Attached files

file filename
EX-21 - EXHIBIT 21 - SUBSIDIARIES OF SOUTHERN NATURAL GAS COMPANY - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit21.htm
EX-12 - EXHIBIT 12 - RATIO OF EARNINGS TO FIXED CHARGES - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit12.htm
EX-4.C - EXHIBIT 4.C - INDENTURE (03-05-2003) - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit4_c.htm
EX-32.B - EXHIBIT 32.B - 906 CERTIFICATION OF CHIEF FINANCIAL OFFICER - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit32_b.htm
EX-32.A - EXHIBIT 32.A - 906 CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit32_a.htm
EX-31.B - EXHIBIT 31.B - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit31_b.htm
EX-23.A - EXHIBIT 23.A - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (E&Y) (SNG) - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit23_a.htm
EX-23.B - EXHIBIT 23.B - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PWC) (SNG) - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit23_b.htm
EX-31.A - EXHIBIT 31.A - 302 CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER - SOUTHERN NATURAL GAS COMPANY, L.L.C.exhibit31_a.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________
Form 10-K
(Mark One)
R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
For the fiscal year ended December 31, 2009
   
 
OR
   
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
For the transition period from                                                                to
Commission File Number 1-2745
Southern Natural Gas Company
(Exact Name of Registrant as Specified in Its Charter)
Delaware
63-0196650
(State or Other Jurisdiction of
(I.R.S. Employer
Incorporation or Organization)
Identification No.)
   
El Paso Building
 
1001 Louisiana Street
 
Houston, Texas
77002
(Address of Principal Executive Offices)
(Zip Code)
 
Telephone Number: (713) 420-2600
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes £ No R

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £

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

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

Large accelerated filer £
Accelerated filer £
Non-accelerated filer R
(Do not check if a smaller reporting company)
Smaller Reporting Company  £

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

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

Documents Incorporated by Reference: None
 

 

SOUTHERN NATURAL GAS COMPANY
 
 
Caption
Page 
     
   
     
   
     
   
     
   
 
 
Below is a list of terms that are common to our industry and used throughout this document:
 
 
/d
=
per day
LNG
=
liquefied natural gas
 
BBtu
=
billion British thermal units
MMcf
=
million cubic feet
 
Bcf
=
billion cubic feet
Tonne
=
metric ton
 
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.
 


 
 
Overview and Strategy
 
We are a Delaware general partnership, originally formed in 1935 as a corporation. We are owned 75 percent indirectly through a wholly owned subsidiary of El Paso Corporation (El Paso) and 25 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership of El Paso. EPB was formed in November 2007 at which time El Paso contributed 10 percent of its interest in us to EPB. In September 2008, EPB acquired an additional 15 percent ownership interest in us from El Paso.
 
In November 2007, in conjunction with the formation of EPB, we distributed our 50 percent interest in Citrus Corp. (Citrus) and our wholly owned subsidiaries, Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba Express), to El Paso. Citrus owns the Florida Gas Transmission Company, LLC pipeline system and SLNG owns the Elba Island LNG facility. SLNG and Elba Express have been reflected as discontinued operations in our financial statements for periods prior to their distribution. For a further discussion of these discontinued operations, see Part II, Item 8, Financial Statements and Supplementary Data, Note 2. In addition, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes. Accordingly, we settled our then existing current and deferred tax balances through El Paso’s cash management program pursuant to our tax sharing agreement with El Paso.
 
Our pipeline system and storage facilities operate under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.
 
 Our strategy is to enhance the value of our transportation and storage business by:

 
providing outstanding customer service;

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

 
developing new growth projects in our market and supply areas;

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

 
successfully recontracting expiring contracts for transportation capacity or contracting available capacity; and

 
focusing on efficiency and synergies across our system.

Pipeline System. Our pipeline system consists of approximately 7,600 miles of pipeline with a design capacity of 3,700 MMcf/d. During 2009, 2008 and 2007, average throughput was 2,322 BBtu/d, 2,339 BBtu/d and 2,345 BBtu/d. This system extends from supply basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. We are the principal natural gas transporter to the southeastern markets in Alabama, Georgia and South Carolina. Our system is also connected to the Elba Island LNG terminal near Savannah, Georgia. This terminal has a peak send-out capacity of approximately 1.2 Bcf/d.
 
  FERC Approved Projects. As of December 31, 2009, we had the following FERC-approved expansion projects on our system. For a further discussion of our other expansion projects, see Item 7, Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

 
 
Project
 
Capacity
(MMcf/d)
 
 
 
Description
 
Anticipated
Completion or
In-Service Date
 
               
South System III
    370  
To add 81 miles of pipe and 17,310 of horsepower compression on our pipeline facilities.
    2011-2012  
Southeast Supply Header
Phase II
    350  
To add 26,000 of horsepower compression to the jointly owned pipeline facilities.
    2011  
 
Storage Facilities. Along our pipeline system, we own and operate 100 percent of the Muldon storage facility in Monroe County, Mississippi and own a 50 percent interest in and operate the Bear Creek Storage Company, LLC (Bear Creek) in Bienville Parish, Louisiana. Bear Creek provides storage services pursuant to firm contracts to us and Tennessee Gas Pipeline Company, a subsidiary of El Paso, which owns the remaining 50 percent interest. Our interest in Bear Creek and the Muldon storage facilities have a combined working natural gas storage capacity of 60 Bcf and peak withdrawal capacity of 1.2 Bcf/d. We provide storage services to our customers utilizing the Bear Creek and the Muldon storage facilities at our FERC tariff rate.
 
Markets and Competition
 
Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.
 
The southeastern market served by our pipeline is the fastest growing natural gas demand region in the United States. Demand for deliveries from our pipeline is characterized by two peak delivery periods, the winter heating season and the summer cooling season.
 
The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as shale, tight sands, and coal bed methane, is rapidly increasing.  This shift will change the supply patterns and flows on pipelines. The impact will vary among pipelines according to the proximity of the new supply sources. Our pipeline is directly connected to the Haynesville Shale formation in northern Louisiana. Our pipeline is also indirectly connected, through new interconnecting pipelines, to the Barnett Shale, Bossier Sands, Woodford Shale and Fayetteville Shale.  It is likely that natural gas from these sources will increase over time. This will affect the flows on the system and the array of shipper contracts.
 
Imported LNG has been a growing supply sector of the natural gas market. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems may also compete with us for transportation of gas into market areas we serve.
 
Electric power generation has been a growing demand sector of the natural gas market. The growth of natural gas-fired electric power benefits the natural gas industry by creating more demand for natural gas. This potential benefit is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity, 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 transportation contracts with natural gas pipelines.
 
Growth of the natural gas market has been adversely affected by the current economic slowdown in the U.S. and global economies. The decline in economic activity reduced industrial demand for natural gas and electricity, which affected natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. We expect the demand and growth for natural gas to return as the economy recovers. Natural gas has a favorable competitive position as an electric generation fuel because it is a clean and abundant fuel with lower capital requirements compared with other alternatives. The lower demand and the credit restrictions on investments in the recent past may slow development of supply projects. While our pipeline could experience some level of reduced throughput and revenues, or slower development of expansion projects as a result of these factors, we generate a significant (greater than 80 percent) portion of our revenues through fixed monthly reservation or demand charges on long-term contracts at rates stipulated under our tariff or in our contracts.



Our existing transportation and storage contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.
 
We face competition in a number of our key markets and we compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on our system competes 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 our other customers. In addition, we compete with pipelines and gathering systems for connection to new supply sources.
 
Our most direct competitor is Transco, which owns an approximately 10,500-mile pipeline extending from Texas to New York. It has firm transportation contracts with some of our largest customers, including Atlanta Gas Light Company, Alabama Gas Corporation, Southern Company Services, and SCANA Corporation.
 
The following table details our customer and contract information related to our pipeline system as of   December 31, 2009. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.
 
Customer Information
Contract Information
Approximately 270 firm and interruptible customers.
Approximately 200 firm transportation contracts. Weighted average remaining contract term of approximately six years.
   
Major Customers:
Atlanta Gas Light Company(1)
(1,063 BBtu/d)
 
 
Expire in 2013-2024.
   
Southern Company Services
 
(433 BBtu/d)
Expire in 2011-2018.
   
Alabama Gas Corporation
 
(372 BBtu/d)
Expire in 2010-2013.
   
SCANA Corporation
 
(315 BBtu/d)
Expire in 2013-2019.
____________

(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 and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. Generally, the FERC’s authority extends to:

 
rates and charges for natural gas transportation and storage;

 
certification and construction of new facilities;

 
extension or abandonment of services and facilities;

 
maintenance of accounts and records;

 
relationships between pipelines and certain affiliates;

 
terms and conditions of service;

 
depreciation and amortization policies;

 
acquisition and disposition of facilities; and

 
initiation and discontinuation of services.

Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations.

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

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



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

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the 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.

The financial results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volumes of natural gas we are able to transport and store depends on the actions of third parties and are beyond our control. Such actions include factors that impact our customers’ demand and producers’ supply, including factors that negatively impact our customers’ need for natural gas from us, as well as the continued availability of natural gas production and reserves connected to our pipeline system.  Further, the following factors, most of which are also beyond our control, may unfavorably impact our ability to maintain or increase current throughput, or to remarket unsubscribed capacity on our pipeline system:

 
service area competition;

 
price competition;

 
expiration or turn back of significant contracts;

 
changes in regulation and actions of regulatory bodies;

 
weather conditions that impact natural gas throughput and storage levels;

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

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

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

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



 
legislative, regulatory or judicial actions, such as mandatory renewable portfolio standards and greenhouse gas (GHG) regulations and/or legislation that could result in (i) changes in the demand for natural gas and oil, (ii) changes in the availability of or demand for alternative energy sources such as hydroelectric and nuclear power, wind and solar energy and/or (iii) changes in the demand for less carbon intensive energy sources;

 
availability and cost to fund ongoing maintenance and growth projects, especially in periods of prolonged economic decline;

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

 
adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets;
 
 
our ability to achieve targeted annual operating and administrative expenses primarily by reducing internal costs and improving efficiencies from leveraging a consolidated supply chain organization; and
 
 
unfavorable movements in natural gas prices in certain supply and demand areas.

A substantial portion of our revenues are generated from transportation contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. Currently, a substantial portion of our firm transportation contacts are subscribed through 2013. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control as discussed in more detail above. In addition, changes in state regulation of local distribution companies may cause us to negotiate short-term contracts or turn back our capacity when our contracts expire.

In 2009, our contracts with Atlanta Gas Light Company, Southern Company Services, Alabama Gas Corporation and SCANA Corporation represented approximately 28 percent, 11 percent, 10 percent and 8 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.

We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.

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




A portion of our transportation services are provided pursuant to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.

It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated “recourse rate” for that service, and that contract must be filed and accepted by FERC. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation, cost of capital, taxes or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers.

Fluctuations in energy commodity prices could adversely affect our business.

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

We retain a fixed percentage of natural gas received for transportation and storage as provided in our tariff.  This retained natural gas is used as fuel and to replace lost and unaccounted for natural gas.  As calculated in a manner set forth in our tariff, volumes from any excess natural gas retained and not used in operations are to be given back to our customers through lower retention percentages determined on an annual basis. Any under-recoveries will be returned to us through higher percentages determined on an annual basis. If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Consequently, a significant prolonged downturn in natural gas prices could have a material adverse effect on our financial condition, results of operations and liquidity. Fluctuations in energy prices are caused by a number of factors, including:

 
regional, domestic and international supply and demand, including changes in supply and demand due to general economic conditions and weather;

 
availability and adequacy of gathering, processing and transportation facilities;

 
energy legislation and regulation, including potential changes associated with GHG emissions and renewable portfolio standards;

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

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

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




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

Our business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior and various state and local regulatory agencies whose actions 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 and sets authorized rates of return. In January 2010, the FERC approved our settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our next general rate case to be effective after August 31, 2012 but no later than September 1, 2013, and (iv) extended the vast majority of our firm transportation contracts until August 31, 2013.

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

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

Increased regulatory requirements relating to the integrity of our pipeline requires additional spending in order to maintain compliance with the FERC’s requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.

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

In estimating our environmental liabilities, we face uncertainties that include:

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

 
discovering new sites or additional information at existing sites;

 
forecasting cash flow timing to implement proposed pollution control and cleanup costs;

 
receiving regulatory approval for remediation programs;

 
quantifying liability under environmental laws that may impose joint and several liability on potentially responsible parties and managing allocation responsibilities;

 
evaluating and understanding environmental laws and regulations, including their interpretation and enforcement;
 
 
interpreting whether various maintenance activities performed in the past and currently being performed required pre-construction permits pursuant to the Clean Air Act; and
 
 
changing environmental laws and regulations that may increase our costs.
 
In addition to potentially increasing the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards, emission standards with regard to our reciprocating internal combustion engines on our pipeline system, GHG reporting and potential mandatory GHG emissions reductions. Future environmental compliance costs relating to GHGs associated with our operations are not yet clear.  For a further discussion on GHGs, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies.
 
Although it is uncertain what impact legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances or pay taxes related to our GHG and other emissions, and (v) administer and manage an emissions program for GHG and other emissions. Changes in regulations, including adopting new standards for emission controls from certain of our facilities, could also result in delays in obtaining required permits to construct our facilities. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipeline and in the prices at which we sell natural gas, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.
 
Our operations are subject to operational hazards and uninsured risks.
 
Our operations are subject to the inherent risks normally associated with pipeline operations, including pipeline failures, explosions, pollution, release of toxic substances, fires, adverse weather conditions (such as hurricanes and flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses. In addition, although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of GHG could have a negative impact on our operations in the future.
 
While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles as well as limits on our maximum recovery, and do not cover all risks. There is also the risk that our coverages will change over time in light of increased premiums or changes in the terms of the insurance coverages that could result in our decision to either terminate certain coverages, increase our deductibles or decrease our maximum recoveries. In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.




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 and storage 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 the FERC and other regulatory agencies on a timely basis and on terms that are acceptable to us, including the potential impact of delays and increased costs caused by certain environmental and landowner groups with interests along the route of our pipeline;

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

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

 
potential changes in federal, state and local statutes, regulations and orders, such as environmental requirements, including climate change requirements, that delay or 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 or to commence and complete construction on a timely basis or 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, labor, contractor productivity, delays in construction or other factors beyond our control, that we may not be able to recover from our customers which may be material;

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

 
the lack of transportation, storage or throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs.  There is also the risk that the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or we may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.
 
Adverse general domestic economic conditions could negatively affect our operating results, financial condition, or liquidity.
 
We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. The global economy is experiencing a recession and the financial markets have experienced extreme volatility and instability. In response, over the last year, El Paso announced certain actions designed to reduce its need to access such financial markets, including reductions in the capital programs of certain of its operating subsidiaries and the sale of several non-core assets.
 
If we or El Paso experience prolonged periods of recession or slowed economic growth in the U.S., demand growth from consumers for natural gas transported by us may continue to decrease, which could impact the development of our future expansion projects. Additionally, our or El Paso’s access to capital could be impeded and the cost of capital we obtain could be higher. Finally, we are subject to the risks arising from changes in legislation and regulation associated with any such recession or prolonged economic slowdown, including creating preference for renewables, as part of a legislative package to stimulate the economy. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.




We are subject to financing and interest rate risks.

Our future success, financial condition and liquidity could be adversely affected based on our ability to access capital markets and obtain financing at cost effective rates. This is dependent on a number of factors in addition to general economic conditions discussed above, many of which we cannot control, including changes in:

 
our credit ratings;

 
the structured and commercial financial markets;

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

 
market prices for hydrocarbon products.

Risks Related to Our Affiliation with El Paso and EPB

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

We are a majority owned subsidiary of El Paso.

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

 
decisions on our financing and capital raising activities;

 
mergers or other business combinations;

 
our acquisitions or dispositions of assets; and

 
our participation in El Paso’s cash management program.

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

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

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

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

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our and El Paso’s leverage, liquidity, and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital.
 
El Paso provides cash management and other corporate services for us. We are currently required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy any affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.
 
Our relationship with El Paso and EPB subjects us to potential conflicts of interest and they may favor their interests to the detriment of us.
 
Although El Paso has majority control of most decisions affecting our business, there are certain decisions that require the approval of both El Paso and EPB, including material regulatory filings, any significant sale of our assets, mergers and certain changes in affiliated service agreements. Conflicts of interest or disagreements could arise between El Paso and EPB with regard to such matters requiring unanimous approval, which could negatively impact our future operations.
 
 
We have not included a response to this item since no response is required under Item 1B of Form 10K.
 
 
A description of our properties is included in Item 1, Business, and is incorporated herein by reference.
 
We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interest in these properties or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.
 

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.


None.


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

We are required to make distributions to our partners of available cash as defined in our partnership agreement on a quarterly basis from legally available funds that have been approved for payment by our Management Committee. We made cash distributions to our partners of approximately $171 million in 2009 and approximately $200 million in 2008. No dividends or cash distributions were declared or paid in 2007. Additionally, in January 2010, we made a cash distribution of approximately $83 million to our partners.


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

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



 
Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors. We have included a discussion in this MD&A of our business, growth projects, results of operations, liquidity, contractual obligations and critical accounting policies and estimates that may affect us as we operate in the future.

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

Overview

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

 
Type
 
 
Description
 
Percent of Total
Revenues in 2009
Reservation
 
Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.
 
88
         
Usage and Other
 
Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.
 
12

The Federal Energy Regulatory Commission (FERC) regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. In January 2010, the FERC approved our settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our next general rate case to be effective after August 31, 2012 but no later than September 1, 2013, and (iv) extended the vast majority of our firm transportation contracts until August 31, 2013. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather.



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

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

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

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

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

 
Southeast Supply Header.  We own an undivided interest in the northern portion of the Southeast Supply Header project jointly owned by Spectra Energy Corp (Spectra) and CenterPoint Energy, which added 115-mile supply line to the western portion of our system. This project is expected to provide access through pipeline interconnects to several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale basins. The estimated cost to us for Phase II is $69 million and is expected to provide us with an additional 350 MMcf/d of supply capacity. In August 2009, we received a certificate of authorization from the FERC to construct Phase II, which is anticipated to be placed in service in June 2011.
 
We believe that cash flows from operating activities, combined with amounts available to us under El Paso’s cash management program and capital contributions from our partners, will be adequate to meet our capital requirements and our existing operating needs.


Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of both consolidated operations and an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance. We define EBIT as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to our net income, our throughput volumes and an analysis and discussion of our results in 2009 compared with 2008 and 2008 compared with 2007.

Operating Results:

 
 
2009
   
2008
   
2007
 
   
(In millions, except for volumes)
 
Operating revenues
  $ 510     $ 540     $ 482  
Operating expenses
    (255 )     (269 )     (240 )
Operating income
    255       271       242  
Earnings from unconsolidated affiliates
    11       13       88  
Other income, net
    2       10       13  
EBIT(1) 
    268       294       343  
Interest and debt expense
    (62 )     (72 )     (91 )
Affiliated interest income
    2       13       19  
Income tax expense
                (69 )
Income from continuing operations
    208       235       202  
Discontinued operations, net of income taxes
                19  
Net income
  $ 208     $ 235     $ 221  
Throughput volumes (BBtu/d)(2) 
    2,322       2,339       2,345  
____________

(1)
2007 EBIT represents EBIT from continuing operations.
(2)
Throughput volumes include billable transportation throughput volumes for storage injection.

EBIT Analysis:

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

(1)
Consists of individually insignificant items.


 Expansions.  During 2009, the allowance for funds used during construction (AFUDC) has been reduced by approximately $12 million due to lower capital expenditures as compared to 2008. This decrease is primarily attributable to the completion of the Cypress Phase II and Southeast Supply Header Phase I projects placed into service in May 2008 and September 2008. Since we placed Phase I of the Cypress project in service in May 2007 and Phase II of the project in May 2008, we experienced an increased level of revenue throughout 2008 and a decrease in AFUDC on this project in 2008 as compared to 2007. The reduction in AFUDC on the Cypress project during 2008 was partially offset by higher AFUDC related to the construction of Phase I of the Southeast Supply Header, which was placed into service in September 2008.
 
During 2009, BG LNG Services (BG) informed us of their intent not to exercise their option to have us construct the Cypress Phase III expansion. However, BG has made alternative commitments to subscribe to certain other firm capacity on another of El Paso’s pipeline systems and to provide certain rate considerations on its existing transportation contract for Cypress Phases I and II. In August 2009, we received certificates of authorization from the FERC on the South System III and Southeast Supply Header Phase II projects.
 
In addition to our backlog of contracted organic growth projects, we have other projects that are in various phases of commercial development. Many of the potential projects involve expansion capacity to serve increased natural gas-fired generation loads. Although we pursue the development of these potential projects from time to time, there can be no assurance that we will be successful in negotiating the definitive binding contracts necessary for such projects to be included in our backlog of contracted organic growth projects.
 
Service Revenues. During 2009, our service revenue increased primarily due to higher tariff rates placed into service on September 1, 2009 pursuant to our rate case settlement which is further discussed above. During 2008, our service revenues increased primarily due to an increase in our firm transportation revenue offset by lower interruptible services and usage revenue as compared to 2007.
 
Gas Not Used in Operations and Other Natural Gas Sales and Purchases. Prior to September 1, 2009, the financial impacts of our operational gas, net of gas used in operations, was based on the price of natural gas and the amount of natural gas we were allowed to retain and dispose of according to our tariff, relative to the amounts of natural gas we used for operating purposes and the cost of operating our electric compression facilities. Effective September 1, 2009, a volume tracker was implemented as part of our rate case settlement as further discussed below, therefore we no longer share retained gas not used in operations. However, through August 31, 2009, our share of retained gas not used in operations resulted in revenues to us, which were impacted by volumes and prices during a given period. For the year ended December 31, 2009, our operating expense was $22 million lower than in 2008 primarily due to favorable revaluation of retained volumes on our system. Offsetting this favorable impact during the year ended December 31, 2009 was a $15 million reduction in revenue primarily related to favorable sales in 2008. During the year ended December 31, 2008, our EBIT was lower primarily due to higher cost of electric compression on our system and lower gas prices at year end.
 
Calpine Bankruptcy. During 2008, we recognized revenue related to distributions received under Calpine’s approved plan of reorganization.
 
Operating and General and Administrative Expenses. Our operating and general and administrative costs were higher in 2008 than 2007, primarily due to higher repair and maintenance costs and higher allocated costs from El Paso based on the estimated level of resources devoted to us and the relative size of our EBIT, gross property and payroll when compared to El Paso’s other affiliates.
 
Earnings from Citrus. Our operating results for 2007 reflect earnings from Citrus prior to its distribution to El Paso in November 2007 in conjunction with the formation of EPB.
 
Interest and Debt Expense
 
Interest and debt expense for the year ended December 31, 2009, was $10 million lower than in 2008 primarily due to lower average outstanding debt balances resulting from the retirement and repurchases of debt in June and September 2008. Interest and debt expense for the year ended December 31, 2008, was $19 million lower than in 2007 primarily due to lower average outstanding debt balances. For further information on our outstanding debt balances, see Item 8, Financial Statements and Supplementary Data, Note 6.
 
Affiliated Interest Income
 
Affiliated interest income for the year ended December 31, 2009 was $11 million lower than in 2008 and $6 million lower for the year ended December 31, 2008 as compared to 2007 due to lower average advances due from El Paso under its cash management program and lower short-term interest rates. During 2009, the average advances due from El Paso decreased primarily due to debt retirement and repurchases in June and September 2008 with recoveries of our note receivable. The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:

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

Income Taxes

Effective November 1, 2007, we no longer pay income taxes as a result of our conversion into a partnership, which impacted our 2007 effective tax rate. Our effective tax rate of 25 percent for the year ended December 31, 2007, was lower than the statutory rate of 35 percent primarily due to the tax effect of earnings from unconsolidated affiliates that qualify for the dividends received deduction, partially offset by the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 3.


 












Liquidity and Capital Resources

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

Although recent financial conditions have shown signs of improvement, continued volatility in 2010 and beyond in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital.  Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long-term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas. 

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

For further detail on our risk factors including potential adverse general economic conditions including our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A, Risk Factors.

2009 Cash Flow Activities. Our cash flows for the year ended December 31, 2009 are summarized as follows (In millions):
       
Cash Flow from Operations
     
Net income
  $ 208  
Non-cash income adjustments
    56  
Change in other assets and liabilities
    22  
Total cash flow from operations
    286  
         
Cash Inflows
       
Investing activities
       
Proceeds from sale of assets
    41  
         
Cash Outflows
       
Investing activities
       
Additions to property, plant and equipment
    138  
Net change in notes receivable from affiliate
    18  
      156  
Financing activities
       
Distributions to partners
    171  
         
Total cash outflows
    327  
Net change in cash
  $  
 
 
 
 
 
During 2009, we generated $286 million of operating cash flow. We utilized these amounts to fund maintenance of our system as well as pay distributions to our partners. During the year ended December 31, 2009, we paid cash distributions of approximately $171 million to our partners. In addition, in January 2010 we paid a cash distribution to our partners of approximately $83 million. Our cash capital expenditures for the year ended December 31, 2009 and those planned for 2010 are listed below:

 
 
2009
   
Expected
2010
 
   
(In millions)
 
Maintenance
  $ 60     $ 95  
Expansion/Other
    84       249  
Hurricanes(1) 
    (6 )      
Total
  $ 138     $ 344  
____________

(1) Amounts shown are net of insurance proceeds of $9 million in 2009.

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

Contractual Obligations

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

 
 
 
Due in
less than 1 Year
   
Due in
1 to 3 Years
   
Due in
3 to 5 Years
   
Thereafter
   
Total
 
   
(In millions)
 
Long-term debt:
                             
Principal
  $     $     $     $ 911     $ 911  
Interest
    61       123       123       620       927  
                                         
Operating leases
    3       6       6       8       23  
Other contractual commitments and purchase obligations:
                                       
Transportation and storage commitments
    18       9                   27  
Other commitments
    53       15                   68  
Total contractual obligations
  $ 135     $ 153     $ 129     $ 1,539     $ 1,956  

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

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




Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:

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

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

Commitments and Contingencies

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

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

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

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

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

In addition, in March 2009, the EPA proposed a rule impacting emissions from reciprocating internal combustion engines, which would require us to install emission controls on our pipeline system. It is expected that the rule will be finalized in August 2010. As proposed, engines subject to the regulations would have to be in compliance by August 2013. Based upon that timeframe, we would expect that we would commence incurring expenditures in late 2010, with the majority of the work and expenditures incurred in 2011 and 2012. If the regulations are adopted as proposed, we would expect to incur approximately $12 million in capital expenditures over the period from 2010 to 2013.

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

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

Off-Balance Sheet Arrangements

For a discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Notes 7 and 11, which are incorporated herein by reference.





 

Critical Accounting Policies and Estimates
 
The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material impact on our results of operations. For additional information concerning our other accounting policies, see the notes to the financial statements included in Item 8, Financial Statements and Supplementary Data, Note 1.
 
Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standards Board’s accounting standards on rate-regulated operations. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under U.S. generally accepted accounting principles for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of this standard, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.
 
Accounting for Other Postretirement Benefits. We reflect an asset or liability for our postretirement benefit plan based on its over funded or under funded status. As of December 31, 2009, our postretirement benefit plan was under funded by $7 million. Our postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rates used in calculating our benefit obligation. We select our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.
 
    Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligation, along with changes to the plan and other items, are deferred and recorded as either a regulatory asset or liability. A one percent change in our primary assumptions would not have had a significant effect on net postretirement benefit cost. The following table shows the impact of a one percent change to the funded status for the year ended December 31, 2009 (in millions):

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

New Accounting Pronouncements Issued But Not Yet Adopted

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





We are exposed to the risk of changing interest rates. At December 31, 2009, we had a note receivable from El Paso of approximately $154 million, with a variable interest rate of 1.5% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due upon demand and the market-based nature of the interest rate.
 
The table below shows the carrying value, related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities and the fair value of these securities estimated based on quoted market prices for the same or similar issues.

 
 
December 31, 2009
   
December 31, 2008
 
 
 
Expected Fiscal Year of Maturity of
   
 
       
 
 
Carrying Amounts
   
Fair
   
Carrying
   
Fair
 
 
    2009-2013    
Thereafter
   
Total
   
Value
   
Amount
   
Value
 
   
(In millions, except for rate)
 
Liabilities:
                                     
Long-term debt — fixed rate
  $     $ 910     $ 910     $ 977     $ 910     $ 726  
Average effective interest rate
            6.8 %                                
 
 
 
 
 

 




MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by the Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

 
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

 
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

 
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of    December 31, 2009. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of  December 31, 2009.
 
 
 
 
 

 


Report of Independent Registered Public Accounting Firm

The Partners of Southern Natural Gas Company

We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of income and comprehensive income, partners’ capital/stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2009. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The consolidated financial statements of Citrus Corp. and Subsidiaries (a corporation in which the Company had a 50% interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included from Citrus Corp. and Subsidiaries, is based solely on the report of the other auditors, exclusive of the income adjustment related to the disposition of the equity interest in November 2007. In the consolidated financial statements, earnings from the Company’s investment in Citrus Corp. represent approximately 28% of income before income taxes for the year ended December 31, 2007.

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

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Southern Natural Gas Company at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted a new income tax accounting standard, and effective January 1, 2008, the Company adopted the provisions of an accounting standard update related to measurement date and changed the measurement date of its postretirement benefit plan.

/s/ Ernst & Young LLP
Houston, Texas
February 26, 2010



SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In millions)

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


See accompanying notes.



SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions)

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

See accompanying notes.


SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)

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


See accompanying notes.


SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL/STOCKHOLDER’S EQUITY
(In millions, except share amounts)

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

See accompanying notes.



SOUTHERN NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware general partnership, originally formed in 1935 as a corporation.  We are owned 75 percent by El Paso SNG Holding Company, L.L.C., a subsidiary of El Paso Corporation (El Paso) and 25 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (EPB) which is majority owned by El Paso. In conjunction with the formation of EPB in November 2007, we distributed our 50 percent interest in Citrus Corp. (Citrus), our wholly owned subsidiaries Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba Express) to El Paso effective November 21, 2007. Citrus owns the Florida Gas Transmission Company, LLC (FGT) pipeline system and SLNG owns our Elba Island LNG facility. We have reflected the SLNG and Elba Express operations as discontinued operations in our financial statements for periods prior to their distribution. Additionally, effective November 1, 2007, we converted to a general partnership and are no longer subject to income taxes and settled our current and deferred income tax balances through El Paso’s cash management program. For a further discussion of these and other related transactions, see Notes 2, 3 and 11.

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of intercompany accounts and transactions.

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

Use of Estimates

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

Regulated Operations

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

Cash and Cash Equivalents

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


Allowance for Doubtful Accounts

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

Materials and Supplies

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

Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas received on a customer’s contract at the supply point differs from the amount of natural gas delivered under the customer’s transportation contract at the delivery point. We value these 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 natural gas used to resolve shipper imbalances over the course of a year, we have the right under our tariff to recover applicable losses or refund applicable gains through a storage cost reconciliation charge. This charge is applied to volumes as they are transported on our system. Annually, we true-up any losses or gains obtained during the year by adjusting the following years’ storage cost reconciliation charge.

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

Property, Plant and Equipment

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

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar 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 two to 43 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage 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, as defined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements.

At December 31, 2009 and 2008, we had $34 million and $48 million of construction work in progress included in our property, plant and equipment.



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

Asset and Investment Divestitures/Impairments

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

We reclassify assets to be sold in our financial statements as either held-for-sale or from discontinued operations when it becomes probable that we will dispose of the assets within the next twelve months and when they meet other criteria, including whether we will have significant long-term continuing involvement with those assets after they are sold.  We cease depreciating assets in the period that they are reclassified as either held for sale or from discontinued operations, and reflect the results of our discontinued operations in our income statement separtely from those of continuing operations.
 
Cash flows from our discontinued businesses are reflected as discontinued operating, investing, and financing activities in our statement of cash flows. Cash provided by discontinued activities in the operating activities section of our cash flow statement includes all operating cash flows generated by our discontinued businesses during the period. Proceeds from the sale of our discontinued operations are classified in cash provided by discontinued activities in the cash flows from investing activities section of our cash flow statement. To the extent that these operations participated in El Paso’s cash management program, we reflected transactions related to El Paso’s cash management program as financing activities in our cash flow statement. We cease depreciating assets in the period that they are reclassified as either held for sale or as discontinued operations.

Revenue Recognition

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




Environmental Costs and Other Contingencies
 
Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.
 
We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.
 
Other Contingencies.  We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
 
Income Taxes
 
Effective November 1, 2007, we converted to a general partnership in conjunction with the formation of EPB and accordingly, we are no longer subject to income taxes. As a result of our conversion to a general partnership, we settled our then existing current and deferred tax balances with recoveries of note receivables from El Paso under its cash management program pursuant to our tax sharing agreement with El Paso (see Notes 3 and 11). Prior to that date, we recorded current income taxes based on our taxable income and provided for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represented the income tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We accounted for tax credits under the flow-through method, which reduced the provision for income taxes in the year the tax credits first became available. We reduced deferred tax assets by a valuation allowance when, based on our estimates, it was more likely than not that a portion of those assets would not be realized in a future period.

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

Accounting for Asset Retirement Obligations

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




We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells. Our legal obligations primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in estimates based on changes in the expected amount and timing of payments to settle our asset retirement obligations. We intend on operating and maintaining our natural gas pipeline and storage system as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.

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

 
 
2009
   
2008
 
   
(In millions)
 
Net asset retirement obligation at January 1
  $ 20     $  
Accretion expense
    2        
Changes in estimate
    (3 )     20  
Net asset retirement obligation at December 31(1) 
  $ 19     $ 20  
____________

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

Postretirement Benefits

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

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

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

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




New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2009, the following accounting standards had not yet been adopted by us.

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

Variable Interest Entities. In June 2009, the FASB updated accounting standards for variable interest entities to revise how companies determine the primary beneficiaries of these entities, among other changes. Companies will now be required to use a qualitative approach based on their responsibilities and power over the entities’ operations, rather than a quantitative approach in determining the primary beneficiary as previously required.  The adoption of this accounting standard in January of 2010 did not have a material impact on our financial statements.

2. Divestitures

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

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

3. Income Taxes
 
In conjunction with the formation of EPB, we converted our legal structure into a general partnership effective November 1, 2007 and are no longer subject to income taxes. We also settled our then existing current and deferred income tax balances pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program.
 
Components of Income Tax Expense. The following table reflects the components of income tax expesne included in income from continuing operations for the year ended December 31, 2007:
 
       
   
(In millions)
 
Current
     
Federal
  $ 40  
State
    6  
      46  
Deferred
       
Federal
    19  
State
    4  
      23  
Total income taxes
  $ 69  
 
  Effective Tax Rate Reconciliation. Our income tax expense, included in income from continuing operations differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for the year ended December 31, 2007:
   
(In millions, except for rates)
 
Income taxes at the statutory federal rate of 35%
  $ 95  
Increase (decrease)
       
Pretax income not subject to income tax after conversion to partnership
    (11 )
State income taxes, net of federal income tax benefit
    6  
Earnings from unconsolidated affiliates where we anticipate receiving dividends
    (21 )
Income taxes
  $ 69  
Effective tax rate
    25 %

4. Fair Value of Financial Instruments

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

In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:
 
 
2009
   
2008
 
 
 
 
Carrying
Amount
   
Fair
Value
   
Carrying
Amount
   
Fair
Value
 
   
(In millions)
 
Long-term debt, including current maturities
  $ 910     $ 977     $ 910     $ 726  

5. Regulatory Assets and Liabilities

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

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

The significant regulatory assets and liabilities include:

Taxes on Capitalized Funds Used During Construction: These regulatory asset balances were established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets.  Taxes on capitalized funds used during construction are amortized and the offsetting deferred income taxes are included in the rate base.  Both are recovered over the depreciable lives of the long lived asset to which they relate.
Unamortized Net Loss on Reacquired Debt: These amounts represent the deferred and unamortized portion of losses on reacquired debt which are not included in the rate base, but are recovered over the original life of the debt issue through the authorized rate of return.

Postret