Note 11 as well as Citrus’ audited financial statements and related notes beginning on page 39 of this Form 10-K.

LNG Terminal. Our wholly owned subsidiary, Southern LNG Inc., owns a LNG receiving terminal located on Elba Island, near Savannah, Georgia. We completed an expansion of the facility and placed it into service during February 2006. This expansion has increased the peak sendout capacity to 1,215 MMcf/d and the base load sendout capacity to 806 MMcf/d. The capacity at the terminal is contracted with subsidiaries of British Gas and Royal Dutch Shell PLC.

Storage Facilities. Along our SNG pipeline system, we have a total of approximately 60 Bcf of underground working natural gas storage capacity. Our storage facilities include the Muldon facility in Monroe County, Mississippi, which has a storage capacity of 31 Bcf, and our 50 percent interest in Bear Creek Storage Company (Bear Creek), with our proportionate share of storage capacity of 29 Bcf.

Bear Creek is a joint venture that we own equally with our affiliate, Tennessee Gas Storage Company, a subsidiary of Tennessee Gas Pipeline Company (TGP). Bear Creek owns and operates an underground natural gas storage facility located in Louisiana. The facility has a capacity of 50 Bcf of base gas and 58 Bcf of working storage. Bear Creek’s working storage capacity is committed equally to TGP and us under long-term contracts.

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. In addition to our traditional suppliers, our SNG pipeline system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.

Imported LNG is one of the fastest growing supply sectors of the natural gas market. LNG terminals and other regasification facilities can serve as important 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 also may compete with us for transportation of gas into market areas we serve.

Electric power generation is the fastest growing demand sector of the natural gas market. The growth of the electric power industry potentially benefits the natural gas industry by creating more demand for natural gas turbine generated electric power. This effect is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity, increased natural gas prices and the use and availability of other fuel sources for power generation. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and electric transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm contracts with us.

Our existing transportation and storage contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing contracts or remarket expiring capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs, although at times, we discount these rates to remain competitive.

The following table details our customers, contracts and competition on our SNG pipeline system as of December 31, 2006:


Customer Information	Contract Information	Competition
Approximately 270 firm and interruptible customers Major Customers: Atlanta Gas Light Company⁽¹⁾ (959 BBtu/d) Southern Company Services (418 BBtu/d) Alabama Gas Corporation (413 BBtu/d) Scana Corporation (316 BBtu/d)	Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately six years. Expire in 2009-2015. Expire in 2010-2018. Expire in 2010-2013. Expire in 2007-2019.	We face strong competition in a number of our key markets. 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 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, we compete with several pipelines for the transportation business of their customers. In addition, we compete with pipelines and gathering systems for connection to new supply sources.


⁽¹⁾		Atlanta Gas Light Company is currently releasing a significant portion of its firm capacity to a subsidiary of Scana Corporation under terms allowed by our tariff.

Regulatory Environment

Our interstate natural gas transmission system, storage and LNG terminalling 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, terms and conditions of service to our customers. Generally, the FERC’s authority extends to:

	•		rates and charges for natural gas transportation, storage and LNG terminalling;

	•		certification and construction of new facilities;

	•		extension or abandonment of services and facilities;

	•		maintenance of accounts and records;

	•		relationships between pipelines and certain affiliates;

	•		terms and conditions of services;

	•		depreciation and amortization policies;

	•		acquisition and disposition of facilities; and

	•		initiation and discontinuation of services.

Our interstate pipeline systems and LNG terminal are also subject to federal, state and local statutes and regulations regarding pipeline and LNG safety and environmental matters. We have ongoing inspection programs designed to keep all of our facilities in compliance with pipeline safety and environmental requirements and we believe that our systems are in material compliance with the applicable requirements.

We are subject to U.S. Department of Transportation regulations that establish safety requirements in the design, construction, operation and maintenance of our interstate natural gas transmission systems and storage facilities. Our LNG terminalling business is regulated by the U.S. Coast Guard.

Environmental

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

Employees

As of February 21, 2007, we had approximately 480 full-time employees, none of whom are subject to a collective bargaining arrangement.

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. Such forward-looking statements are based on assumptions and beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur or be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the 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 success depends on factors beyond our control.

Our business is the transportation and storage of natural gas and LNG terminalling operations for third parties. Our results of operations are, to a large extent, driven by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volumes of natural gas we are able to transport and store depends on the actions of those third parties, and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably impact our ability to maintain or increase current throughput, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity:

	•		service area competition;

	•		expiration or turn back of significant contracts;

	•		changes in regulation and actions of regulatory bodies;

	•		weather conditions that impact throughput and storage levels;

	•		price competition;

	•		drilling activity and availability of natural gas;

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

	•		decreased natural gas demand due to various factors, including increases in prices and the increased availability or popularity of alternative energy sources such as hydroelectric, coal and fuel oil;

	•		availability and increased cost of capital to fund ongoing maintenance and growth projects;

	•		opposition to energy infrastructure development, especially in environmentally sensitive areas;

	•		adverse general economic conditions; and

	•		unfavorable movements in natural gas prices in supply and demand areas.

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

Our revenues are generated under transportation and storage contracts that expire periodically and must be renegotiated, extended or replaced. Although we actively pursue the renegotiation, extension or replacement of these contracts, we may not be able to extend or replace these contracts when they expire or may only be able to do so on terms that are not as favorable as existing contracts. If we are unable to renew, extend, or replace these contracts or if we renew them on less favorable terms, we may suffer a material reduction in our revenues and earnings. Currently, most of our firm transportation capacity is subscribed through mid-2010.

Fluctuations in energy commodity prices could adversely affect our business.

Revenues generated by our transportation, storage and LNG terminalling contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission, storage and LNG 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 gas reserves and obtaining additional supplies from interconnecting pipelines, primarily in the Gulf of Mexico. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of natural gas available for transmission and storage through our system. A decline in energy prices could also reduce the supply of LNG to our LNG terminal. We retain a fixed percentage of natural gas transported. This retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. Pricing volatility may, in some cases, impact the value of under or over recoveries of retained natural gas, as well as imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters and our long-term recontracting efforts may be negatively impacted. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Fluctuations in energy prices are caused by a number of factors, including:

	•		regional, domestic and international supply and demand;

	•		availability and adequacy of transportation facilities;

	•		energy legislation;

	•		federal and state taxes, if any, on the transportation and storage of natural gas;

	•		abundance of supplies of alternative energy sources; and

	•		political unrest among oil producing countries.

The agencies that regulate us and our customers affect our profitability.

Our business is regulated by the FERC, the U.S. Department of Transportation and various state and local regulatory agencies. In addition, our LNG terminalling business is regulated by the U.S. Coast Guard. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services. In setting authorized rates of return in recent FERC decisions, the FERC has utilized a proxy group of companies that includes local distribution companies that are not faced with as much competition or risks as interstate pipelines. The inclusion of these lower risk companies may create downward pressure on tariff rates when subjected to review by the FERC in future rate proceedings. Shippers on other pipelines have sought reductions from the FERC for the rates charged to their customers. If our tariff rates were reduced or redesigned in a future rate proceeding, our results of operations, financial position and cash flows could be materially adversely affected.

In addition, increased regulatory requirements relating to the integrity of our pipeline requires additional spending in order to maintain compliance with these 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.

Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.

Our operations are subject to various environmental laws and regulations that establish 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 and remediation of contaminated properties (some of which have been designated as Superfund sites by the United States Environmental Protection Agency 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. It is not possible for us to estimate exactly the amount and timing of all future expenditures related to environmental matters because of:

	•		The uncertainties in estimating pollution control and clean up costs, including sites where preliminary site investigation or assessments have been completed;

	•		The discovery of new sites or additional information at existing sites;

	•		The uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; and

	•		The nature of environmental laws and regulations, including the interpretation and enforcement thereof.

Currently, various legislative and regulatory measures to address greenhouse gas (GHG) emissions (including carbon dioxide and methane) are in various phases of discussion or implementation. These include the Kyoto Protocol (which is impacting proposed domestic legislation), proposed federal legislation and state actions to develop statewide or regional programs, each of which have imposed or would impose reductions in GHG emissions. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. These actions could also impact the consumption of natural gas, thereby affecting our operations.

Although we believe we have established appropriate reserves for our environmental liabilities, we could be required to set aside additional amounts due to these uncertainties which could significantly impact our future results of operations, cash flows or financial position. For additional information concerning our environmental matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

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 ruptures, explosions, pollution, release of toxic substances, fires, adverse weather conditions and other hazards, each of which could result in damage to or destruction of our facilities or damages or injuries to persons. In addition, our operations and assets face possible risks associated with acts of aggression or terrorism. If any of these events were to occur, we could suffer substantial losses.

While we maintain insurance against many of these risks, to the extent and in amounts we believe are reasonable, this insurance does not cover all risks. Many of our insurance coverages have material deductibles, as well as limits on our maximum recovery. 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.

Four of our customers account for a majority of our firm transportation capacity.

In 2006, our contracts with Atlanta Gas Light Company, Southern Company Services, Alabama Gas Corporation and Scana Corporation represented approximately 27 percent, 12 percent, 12 percent and 9 percent of our firm 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 creditworthiness could adversely affect our results of operations, financial position and cash flows.

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

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

	•		our ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on terms that are acceptable to us;

	•		the ability to obtain continued access to sufficient capital to fund expansion projects;

	•		potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;

	•		impediments on our ability to acquire rights-of-way or land rights on a timely basis 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 inflation or increased costs of equipment, materials or labor, or other factors beyond our control, that may be material;

	•		lack of anticipated future growth in natural gas supply; and

	•		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. As a result, new facilities may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

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 we are unable to retain and recruit employees such as engineers and other technical positions, our business could be negatively impacted.

Risks Related to Our Affiliation with El Paso

El Paso files 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 incorporated by reference into this report.

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 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 B2 by Moody’s Investor Service and B by Standard & Poor’s. The ratings assigned to our senior unsecured indebtedness are currently rated Ba1 by Moody’s Investor Service and B+ by Standard & Poor’s. We and El Paso are on a positive outlook with these agencies. Downgrades of our or El Paso’s credit ratings could increase our cost of capital and collateral requirements, and could impede our access to capital markets.

El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated receivable. In addition, we conduct commercial transactions with some of our affiliates. If 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 affiliated company payables. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

We are a wholly owned subsidiary of El Paso.

As a wholly owned subsidiary of El Paso, subject to limitations in our indenture, El Paso has substantial control over:

	•		our payment of dividends;

	•		decisions on our financing and capital raising activities;

	•		mergers or other business combinations;

	•		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.

Risks Related to Citrus Corp.

FGT depends substantially upon a small number of customers.

Five customers on FGT’s pipeline system account for approximately 65 percent of its contracted capacity, with the two most significant customers, Florida Power & Light Company and TECO Energy, Inc., including its subsidiaries Tampa Electric Company and Peoples Gas System, Inc., being obligated for approximately 36 percent and 18 percent of such capacity. Accordingly, failure of one or more of FGT’s most significant customers to pay reservation charges could reduce its revenues materially and have a material adverse effect on its financial condition, results of operations, or cash flows.

Important actions by Citrus and FGT require approval by both CrossCountry Energy, LLC (CrossCountry) and us.

Citrus’ and FGT’s organizational documents require that important matters such as the declaration of dividends and similar payments, the approval of operating budgets, the incurrence of indebtedness and the consummation of significant transactions be approved by both CrossCountry, which owns the other 50 percent of Citrus, and us. CrossCountry is wholly owned by Southern Union Company (Southern Union). Consequently, we are dependent on Southern Union’s agreement to effect any such actions. Southern Union’s interests with respect to these important matters could be different from ours and, accordingly, we may be unable to cause Citrus and FGT to take important actions, such as the payment of dividends and the sale or acquisition of assets.

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 businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interest in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Item 4, Submission of Matters to a Vote of Security Holders, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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

The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. 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 in this section. Factors that could cause actual results to differ include those risks and uncertainties that are discussed in Part I, Item 1A, Risk Factors.

Overview

Our business primarily consists of interstate natural gas transmission, storage and LNG terminalling operations. Each of these businesses faces varying degrees of competition from other pipelines and proposed 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, storage and LNG terminalling services consist of the following types.

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, market conditions, regulatory actions, competition, the creditworthiness of our customers and weather.

Our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs, although at times, we discount these rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues. The weighted average remaining contract term for active contracts, excluding our LNG contracts, is approximately six years as of December 31, 2006.

Below is the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2006, including those with terms beginning in 2007 or later.


			Percent of Total		Reservation		Percent of Total
	BBtu/d		Contracted Capacity		Revenues		Reservation Revenue
	(In millions)
2007		181		5	$	6		2
2008		19		1		1		—
2009		199		6		15		4
2010		1,505		43		161		47
2011 and beyond		1,583		45		161		47

Total		3,487		100	$	344		100

Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business which consists of consolidated operations as well as investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes and (iii) interest and debt expense. We exclude interest and debt expense from this measure so that our investors may evaluate our operating results independently from our financing methods. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows. Below is a reconciliation of EBIT to net income for the years ended December 31:


	2006			2005
	(In millions, except
	volume amounts)
Operating revenues	$	528		$	477
Operating expenses		(276	)		(249	)

Operating income		252			228
Earnings from unconsolidated affiliates		78			80
Other income, net		9			22

EBIT		339			330
Interest and debt expense		(94	)		(93	)
Affiliated interest income		18			11
Income taxes		(79	)		(74	)

Net income	$	184		$	174

Throughput volumes (BBtu/d)⁽¹⁾		3,177			2,942


⁽¹⁾		Throughput volumes include volumes associated with our proportionate share of our 50 percent equity interest in Citrus and billable transportation throughput volumes for storage injection.

The following items contributed to our overall EBIT increase of $9 million for the year ended December 31, 2006 as compared to 2005:


										EBIT
	Revenue			Expense			Other			Impact
	Favorable/(Unfavorable)
	(In millions)
Higher service revenues	$	26		$	—		$	—		$	26
Expansions		27			(2	)		(10	)		15
Gas not used in operations and other natural gas sales		(2	)		(5	)		—			(7	)
Impact of Hurricane Katrina		—			(7	)		—			(7	)
Gain on the sale of assets in 2005		—			(9	)		—			(9	)
Earnings from Citrus		—			—			(4	)		(4	)
Other⁽¹⁾		—			(4	)		(1	)		(5	)

Total impact on EBIT	$	51		$	(27	)	$	(15	)	$	9


⁽¹⁾		Consists of individually insignificant items.

The following discusses some of the significant items listed above as well as events that may affect our operations in the future.

Higher Service Revenues. During the year ended December 31, 2006, our revenues increased primarily due to higher rates as a result of our rate case settlement in March 2005. In addition, we experienced increased activity under various interruptible services provided under our tariffs as a result of increased demand in our service areas as well as higher throughput on our system during the summer of 2006.

Expansions. Our expansions consist of two projects that were approved by the FERC. In February 2006, the Elba Island LNG expansion was placed in service resulting in an increase in our operating revenues. This increase was partially offset by depreciation on the facilities and a reduction in other income due to amounts capitalized in 2005 related to the allowance for funds used during construction (AFUDC) of the expansion. This expansion is estimated to increase our revenues by approximately $29 million annually.

In June 2006, we received permission from the FERC for our Cypress expansion to construct approximately 177 miles of pipeline to connect our Elba Island facility with markets in Georgia and Florida. The project will consist of three phases with a total capital

cost of approximately $321 million and a total contract level up to 500 MMcf/d. We have begun construction of Phase I which has a projected in service date of May 2007. As a result, our earnings increased during 2006 due to amounts capitalized related to the AFUDC of the expansion. Upon completion of Phase I, our revenues are estimated to increase by approximately $39 million annually. Upon completion of all phases, our revenues are estimated to increase by approximately $62 million annually.

Gas Not Used in Operations and Other Natural Gas Sales. The financial impact of operational gas, net of gas used in operations, is based on the amount of natural gas we are allowed to retain and dispose of according to our tariff, relative to the amounts of natural gas we use for operating purposes and the price of natural gas. Gas not used in operations results in revenues to us, which are impacted by volumes and prices during a given period. Volumes of natural gas not utilized for operations are based on factors such as system throughput, facility enhancements and the ability to operate the system in the most efficient and safe manner. As a result of our rate case settlement in March 2005, our fuel retention percentage was reduced and a customer sharing provision was implemented. During the year ended December 31, 2006, we experienced a decrease in our EBIT due primarily to a decrease in over retained volumes and a decrease in the index prices used to value those volumes.

Impact of Hurricane Katrina. During 2006, we continued to repair the damage caused by Hurricane Katrina. We incurred higher operation and maintenance expenses due to only a partial insurance recovery of these repair costs. For a further discussion of the impact of this hurricane, see our Liquidity and Capital Expenditures discussion below.

Gain on the Sale of Assets. In 2005, we recorded a gain of $7 million on the sale of pipeline and measurement facilities to Atlanta Gas Light Company and a gain of $2 million on the sale of a gathering system.

Earnings from Citrus. Our earnings from Citrus decreased for the year ended December 31, 2006 compared to 2005, primarily due to an increase in operating expenses and depreciation expense associated with FGT’s approved rate settlement, partially offset by an increase in Citrus’ revenues from interruptible services.

Affiliated Interest Income

Affiliated interest income for the year ended December 31, 2006 was $7 million higher than in 2005 due to higher average advances to El Paso under its cash management program and higher average short-term interest rates. The average advances due from El Paso of $256 million in 2005 increased to $328 million in 2006. In addition, the average short-term interest rates increased from 4.2% in 2005 to 5.7% in 2006.

Income Taxes


	Year Ended
	December 31,
	2006			2005
	(In millions,
	except for rates)
Income taxes	$	79		$	74
Effective tax rate		30	%		30	%

Our effective tax rates were lower than the statutory rate of 35 percent in both periods primarily due to the tax effect of earnings from unconsolidated affiliates where we anticipate receiving dividends 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 rates, see Item 8, Financial Statements and Supplementary Data, Note 2.

Liquidity and Capital Expenditures

Liquidity Overview

Our liquidity needs are provided by cash flows from operating activities. In addition, we participate in El Paso’s cash management program. Under El Paso’s cash management program, depending on whether we have short-term cash surpluses or requirements, we either provide cash to El Paso or El Paso provides cash to us in exchange for an affiliated note receivable or payable. We have historically provided cash advances to El Paso, and we reflect these advances as investing activities in our statement of cash flows. At December 31, 2006, we had a note receivable from El Paso of $219 million that is due upon demand. However, we do not anticipate settlement within the next twelve months. In addition to our advances under the cash management program, we had other notes receivable from El Paso of $88 million at December 31, 2006. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of El Paso’s cash management program and our other note receivables.

During the fourth quarter of 2006, we entered into agreements to sell certain accounts receivable to a qualifying special purpose entity under Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. As of December 31, 2006, we sold approximately $49 million of receivables, net of an allowance of approximately $1 million, received cash of approximately $26 million, received subordinated beneficial interests of approximately $23 million and recognized a loss of less than $1 million. The cash received from the sale was advanced to El Paso under the cash management program. We reflect accounts receivable sold under this program and the related redemption of the subordinated beneficial interests as operating cash flows in our statement of cash flows. For a further discussion of the sales of our accounts receivable, see Item 8, Financial Statements and Supplementary Data, Note 11.

We believe that cash flows from operating activities and amounts available under El Paso’s cash management program, if necessary, will be adequate to meet our short-term capital requirements for our existing operations and planned expansion opportunities.

El Paso recently announced that it will pursue the formation of a master limited partnership in 2007 to enhance the value and financial flexibility of its pipeline assets and to provide a lower cost source of capital for new projects.

Capital Expenditures

Our capital expenditures for the years ended December 31 were as follows:


	2006		2005
	(In millions)
Maintenance	$	72	$	67
Expansion/Other		162		76
Hurricanes⁽¹⁾		64		34

Total	$	298	$	177


⁽¹⁾		Amounts shown are net of insurance proceeds of $16 million and $43 million in 2006 and 2005, respectively.

Under our current plan, we expect to spend between approximately $57 million and $83 million in each of the next three years for capital expenditures, primarily to maintain the integrity of our pipeline, to comply with clean air regulations and to ensure the safe and reliable delivery of natural gas to our customers. In addition, we have budgeted to spend between $143 million and $437 million in each of the next three years to expand the capacity and services of our system for long-term contracts. We expect to fund our capital expenditures through a combination of internally generated funds and, if necessary, repayments by El Paso of amounts advanced under its cash management program.

Hurricanes

We continue to repair the damage to our pipeline caused by Hurricane Katrina in 2005. We currently estimate total repair costs of approximately $150 million. Our mutual insurance company has indicated that we will not receive insurance recoveries on some of the amounts due to exceeding aggregate loss limits per event. We expect the remaining repair costs to be incurred in 2007 and most of the insurance reimbursements to be received in 2007 and into 2008. While we do not believe the unrecovered costs will materially impact our overall liquidity or financial results, the timing between expenditures and reimbursements may impact our liquidity from period to period. The table below provides further detail on what we have spent to date, our estimated remaining costs, and insurance recoveries.


	Recoverable		Unrecoverable
	Costs		Costs⁽¹⁾		Total
Cumulative costs through December 31, 2006	$	40	$	85	$	125
Estimated remaining		10		15		25

Total costs	$	50	$	100	$	150

Less: Reimbursements to date		15

Expected future reimbursements	$	35


⁽¹⁾		Approximately $80 million of these costs are capital costs.

The mutual insurance company also notified us that effective June 1, 2006, the aggregate loss limits on future events are reduced to $500 million from $1 billion, which will limit our recoveries on future hurricanes or other insurable events.

Commitments and Contingencies

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

New Accounting Pronouncements Issued But Not Yet Adopted

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk is exposure to changing interest rates. The table below shows the carrying value and related weighted average effective interest rates of our interest bearing securities by expected maturity dates and the fair value of those securities. At December 31, 2006, the fair values of our fixed rate long-term debt securities have been estimated based on quoted market prices for the same or similar issues.


	December 31, 2006																December 31, 2005
	Expected Fiscal Year of Maturity
	of Carrying Amounts
															Fair		Carrying		Fair
	2007			2008			2010			Thereafter			Total		Value		Amount		Value
	(In millions, except for rates)
Liabilities:
Long-term debt, including current maturities — fixed rate	$	100		$	100		$	398		$	598		$	1,196	$	1,302	$	1,195	$	1,277
Average effective interest rate		6.8	%		6.3	%		9.1	%		7.7	%

We are also exposed to changes in natural gas prices associated with the excess natural gas that we are allowed to retain, net of gas used in operations.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder of Southern Natural Gas Company

We have audited the accompanying consolidated balance sheet of Southern Natural Gas Company (the Company) as of December 31, 2006, and the related consolidated statements of income and comprehensive income, stockholder’s equity, and cash flows for the year then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a) for the year ended December 31, 2006. 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 audit. The consolidated financial statements of Citrus Corp. and Subsidiaries (a corporation in which the Company has 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 for Citrus Corp. and Subsidiaries, is based solely on the report of the other auditors. In the consolidated financial statements, the Company’s investment in Citrus Corp. and Subsidiaries represents approximately 18% of total assets as of December 31, 2006, and earnings from this investment represent approximately 24% of income before income taxes for the year then ended.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 audit 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 audit and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audit 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, 2006, and the consolidated results of its operations and its cash flows for the year then ended, 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, 2006, the Company adopted the Federal Energy Regulatory Commission’s accounting release related to pipeline assessment costs, and effective December 31, 2006, the Company adopted the recognition provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 106, and 132(R).

/s/ Ernst & Young LLP

Houston, Texas
February 26, 2007

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of Southern Natural Gas Company:

In our opinion, the accompanying consolidated financial statements listed in the Index appearing under Item 15(a)(1), present fairly, in all material respects, the consolidated financial position of Southern Natural Gas Company and its subsidiaries (the “Company”) at December 31, 2005, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2005 listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and the financial statement schedule 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.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama
March 15, 2006

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)


	December 31,
	2006		2005
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts receivable
Customer, net of allowance of $1 in 2005		9		58
Affiliates		33		—
Other		3		5
Materials and supplies		12		12
Deferred income taxes		9		9
Other		14		17

Total current assets		80		101

Property, plant and equipment, at cost		3,652		3,369
Less accumulated depreciation, depletion and amortization		1,404		1,368

Total property, plant and equipment, net		2,248		2,001

Other assets
Investments in unconsolidated affiliates		695		697
Notes receivable from affiliate		307		339
Other		63		52

		1,065		1,088

Total assets	$	3,393	$	3,190


LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	36	$	40
Affiliates		16		17
Other		16		12
Current maturities of long-term debt		100		—
Taxes payable		51		67
Accrued interest		30		30
Other		8		11

Total current liabilities		257		177

Long-term debt, less current maturities		1,096		1,195

Other liabilities
Deferred income taxes		360		320
Other		36		44

		396		364


Commitments and contingencies
Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding		—		—
Additional paid-in capital		340		340
Retained earnings		1,304		1,120
Accumulated other comprehensive loss		—		(6	)

Total stockholder’s equity		1,644		1,454

Total liabilities and stockholder’s equity	$	3,393	$	3,190

See accompanying notes.

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)


	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities
Net income	$	184		$	174		$	169
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		55			51			50
Deferred income tax expense		37			19			26
Gain on sale of long-lived assets		—			(9	)		—
Earnings from unconsolidated affiliates, adjusted for cash distributions		2			45			(8	)
Other non-cash income items		(3	)		(8	)		(3	)
Asset and liability changes
Accounts receivable		19			18			3
Accounts payable		(6	)		18			3
Taxes payable		(14	)		6			—
Other, net		(16	)		(6	)		(23	)

Net cash provided by operating activities		258			308			217


Cash flows from investing activities
Additions to property, plant and equipment		(298	)		(177	)		(199	)
Net change in notes receivable affiliates		32			(168	)		(18	)
Proceeds from the sale of assets		3			32			—
Net change in restricted cash		5			5			(1	)
Other		—			—			1

Net cash used in investing activities		(258	)		(308	)		(217	)


Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—

End of period	$	—		$	—		$	—

See accompanying notes.

SOUTHERN NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware corporation incorporated in 1935, and a wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business consists of the interstate transportation and storage of natural gas and LNG terminalling operations. We conduct our business activities through natural gas pipeline systems, which include our Southern Natural Gas pipeline system and our 50 percent indirect ownership interest in the Florida Gas Transmission Company (FGT) pipeline system, a LNG receiving terminal and storage facilities. Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles and we include the accounts of all majority owned and controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. Our financial statements for prior periods also include reclassifications that were made to conform to the current year presentation. Those reclassifications had no impact on reported net income or stockholder’s equity.

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 variable 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 the financial statements. Actual results can, and often do, differ from those estimates.

Regulated Operations

Our natural gas transmission system, storage and LNG terminalling 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 apply the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, 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 will 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, an equity return component on regulated capital projects and certain items 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.

We maintain cash on deposit with banks that is pledged for a particular use or restricted to support a potential liability. We classify these balances as restricted cash in other current or non-current assets in our balance sheet based on when we expect this cash to be used. We had $5 million of restricted cash in current assets as of December 31, 2005 that was returned to us as of December 31, 2006.

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 an outstanding receivable balance. We regularly review collectibility 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 actual amount of natural gas received on a customer’s contract at the supply point differs from the actual amount of natural gas delivered under the customer’s transportation contract at the delivery point. We value imbalances due to or from shippers at specified index prices set forth in our tariff based on the production month in which the imbalances occur. Customer imbalances are aggregated and netted on a monthly basis, and settled in cash, subject to the terms of our tariff. For differences in value between the amounts we pay or receive for the purchase or sale of 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.

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. In addition, 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 the fair value of the assets acquired. 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. Prior to January 1, 2006, we capitalized certain costs incurred related to our pipeline integrity programs as part of our property, plant and equipment. Beginning January 1, 2006, we began expensing certain of these costs based on FERC guidance. During the year ended December 31, 2006, we expensed approximately $3 million as a result of the adoption of this accounting release.

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. Currently, our depreciation rates vary from less than one percent to 20 percent per year. Using these rates, the remaining depreciable lives of these assets range from one to 65 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage service rates.

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. We include gains or losses on dispositions of operating units in operating income.

At December 31, 2006 and 2005, we had approximately $203 million and $182 million of construction work in progress included in our property, plant and equipment.

We capitalize a carrying cost, or an allowance for funds used during construction, on 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 on debt amounts capitalized during the years ended December 31, 2006, 2005 and 2004, were $3 million, $5 million and $3 million. These debt amounts are included as a reduction to interest and debt expense in our income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized during the years ended December 31, 2006, 2005 and 2004, were $5 million, $10 million and $6 million (exclusive of any tax related impacts). These equity amounts are included as other non-operating income on our income statement. Capitalized carrying costs for debt and equity financed construction are reflected as an increase in the cost of the asset on our balance sheet.

Asset and Investment 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 an event occurs, we evaluate the recoverability of our long-lived assets’ carrying values based on either (i) our long-lived assets’ ability to generate future cash flows on an undiscounted basis or (ii) the fair value of our investments in unconsolidated affiliates. 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 these assets downward, if necessary, to their 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 sales, among other factors.

Revenue Recognition

Our revenues are primarily generated from transportation, storage and LNG terminalling 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 not used in operations is based on the volumes of natural gas we are allowed to retain and dispose of relative to the amounts we use for operating purposes. We recognize revenues on gas not used in operations when the volumes are retained according to our tariff. 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.

Price Risk Management Activities

Our equity investee, Citrus Corp. (Citrus), historically used derivatives to mitigate, or hedge, cash flow risk associated with its variable interest rates on long-term debt. Citrus accounts for these derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and records changes in the fair value of these derivatives in other comprehensive income. We reflect our proportionate share of the impact these derivative instruments have on Citrus’ financial statements as adjustments to our other comprehensive income and our investment in unconsolidated affiliates.

Environmental Costs and Other Contingencies

Environmental Costs. We record environmental liabilities at their undiscounted amounts on our balance sheet in 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 or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period expense when clean-up efforts do not benefit future periods.

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

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

Income Taxes

El Paso maintains a tax accrual policy to record both regular and alternative minimum taxes for companies included in its consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated returns. El Paso pays all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso may bill or refund its subsidiaries for their portion of these income tax payments.

Pursuant to El Paso’s policy, we record current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

Accounting for Asset Retirement Obligations

We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for legal obligations associated with the replacement, removal, or retirement of our long-lived assets. Our asset retirement liabilities are 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 long-lived 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, depletion and amortization expense in our income statement. Because we believe it is probable that we will recover certain of these costs through our rates, we have recorded an asset (rather than expense) associated with certain of the depreciation of the property, plant and equipment and certain of the accretion of the liabilities described above.

We have legal obligations associated with our natural gas pipelines and related transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities relate primarily to purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We accrue a liability for legal obligations based on an estimate of the timing and amount of their settlement.

We are required to operate and maintain our natural gas pipeline and storage systems, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that the substantial majority of our natural gas pipeline and storage system assets have indeterminate lives. Accordingly, our asset retirement liabilities as of December 31, 2006 and 2005 were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Pension and Other Postretirement Benefits

In December 2006, we adopted the provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132(R). Under SFAS No. 158, we record an asset or liability for our pension and other postretirement benefit plans based on their funded or unfunded status. We also record any deferred amounts related to unrealized gains and losses or changes in actuarial assumptions in accumulated other comprehensive income, a component of stockholder’s equity, until those gains and losses are recognized in the income statement. For a further discussion of our adoption of SFAS No. 158, see Note 8.

Evaluation of Prior Period Misstatements in Current Financial Statements

In December 2006, we adopted the provisions of the Securities and Exchange Commission's (SEC) Staff Accounting Bulletin (SAB) No. 108. Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how to evaluate the impact of financial statement misstatements from prior periods that have been identified in the current year. The adoption of these provisions did not have any impact on our financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2006, the following accounting standards and interpretations had not yet been adopted by us.

Accounting for Uncertainty in Income Taxes. In July 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes. FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and all years where the statute of limitations has not expired. FIN No. 48 requires companies to meet a more likely than not threshold (i.e. greater than a 50 percent likelihood of a tax position being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this more likely than not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon ultimate settlement. The cumulative effect of applying this interpretation will be recorded as an adjustment to the beginning balance of retained earnings, or other components of stockholder’s equity as appropriate, in the period of adoption. This interpretation is effective for fiscal years beginning after December 15, 2006, and we do not anticipate that it will have a material impact on our financial statements.

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which provides guidance on measuring the fair value of assets and liabilities in the financial statements. We will be required to adopt the provisions of this standard no later than in 2008, and are currently evaluating the impact, if any, that it will have on our financial statements.

Measurement Date of Other Postretirement Benefits. In December 2006, we adopted the recognition provisions of SFAS No. 158. This standard will also require us to change the measurement date of our other postretirement benefit plans from September 30, the date we currently use, to December 31 beginning in 2008. We are evaluating the impact, if any, that the measurement date provisions of this standard will have on our financial statements.

2. Income Taxes

Components of Income Taxes. The following table reflects the components of income taxes included in net income for each of the three years ended December 31:


	2006		2005		2004
	(In millions)
Current
Federal	$	39	$	48	$	42
State		3		7		6

		42		55		48


Deferred
Federal		32		18		22
State		5		1		4

		37		19		26

Total income taxes	$	79	$	74	$	74

Effective Tax Rate Reconciliation. Our income taxes differ from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:


	2006			2005			2004
	(In millions, except for rates)
Income taxes at the statutory federal rate of 35%	$	92		$	87		$	85
Increase (decrease)
State income taxes, net of federal income tax benefit		5			5			6
Earnings from unconsolidated affiliates where we anticipate receiving dividends		(17	)		(18	)		(17	)
Other		(1	)		—			—

Income taxes	$	79		$	74		$	74

Effective tax rate		30	%		30	%		30	%

Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:


	2006			2005
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	330		$	294
Investment in unconsolidated affiliates		25			25
Other		36			35

Total deferred tax liability		391			354


Deferred tax assets
U.S. net operating loss and tax credit carryovers		2			2
Other		39			42
Valuation allowance		(1	)		(1	)

Total deferred tax asset		40			43

Net deferred tax liability	$	351		$	311

Tax Carryovers. The following are the components of our tax carryovers as of December 31, 2006:


	Amount		Expiration Year
			(In millions)
General business credit	$	1	2016-2022
Net operating loss		4	2018-2021

Usage of these carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations. We have recorded a valuation allowance to reserve for the deferred taxes related to our general business credits.

Valuation Allowances. Deferred tax assets are recorded on net operating losses and temporary differences in the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. We believe it is more likely than not that we will realize the benefit of our deferred tax assets, net of any existing valuation allowances, due to the effect of future reversals of existing taxable temporary differences primarily related to depreciation.

3. Financial Instruments

The carrying amounts and estimated fair values of our financial instruments are as follows at December 31:

2006

2005

Carrying

Fair

Carrying

Fair

Amount

Value

Amount

Value

(In millions)

Balance sheet financial instruments:

Long-term debt, including current maturities⁽¹⁾

1,196

1,302

1,195

1,277


⁽¹⁾		We estimated the fair value of our debt with fixed interest rates based on quoted market prices for the same or similar issues.

At December 31, 2006 and 2005, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term maturity of these instruments.

4. Regulatory Assets and Liabilities

Below are the details of our regulatory assets and liabilities at December 31:


Description	2006		2005
	(In millions)
Non-current regulatory assets
Deferred taxes on capitalized funds used during construction	$	47	$	44
Other		7		2

Total non-current regulatory assets⁽¹⁾	$	54	$	46


Non-current regulatory liabilities
Cost of removal of offshore assets	$	12	$	15
Excess deferred federal income taxes		2		2
Other		—		3

Total non-current regulatory liabilities⁽¹⁾	$	14	$	20

⁽¹⁾

Amounts are included as other non-current assets and liabilities on our balance sheets.

5. Accounting for Hedging Activities

As of December 31, 2006 and 2005, our accumulated other comprehensive loss included an unrealized loss of approximately $5 million and $6 million, net of income taxes related to our proportionate interest in the value of Citrus’ cash flow hedges. This amount will be reclassified to earnings over the terms of Citrus’ outstanding debt. We estimate that $1 million of this unrealized loss will be reclassified from accumulated other comprehensive loss over the next twelve months. For the years ended December 31, 2006, 2005 and 2004, no ineffectiveness was recorded in earnings related to these cash flow hedges.

6. Debt and Credit Facilities

Debt

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


	2006		2005
	(In millions)
6.70% Notes due October 2007	$	100	$	100
6.125% Notes due September 2008		100		100
8.875% Notes due March 2010		400		400
7.35% Notes due February 2031		300		300
8.0% Notes due March 2032		300		300

		1,200		1,200
Less: Current maturities		100		—
Unamortized discount		4		5

Total long-term debt, less current maturities	$	1,096	$	1,195

Aggregate maturities of the principal amounts of long-term debt are as follows:


Year	(In millions)
2007	$	100
2008		100
2010		400
Thereafter		600

Total maturities of long-term debt	$	1,200

We have the ability to call $1.0 billion of our notes at any time prior to their stated maturity date. If we were to exercise our option to call these notes, we would be obligated to pay principal, accrued interest and a make-whole premium to redeem the debt.

Under our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), the most restrictive of which shall not exceed 6 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; and (vi) potential limitations on our ability to participate in El Paso’s cash management program discussed in Note 11. For the year ended December 31, 2006, 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 named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. These cases were filed in 1997 by an individual under the False Claims Act, which has been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In May 2005, a representative appointed by the court issued a recommendation to dismiss most of the actions. In October 2006, the U.S. District Judge issued an order dismissing all measurement claims against all defendants. An appeal has been filed.

Royalty Claim. In five contract settlements reached in the late 1980s with Elf Aquitaine (Elf) pertaining to the pricing of gas produced from certain federal offshore blocks, we indemnified Elf against royalty claims that potentially could have been asserted by the Minerals Management Service (MMS). Following its settlements with us, Elf received demands from the MMS for royalty payments related to the settlements. With our approval, Elf protested the demands for over a decade while trying to reach a settlement with the MMS. Elf, which is now TOTAL E&P USA (TOTAL), advised us that it had renewed efforts to settle these claims. TOTAL has informed us that the MMS is claiming royalties in excess of $13 million, a large portion of which is interest for the settlements. We advised TOTAL that not all of the amounts sought by the MMS are covered by our indemnity. If TOTAL cannot resolve these claims administratively with the MMS, then an appeal can be taken to the federal courts. We have the right under a pre-existing settlement with our customers to recover, through a surcharge payable by our customers, a portion of the amount ultimately paid under the royalty indemnity with TOTAL.

In addition to the above matters, we and our subsidiaries and affiliates are also named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business.

For each of our outstanding legal 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. As further information becomes available, or other relevant developments occur, we 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 current reserves are adequate. At December 31, 2006, we had accrued

approximately $2 million for our outstanding legal matters.

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 December 31, 2006, we had accrued approximately $1 million for expected remediation costs and associated onsite, offsite and groundwater technical studies. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than the other, the lower end of the expected range has been accrued.

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 and regulations and claims for damages to property, employees, other persons and the environment 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.

Other Matter

Duke Litigation. Citrus Trading Corporation, a direct subsidiary of Citrus, filed a suit against Spectra LNG Sales, formerly Duke Energy LNG Sales, Inc., for wrongful termination of a gas supply contract that had been entered into by the parties in 1998. In January 2007, the claim was settled.

Capital Commitments and Purchase Obligations

At December 31, 2006, we had capital and investment commitments of approximately $100 million related to our expansion projects. Our other planned capital and investment projects are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures. In addition, we have entered into unconditional purchase obligations for products and services totaling $50 million at December 31, 2006. Our annual obligations under these agreements are $19 million in 2007, $19 million in 2008, $10 million in 2009 and $1 million in both 2010 and 2011.

Operating Leases

We lease property, facilities and equipment under various operating leases. The majority of our commitments for operating leases is the lease of the AmSouth Center located in Birmingham, Alabama. Beginning in September 2007, we will replace our lease of the AmSouth Center with a ten year lease of Colonial Brookwood Center, which is also located in Birmingham, Alabama. El Paso guarantees our obligations under these lease agreements. Minimum future annual rental commitments on our operating leases as of December 31, 2006, were as follows:


Year Ending
December 31,	(In millions)
2007	$	3
2008		3
2009		1
2010		1
2011		1

Total	$	9

Rental expense on our operating leases for each of the years ended December 31, 2006, 2005 and 2004 was $3 million. These amounts include our share of rent allocated to us from El Paso.

8. Retirement Benefits

Pension and Retirement Benefits. El Paso maintains a pension plan to provide benefits determined under a cash balance formula covering substantially all of its U.S. employees, including our employees. Prior to January 1, 2000, Sonat Inc. (Sonat), our former parent company, maintained a pension plan for our employees. On January 1, 2000, the Sonat pension plan was merged into El Paso’s cash balance plan. El Paso also maintains a defined contribution plan covering its U.S. employees, including our employees. El Paso matches 75 percent of participant basic contributions up to 6 percent of eligible compensation and can make additional discretionary matching contributions. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits. We provide 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. El Paso reserves the right to change these benefits. Employees 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. We expect to contribute approximately $3 million to our postretirement benefit plan in 2007.

On December 31, 2006, we adopted the provisions of SFAS No. 158, and upon adoption reflected the liabilities related to our postretirement benefit plan based on its funded status. The adoption of this standard decreased our non-current liabilities by approximately $7 million, increased our other non-current deferred tax liabilities by approximately $3 million, and increased our accumulated other comprehensive income by approximately $5 million. We anticipate that less than $1 million of our accumulated other comprehensive loss will be recognized as part of our net periodic benefit cost in 2007.

Change in Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. Our benefits are presented and computed as of and for the twelve months ended September 30:


	2006			2005
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	85		$	89
Interest cost		4			5
Participant contributions		1			1
Actuarial gain		(11	)		(4	)
Benefits paid		(6	)		(6	)

Accumulated postretirement benefit obligation at end of period	$	73		$	85


Change in plan assets:
Fair value of plan assets at beginning of period	$	56		$	53
Actual return on plan assets		4			4
Employer contributions		4			4
Participant contributions		1			1
Benefits paid		(6	)		(6	)

Fair value of plan assets at end of period	$	59		$	56


Reconciliation of funded status:
Fair value of plan assets at September 30	$	59		$	56
Less: Accumulated postretirement benefit obligation at end of period		73			85

Funded status at September 30		(14	)		(29	)
Unrecognized net actuarial loss⁽¹⁾		—			6

Net liability at December 31⁽²⁾	$	(14	)	$	(23	)


⁽¹⁾		Amounts were reclassified to accumulated other comprehensive income upon the adoption of SFAS No. 158 in 2006.
⁽²⁾		Amounts at December 31, 2006 is included in other non-current liabilities on our balance sheet.

Expected Payment of Future Benefits. As of December 31, 2006, we expect the following payments under our plans (in millions):


Year Ending
December 31,
2007	$	5
2008		6
2009		6
2010		6
2011		6
2012 — 2016		26

Total	$	55

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


	2006			2005			2004
	(In millions)
Interest cost	$	4		$	5		$	6
Expected return on plan assets		(3	)		(3	)		(3	)
Amortization of actuarial loss		—			—			2

Net postretirement benefit cost	$	1		$	2		$	5

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 for 2006, 2005 and 2004:


	2006		2005		2004
	(Percent)
Assumptions related to benefit obligations at September 30:
Discount rate		5.50		5.25
Assumptions related to benefit costs at December 31:
Discount rate		5.25		5.75		6.00
Expected return on plan assets⁽¹⁾		8.00		7.50		7.50


⁽¹⁾		The expected return on plan assets is a pre-tax rate (before a tax rate ranging from 29 percent to 30 percent on postretirement benefits) that is primarily based on an expected risk-free investment return, adjusted for historical risk premiums and specific risk adjustments associated with our debt and equity securities. These expected returns were then weighted based on the target asset allocations of our investment portfolio.

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 10.3 percent in 2006, 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 2006 or 2005. A one-percentage point change in these trends would have the following increase (decrease) on our accumulated post retirement benefit obligation as of September 30:


	2006			2005
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	6		$	8
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(5	)	$	(6	)

Plan Assets. The following table provides the actual asset allocations in our postretirement plan as of September 30:


	Actual		Actual
Asset Category	2006		2005
	(Percent)
Equity securities		64		60
Debt securities		34		31
Other		2		9

Total		100		100

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 support the benefit obligation to participants, retirees and beneficiaries. In meeting this objective, the plan seeks to achieve a high level of investment return consistent with a prudent level of portfolio risk. Investment objectives are long-term in nature covering typical market cycles of three to five years. Any shortfall in investment performance compared to investment objectives is the result of general economic and capital market conditions.

The target allocation for the invested assets is 65 percent equity and 35 percent fixed income. Other assets are held in cash for payment of benefits upon presentment. Any El Paso stock held by the plan is held indirectly through investments in mutual funds.

9. Transactions with Major Customers

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


	2006		2005		2004
	(In millions)
Scana Corporation⁽¹⁾	$	71	$	62	$	64
Southern Company Services⁽²⁾		53		55		48
BG LNG⁽³⁾		66		46		47


⁽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.

⁽²⁾		In 2004, Southern Company Services did not represent more than 10 percent of our revenues.

⁽³⁾		In 2005 and 2004, BG LNG did not represent more than 10 percent of our revenues.

10. Supplemental Cash Flow Information

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


	2006		2005		2004
	(In millions)
Interest paid, net of capitalized interest	$	94	$	93	$	94
Income tax payments		58		49		48

11. Investments in Unconsolidated Affiliates and Transactions with Affiliates

Investments in Unconsolidated Affiliates

Citrus. We have a 50 percent ownership interest in Citrus. CrossCountry Energy, LLC (CrossCountry) owns the other 50 percent of Citrus. The ownership agreements of Citrus provide each partner with a right of first refusal to purchase the ownership interest of the other partner. Our investment in Citrus is limited to our ownership of the voting stock of Citrus, and we have no financial obligations, commitments or guarantees, either written or oral, to support Citrus.

Our investment in Citrus at December 31, 2006 and 2005 was $597 million and $596 million. During 2006, 2005 and 2004, we received $63 million, $61 million and $70 million in dividends from Citrus.

Bear Creek Storage Company (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Tennessee Gas Storage Company, our affiliate. Our investment in Bear Creek at December 31, 2006 and 2005 was $98 million and $101 million. During 2006 and 2005, we received $17 million and $64 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:


	2006		2005		2004
	(In millions)
Operating results data:
Operating revenues	$	262	$	256	$	249
Operating expenses		113		109		100
Income from continuing operations and net income⁽¹⁾		78		76		74


	2006		2005
	(In millions)
Financial position data:
Current assets	$	71	$	74
Non-current assets		1,589		1,573
Short-term debt		42		7
Other current liabilities		54		32
Long-term debt		418		461
Other non-current liabilities		400		402
Equity in net assets⁽¹⁾		746		745


⁽¹⁾		The differences between our proportionate share of our equity investments’ net income and our earnings from unconsolidated affiliates and our share of their equity in net assets and our overall investment are due primarily to the excess purchase price amortization related to Citrus and differences between the estimated and actual equity earnings on our investments.

Transactions with Affiliates

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. We have historically provided cash to El Paso in exchange for an affiliated note receivable that is due upon demand. However, we do not anticipate settlement within the next twelve months and therefore, have classified this receivable as non-current on our balance sheets. At December 31, 2006 and 2005, we had a note receivable from El Paso of $219 million and $272 million. The interest rate at December 31, 2006 and 2005 was 5.3% and 5.0%.

Note Receivables. At December 31, 2006 and 2005, we also had a variable interest rate note receivable from El Paso of $86 million and $65 million. The interest rate at December 31, 2006 and 2005 was 5.3% and 5.0%. In addition, we had a non-interest bearing note receivable of approximately $2 million at December 31, 2006 and 2005. We classified these notes as non-current on our balance sheets.

Accounts Receivable Sales Program. During the fourth quarter of 2006, we entered into agreements to sell certain accounts receivable to a qualifying special purpose entity (QSPE) under SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. As of December 31, 2006, we sold approximately $49 million of receivables, net of an allowance of approximately $1 million, received cash of approximately $26 million, received subordinated beneficial interests of approximately $23 million and recognized a loss of less than $1 million. In conjunction with the sale, the QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $26 million on the closing date. Prior to its redemption, we reflect the subordinated beneficial interest in receivables sold as accounts receivable — affiliates on our balance sheet. We reflect accounts receivable sold under this program and the related redemption of the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the accounts receivable and performing all administrative duties for the QSPE, which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the year ended December 31, 2006.

Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. We had state income taxes receivable of $2 million at December 31, 2006, which are included in accounts receivable-other on our balance sheets. We had income taxes payable of $38 million and $52 million at December 31, 2006 and 2005. The majority of these balances will become payable to El Paso. See Note 1 for a discussion of our tax accrual policy.

Other Affiliate Balances. The following table shows other balances with our affiliates arising in the ordinary course of business:


	December 31,		December 31,
	2006		2005
	(In millions)
Accounts receivable-other	$	—	$	4
Other current liabilities		1		1

Affiliate Revenues and Expenses. We enter into transactions with affiliates in the normal course of our business to transport natural gas. Services provided to these affiliates are based on the same terms as non-affiliates.

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 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 EBIT, gross property and payroll.

The following table shows revenues and charges from our affiliates for each of the three years ended December 31:


	2006		2005		2004
	(In millions)
Revenues from affiliates	$	9	$	7	$	10
Operation and maintenance expenses from affiliates		65		74		66

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)
2006
Operating revenues	$	135	$	127	$	130	$	136	$	528
Operating income		67		60		60		65		252
Net income		44		44		45		51		184

2005
Operating revenues	$	125	$	112	$	116	$	124	$	477
Operating income		72		58		49		49		228
Net income		52		43		39		40		174

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

As previously reported in our Current Report on Form 8-K dated April 18, 2006, as amended on May 8, 2006, we appointed Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2006 and dismissed PricewaterhouseCoopers LLP. During the fiscal years ended December 31, 2006 and 2005, there were no disagreements with our former accountant or reportable events as defined in Item 304(a)(1)(iv) and Item 304(a)(1)(v) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2006, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures, as defined by the Securities Exchange Act of 1934, as amended. 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 reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based on the results of this evaluation, our President and Chief Financial Officer concluded that our disclosure controls and procedures were effective at December 31, 2006.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the fourth quarter of 2006.

ITEM 9B. OTHER INFORMATION

None.

PART III

Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence,” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2006 and 2005 of $678,000 and $740,000 were for professional services rendered by Ernst & Young LLP and PricewaterhouseCoopers LLP, respectively for the audits of the consolidated financial statements of Southern Natural Gas Company.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firms for the years ended December 31, 2006 and 2005.

Policy for Approval of Audit and Non-Audit Fees

We are a wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has 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 2007 Annual Meeting of Stockholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report:

1. Financial statements.

The following consolidated financial statements are included in Part II, Item 8 of this report:


	Page
Southern Natural Gas Company
Reports of Independent Registered Public Accounting Firms		17
Consolidated Statements of Income and Comprehensive Income		19
Consolidated Balance Sheets		20
Consolidated Statements of Cash Flows		21
Consolidated Statements of Stockholder’s Equity		22
Notes to Consolidated Financial Statements		23

The following financial statements of our equity investment are included on the following pages of this report:


	Page
Citrus Corp.
Report of Independent Registered Public Accounting Firm		41
Consolidated Balance Sheets		42
Consolidated Statements of Income		43
Consolidated Statements of Stockholders’ Equity		44
Consolidated Statements of Comprehensive Income		44
Consolidated Statements of Cash Flow		45
Notes to Consolidated Financial Statements		46

2. Financial statement schedules


Schedule II — Valuation and Qualifying Accounts			36

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.

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the 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.

Report of Independent Registered Public Accounting Firm

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

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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” as of December 31, 2006.

Houston, Texas
February 26, 2007

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,			December 31,
	2006			2005
	(In thousands)
ASSETS

Current Assets
Cash and cash equivalents	$	15,267		$	21,406
Accounts receivable — net of allowance for doubtful accounts of $282 and $23		45,049			41,072
Income tax receivable		—			872
Materials and supplies		2,954			3,077
Exchange gas receivable		—			508
Other		1,025			1,184

Total Current Assets		64,295			68,119


Property, Plant and Equipment, at Cost
Plant in service		4,163,082			4,118,518
Construction work in progress		85,746			9,693
Less — accumulated depreciation and amortization		(1,304,133	)		(1,211,663	)

Property, Plant and Equipment, Net		2,944,695			2,916,548


Other Assets
Unamortized debt expense		4,687			5,735
Regulatory assets		19,260			24,092
Other		88,176			74,893

Total Other Assets		112,123			104,720

Total Assets	$	3,121,113		$	3,089,387


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Long-term debt due within one year	$	84,000		$	14,000
Accounts payable — trade and other		37,741			21,325
Accounts payable — affiliated companies		2,823			5,501
Accrued interest		14,805			15,091
Accrued income taxes		2,375			—
Accrued taxes, other than income		9,332			9,090
Exchange gas payable		24,225			5,182
Other		16,040			6,161

Total Current Liabilities		191,341			76,350


Deferred Credits
Deferred income taxes		777,404			758,775
Regulatory liabilities		14,256			9,049
Other		8,129			33,070

Total Deferred Credits		799,789			800,894


Long-Term Debt		836,882			922,355

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		(10,524	)		(13,162	)
Retained earnings		669,353			668,678

Total Stockholders’ Equity		1,293,101			1,289,788


Total Liabilities and Stockholders’ Equity	$	3,121,113		$	3,089,387

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

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(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 Income
Balance, beginning of period		(13,162	)		(15,800	)		(17,247	)
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,638			2,638			1,447

Balance, end of period		(10,524	)		(13,162	)		(15,800	)


Retained Earnings
Balance, beginning of period		668,678			665,934			679,090
Net income		126,075			123,944			126,844
Dividends		(125,400	)		(121,200	)		(140,000	)

Balance, end of period		669,353			668,678			665,934


Total Stockholders’ Equity	$	1,293,101		$	1,289,788		$	1,284,406

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended		Year Ended		Year Ended
	December 31,		December 31,		December 31,
	2006		2005		2004
	(In thousands)
Net income	$	126,075	$	123,944	$	126,844
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,638		2,638		1,447

Total Comprehensive Income	$	128,713	$	126,582	$	128,291

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

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(In thousands)
Cash flows provided by operating activities

Net income	$	126,075		$	123,944		$	126,844
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		98,653			91,125			68,053
Amortization of hedge loss in other comprehensive income		2,638			2,638			1,447
Amortization of discount and swap hedge loss in long term debt		527			530			535
Amortization of regulatory assets and other deferred charges		3,274			3,380			5,205
Amortization of debt costs		1,048			1,053			922
Deferred income taxes		18,629			12,740			69,694
Price risk management fair market valuation revaluation		—			—			10,980
Price risk gain on buy out of gas contracts		—			—			(19,884	)
Allowance for funds used during construction		(1,630	)		(1,441	)		(1,136	)
Gain on sale of assets		—			(1,236	)		—
Changes in operating assets and liabilities:
Accounts receivable		(3,327	)		403			(1,762	)
Accounts payable		(3,316	)		(10,567	)		(17,258	)
Accrued interest		(286	)		(324	)		(3,639	)
Accrued income tax		3,247			(7,204	)		5,183
Other current assets and liabilities		18,749			3,234			(9,680	)
Price risk management assets and liabilities		—			—			(23,162	)
Other assets and liabilities		(24,627	)		36,140			2,169

Net cash provided by operating activities		239,654			254,415			214,511

Cash flows used in investing activities
Capital expenditures		(106,023	)		(37,610	)		(48,982	)
Allowance for funds used during construction		1,630			1,441			1,136
Proceeds from sale of assets		—			1,715			—

Net cash used in investing activities		(104,393	)		(34,454	)		(47,846	)

Cash flows used in financing activities
Dividends		(125,400	)		(121,200	)		(140,000	)
Net (payments) borrowings on the revolving credit facility		(2,000	)		(75,000	)		117,000
Long-term debt finance costs		—			—			(746	)
Payments on long-term debt		(14,000	)		(14,000	)		(256,500	)

Net cash used in financing activities		(141,400	)		(210,200	)		(280,246	)

Net increase (decrease) in cash and cash equivalents		(6,139	)		9,761			(113,581	)
Cash and cash equivalents, beginning of period		21,406			11,645			125,226

Cash and cash equivalents, end of period	$	15,267		$	21,406		$	11,645


Supplemental disclosure of cash flow information
Interest paid (net of amounts capitalized)	$	72,067		$	74,714		$	95,770
Income tax paid	$	56,814		$	66,954		$	4,432

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

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)		Corporate Structure

		Citrus Corp. (Citrus), a holding company formed in 1986, owns 100 percent of the membership interest in Florida Gas Transmission Company, LLC (FGT), and 100 percent of the stock of Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company. At December 31, 2006 the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly-owned subsidiary of Southern Natural Gas Company (Southern), and 50 percent by CrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry Energy, LLC (CrossCountry). Southern’s 50 percent ownership had previously been contributed by its parent, El Paso Corporation (El Paso) in March 2003. 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.

		FGT, an interstate 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, FGT 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.

		Regulatory Accounting — FGT’s accounting policies generally conform to Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under accounting principles generally accepted in the United States for non-regulated entities. FGT is subject to regulation by the FERC.

		Revenue Recognition — Revenues consist primarily of fees earned from gas transportation services. Reservation revenues on firm contracted capacity are recognized ratably over the contract period. 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 FGT 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. FGT establishes reserves for such potential refunds, as appropriate. There were no potential rate refund reserves at December 31, 2006 and 2005, respectively.

		Derivative Instruments — The Company was previously engaged in price risk management activities for both trading and non-trading activities and accounted for those contracts under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (Note 4). Instruments utilized in connection with trading activities

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		were accounted for on a mark-to-market basis and were reflected at fair value as Assets and Liabilities from Price Risk Management Activities in the Consolidated Balance Sheets. The Company classified price risk management activities as either current or non-current assets or liabilities based on their anticipated settlement date. Earnings from revaluation of price risk management assets and liabilities were included in Other Income (Expense). Cash flow hedge accounting is utilized for non-trading purposes to hedge the impact of interest rate fluctuations associated with the Company’s debt. Unrealized gains and losses from cash flow hedges, to the extent such amounts are effective, are recognized as a component of other comprehensive income, and subsequently recognized in earnings in the same periods as the hedged forecasted transaction affects earnings. The ineffective component from cash flow hedges is recognized in Other Income (Expense) each period. In instances where the hedge no longer qualifies as being effective, hedge accounting is terminated prospectively and the accumulated gain or loss is recognized in earnings in the same periods during which the hedged forecasted transaction affects earnings. Where fair value hedge accounting is appropriate, the offset that is attributed to the risk being hedged is recorded as an adjustment to the carrying amount of the hedged item and is recognized in earnings (Note 4). In the Company’s cash flow statement, cash inflows and outflows associated with the settlement of the price risk management activities are recognized in operating cash flows, and any receivables and payables resulting from these settlements are reported as trade receivables or payables on the balance sheet.

		Property, Plant and Equipment (Note 10) — Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities and is recorded at its original cost. FGT capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component (see second following paragraph). Costs of replacements and renewals of units of property are capitalized. The original costs of units of property retired are charged to the accumulated depreciation, net of salvage and removal costs. FGT 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 FGT and other subsidiaries 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.

		FGT has provided for depreciation of assets net of estimated salvage value, on a straight-line basis, at an annual composite rate of 2.78 percent, 2.56 percent and 1.74 percent for the years ended December 31, 2006, 2005 and 2004, respectively. The increase was due to higher depreciation reflecting the settlement of FGT’s rate case effective April 1, 2005.

		The recognition of an allowance for funds used during construction (AFUDC) is a utility accounting practice calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of servicing the 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 $3.4 million, $1.4 million and $1.1 million for the years ended December 31, 2006, 2005 and 2004, respectively. AFUDC borrowed is included in Interest Expense and AFUDC equity is included in Other Income in the accompanying statements of income.

		The Company applies the provisions of SFAS 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, FGT recorded an increase in plant in service and a liability for an

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		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 FGT’s pipeline system. The ARO asset at December 31, 2006 had a net book value of $0.5 million.

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


	Year Ended			Year Ended
	December 31,			December 31,
	2006			2005
	(In thousands)
Beginning balance	$	493		$	—
Incurred		—			493
Settled		(36	)		—
Accretion Expense		24			—

Ending balance	$	481		$	493

		The Company applies the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets to account for asset impairments. Under this standard, an asset is evaluated for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which an asset was intended to be used, decisions to sell an asset, and adverse changes in the legal or business environment such as adverse actions by regulators.

		Gas Imbalances — 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 FGT’s tariff, and generally do not impact earnings.

		Environmental Expenditures — 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 (Note 13).

		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.

		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 5) — The Company accounts for income taxes under the provisions of SFAS No. 109, Accounting for Income Taxes. SFAS No. 109 provides for an asset and liability approach to accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		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, $0.0 million and $0.0 million in the years ended December 31, 2006, 2005 and 2004, respectively.

		Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 Recently Adopted

		*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)”*: Issued by the FASB in September 2006, the Statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. The Statement also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The recognition and disclosure provisions of the Statement, which is effective for fiscal years ending after December 15, 2006, was adopted by the Company effective December 31, 2006. The measurement provisions of the Statement are effective for fiscal years ending after December 15, 2008. (Note 6)

		SEC Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006, the SEC provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB No. 108 is effective for fiscal years ending after November 15, 2006. The adoption of SAB No. 108 did not materially impact the Company’s consolidated financial statements.

		*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 Financial Accounting Standards Board (FASB) in July 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. The Company has evaluated this guidance and does not believe its consolidated financial statements will be materially impacted.

		*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 generally accepted accounting principles. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

CITRUS CORP. AND SUBSIDIARIES
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, 2006					December 31, 2005
	Due	Book Value			Fair Value		Book Value			Fair Value
		(In thousands)
Citrus
8.490% Senior Notes	2007-2009	$	90,000		$	95,011	$	90,000		$	95,624
FGT
9.750% Senior B Notes	1999-2008		13,000			13,663		19,500			20,139
10.110% Senior C Notes	2009-2013		70,000			82,773		70,000			85,513
9.190% Senior Notes	2005-2024		135,000			167,004		142,500			182,012
7.625% Senior Notes	2010		325,000			348,137		325,000			353,940
7.000% Senior Notes	2012		250,000			271,893		250,000			275,737
Revolving Credit Agreement	2007		40,000			40,000		42,000			42,000

Total debt outstanding			923,000		$	1,018,481		939,000		$	1,054,965

Unamortized Debt Discount and Swap Loss			(2,118	)				(2,645	)

Total debt			920,882					936,355
Current portion of long-term debt			(84,000	)				(14,000	)

Total long-term debt		$	836,882				$	922,355

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


	December 31,
	2006
Year	(In thousands)
2007	$	84,000
2008		44,000
2009		51,500
2010		346,500
2011		21,500
Thereafter		375,500

	$	923,000

On August 13, 2004 FGT entered into a Revolving Credit Agreement (“2004 Revolver”) with an initial commitment level of $50.0 million. Effective November 15, 2004 the commitment level was increased by $125.0 million to $175.0 million. Since that time, FGT has routinely utilized the 2004 Revolver to fund working capital needs. On December 31, 2006 and 2005 the amounts drawn under the 2004 Revolver were $40.0 million and $42.0 million, respectively, with a weighted average interest rate of 6.08 percent and 5.11 percent (based on LIBOR plus 0.70 percent), respectively. Additionally, a commitment fee of 0.15 percent is payable quarterly on the unused commitment balance. The debt issuance costs accumulated for the 2004 Revolver at December 31, 2006 and 2005 were $0.2 million and $0.4 million, respectively. The Revolving Credit Agreement will terminate in August 2007. It is anticipated that a new revolving credit agreement will be entered into with similar terms and purpose, but there can be no assurance that management will be successful in renegotiating the revolving credit agreement.

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		The book value of the 2004 Revolver approximates its 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, 2006 and 2005 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

		The agreements relating to FGT’s 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. As of December 31, 2006 and 2005, FGT was in compliance with both affirmative and restrictive covenants of the note agreements.

		Under the terms of its debt agreements, FGT may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and FGT’s 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 FGT have events of default that contain commonly used cross-default provisions. An event of default by either Citrus or FGT 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 FGT to be accelerated.

		Management believes that cash flow from operations and its ability to refinance its existing revolver provides the Company adequate liquidity to meet its working capital needs through December 31, 2007. Should the Company not be successful in its refinancing efforts, the Company would implement alternative plans that include obtaining other liquidity sources, including new borrowings from third parties, deferring certain capital spending and deferring dividends to its partners. While the Company believes that it could successfully complete the alternative plans, if necessary, there can be no assurance the Company would be successful in its implementation of such plans.

(4)		Derivative Instruments

		The Company determined that its gas purchase contracts for resale and related gas sales contracts were derivative instruments and recorded these at fair value as price risk management assets and liabilities under SFAS No. 133, as amended. The valuation was calculated using a discount rate adjusted for the Company’s borrowing premium of 250 basis points, which created an implied reserve for credit and other related risks. The Company estimated the fair value of all derivative instruments based on quoted market prices, current market conditions, estimates obtained from third-party brokers or dealers, or amounts derived using internal valuation models. The Company performed a quarterly revaluation on the carrying balances that were reflected in current earnings. The impact to earnings from revaluation, mostly due to price fluctuations, was a loss of $11.0 million for the year ended December 31, 2004 and was included in Other Expenses. During the fourth quarter of 2004 the Company sold its remaining derivative contract without a material impact on the consolidated statements of income.

		Trading ceased all trading activities effective the fourth quarter of 1997. It subsequently sold its remaining contracts and no longer has any gas purchase or gas sale contracts.

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			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(In thousands)
Statutory federal income tax provision	$	70,712		$	69,661		$	72,122
State income taxes, net of federal benefit		5,176			6,813			7,053
Other		72			(1,388	)		45

Income tax expense	$	75,960		$	75,086		$	79,220


Effective Tax Rate		37.6	%		37.7	%		38.4	%

		The Company had an alternative minimum tax (AMT) credit of $8.8 million which was used to offset regular income taxes payable in 2005. The AMT credit had an indefinite carry-forward period. For financial statement purposes, the Company had recognized the benefit of the AMT credit carry-forward as a reduction of deferred tax liabilities. The credit was fully utilized in 2005.

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

(6)		Employee Benefit Plans

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

		Certain retirees of FGT were covered under a deferred compensation plan managed and funded by Enron subsidiaries, one previously sold and the other now in bankruptcy. This matter has been included as part of the claim filed by FGT against Enron and another affiliated bankrupt company. FGT and Enron agreed in principle to a settlement, resulting in an allowed claim by FGT of approximately $3.4 million against Enron for the deferred compensation plan. Documents were approved by the bankruptcy court in May 2005. As a result of this settlement FGT assumed a deferred compensation plan liability of $1.8 million, which was recorded in 2004. The balances at December 31, 2006 and 2005 were $1.4 million and $1.8 million, respectively, and were reported in Other Current Liabilities ($0.3 million and $0.4 million, respectively) and in Other Deferred Credits ($1.1 million and $1.4 million, respectively) (Note 12). The anticipated proceeds from Enron for the bankruptcy claim described above were $0.5 million and were recorded as a long term receivable at December 31, 2004. In 2005 FGT assigned its claim to a third party and in June 2005 a payment of $0.8 million was received and recorded against the receivable. The excess $0.3 million was recorded as Other Income in the year ended December 31, 2005 (Note 8).

		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. Pension expense charged to the Company by Enron was $0.3 million for the year ended December 31, 2004. This excludes the Cash Balance termination amount discussed below.

		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 8), and a charge to operating expense. In 2004, with the settlement of the rate case (Note 9), FGT recognized a regulatory asset for its portion, $9.3

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		million, with a reduction to operating expense. Per the rate case settlement FGT 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 $1.8 million, $1.9 million and $1.4 million for the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006 and 2005 the remaining regulatory asset balance was $4.2 million and $6.0 million, respectively (Note 11). Based on the current status of the Cash Balance Plan termination cost and the amount expected to be allocated to the Company as its proportionate share of the plan’s termination liability, the Company continues to believe its accruals related to this matter are adequate. Although there can be no assurance that amounts ultimately allocated to and paid by the Company will not be materially different, we do not believe that the ultimate resolution of these matters will have a materially adverse effect on the Company’s consolidated financial position or cash flows, but it could have significant impact on the results of operations in future periods.

		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 FGT and became eligible at that time to participate in employee welfare and benefit plan adopted by FGT.

		Effective March 1, 2005 FGT adopted the Florida Gas Transmission Company 401(k) Savings Plan (the Plan). All employees of FGT 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 FGT to make discretionary profit sharing contributions for the benefit of all participants. FGT matches 50 percent of participant contributions under this Plan up to a maximum of 4% of eligible compensation. 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. FGT’s expensed its contribution of $0.4 million and $0.3 million for the years ended December 31, 2006 and 2005, respectively.

		Other Post — Employment Benefits

		Prior to December 1, 2004 FGT was a participating employer in the Enron Gas Pipelines Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary association (VEBA) under Section 501(c)(9) of the Internal Revenue Code of 1986, as amended (Tax Code), which provided certain post-retirement medical, life insurance and dental benefits to employees of FGT and certain other Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp. Medical Plan for Inactive Participants. Enron has made the determination that it will partition the Trust and distribute the assets and liabilities of the Trust among the participating employers of the Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer. The Trust Committee has final approval on allocation methodology for the Trust assets. Enron filed a motion in the Enron bankruptcy proceedings on July 22, 2003 which was stayed and then refiled and amended on June 17, 2005 and again refiled and amended on December 1, 2006 which provides that each participating employer expressly assumes liability for its allocable portion of retiree benefits and releases Enron from any liability with respect to the Trust in order to receive the assets of the Trust. On June 7, 2005 a class action suit captioned Lou Geiler et al v. Robert W. Jones, et al., was filed in United States District Court for the District of Nebraska by, among others, former employees of Northern Natural Gas Company (Northern) on behalf of the participants in the Northern Medical and Dental Plan for Retirees and Surviving Spouses against former and present members of the Trust Committee, the Trustee and the participating employers of the Trust, including FGT, claiming the Trust Committee and the Trustee have violated their fiduciary duties under ERISA and seeking a declaration from the Court binding on all participating employers of an accounting and distribution of the assets held in the Trust and a complete and accurate listing of the individuals properly allocated to Northern from the Enron Plan. On the same date essentially the same group filed a motion in the Enron bankruptcy proceedings to strike the Enron motion from further consideration. On February 6, 2006 the Nebraska action was dismissed. The plaintiffs filed an appeal of the dismissal on March 8, 2006. An agreement was reached on the conditions of the partition of the Trust among the VEBA participating employers, Enron and the Trust Committee and approved by the Enron

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		bankruptcy court on December 21, 2006. As a result the Nebraska action appeal was dismissed on January 25, 2007.

		The net periodic post-retirement benefit cost charged to the Company by Enron was $0.6 million for the year ended December 31, 2004. Substantially all of this amount relates to FGT and was recovered through rates.

		During the period December 1, 2004 through February 28, 2005, following FGT’s November 17, 2004 acquisition by CCE Holdings, coverage to eligible employees and their eligible dependents was provided by CrossCountry Energy Retiree Health Plan, which provides only medical benefits. FGT continues to provide certain retiree benefits through employer contributions to a qualified contribution plan, with the amounts generally varying based on age and years of service.

		Effective March 1, 2005 such benefits are provided under an identical plan sponsored by FGT as a single employer post-retirement benefit plan.

		With regard to its sponsored plan, FGT has entered into a VEBA trust (the “VEBA Trust”) agreement with JPMorgan Chase Bank Trust Company as a trustee. The VEBA Trust has established or adopted plans to provide certain post-retirement life, health, accident and other benefits. The VEBA Trust is a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to employees of the Company. FGT contributed $1.2 million and $1.5 million to the VEBA Trust for the years ended December 31, 2006 and 2005, respectively. Upon settlement of the Trust, any distribution of assets FGT receives from the Trust, estimated to be approximately $6.3 million per the Enron filing described above will be contributed to the VEBA Trust.

		Prior to 2005, FGT’s general policy was to fund accrued post-retirement health care costs as allocated by Enron. As a result of FGT’s change in 2005 from a participant in a multi employer plan to a single employer plan, FGT now accounts for its OPEB liability and expense on an actuarial basis, recording its health and life benefit costs over the active service period of employees to the date of full eligibility for the benefits. At December 31, 2005 FGT recognized its OPEB liability by recording a deferred credit of $2.2 million (Note 12) and a corresponding regulatory asset of $2.2 million (Note 11).

		The Company has postretirement health care plans which cover substantially all employees. The health care plans generally provide for cost sharing in the form of retiree contributions, deductibles, and coinsurance between the Company and its retirees, and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.

		Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of 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 income in stockholder’s 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 Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” 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, 2006. 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

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table represents a reconciliation of FGT’s OPEB plan for the periods indicated.


	Year Ended			Year Ended
	December 31,			December 31,
	2006			2005
	(In thousands)
Change in Benefit Obligation
Benefit obligation at the beginning of period ⁽¹⁾	$	6,665		$	9,872
Service cost		46			71
Interest cost		312			490
Actuarial gain		(691	)		(3,522	)
Retiree premiums		427			757
Benefits paid		(964	)		(1,003	)

Benefit obligation at end of year		5,795			6,665


Change in Plan Assets
Fair value of plan assets at the beginning of period ^{(1) (2)}		7,840			6,240
Return on plan assets		(37	)		352
Employer contributions		1,231			1,494
Retiree premiums		427			757
Benefits paid		(964	)		(1,003	)

Fair value of plan assets at end of year		8,497			7,840


Funded Status
Funded status at the end of the year	$	2,702		$	1,175

Unrecognized net actuarial gain					(3,348	)

Net liability recognized				$	(2,173	)


Amount recognized in the Consolidated Balance Sheet
Regulatory assets (Note 11)	$	—		$	2,173
Other assets — other (Note 11)		2,702			—
Regulatory liability (Note 12)		(1,472	)
Deferred credits — other (Note 12)		—			(2,173	)

Net asset (liability) recognized	$	1,230		$	—


	⁽¹⁾		For the purpose of this reconciliation, the plan adoption date is considered to be the same as the beginning period, January 1, 2005.

	⁽²⁾		Plan assets at December 31, 2006 and 2005 include the amount of assets expected to be received from the Enron Trust of $6.3 million.

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted-average assumptions used to determine FGT’s benefit obligations for the periods indicated were as follows:


	Year Ended			Year Ended
	December 31,			December 31,
	2006			2005
Discount rate		5.68	%		5.50	%
Health care cost trend rates		11.00	%		12.00	%
	graded to 4.85%			graded to 4.65%
	by 2013			by 2012

FGT’s net periodic (benefit) costs for the periods indicated consisted of the following:


	Year Ended			Year Ended
	December 31,			December 31,
	2006			2005
	(In thousands)
Service cost	$	46		$	71
Interest cost		312			490
Expected return on plan assets		(402	)		(352	)
Recognized actuarial gain		(223	)		(174	)

Net periodic (benefit) cost	$	(267	)	$	35

The weighted-average assumptions used to determine FGT’s net periodic benefit costs for the periods indicated were as follows:


	Year Ended			Year Ended
	December 31,			December 31,
	2006			2005
Discount rate		5.50	%		5.75	%
Rate of compensation increase		N/A			N/A
Expected long-term return on plan assets		5.00	%		5.00	%
Health care cost trend rates		12.00	%		12.00	%
	graded to 4.65%			graded to 4.75%
	by 2012			by 2012

FGT employs a building block approach in determining the expected long-term rate on return on plan assets. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. The long-term portfolio return is established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:


	One		One
	Percentage		Percentage
	Point		Point
	Increase		Decrease
	(In thousands)
Effect on total service and interest cost components	$	14	$	(13	)
Effect on postretirement benefit obligation	$	274	$	(245	)

		Discount Rate Selection — The discount rate for each measurement date is selected via a benchmark approach that reflects comparative changes in the Moody’s Long Term Corporate Bond Yield for AA Bond ratings with maturities 20 years and above and the Citigroup Pension Liability Index Discount Rate.

		The result is compared for consistency with the single rate determined by projecting the aggregate employer provided benefit cash flows from each plan for each future year, discounting such projected cash flows using annual spot yield rates published as the Citigroup Pension Discount Curve on the Society of Actuaries website for each measurement date and determining the single discount rate that produces the same discounted value. The result is rounded to the nearest multiple of 25 basis points.

		Plan Asset Information — The plan assets shall be invested in accordance with sound investment practices that emphasize long-term investment fundamentals. An investment objective of income and growth for the plan has been adopted. This investment objective: (i) is a risk-averse balanced approach that emphasizes a stable and substantial source of current income and some capital appreciation over the long-term; (ii) implies a willingness to risk some declines in value over the short-term, so long as the plan is positioned to generate current income and exhibits some capital appreciation; (iii) is expected to earn long-term returns sufficient to keep pace with the rate of inflation over most market cycles (net of spending and investment and administrative expenses), but may lag inflation in some environments; (iv) diversifies the plan in order to provide opportunities for long-term growth and to reduce the potential for large losses that could occur from holding concentrated positions; and (iv) recognizes that investment results over the long-term may lag those of a typical balanced portfolio since a typical balanced portfolio tends to be more aggressively invested. Nevertheless, this plan is expected to earn a long-term return that compares favorably to appropriate market indices.

		It is expected that these objectives can be obtained through a well-diversified portfolio structure in a manner consistent with the investment policy.

		FGT’s OPEB weighted-average asset allocation by asset category for the $2.0 million and $1.2 million of assets actually in the VEBA Trust at December 31, 2006 and 2005, respectively, was as follows:


	December 31,			December 31,
	2006			2005
Equity securities		0	%		0	%
Debt securities		0	%		0	%
Cash and cash equivalents		100	%		100	%

Total		100	%		100	%

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		Based on the postretirement plan objectives, asset allocations should be maintained as follows: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent, and cash and cash equivalents of 0 percent to ten 10 percent.

		The above referenced asset allocations for postretirement benefits are based upon guidelines established by FGT’s Investment Policy and is monitored by the Investment Committee of the board of directors in conjunction with an external investment advisor. On occasion, the asset allocations may fluctuate versus these guidelines as a result of administrative oversight by the Investment Committee.

		FGT expects to contribute approximately $0.5 million to its post-retirement benefit plan net of Medicare Part D subsidies in 2007.

		The estimated benefit payments, which reflect expected future service, as appropriate, that are projected to be paid are as follows:


	Expected Benefits		Payments
	Before Effect of		Medicare Part
	Medicare Part D		D		Net
Years	(in thousands)
2007	$	539	$	89	$	450
2008		583		93		490
2009		615		95		520
2010		622		96		526
2011		621		95		526
2012 - 2016		2,961		426		2,535

(7)		Major Customers and Concentration of Credit Risk

		Revenues from individual third party and affiliate customers exceeding 10 percent of total revenues for the periods indicated were approximately as listed below, and in total represented 58%, 54% and 50% of total revenue, respectively.


	Year Ended		Year Ended		Year Ended
	December 31,		December 31,		December 31,
	2006		2005		2004
	(In thousands)
Florida Power & Light Company	$	200,592	$	181,486	$	189,500
Teco Energy, Inc.	$	80,192	$	76,059	$	68,971

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company had the following transportation receivables from these customers at the dates indicated:


	December 31,		December 31,
	2006		2005
	(In thousands)
Florida Power & Light Company	$	15,065	$	15,153
Teco Energy, Inc.	$	6,161	$	5,365

		The Company has a concentration of customers in the electric and gas utility industries. These concentrations of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company’s receivable portfolio as a whole. The Company also has a concentration of customers located in the southeastern United States, primarily within the state of Florida. Receivables are generally not collateralized. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments, deposits, or other forms of security to the Company. FGT sought additional assurances from customers due to credit concerns, and had customer deposits totaling $1.6 million and $1.2 million, and prepayments of $0.2 million and $0.5 million at December 31, 2006 and 2005, respectively. The Company’s Management believes that the portfolio of FGT’s receivables, which includes regulated electric utilities, regulated local distribution companies, and municipalities, is of minimal credit risk.

(8)		Related Party Transactions

		In December 2001 Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy court. At December 31, 2004 FGT and Trading had aggregate outstanding claims with the Bankruptcy Court against Enron and affiliated bankrupt companies of $220.6 million. Of these claims, FGT and Trading filed claims totaling $68.1 and $152.5 million, respectively. FGT and Trading claims pertaining to contracts rejected by ENA were $21.4 and $152.3 million, respectively. In March 2005, ENA filed objections to Trading’s claim. In September 2006 the judge issued an order rejecting certain of Trading’s arguments and ruling that a contract under which ENA had an in the money position against Trading may be offset against a related contract under which Trading had an in the money position against ENA. The result of the order is a reduction in the allowable amount of Trading’s initial claim to $22.7 million. The parties have reached a settlement in principle on the matter which is awaiting a hearing with the Bankruptcy Court for approval (Note 15).

		FGT’s claims against ENA on transportation contracts were reduced by approximately $21.2 million when a third party took assignment of ENA’s transportation contracts. In 2004 FGT settled the amount of all of its claims (including the deferred compensation retiree claim (Note 6)) against Enron and a subsidiary debtor. Total allowed claims (including debtor set-offs) were $13.3 million. After approval of the settlement by the Bankruptcy Court, in June 2005 FGT sold its claims, received $3.4 million and recorded Other Income of $0.9 million.

		FGT had a construction reimbursement agreement with ENA under which amounts owed to FGT were delinquent. These obligations totaled approximately $7.4 million and were included in FGT’s filed bankruptcy claims. These receivables were fully reserved by FGT prior to 2003. Under the Settlement filed by FGT on August 13, 2004 and approved by the FERC on December 21, 2004 FGT will recover the under-recovery on this obligation by rolling in the costs of the facilities constructed, less the recovery from ENA, in its tariff rates (see Note 9). As part of the June 2005 sale of its claims, FGT received $2.1 million for this part of the claim.

		The Company provided natural gas sales and transportation services to El Paso affiliates at rates equal to rates charged to non-affiliated customers in the same class of service. Revenues related to these transportation services were approximately $1.0 million, $4.5 million and $3.7 million in the years ended December 31, 2006, 2005 and 2004, respectively. The Company’s gas sales were immaterial in the years ended December 31, 2006, 2005 and 2004. The Company also purchased gas from affiliates of Enron of approximately $0.0 million,

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		$0.0 million and $5.8 million, and from affiliates of El Paso of approximately $0.0 million, $0.0 million and $19.5 million in the years ended December 31, 2006, 2005 and 2004, respectively. FGT also purchased transportation services from Southern in connection with its Phase III Expansion completed in early 1995. FGT contracted for firm capacity of 100,000 Mcf/day on Southern’s system for a primary term of 10 years, to be continued for successive terms of one year each thereafter unless cancelled by either party, by giving 180 days notice to the other party prior to the end of the primary term or any yearly extension thereof. The amount expensed for these services totaled $6.6 million, $6.3 million and $6.5 million in the years ended December 31, 2006, 2005 and 2004, respectively.

		FGT entered into a 20-year compression service agreement with Enron Compression Services Company (ECS) in March 2000, as amended, service under which commenced on April 1, 2002. This agreement required FGT to pay ECS to provide electric horsepower capacity and related horsepower hours to be used to operate an electric compressor unit within Compressor Station No. 13A. Amounts paid to ECS in the year ended December 31, 2004 totaled $2.4 million. Under related agreements, ECS was required to pay FGT an annual lease fee and a monthly operating and maintenance fee to operate and maintain the facilities. Amounts received from ECS in the year ended December 31, 2004 for these services totaled $0.4 million. A Netting Agreement, effective November 1, 2002, was executed with ECS, providing for the netting of payments due under each of the O&M, lease, and compression service agreements with ECS. Effective December 1, 2004, ECS assigned all of its interest in the compression services and related agreements to Paragon ECS Holdings, LLC, a non-affiliated entity.

		Related to Enron’s bankruptcy, the Bankruptcy Court authorized an overhead expense allocation methodology on November 25, 2002. In compliance with the authorization, recipient companies subject to regulation and rate base constraints may limit amounts remitted to Enron to an amount equivalent to 2001, plus quantifiable adjustments. The Company invoked this regulation and rate base constraint limitation in the calculation of expenses accrued for January 1 through March 31, 2004. Effective April 1, 2004 services previously provided by bankrupt Enron affiliates to the Company pursuant to the allocation methodology ordered by the Bankruptcy Court were covered and charged under the terms of the Transition Services Agreement / Transition Supplemental Services Agreement (TSA/TSSA). This agreement between Enron and CrossCountry was administered by CrossCountry Energy Services, LLC (CCES), a subsidiary of CCE Holdings, which allocated to the Company its share of total costs. Effective November 17, 2004 an Amended TSA/TSSA agreement was put into effect. This agreement expired on July 31, 2005. The total costs are not materially different from those previously charged. The Company expensed administrative expenses from Enron and affiliated service companies of approximately $8.4 million, including insurance cost of approximately $6.7 million in the year ended December 31, 2004. The amount expensed for the seven months period ended July 31, 2005 was approximately $1.5 million.

		On November 5, 2004, CCE Holdings entered into an Administrative Services Agreement (ASA) with SU Pipeline Management LP (Manager), a Delaware limited partnership and a wholly-owned subsidiary of Southern Union. Pursuant to the ASA, Manager was responsible for the operations and administrative functions of the enterprise, CCE Holdings and Manager shared certain operations of Manager and its affiliates, and CCE Holdings was obligated to bear its share of costs of the Manager and its affiliates. Costs are allocated by Manager and its affiliates to the operating subsidiaries and investees, based on relevant criteria, including time spent, miles of pipe, total assets, labor allocations, or other appropriate methods. The Manager provided services to CCE Holdings from November 17, 2004 to December 1, 2006. Following the closing of the Redemption Agreement on December 1, 2006, services continue to be provided by Southern Union affiliates to FGT, and costs allocated using allocation methods consistent with past practices.

		The Company has related party activities for operational and administrative services performed by CCES, Panhandle Eastern Pipeline Company, LP (a subsidiary of Southern Union) and other related parties, on behalf of the Company, and corporate service charges from Southern Union. Expenses are generally charged based on either actual usage of services or allocated based on estimates of time spent working for the benefit of the various affiliated companies. Amounts expensed by the Company were $20.6 million, $20.2 million and $15.6 million in the years ended December 31, 2006, 2005 and 2004, respectively, and included corporate service charges from Southern Union of $4.0 million, $1.6 million and $0.0 million in the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006 and 2005, the Company had current accounts payable to affiliated companies of $2.8 million and $5.5 million, respectively, relating to these services.

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		In 2005, the Company paid a subsidiary of CCE Holdings $9.6 million to settle the Cash Balance Plan obligation, which CCE Holdings effectively paid in conjunction with the 2004 acquisition of the Company.

		The Company paid cash dividends to its shareholders of $125.4 million, $121.2 million and $140.0 million in the years ended December 31, 2006, 2005, and 2004, respectively.

(9)		Regulatory Matters

		On August 13, 2004 FGT filed a Stipulation and Agreement of Settlement (“Rate Case Settlement”) in its Section 4 rate proceeding in Docket No. RP04-12, which established settlement rates and resolved all issues. The settlement rates were approved and became effective on April 1, 2004 for all FGT services and again on April 1, 2005 for Rate Schedule FTS-2 when the basis for rates on FGT’s incremental facilities changed from a levelized cost of service to a traditional cost of service.

		On December 15, 2003 the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (“HCA”). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002, a bill signed into law on December 17, 2002. The rule requires operators to identify HCAs along their pipelines by December 2004 and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing, or direct assessment, by June 2004. Operators must risk rank their pipeline segments containing HCAs, and must complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first with the balance being completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to in excess of $15,000 per mile. In addition, some system modifications will be necessary to accommodate the in-line inspections. While identification and location of all the HCAs has been completed, it is impossible to determine the scope of required remediation activities prior to completion of the assessments and inspections. Therefore, the cost of implementing the requirements of this regulation is impossible to determine at this time. The required modifications and inspections are estimated to be in the range of approximately $16-$20 million per year, inclusive of remediation costs. Pursuant to the August 13, 2004 Rate Case Settlement, FGT has the right to make limited sections 4 filings to recover, via a surcharge during the settlement’s term, depreciation and return on up to approximately $40 million in security, integrity assessment and repair costs, and Florida Turnpike relocation and modification costs. Costs incurred for such projects in service through December 31, 2006 are expected to create a surcharge of $0.02 per MMBtu effective on April 1, 2007.

		In June 2005 FERC issued an order Docket No. AI05-1-000 that expands on the accounting guidance in the proposed accounting release issued in November 2004 on mandated pipeline integrity programs. The order interprets the FERC’s existing accounting rules and standardizes classifications of expenditures made by pipelines in connection with an integrity management program. The order is effective for integrity management expenditures incurred on or after January 1, 2006. FGT capitalizes all pipeline assessment costs based on its August 13, 2004 Rate Case Settlement. The Rate Case Settlement contained no reference to the FERC Docket No. AI05-1-000 regarding pipeline assessment costs and provided that the final FERC order approving the Rate Case Settlement constituted final approval of all necessary authorizations to effectuate its provisions. The Rate Case Settlement provisions became effective on March 1, 2005 and new tariff sheets to implement these provisions were filed on March 15, 2005. FERC issued an order accepting the tariff sheets on May 20, 2005. In the year to December 31, 2006, FGT completed and capitalized $6.7 million on pipeline assessment projects, as part of the integrity programs.

		On October 5, 2005 FGT filed an application with FERC for the Company’s proposed Phase VII expansion project. The proposed project will expand FGT’s existing pipeline infrastructure in Florida and provide the growing Florida energy market access to additional natural gas supply from the Southern LNG Elba Island liquefied natural gas import terminal near Savannah, Georgia. The Phase VII project calls for FGT to build approximately 33 miles of 36-inch diameter pipeline looping in several segments along an existing right of way and install 9,800 horsepower of compression to be constructed in two phases. The expansion will provide about 160 million cubic feet per day of additional capacity to transport natural gas from a connection

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		with Southern Natural Gas Company’s proposed Cypress Pipeline project in Clay County, Florida. The project’s two phases are expected to be in service in May 2007 and May 2009. The estimated cost of expansion is up to approximately $104 million. The FERC issued an order approving the project on June 15, 2006 and construction commenced on November 6, 2006.

		On October 20, 2005, FGT filed an application with FERC for the Company’s State Road 91 Relocation Project. The proposed project will consist of the abandonment of approximately 11.15 miles of 18-inch diameter pipeline and 10.75 miles of 24-inch diameter pipeline in Broward, County Florida. The replacement pipeline will consist of approximately 11.15 miles of 36-inch diameter pipeline. The abandonment and replacement is being performed to accommodate the widening of State Road 91 by the Florida Department of Transportation/Florida Turnpike Enterprise (FDOT/FTE). The estimated cost of the pipeline relocation project is estimated at $110.5 million and FGT is seeking recovery of the construction costs from the FDOT/FTE. The FERC issued an order approving the project on May 3, 2006. FGT has requested authorization to commence construction on February 21, 2007.

(10)		Property, Plant and Equipment

		The principal components of the Company’s property, plant and equipment at the dates indicated were as follows:


	December 31,			December 31,
	2006			2005
	(In thousands)
Transmission plant	$	2,859,920		$	2,812,586
General plant		24,970			26,383
Intangible plant		25,726			27,083
Construction work-in-progress		85,746			9,693
Acquisition adjustment		1,252,466			1,252,466

		4,248,828			4,128,211
less: Accumulated depreciation and amortization		(1,304,133	)		(1,211,663	)

Property, Plant and Equipment, net	$	2,944,695		$	2,916,548

(11)		Other Assets

		The principal components of the Company’s regulatory assets at the dates indicated were as follows:


	December 31,		December 31,
	2006		2005
	(In thousands)
Ramp-up assets, net ⁽¹⁾	$	11,928	$	12,240
Cash balance plan settlement (Note 6)		4,185		6,047
Other post employment benefits (Note 6)		—		2,173
Environmental non-PCB clean-up cost (Note 13)		1,000		1,000
Other miscellaneous		2,147		2,632

Total Regulatory Assets	$	19,260	$	24,092


	⁽¹⁾		Ramp-up assets are regulatory assets which FGT was specifically allowed to establish in the FERC certificates authorizing the Phase IV and V Expansion projects.

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal components of the Company’s other assets at the dates indicated were as follows:


	December 31,		December 31,
	2006		2005
	(In thousands)
Long-term receivables	$	71,648	$	72,570
Fuel tracker		11,747		—
Other post employment benefits (Note 6)		2,702		—
Other miscellaneous		2,079		2,323

Total Other Assets — other	$	88,176	$	74,893

(12)		Deferred Credits

		The principal components of the Company’s regulatory liabilities at the dates indicated were as follows:


	December 31,		December 31,
	2006		2005
	(In thousands)
Balancing tools ⁽¹⁾	$	12,154	$	9,049
Other post employment benefits (Note 6)		1,472		—
Other miscellaneous		630		—

Total Regulatory liabilities	$	14,256	$	9,049


	⁽¹⁾		Balancing tools are a regulatory method by which FGT recovers the costs of operational balancing of the pipeline’s system. The balance can be a deferred charge or credit, depending on timing, rate changes and operational activities.

The principal components of the Company’s other deferred credits at the dates indicated were as follows:


	December 31,		December 31,
	2006		2005
	(In thousands)
Post construction mitigation costs	$	2,073	$	2,600
Construction prepayments		—		4,536
Customer deposits (Note 7)		—		1,249
Fuel tracker		—		14,477
Deferred compensation (Note 6)		1,090		1,425
Environmental non-PCB clean-up cost reserve (Note 13)		1,423		1,631
Tax contingency		1,664		2,594
Asset retirement obligation (Note 2)		481		493
Other post employment benefits (Note 6)		—		2,173
Other miscellaneous		1,398		1,892

Total Deferred Credits — other	$	8,129	$	33,070

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(13)		Environmental Reserve

		The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments resulted in increased operating expenses. These increased operating expenses did not have a material impact on the Company’s consolidated financial statements.

		FGT conducts assessment, remediation, and ongoing monitoring of soil and groundwater impact which resulted from its past waste management practices at its Rio Paisano and Station 11 facilities. The anticipated costs over the next five years are: 2007 — $0.2 million, 2008 - $0.3 million, 2009 — $0.1 million, 2010 — $0.2 million and 2011 — $0.3 million. The expenditures thereafter are estimated to be $0.5 million for soil and groundwater remediation. The liability is recognized in other current liabilities and in other deferred credits and in total amounted to $1.6 million and $1.7 million at December 31, 2006 and 2005, respectively. Costs of $0.1 million, $0.8 million and $0.3 million were expensed during the years ended December 31, 2006, 2005 and 2004, respectively. FGT recorded the estimated costs of remediation to be spent after April 1, 2010 of $1.0 million and $1.0 million at December 31, 2006 and 2005, respectively (Note 11), as a regulatory asset based on the probability of recovery in rates in its next rate case.

		Prior to December 31, 2005, no such liability was recognized since it was previously estimated to be less than $1 million, and therefore, considered not to be material. Amounts incurred for environmental assessment and remediation were expensed as incurred.

(14)		Accumulated Other Comprehensive Income

		Deferred gains and (losses) in connection with the termination of the following derivative instruments which were previously accounted for as cash flow hedges form part of other comprehensive income. Such amounts are being amortized over the terms of the hedged debt.

		The table below provides an overview of comprehensive income for the periods indicated.


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	(In thousands)
Interest rate lock on 7.625% $325 million note due 2010	$	1,872		$	1,872		$	1,872
Interest rate swap loss on 7.0% $250 million note due 2012		1,228			1,228			1,229
Interest rate swap gain on 9.19% $150 million note due 2005-2024		(462	)		(462	)		(1,654	)

	$	2,638		$	2,638		$	1,447

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides an overview of the components in accumulated other comprehensive income at the dates indicated.


	Termination	Amortization	Original			December 31,			December 31,
	Date	Period	Gain/(Loss)			2006			2005
			(In thousands)
Interest rate lock on 7.625% $325 million note due 2010	December 2000	10 years	$	(18,724	)	$	(7,334	)	$	(9,206	)
Interest rate swap loss on 7.0% $250 million note due 2012	July 2002	10 years		(12,280	)		(6,807	)		(8,035	)
Interest rate swap gain on 9.19% $150 million note due 2005-2024	November 1994	20 years		9,236			3,617			4,079

						$	(10,524	)	$	(13,162	)

(15)		Commitments and Contingencies

		From time to time, in the normal course of business, the Company is involved in litigation, claims or assessments that may result in future economic detriment. Where appropriate, Citrus has made accruals in accordance with FASB Statement No. 5, Accounting for Contingencies, in order to provide for such matters. Management believes the final disposition of these matters will not have a material adverse effect on the Company’s’ results of operations or financial position.

		The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects in the planning stages that may, over the next ten years, impact one or more of FGT’s mainline pipelines co-located in FDOT/FTE rights-of-way. FGT is currently considering its options relating to the first phase of the turnpike project, which include replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way in Florida. Estimated cost of such replacement would be $110 million. FGT is also in discussions with the FDOT/FTE related to additional projects that may affect FGT’s 18- and 24-inch pipelines within FDOT/FTE right-of-way. The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or right-of-way costs, cannot be determined at this time.

		Under certain conditions, existing agreements between FGT and the FDOT/FTE require the FDOT/FTE to provide any new right-of-way needed for relocation of the pipelines and for FGT to pay for rearrangement or relocation costs. Under certain other conditions, FGT may be entitled to reimbursement for the costs associated with relocation, including construction and right-of-way costs. On April 8, 2005, FGT filed a complaint in the Ninth Judicial Circuit, Orange County, Florida seeking a declaratory judgment order finding, among other things, that FGT has a compensable property interest in certain easements and agreements with the FDOT/FTE, and that FGT is entitled to recover: (i) compensation for any of FGT’s right-of-way to be taken, (ii) costs incurred and to be incurred by FGT for relocation of its pipeline in connection with FDOT/FTE’s changes to State Road 91; and (iii) $5.5 million in expenditures related to a prior relocation project (for which an invoice was presented to FDOT/FTE that FDOT/FTE refused to pay). FGT also sought an order declaring that FDOT/FTE has a duty to avoid conflict at FGT facilities when reasonably possible and to provide sufficient rights-of-way to allow FGT to fully operate, relocate and maintain its facilities in a manner contemplated by the agreements or pay compensation for the loss of FGT’s property rights. On August 15, 2006, FGT also filed a motion for temporary injunction seeking to halt construction pending the trial date, which motion was denied by the court on October 11, 2006. On November 2, 2006, FGT filed to dismiss the action without prejudice. On January 25, 2007, FGT filed a complaint against FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, which seeks relief with respect to three specific sets of FDOT widening projects in Broward County. The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence. Should FGT be denied reimbursement by the FDOT/FTE for any possible relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowing. FGT expects to seek rate recovery at FERC for all reasonable and prudent costs incurred in relocating its pipelines to accommodate the

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		FDOT/FTE to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of reimbursement will fully compensate FGT for its costs.

		FGT and Trading previously filed bankruptcy-related claims against Enron and other affiliated bankrupt companies totaling $220.6 million. Of these claims, FGT and Trading filed claims totaling $68.1 and $152.5 million, respectively. FGT and Enron agreed on the amount of the claim at $13.3 million, and FGT assigned its claims to a third party and received $3.4 million in June 2005. Trading’s claim is for rejection damages on two physical/financial swaps and a gas sales contract, as well as certain delinquent amounts owed pre-petition. In March 2005, Enron North America Corp. (ENA) filed objections to Trading’s claim. In September 2006 the judge issued an order which rejected certain of Trading’s arguments and ruled that a contract under which ENA had an in the money position against Trading may be offset against a related contract under which Trading had an in the money position against ENA. The result of the order is a reduction in the allowable amount of Trading’s initial claim to $22.7 million. The parties have reached a settlement in principle on the amount of the allowed claim which is awaiting a hearing with the Bankruptcy Court for approval.

		On March 7, 2003, Trading filed a declaratory order action, involving a contract between it and Duke Energy LNG Sales, Inc. (Duke). Trading requested that the court declare that Duke breached the parties’ natural gas purchase contract by failing to provide sufficient volumes of gas to Trading. The suit sought damages and a judicial determination that Duke had not suffered a “loss of supply” under the parties’ contract, which could, if it continued, have given rise to the right of Duke to terminate the contract at a point in the future. On April 14, 2003, Duke sent Trading a notice that the contract was terminated as of April 16, 2003 (due to Trading’s alleged failure to timely increase the amount of a letter of credit); although it disagreed with Duke’s position, Trading increased the letter of credit on April 15, 2003. Duke answered and filed a counterclaim, arguing that Trading failed to timely increase the amount of a letter of credit, and that it had breached a “resale restriction” on the gas. Trading disputed that it had breached the agreement, or that any event had given rise to a right to terminate by Duke. On June 2, 2003, Trading notified Duke that, because Duke had defaulted and failed to cure, Trading was terminating the agreement effective as of June 5, 2003. On August 8, 2003, Trading sent its final “termination payment” invoice to Duke in the amount of $187 million, and recorded a receivable of $75 million (subsequently reduced by $6.5 million to $68.5 million to provide for a related settlement, see below). Trading moved for summary judgment and Duke cross-moved on the central issue of whether Duke’s failure to perform was justified under the letter of credit requirements of the agreements. The judge denied the motions from both parties in his ruling dated August 23, 2005 and subsequently ordered the parties to attempt to narrow the scope of the issues to be tried. Pre-trial conferences were held in January 2007, a jury was selected and opening arguments were scheduled. Following the judge’s rulings on certain matters, on January 29, 2007 Citrus reached a settlement with Spectra Energy LNG Sales, Inc, formerly known as Duke Energy LNG Sales, Inc, and its parent company Spectra Energy Corp. (collectively “Spectra”), whereby Spectra agreed to pay $100 million to Citrus. This transaction will result in an approximately $23 million pre-tax ($14 million after-tax) gain realized and subsequently to be recorded in the first quarter 2007.

		Prior to the Enron bankruptcy, Enron North America Corp. (ENA) was the principal counterparty to Trading’s gas purchase and sale agreements (including swaps). ENA has rejected these contracts in bankruptcy. A pre-petition gas purchase payable to ENA of $12.4 million was reversed in 2003 when it was determined that the Company had a right of offset against claims for pre-petition receivables. Pursuant to an existing operating agreement which was rejected by ENA in 2003 but under which an El Paso affiliate performed, an affiliate of El Paso was required to buy gas, purchased from a significant third party that exceeded the requirements of Trading’s existing sales contracts. Under this third party contract, gas was purchased primarily at rates based upon an indexed oil price formula. This gas was then sold primarily at market rates. On April 16, 2003 the significant third party supplier terminated the supply contract. Trading then only purchased the requirements to fulfill existing sales contracts from third parties at market rates. As a result of these developments, the cash flow stream was dependent on variable pricing, whereas before Enron’s bankruptcy, the cash flow stream was fixed (under certain swaps). In June 2004 the Company paid $16.2 million and recorded an accrual for a contingent obligation of up to $6.5 million to terminate a gas sales contract with a third-party, resulting in a net gain totaling $19.9 million. The contingent obligation was extinguished with a payment to the third-party on February 6, 2007 of $6.5 million from proceeds resulting from the settlement of the Duke Energy LNG Sales, Inc. (Duke) litigation.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Southern Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 28^th day of February 2007.


	SOUTHERN NATURAL GAS COMPANY
	By:	/s/ JAMES C. YARDLEY
		James C. Yardley
		Chairman of the Board and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Southern Natural Gas Company and in the capacities and on the dates indicated:


Signature	Title	Date


/s/ JAMES C. YARDLEY	Chairman of the Board and President	February 28, 2007
James C. Yardley	(Principal Executive Officer)

/s/ JOHN R. SULT	Senior Vice President,	February 28, 2007
John R. Sult	Chief Financial Officer and Controller
	(Principal Accounting and Financial Officer)

/s/ DANIEL B. MARTIN Daniel B. Martin	Senior Vice President and Director	February 28, 2007

/s/ NORMAN G. Holmes Norman G. Holmes	Senior Vice President, Chief Commercial Officer and Director	February 28, 2007

SOUTHERN NATURAL GAS COMPANY

EXHIBIT INDEX
December 31, 2006

Each exhibit identified below is a part of this report. Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


Exhibit
Number		Description
3.A		Restated Certificate of Incorporation dated as of March 7, 2002 (Exhibit 3.A to our 2001 Form 10-K).

3.B		By-laws dated as of June 24, 2002. (Exhibit 3.B to our 2002 Form 10-K).

*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.

*4.A.1		First Supplemental Indenture, dated as of September 30, 1997, between Southern Natural Gas Company and the Trustee.

*4.A.2		Second Supplemental Indenture dated as of February 13, 2001, between Southern Natural Gas Company and the Trustee.

4.B		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 (Exhibit 4.1 to our Form 8-K filed March 5, 2003).

10.A		First Tier Receivables Sale Agreement dated October 6, 2006, between Southern Natural Gas Company and SNG Finance Company, L.L.C. (Exhibit 10.A to our Form 8-K filed October 13 , 2006).

10.B		Second Tier Receivables Sale Agreement dated October 6, 2006, between SNG Finance Company, L.L.C. and SNG Funding Company, L.L.C. (Exhibit 10.B to Form 8-K filed October 13, 2006).

10.C		Receivables Purchase Agreement dated October 6, 2006, among SNG Funding Company, L.L.C., as Seller, Southern Natural Gas Company, as Servicer, Starbird Funding Corporation, as the initial Conduit Investor and Committed Investor, the other investors from time to time parties thereto, BNP Paribas, New York Branch, as the initial Managing Agent, the other Managing Agents from time to time parties thereto, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.C to our Form 8-K filed October 13, 2006).

*10.C.1		Amendment No. 1, dated as of December 1, 2006, to the Receivables Purchase Agreement dated as of October 6, 2006, among SNG Funding Company, Southern Natural Gas Company, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent.

21		Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

*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.


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


									Accumulated
					Additional				other			Total
	Common stock				paid-in		Retained		comprehensive			stockholder’s
	Shares		Amount		capital		earnings		income(loss)			equity
January 1, 2004		1,000	$	—	$	340	$	777	$	(8	)	$	1,109
Net income								169					169

December 31, 2004		1,000		—		340		946		(8	)		1,278
Net income								174					174
Other comprehensive income				—		—		—		2			2

December 31, 2005		1,000		—		340		1,120		(6	)		1,454
Net income								184					184
Other comprehensive income				—		—		—		1			1
Adoption of SFAS No. 158, net of income taxes of $2				—		—		—		5			5

December 31, 2006		1,000	$	—	$	340	$	1,304	$	—		$	1,644


	Balance at		Charged to					Charged to			Balance
	Beginning		Costs and					Other			at End
Description	of Period		Expenses		Deductions			Accounts			of Period
2006
Allowance for doubtful accounts	$	1	$	—	$	—		$	(1	)	$	—
Valuation allowance on deferred tax assets		1		—		—			—			1
Legal reserves		2		—		—			—			2
Environmental reserves		—		1		—			—			1

2005
Allowance for doubtful accounts	$	3	$	—	$	—		$	(2	)	$	1
Valuation allowance on deferred tax assets		1		—		—			—			1
Legal reserves		2		—		—			—			2

2004
Allowance for doubtful accounts	$	3	$	—	$	—		$	—		$	3
Valuation allowance on deferred tax assets		1		—		—			—			1
Legal reserves		1		—		—			1			2
Environmental reserves		3		1		(4	)⁽¹⁾		—			—


⁽¹⁾		Primarily payments made for environmental remediation activities.


		Page
Report of Independent Registered Public Accounting Firm		41

Audited Consolidated Financial Statements
Consolidated Balance Sheets		42
Consolidated Statements of Income		43
Consolidated Statements of Stockholders’ Equity		44
Consolidated Statements of Comprehensive Income		44
Consolidated Statements of Cash Flows		45
Notes to Consolidated Financial Statements		46 - 68

(5)		Income Taxes

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

		changes in the funded status (i.e., actuarial gains) as a regulatory liability and not as an adjustment to accumulated other comprehensive income.

		The following table summarizes the impact of adopting Statement No. 158 on the Company’s postretirement plan reported in the Consolidated Balance Sheet at December 31, 2006:


				SFAS 158
				adoption			Post-SFAS
	Pre-SFAS 158			adjustment			158
	(in thousands)
Prepaid postretirement benefit cost (non-current) (Note 11)	$	(721	)	$	3,423		$	2,702
Regulatory asset		1,951			(1,951	)		—
Regulatory liability		—			(1,472	)		(1,472	)