SOUTHERN NATURAL GAS CO - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

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 NO. 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 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 [X] 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. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [X]

STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT: .............................NONE

INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.

Common Stock, par value $1 per share. Shares outstanding on March 27,
2003: 1,000

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

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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SOUTHERN NATURAL GAS COMPANY

TABLE OF CONTENTS

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

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

/d = per day
BBtu = billion British thermal units
Bcf = billion cubic feet
Bcfe = billion cubic feet of natural gas equivalent
MMcf = million cubic feet

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

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

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PART I

ITEM 1. BUSINESS

GENERAL

We are a Delaware corporation incorporated in 1935. In October 1999, we
became a wholly owned subsidiary of El Paso Corporation through the merger of
Sonat Inc. with El Paso. Our primary business consists of the interstate
transportation and storage of natural gas. We conduct our business activities
through our natural gas pipeline system, storage facilities and a terminalling
facility, all of which are discussed below.

The Pipeline System. The Southern Natural Gas system consists of
approximately 8,000 miles of pipeline with a design capacity of approximately
2,963 MMcf/d. During 2002, 2001 and 2000, our average throughput was 2,020
BBtu/d, 1,877 BBtu/d and 2,132 BBtu/d. Our interstate pipeline system extends
from natural gas fields in Texas, Louisiana, Mississippi, Alabama and the Gulf
of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South
Carolina and Tennessee, including the metropolitan areas of Atlanta and
Birmingham. We are the principal natural gas supplier to the growing
southeastern markets of Alabama and Georgia.

Under our tariff structure, which is governed by the Federal Energy
Regulatory Commission (FERC), customers pay us on the basis of stated rates for
transportation services. Approximately 92 percent of our transportation revenue
is attributable to a capacity reservation or a demand charge paid by "firm"
customers. These firm customers are obligated to pay a monthly demand charge,
regardless of the amount of natural gas they transport or store, for the term of
their contracts. The remaining 8 percent of our transportation services revenue
is attributable to charges based solely on the volumes of natural gas actually
transported or stored on our pipeline system.

We have several transmission system expansion projects that have been
approved by the FERC as follows:

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(1) Pipeline looping is the installation of a pipeline, parallel to an existing
pipeline, with tie-ins at several points along the existing pipeline.
Looping increases the transmission system's capacity.

Liquefied Natural Gas (LNG) Terminal. Our wholly owned subsidiary,
Southern LNG, owns a liquefied natural gas receiving terminal, located on Elba
Island, near Savannah, Georgia, capable of achieving a peak sendout of 675
MMcf/d and a base load sendout of 446 MMcf/d. In September 2001, we announced
plans to expand the peak sendout capacity of the Elba Island Facility by 540
MMcf/d and the base load sendout by 360 MMcf/d (for a total peak sendout
capacity once completed of 1,215 MMcf/d and a base load sendout of 806 MMcf/d).
The expansion will cost approximately $145 million and has a planned in-service
date of late 2005. The terminal was placed in service following its
recommissioning and began receiving deliveries in December 2001. The current
capacity at the terminal is contracted with our affiliate, El Paso Merchant
Energy, under a contract that extends through 2023.

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

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

REGULATORY ENVIRONMENT

Our interstate natural gas transmission system, storage and terminalling
operations are regulated by the FERC under the Natural Gas Act of 1938 and the
Natural Gas Policy Act of 1978. Our pipeline, LNG terminal and storage
facilities operate under FERC-approved tariffs that establish rates and terms
and conditions for service to our customers. Generally, the FERC's authority
extends to:

- rates and charges for natural gas transportation, storage and
terminalling;

- certification and construction of new facilities;

- extension or abandonment of facilities;

- maintenance of accounts and records;

- relationships between pipeline and marketing affiliates;

- terms and conditions of services;

- depreciation and amortization policies;

- acquisition and disposition of facilities; and

- initiation and discontinuation of services.

The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, and include provisions for a reasonable
return on our invested capital. Consequently, our results have historically been
relatively stable. However, our results can be subject to volatility due to
factors such as weather, changes in natural gas prices and market conditions,
competition, regulatory actions and the credit-worthiness of our customers.

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

We are also subject to regulation over the safety requirements in the
design, construction, operation and maintenance of our interstate natural gas
transmission system and storage facilities by the U.S. Department of
Transportation. Our operations on U.S. government land are regulated by the U.S.
Department of the Interior.

A discussion of our significant rate and regulatory matters is included in
Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is
incorporated herein by reference.

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MARKETS AND COMPETITION

We have approximately 260 firm and interruptible customers, including
natural gas distribution companies and industrial companies, electric generation
companies, natural gas producers, other natural gas pipelines and natural gas
marketing and trading companies. We provide transportation services in both our
natural gas supply and market areas. We have approximately 170 firm
transportation contracts with a weighted average remaining contract term of
approximately five years. Substantially all of the firm transportation capacity
currently available in our two largest market areas is fully subscribed through
mid-2005. Our pipeline system connects with multiple pipelines that provide our
customers with access to diverse sources of supply and various natural gas
markets served by these pipelines.

The following three customers contract for a majority of our firm capacity:

- Atlanta Gas Light Company subscribes to a capacity of 939 MMcf/d under
contracts that expire beginning in 2005 through 2007, with the majority
expiring in 2005.(1)

- Alabama Gas Corporation subscribes to a capacity of 386 MMcf/d under
contracts that expire beginning in 2005 through 2008. In connection with
our pipeline expansions to be placed in service in 2003, all of their
current contracts will extend through 2008.

- Scana Resources subscribes to a capacity of 247 MMcf/d under contracts
that expire beginning in 2003 through 2017. In connection with our
pipeline expansions to be placed in service in 2003, all but 50 MMcf/d of
Scana's current contracts will extend through 2010. Scana's 50 MMcf/d
contract will continue to extend through 2017.
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(1) Atlanta Gas Light Company is currently releasing a significant portion
of its firm capacity to a subsidiary of Scana Resources, Inc. under
terms allowed by our tariff.

All of our firm transportation contracts automatically extend the term for
additional months or years unless notice of termination is given by one of the
parties.

Our interstate natural gas transmission system faces varying degrees of
competition from other pipelines, as well as from alternative energy sources
such as electricity, hydroelectric power, coal and fuel oil. We compete with
other interstate and intrastate pipelines for deliveries to customers who can
take deliveries at multiple connection points. We also compete with other
pipelines and local distribution companies to deliver increased quantities of
natural gas to our market area. In addition, we compete with pipelines and
gathering systems for connection to new supply sources.

Electric power generation is one of the fastest growing demand sectors of
the natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry are currently
unclear. Restructuring and deregulation benefits the natural gas industry by
creating more demand for natural gas turbine generated electric power, but this
effect is offset, in varying degrees, by increased generation efficiency and
more effective use of surplus electric capacity as a result of open market
access.

Imported LNG is one of the fastest growing supply sectors of the natural
gas market. Terminals and other regasification facilities can serve as important
sources of supply for pipelines, enhancing the delivery capabilities and
operational flexibility, and complementing traditional supply and market areas.

Our ability to extend our existing contracts or re-market expiring capacity
is dependent on competitive alternatives, access to capital, the regulatory
environment at the local, state and federal levels and market supply and demand
factors at the relevant dates these contracts are extended or expire. The
duration of new or re-negotiated contracts will be affected by current prices,
competitive conditions and judgments concerning future market trends and
volatility. While we attempt to negotiate contract terms at fully subscribed
quantities and at maximum rates allowed under our tariffs, we must, at times,
discount our rates to remain competitive.

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ENVIRONMENTAL

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

EMPLOYEES

As of March 26, 2003, we had approximately 450 full-time employees, none of
whom is subject to a collective bargaining arrangement.

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ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

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

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

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

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

All of our common stock, par value $1 per share, is owned by El Paso and,
accordingly, there is no public trading market for our stock.

We pay dividends on our common stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.
No common stock dividends were declared or paid in 2002 or 2001.

In March 2003, we declared and paid a $600 million dividend, $310 million
of which was a distribution of outstanding affiliated receivables and $290
million of which was cash.

ITEM 6. SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, has been omitted from this report pursuant
to the reduced disclosure format permitted by General Instruction I to Form
10-K.

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

The information required by this Item is presented in a reduced disclosure
format pursuant to General Instruction I to Form 10-K. The notes to our
consolidated financial statements contain information that is pertinent to the
following analysis, including a discussion of our significant accounting
policies.

GENERAL

Our business consists of interstate natural gas transmission, storage and
terminalling operations. Our interstate natural gas transmission system faces
varying degrees of competition from other pipelines, as well as from alternate
energy sources, such as hydroelectric power, coal and fuel oil. We are regulated
by the FERC, which regulates the rates we can charge our customers. These rates
are a function of our costs of providing services to our customers, and include
a return on our invested capital. As a result, our financial results have
historically been relatively stable. However, they can be subject to volatility
due to factors such as weather, changes in natural gas prices and market
conditions, regulatory actions, competition and the credit-worthiness of our
customers. In addition, our ability to extend existing customer contracts or
re-market expiring contracted capacity is dependent on competitive alternatives,
the regulatory environment and supply and demand factors at the relevant dates
these contracts are extended or expire. We make every attempt to negotiate
contract terms at fully-subscribed quantities and at maximum rates allowed under
our tariffs, although at times, we discount our rates to remain competitive in
particular markets.

RESULTS OF OPERATIONS

We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business. We define EBIT as operating
income, adjusted for equity earnings from unconsolidated affiliates, gains and
losses on sales of assets, an allowance for funds used during construction and
other miscellaneous non-operating items. Items that are not included in this
measure are financing costs, including interest and debt expense, affiliated
interest income, income taxes and extraordinary items. Below is a reconciliation
of operating results to EBIT and to income before extraordinary items for the
year ended December 31:

We believe EBIT is a useful measurement for our investors because it
provides information that can be used to evaluate the effectiveness of our
businesses and investments from an operational perspective, exclusive of the
costs to finance those activities and exclusive of income taxes, neither of
which are directly relevant to the efficiency of those operations. This
measurement may not be comparable to measurements used by other

6

companies and should not be used as a substitute for net income or other
performance measures such as operating cash flow.

OPERATING RESULTS (EBIT)

Operating revenues for the year ended December 31, 2002, were $27 million
higher than in 2001. The increase was primarily due to revenues of $32 million
at our Elba Island facility, which was placed in service following its
recommissioning and began receiving deliveries in December 2001, and revenues of
$8 million from our South System I (Phase I) expansion, which was placed in
service in June 2002. Also contributing to the increase was a $4 million impact
of higher remarketing rates and volumes in 2002 versus 2001 on seasonal
turned-back capacity. These increases were partially offset by $16 million from
lower prices and volumes on sales under natural gas purchase contracts. During
2002, natural gas sold under these contracts was 8 Bcf versus 10 Bcf in 2001,
and our average realized price was $3.15/Bcf versus $4.15/Bcf in 2001. These gas
sales are a result of a remaining gas purchase contract that the FERC allows us
to market at cost. Therefore, these gas sales have no significant effect on our
net results of operations.

Operating expenses for the year ended December 31, 2002, were $2 million
higher than in 2001. The increase was due to higher operating expenses of $13
million and higher depreciation and amortization of $3 million, both due to our
Elba Island facility being in service in 2002. In addition, an increase in ad
valorem and franchise taxes of $2 million in 2002 were due to higher assessed
property values and system additions. These increases were partially offset by
lower purchased natural gas costs of $16 million due to lower prices and volumes
in 2002. During 2002, natural gas volumes purchased under these contracts were 8
Bcf versus 10 Bcf in 2001, and our average gas cost was $3.15/Bcf versus
$4.15/Bcf in 2001.

Other income for the year ended December 31, 2002 was $4 million lower than
in 2001. The decrease was primarily due to $2 million in lower equity earnings
on our Bear Creek investments, a contract termination fee of $2 million received
during 2001 and lower gains of $1 million on sales of non-pipeline assets in
2002 compared to 2001.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the year ended December 31, 2002, was $9
million higher than 2001. Below is the analysis of our interest expense for the
year ended December 31:

The increase in interest expense on long-term debt was due to higher
average debt balances outstanding in 2002 than in 2001. In February 2002, we
issued $300 million aggregate principal amount of 8.0% notes due 2032. This
issuance increased interest on long-term debt by approximately $20 million. We
also retired $200 million of long-term debt resulting in a decrease to interest
expense of approximately $13 million. The remaining increase was primarily due
to a February 2001 debt issuance of $300 million that was outstanding for the
entire year in 2002.

AFFILIATED INTEREST INCOME

Affiliated interest income for the year ended December 31, 2002, was $9
million lower than 2001 due primarily to lower short-term interest rates in
2002, partially offset by increased average advances to El Paso under our cash
management program in 2002. The average short-term interest rate decreased from
4.3% in 2001 to 1.8% in 2002 and average advances to El Paso, under our cash
management program were $460 million in 2002 versus $404 million in 2001.

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INCOME TAXES

Income tax expense for the years ended December 31, 2002 and 2001, was $65
million and $64 million, resulting in effective tax rates of 37 percent for both
years. Our effective tax rates differed from the statutory rate of 35 percent in
both periods primarily due to the impact of state income taxes. For a
reconciliation of the statutory rate of 35 percent to the effective rates, see
Item 8, Financial Statements and Supplementary Data, Note 2.

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

Our liquidity needs are provided by cash flows from operating activities
and the use of a cash management program with our parent company, El Paso. Under
El Paso's cash management program, depending on whether we have short-term cash
surpluses or requirements, we either provide cash to El Paso or El Paso provides
cash to us. We have historically provided cash advances to El Paso, and we
reflect these net advances to our parent as investing activities in our
statement of cash flows. As of December 31, 2002, we had a cumulative net
receivable from El Paso of $430 million as a result of this program. Our
receivables from El Paso are due upon demand. As of December 31, 2002, $61
million of this receivable was classified as current, and the remaining $369
million was classified as non-current notes receivable from affiliates in our
balance sheet. In March 2003, we declared and distributed a dividend of $310
million of our outstanding affiliated receivables to our parent, and we declared
and paid a cash dividend of $290 million. See a further discussion of these
transactions under Recent Events below. We believe that cash flows from
operating activities and cash provided by El Paso's cash management program will
be adequate to meet our short-term capital requirements for existing operations.
Our cash flows for the years ended December 31 were as follows:

In a series of credit rating agency actions in late 2002 and early 2003,
and contemporaneously with the downgrades of the senior unsecured indebtedness
of our parent company, El Paso, our senior unsecured indebtedness was downgraded
to below investment grade and is currently rated B1 by Moody's and B+ by
Standard & Poor's with a negative outlook from both agencies. These downgrades
will increase our cost of capital, collateral requirements and could impede our
access to capital markets in the future.

As a result of the downgrade of El Paso's credit rating to below investment
grade, cash generated within our Bear Creek investment can be used only for
purposes of redeeming the preferred interests of an El Paso financing
arrangement, referred to as Trinity River, that our investment collateralizes
and for its internal cash needs. Until the preferred interests were redeemed in
full, we were not able to receive any cash distributions from our ownership in
Bear Creek. In March 2003, El Paso entered into a $1.2 billion two-year term
loan and the proceeds were used to retire the outstanding balance under the
Trinity River financing agreement.

In August 2002, the FERC issued a notice of proposed rulemaking requiring,
among other things, that FERC regulated entities participating in cash
management arrangements with non-FERC regulated parents maintain a minimum
proprietary capital balance of 30 percent, and that the FERC regulated entity
and its parent maintain investment grade credit ratings, as a condition to
participating in the cash management program. If this proposal is adopted, the
cash management program with El Paso would terminate, which could affect our
liquidity. We cannot predict the outcome of this proposal at this time.

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CAPITAL EXPENDITURES

Our capital expenditures during the periods indicated are listed below:

Under our current plan, we expect to spend between approximately $60
million and $70 million in each of the next three years for capital expenditures
to maintain the integrity of our pipeline and ensure the reliable delivery of
natural gas to our customers. In addition, we have budgeted to spend between
$120 million and $200 million in each of the next three years to expand the
capacity and services of our system for long-term contracts. We expect to fund
our maintenance and expansion capital expenditures through internally generated
funds and by retaining a portion of the proceeds from a 2003 debt offering
discussed below.

DEBT

The following table shows our total long-term debt as of December 31, 2002
(in millions):

6.70% Notes due 2007...................................... $100
6.125% Notes due 2008..................................... 100
7.35% Notes due 2031...................................... 300
8.0% Notes due 2032....................................... 300
----
800
Less: Unamortized discount................................ 2
----
Long-term debt, less current maturities................... $798
====

RECENT EVENTS

In March 2003, we issued an additional $400 million of senior unsecured
notes with an annual interest rate of 8.875%. The net proceeds of $385 million
were used to pay a $290 million dividend to our parent company and $95 million
was retained for future capital expenditures. Annually, we expect the offering
to increase our interest expense by approximately $36 million. We also declared
a $310 million dividend of affiliated receivables from El Paso.

On February 26, 2003, El Paso received a letter from the Office of the
Chief Accountant at the FERC requesting details of our issuance of these notes.
The letter requested that El Paso explain how it intended to use the proceeds
from the offering and if the notes will be included in our capital structure for
ratemaking purposes. The response to the letter was filed on March 12, 2003 and
we fully responded to the request.

Contemporaneously with our issuance of the notes, El Paso contributed its
50 percent interest in Citrus Corp. to us. Citrus is a Delaware corporation that
operates an interstate natural gas pipeline, engages in the sale of natural gas
primarily in Florida and provides construction, operation, maintenance and
financial services. During the two years ended December 31, 2002, and 2001,
equity in the earnings of Citrus were $43 million and $41 million. No cash
distributions were paid by Citrus during this period; however, Citrus has been
expanding its system and using available cash for this purpose.

COMMITMENTS AND CONTINGENCIES

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

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NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES

In July 2002, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 146, Accounting for Costs
Associated with Exit or Disposal Activities. This statement will require us to
recognize costs associated with exit or disposal activities when they are
incurred rather than when we commit to an exit or disposal plan. Examples of
costs covered by this guidance include lease termination costs, employee
severance costs associated with a restructuring, discontinued operations, plant
closings or other exit or disposal activities. This statement is effective for
fiscal years beginning after December 31, 2002, and will impact any exit or
disposal activities we initiate after January 1, 2003.

ACCOUNTING FOR GUARANTEES

In November 2002, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires that
companies record a liability for all guarantees issued after January 31, 2003,
including financial, performance, and fair value guarantees. This liability is
recorded at its fair value upon issuance, and does not affect any existing
guarantees issued before December 31, 2002. While we do not believe there will
be any initial impact of adopting this standard, it will impact any guarantees
we issue in the future.

RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and in good faith,
assumed facts or bases almost always vary from the actual results, and the
differences between assumed facts or bases and actual results can be material,
depending upon the circumstances. Where, in any forward-looking statement, 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 statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate," and similar expressions will
generally identify forward-looking statements. Our forward-looking statements,
whether written or oral, are expressly qualified by these cautionary statements
and any other cautionary statements that may accompany those statements. In
addition, we disclaim any obligation to update any forward-looking statements to
reflect events or circumstances after the date of this report.

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

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RISKS RELATED TO OUR BUSINESS

OUR SUCCESS DEPENDS ON FACTORS BEYOND OUR CONTROL.

Our business is the transportation and storage of natural gas for third
parties. As a result, the volume of natural gas involved in these activities
depends on the actions of those third parties, and is beyond our control.
Further, the following factors, most of which are beyond our control, may
unfavorably impact our ability to maintain or increase current transmission and
storage volumes and rates, to renegotiate existing contracts as they expire, or
to remarket unsubscribed capacity:

- future weather conditions, including those that favor alternative energy
sources;

- price competition;

- drilling activity and supply availability;

- expiration and/or turn back of significant contracts;

- service area competition;

- changes in regulation and actions of regulatory bodies;

- credit risk of customer base;

- increased cost of capital; and

- natural gas and liquids prices.

THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST
BE RENEGOTIATED PERIODICALLY.

Our revenues are generated under transportation contracts which expire
periodically and must be renegotiated and extended or replaced. Although we
actively pursue the renegotiation, extension and/or replacement of these
contracts, we cannot assure you that we will be able to extend or replace these
contracts when they expire or that the terms of any renegotiated contracts will
be as favorable as the existing contracts. Currently, our firm transportation
capacity is fully subscribed through mid-2005 in our largest market areas, but
could be renegotiated at rates below current rates upon the expiration of these
contracts. For a further discussion of these matters, see Part I,
Business -- Markets and Competition.

In particular, our ability to extend and/or replace transportation
contracts could be adversely affected by factors we cannot control, including:

- the proposed construction by other companies of additional pipeline
capacity in markets served by us;

- changes in state regulation of local distribution companies, which may
cause them to negotiate short-term contracts or turn back their capacity
when their contracts expire;

- reduced demand and market conditions;

- the availability of alternative energy sources or gas supply points; and

- regulatory actions.

If we are unable to renew, extend or replace these contracts or if we renew
them on less favorable terms, we may suffer a material reduction in our revenues
and earnings.

WE FACE COMPETITION THAT COULD ADVERSELY AFFECT OUR OPERATING RESULTS.

Our competitors include other major pipeline companies, as well as
participants in other industries supplying and transporting alternative fuels to
industrial, commercial and individual consumers. If we are unable to compete
with services offered by other energy enterprises, our future profitability may
be negatively impacted.

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FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

Revenues generated by our contracts depend on volumes and rates, both of
which can be affected by the prices of natural gas. Increased natural gas prices
could result in loss of load from our customers, such as power companies not
dispatching gas fired power plants, industrial plant shut down or load loss to
competitive fuels and local distribution companies' loss of customer base due to
conversion from natural gas. The success of our operations is subject to
continued development of additional oil and natural gas reserves in the vicinity
of our facilities and our ability to access additional suppliers from
interconnecting pipelines, primarily in the Gulf of Mexico, to offset the
natural decline from existing wells connected to our systems. A decline in
energy prices could precipitate a decrease in these development activities and
could cause a decrease in the volume of reserves available for transmission or
storage on our system. Fluctuations in energy prices are caused by a number of
factors, including:

- regional, domestic and international supply and demand;

- availability and adequacy of transportation facilities;

- energy legislation;

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

- abundance of supplies of alternative energy sources; and

- political unrest among oil-producing countries.

THE AGENCIES THAT REGULATE US AND OUR CUSTOMERS AFFECT OUR PROFITABILITY.

Our pipeline businesses are regulated by the FERC, the U.S. Department of
Transportation, and various state and local regulatory agencies. Regulatory
actions taken by those agencies have the potential to adversely affect our
profitability. In particular, the FERC regulates the rates we are permitted to
charge our customers for our services. If our tariff rates were reduced in a
future rate proceeding, if our volume of business under our currently permitted
rates was decreased significantly or if we were required to substantially
discount the rates for our services because of competition, our profitability
and liquidity could be reduced.

Further, state agencies that regulate our local distribution company
customers could impose requirements that could impact demand for our services.

COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR
ESTIMATES.

Our operations are subject to various environmental laws and regulations.
These laws and regulations obligate us to install and maintain pollution
controls and to clean up various sites at which regulated materials may have
been disposed of or released. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.

It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:

- the uncertainties in estimating clean up costs;

- the discovery of new sites or information;

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

- the nature of environmental laws and regulations; and

- the possible introduction of future environmental laws and regulations.

Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties. For additional
information, see Part II, Item 8, Financial Statements and Supplementary Data,
Note 7.

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OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.

Our operations are subject to the inherent risks normally associated with
those operations, including pipeline ruptures, explosions, pollution, release of
toxic substances, fires and adverse weather conditions, and other hazards, each
of which could result in damage to or destruction of our facilities or damages
to persons and property. In addition, our operations face possible risks
associated with acts of aggression on our assets. If any of these events were to
occur, we could suffer substantial losses.

While we maintain insurance against many of these risks to the extent and
in amounts that we believe are reasonable, our financial condition and
operations could be adversely affected if a significant event occurs that is not
fully covered by insurance.

THREE CUSTOMERS CONTRACT FOR A MAJORITY OF OUR FIRM TRANSPORTATION CAPACITY.

For 2002, contracts with Atlanta Gas Light, Alabama Gas Corporation and
Scana Resources represented approximately 30%, 15% and 10% of our firm
transportation capacity. For additional information, see Part I, Item 1,
Business -- Markets and Competition and Part II, Item 8, Financial Statements
and Supplementary Data, Note 10. The loss of one of these customers or a decline
in its credit-worthiness could adversely affect our results of operations,
financial position and cash flow.

EL PASO MERCHANT ENERGY, AN EL PASO SUBSIDIARY, HAS CONTRACTED FOR ALL EXISTING
FIRM CAPACITY AT THE ELBA ISLAND TERMINAL OWNED AND OPERATED BY SOUTHERN LNG.

All of Southern LNG's existing firm capacity at its Elba Island terminal
has been contracted through November 2023 by an affiliate, El Paso Merchant
Energy (EPME). El Paso has announced its intention to exit non-core businesses
such as the LNG business now operated by EPME. Should El Paso be unsuccessful in
its efforts to sell EPME or its assets to a creditworthy third party or should
El Paso or EPME become subject to bankruptcy or reorganization proceedings,
Southern LNG could suffer a diminution or loss of revenues from EPME for firm
terminalling capacity held by EPME under long-term contract at its Elba Island
terminal.

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

On September 11, 2001, the U.S. was the target of terrorist attacks of
unprecedented scale. Since the September 11th attacks, the U.S. government has
issued warnings that energy assets, including our nation's pipeline
infrastructure, may be a future target of terrorist organizations. These
developments have subjected our operations to increased risks. Any future
terrorist attack on our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our business.

RISKS RELATED TO OUR AFFILIATION WITH EL PASO

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

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 could adversely affect our financial condition, even if we
have not suffered any similar development. The outstanding senior unsecured
indebtedness of El Paso has been downgraded to below investment grade, currently
rated Caa1 by Moody's and B by Standard & Poor's (with a negative outlook at
both agencies), which in turn resulted in a similar downgrading of our
outstanding senior unsecured indebtedness to B1 by Moody's and B+ by Standard &
Poor's (with a negative outlook at both agencies). These downgrades will
increase our cost of

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capital and collateral requirements, and could impede our access to capital
markets. As a result of these recent downgrades, El Paso has realized
substantial demands on its liquidity, which demands have included:

- application of cash required to be withheld from El Paso's cash
management program in order to redeem preferred membership interests at
one of El Paso's minority interest financing structures; and

- cash collateral or margin requirements associated with contractual
commitments of El Paso subsidiaries.

These downgrades may subject El Paso to additional liquidity demands in the
future. These downgrades are a result, at least in part, of the outlook
generally for the consolidated businesses of El Paso and its needs for
liquidity.

In order to meet its short term liquidity needs, El Paso has embarked on
its 2003 Operational and Financial Plan that contemplates drawing all or part of
its availability under its existing bank facilities and consummating significant
asset sales. In addition, El Paso may take additional steps, such as entering
into other financing activities, renegotiating its credit facilities and further
reducing capital expenditures, which should provide additional liquidity. There
can be no assurance that these actions will be consummated on favorable terms,
if at all, or even if consummated, that such actions will be successful in
satisfying El Paso's liquidity needs. In the event that El Paso's liquidity
needs are not satisfied, El Paso could be forced to seek protection from its
creditors in bankruptcy. Such a development could materially adversely affect
our financial condition.

Pursuant to El Paso's cash management program, surplus cash is made
available to El Paso in exchange for an affiliated receivable. In addition, we
conduct commercial transactions with some of our affiliates. As of December 31,
2002, we have net receivables of approximately $421 million from El Paso and its
affiliates. El Paso provides cash management and other corporate services for
us. If El Paso is unable to meet its liquidity needs, there can be no assurance
that we will be able to access cash under the cash management program, or that
our affiliates would pay their obligations to us. However, we might still be
required to satisfy affiliated company payables. Our inability to recover any
intercompany receivables owed to us could adversely affect our ability to repay
our outstanding indebtedness. For a further discussion of those matters, see
Part II, Item 8, Financial Statements and Supplementary Data, Note 12.

WE COULD BE SUBSTANTIVELY CONSOLIDATED WITH EL PASO IF EL PASO WERE FORCED TO
SEEK PROTECTION FROM ITS CREDITORS IN BANKRUPTCY.

If El Paso were the subject of voluntary or involuntary bankruptcy
proceedings, El Paso and its other subsidiaries and their creditors could
attempt to make claims against us, including claims to substantively consolidate
our assets and liabilities with those of El Paso and its other subsidiaries. The
equitable doctrine of substantive consolidation permits a bankruptcy court to
disregard the separateness of related entities and to consolidate and pool the
entities' assets and liabilities and treat them as though held and incurred by
one entity where the interrelationship between the entities warrants such
consolidation. We believe that any effort to substantively consolidate us with
El Paso and/or its other subsidiaries would be without merit. However, we cannot
assure you that El Paso and/or its other subsidiaries or their respective
creditors would not attempt to advance such claims in a bankruptcy proceeding
or, if advanced, how a bankruptcy court would resolve the issue. If a bankruptcy
court were to substantively consolidate us with El Paso and/or its other
subsidiaries, there could be a material adverse effect on our financial
condition and liquidity.

ONGOING LITIGATION AND INVESTIGATIONS REGARDING EL PASO COULD SIGNIFICANTLY
ADVERSELY AFFECT OUR BUSINESS.

On March 20, 2003, El Paso entered into an agreement in principle (the
Western Energy Settlement) with various public and private claimants, including
the states of California, Washington, Oregon, and Nevada, to resolve the
principal litigation, claims, and regulatory proceedings against El Paso and its
subsidiaries relating to the sale or delivery of natural gas and electricity
from September 1996 to the date of the Western Energy Settlement. A more
detailed description of the Western Energy Settlement can be found

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in El Paso's reports filed with the SEC. If El Paso is unable to negotiate
definitive settlement agreements, or if the settlement is not approved by the
courts or the FERC, the proceedings and litigation will continue.

Since July 2002, twelve purported shareholder class action suits alleging
violations of federal securities laws have been filed against El Paso and
several of its officers. Eleven of these suits are now consolidated in federal
court in Houston before a single judge. The suits generally challenge the
accuracy or completeness of press releases and other public statements made
during 2001 and 2002. The twelfth shareholder class action lawsuit was filed in
federal court in New York City in October 2002 challenging the accuracy or
completeness of El Paso's February 27, 2002 prospectus for an equity offering
that was completed on June 21, 2002. It has since been dismissed, in light of
similar claims being asserted in the consolidated suits in Houston. Four
shareholder derivative actions have also been filed. One shareholder derivative
lawsuit was filed in federal court in Houston in August 2002. This derivative
action generally alleges the same claims as those made in the shareholder class
action, has been consolidated with the shareholder class actions pending in
Houston and has been stayed. A second shareholder derivative lawsuit was filed
in Delaware State Court in October 2002 and generally alleges the same claims as
those made in the consolidated shareholder class action lawsuit. A third
shareholder derivative suit was filed in state court in Houston in March 2002,
and a fourth shareholder derivative suit was filed in state court in Houston in
November 2002. The third and fourth shareholder derivative suits both generally
allege that manipulation of California gas supply and gas prices exposed El Paso
to claims of antitrust conspiracy, FERC penalties and erosion of share value. At
this time, El Paso has not been formally served with this lawsuit. At this time,
El Paso's legal exposure related to these lawsuits and claims is not
determinable.

Another action was filed against El Paso in December 2002, on behalf of
participants in El Paso's 401(k) plan.

If El Paso does not prevail in these cases (or any of the other litigation,
administrative or regulatory matters disclosed in El Paso's 2002 Form 10-K to
which El Paso is, or may be, a party), and if the remedy adopted in these cases
substantially impairs El Paso's financial posture, the long-term adverse impact
on El Paso's credit rating, liquidity and its ability to raise capital to meet
its ongoing and future investing and financing needs could be substantial. Such
a negative impact on El Paso could have a material adverse effect on us as well.

THE PROXY CONTEST INITIATED BY SELIM ZILKHA TO REPLACE EL PASO'S BOARD OF
DIRECTORS COULD HAVE A MATERIAL ADVERSE EFFECT ON US.

On February 18, 2003, Selim Zilkha, a stockholder of El Paso, announced his
intention to initiate a proxy solicitation to replace El Paso's entire board of
directors with his own nominees, and on March 11, 2003, Mr. Zilkha filed his
preliminary proxy statement to that effect with the SEC. This proxy contest may
be highly disruptive and may negatively impact El Paso's ability to achieve the
stated objectives of its 2003 Operational and Financial Plan. In addition, El
Paso may have difficulty attracting and retaining key personnel until such proxy
contest is resolved. Therefore, this proxy contest, whether or not successful,
could have a material adverse effect on El Paso's liquidity and financial
condition, which, in turn, could adversely affect our liquidity and financial
position.

WE ARE A WHOLLY OWNED SUBSIDIARY OF EL PASO.

El Paso has substantial control over:

- our payment of dividends;

- decisions on our financings and our capital raising activities;

- mergers or other business combinations;

- our acquisitions or dispositions of assets; and

- our participation in El Paso's cash management program.

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

RISKS RELATED TO OUR LONG-TERM DEBT

OUR SUBSTANTIAL LONG-TERM DEBT COULD IMPAIR OUR FINANCIAL CONDITION AND OUR
ABILITY TO FULFILL OUR DEBT OBLIGATIONS.

We have substantial long-term debt. As of March 5, 2003, we had total
long-term debt of approximately $1.2 billion, all of which was senior unsecured
long-term indebtedness.

Our substantial long-term debt could have important consequences. For
example, it could:

- make it more difficult for us to satisfy our obligations with respect to
our long-term debt, which could in turn result in an event of default on
any or all of such long-term debt;

- impair our ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions, general corporate
purposes or other purposes;

- diminish our ability to withstand a downturn in our business or the
economy generally;

- require us to dedicate a substantial portion of our cash flow from
operations to debt service payments, thereby reducing the availability of
cash for working capital, capital expenditures, acquisitions, general
corporate purposes or other purposes;

- limit our flexibility in planning for, or reacting to, changes in our
business and the industry in which we operate; and

- place us at a competitive disadvantage compared to our competitors that
have proportionately less debt.

If we are unable to meet our debt service obligations, we could be forced
to restructure or refinance our long-term debt, seek additional equity capital
or sell assets. We may be unable to obtain financing or sell assets on
satisfactory terms, or at all.

Covenants applicable to our long-term debt will allow us to incur
significant amounts of additional indebtedness. Our incurrence of significant
additional indebtedness would exacerbate the negative consequences mentioned
above, and could adversely affect our ability to repay our long-term debt.

OUR LONG-TERM DEBT IS SUBJECT TO CROSS-ACCELERATION PROVISIONS.

It is an event of default in the indentures governing our long-term debt if
we fail to pay principal or interest on any of our indebtedness with an
outstanding principal amount that exceeds a specified threshold (which in the
provisions applicable to the notes we issued in March 2003 is set at $25 million
and in the provisions applicable to our other long-term debt is set at $10
million), and such indebtedness could be accelerated as a result of such missed
payment, or if we otherwise default in compliance with the terms of any such
indebtedness, and the default results in acceleration of such indebtedness. If
this were to occur, all of our long-term debt would be subject to possible
acceleration, and we may not be able to repay all such long-term debt upon such
acceleration.

OUR LONG-TERM DEBT IS EFFECTIVELY SUBORDINATED TO LIABILITIES AND INDEBTEDNESS
OF OUR SUBSIDIARIES.

Our long-term debt is not guaranteed by our subsidiaries and our
subsidiaries are not prohibited under our indentures from incurring additional
indebtedness. As a result, holders of our long-term debt will be effectively
subordinated to claims of third party creditors, including holders of
indebtedness, of these subsidiaries. Claims of those other creditors, including
trade creditors, secured creditors, governmental authorities, and holders of
indebtedness or guarantees issued by the subsidiaries, will generally have
priority as to the assets of the subsidiaries over claims by the holders of our
long-term debt. As a result, rights of payment of holders of our

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indebtedness, including the holders of our long-term debt, will be effectively
subordinated to all those claims of creditors of our subsidiaries.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk is exposure to changing interest rates. The table
below shows the carrying value and related weighted average interest rates of
our interest bearing securities, by expected maturity dates, and the fair value
of those securities. As of December 31, 2002, the fair values of our fixed rate
long-term debt securities have been estimated based on quoted market prices for
the same or similar issues.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)

See accompanying notes.

18

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.

19

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)

See accompanying notes.

20

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.

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SOUTHERN NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. Our financial statements for prior
periods include reclassifications that were made to conform to the current year
presentation. Those reclassifications had no impact on reported net income or
stockholder's equity.

Principles of Consolidation

We consolidate entities when we have the ability to control the operating
and financial decisions and policies of that entity. Where we can exert
significant influence over, but do not control, those policies and decisions, we
apply the equity method of accounting. We use the cost method of accounting
where we are unable to exert significant influence over the entity. The
determination of our ability to control or exert significant influence over an
entity involves the use of judgment of the extent of our control or influence
and that of the other equity owners or participants of the entity.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally
accepted accounting principles 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.

Accounting for Regulated Operations

Our natural gas system, storage and terminalling operations are subject to
the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and
the Natural Gas Policy Act of 1978, and we apply the provisions of SFAS No. 71
Accounting for the Effects of Certain Types of Regulation to these businesses.
Accounting requirements for regulated businesses can differ from the accounting
requirements for non-regulated businesses. Transactions that have been recorded
differently as a result of regulatory accounting requirements include the
capitalization of an equity return component on regulated capital projects,
employee related benefits and other costs and taxes included in, or expected to
be included in, future rates.

Our application of SFAS No. 71 is based on the current regulatory
environment and our current tariff rates. Future regulatory developments, rate
cases and market conditions could impact our continued application of these
guidelines. We will continue to evaluate the application of the accounting
principles under SFAS No. 71 based on on-going changes in the regulatory and
economic environment. Things that may influence our assessment are:

- inability to recover cost increases due to rate caps and rate case
moratoriums;

- inability to recover capitalized costs, including an adequate return on
those costs through the ratemaking process;

- excess capacity;

- discounting rates in the markets we serve; and

- impacts of ongoing initiatives in, and deregulation of, the natural gas
industry.

Cash and Cash Equivalents

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

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Allowance for Doubtful Accounts

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

Materials and Supplies

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

Natural Gas Imbalances

Natural gas imbalances generally occur when the actual amount of natural
gas received on a customer's contract at the supply point differs from the
actual amount of natural gas delivered under the customer's transportation
contract at the delivery point. We value imbalances due to or from shippers at
specified index prices set forth in our tariff based on the production month in
which the imbalances occur. Customer imbalances are aggregated and netted (by
customer) on a monthly basis, and settled in cash, subject to the terms of our
tariff. For differences in value between the amounts we pay or receive for the
purchase or sale of gas used to resolve shipper imbalances over the course of a
year, we have the right under our tariff to recover applicable losses through a
storage cost reconciliation charge. This charge is applied to all volumes
transported on our system. We are obligated annually to true-up any losses or
gains obtained during the course of each year in calculating the following
years' storage cost reconciliation charge.

Imbalances due from others are reported in our balance sheet as either
accounts receivable from customers or accounts receivable from affiliates.
Imbalances owed to others are reported on the balance sheet as either trade
accounts payable or accounts payable to affiliates. In addition, we classify all
imbalances as current.

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. We
capitalize direct costs, such as labor and materials and indirect costs, such as
overhead, interest and an equity return component for our regulated businesses
as allowed by the FERC. We capitalize the 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 other
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
one to 20 percent. Using these rates, the remaining depreciable lives of these
assets range from one to 57 years. We re-evaluate depreciation rates each time
we file with the FERC for a change in our transportation and storage service
rates.

When we retire property, plant and equipment, we charge accumulated
depreciation and amortization for the original cost, plus the cost to remove,
sell or dispose, less its salvage value. We do not recognize a gain or loss
unless we sell an entire operating unit. We include gains or losses on
dispositions of operating units in income. On non-regulated property, plant and
equipment, we record a gain or loss in income for the difference between the net
book value relative to proceeds received, if any, when the asset is sold or
retired.

At December 31, 2002 and 2001, we had approximately $126 million and $71
million of construction work in progress included in our property, plant and
equipment.

As a FERC-regulated company, we capitalize a carrying cost (an allowance
for funds used during construction) on funds invested in 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

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calculated based on our average cost of debt. Debt amounts capitalized during
the years ended December 31, 2002, 2001 and 2000, were $2 million, $2 million
and $1 million. These amounts are included as an offset to interest expense in
our income statement. The equity portion is calculated using the most recent
FERC approved equity rate of return. Equity amounts capitalized during the years
ended December 31, 2002, 2001 and 2000 were $5 million, $5 million and $2
million (exclusive of any tax related impacts). These amounts are included as
other non-operating income on our income statement. Capitalized carrying costs
for debt and equity are reflected as an increase in the cost of the asset on our
balance sheet.

Asset Impairments

We apply the provisions of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets to account for asset impairments. Under this
standard, we evaluate an asset for impairment when events or circumstances
indicate that a long-lived asset's carrying value may not be recovered. These
events include market declines, changes in the manner in which we intend to use
an asset or decisions to sell an asset and adverse changes in the legal or
business environment such as adverse actions by regulators. At the time we
decide to exit an activity or sell a long-lived asset or group of assets, we
adjust the carrying value of those assets downward, if necessary, to the
estimated sales price, less costs to sell. We also classify these assets as
either held for sale or as discontinued operations, depending on whether they
have independently determinable cash flows.

Revenue Recognition

Our revenues are generated from transportation and storage services and
sales under natural gas sales contracts. For our transportation and storage
services, we recognize reservation revenues on firm contracted capacity ratably
over the contract period. For interruptible or volumetric based transportation
services, we recognize revenues when we complete the delivery of natural gas to
the agreed upon delivery point and, for storage services, when gas is injected
or withdrawn from the storage facility. Finally, on natural gas sales contracts,
we recognize revenues when we physically deliver gas to an agreed upon delivery
point. Revenues in all services are generally based on the thermal quantity of
gas delivered or subscribed at a price specified in the contract. We are subject
to FERC regulations and, as a result, a portion of revenues we collect may
possibly be refunded in a final order of a pending rate proceeding or as a
result of a rate settlement.

Environmental Costs and Other Contingencies

We record liabilities when our environmental assessments indicate that
remediation efforts are probable, and the costs can be reasonably estimated. We
recognize a current period expense for the liability when the clean-up efforts
do not benefit future periods. We capitalize costs that benefit more than one
accounting period, except in instances where separate agreements or legal and
regulatory guidelines dictate otherwise. Estimates of our liabilities are based
on currently available facts, existing technology and presently enacted laws and
regulations taking into account the likely effects of inflation and 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. These estimates are subject to
revision in future periods based on actual costs or new circumstances and are
included in our balance sheet in other current and long-term liabilities at
their undiscounted amounts. We evaluate recoveries from insurance coverage, rate
recovery, government sponsored and other programs separately from our liability
and, when recovery is assured, we record and report an asset separately from the
associated liability in our financial statements.

We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that an asset has been
impaired or that a liability has been incurred and the amount of impairment or
loss can be reasonably estimated. Funds spent to remedy these contingencies are
charged against a reserve, if one exists, or expensed. When a range of probable
loss can be estimated, we accrue the most likely amount or at least the minimum
of the range of probable loss.

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Income Taxes

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

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

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

Accounting for Costs Associated with Exit or Disposal Activities. In July
2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. This statement will require us to recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. Examples of costs covered by this
guidance include lease termination costs, employee severance costs associated
with a restructuring, discontinued operations, plant closings or other exit or
disposal activities. This statement is effective for fiscal years beginning
after December 31, 2002, and will impact any exit or disposal activities we
initiate after January 1, 2003.

Accounting for Guarantees. In November 2002, the FASB issued FIN No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires that
companies record a liability for all guarantees issued after January 31, 2003,
including financial, performance, and fair value guarantees. This liability is
recorded at its fair value upon issuance, and does not affect any existing
guarantees issued before December 31, 2002. While we do not believe there will
be any initial impact of adopting this standard, it will impact any guarantees
we issue in the future.

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2. INCOME TAXES

The following table reflects the components of income tax expense included
in income before extraordinary items for each of the three years ended December
31:

Our income tax expense included in income before extraordinary items
differs from the amount computed by applying the statutory federal income tax
rate of 35 percent for the following reasons for each of the three years ended
December 31:

The following are the components of our net deferred tax liability as of
December 31:

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Under El Paso's tax accrual policy, we are allocated the tax benefit
associated with our employees' exercise of non-qualified stock options and the
vesting of restricted stock as well as restricted stock dividends. This
allocation reduced taxes payable by $1 million in 2002 and by $3 million in 2001
and 2000. These benefits are included in additional paid-in capital in our
balance sheet.

As of December 31, 2002, we had $1 million of general business credit
carryovers, $1 million of charitable contribution carryovers and $16 million of
net operating loss carryovers. The carryover period for the general business
credits ends at various times from 2009 through 2017. The carryover period for
the contribution carryover ends at various times from 2004 through 2005. The
carryover period for the net operating loss ends as follows -- $14 million in
2018, $1 million in 2019 and $1 million in 2021. Usage of these carryovers is
subject to the limitations provided under Sections 382 and 383 of the Internal
Revenue Code as well as the separate return limitation year rules of IRS
regulations. We have recorded a valuation allowance to reserve for the deferred
tax asset related to our general business credits.

3. EXTRAORDINARY ITEMS

In March 2000, we sold Sea Robin Pipeline Company to comply with a Federal
Trade Commission (FTC) order related to our former parent company's merger with
El Paso. Net proceeds from this sale were $71 million and we recognized an
extraordinary gain of $12 million, net of income taxes of $9 million. We treated
this gain as an extraordinary item to be consistent with El Paso's presentation
of this gain, since the El Paso merger with Sonat was accounted for as a pooling
of interests. In May 2000, we also disposed of our one-third interest in Destin
Pipeline Company to comply with the same FTC order. Net proceeds from this sale
were $159 million and no material gain or loss was recognized.

4. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

As of December 31, 2002 and 2001, the carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term maturity of these
instruments.

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

- ---------------

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

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5. REGULATORY ASSETS AND LIABILITIES

Our non-current regulatory assets are included in regulatory assets, and
non-current liabilities are included in non-current other liabilities. These
balances are presented in our balance sheets on a gross basis. Below are the
details of our regulatory assets and liabilities at December 31:

- ---------------
(1) Amounts are recovered over the remaining depreciable lives of property,
plant and equipment.

(2) These amounts are not included in our rate base on which we earn a
current return.

6. LONG-TERM DEBT

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

Aggregate maturities of the principal amounts of long-term debt for the
next 5 years and in total thereafter are as follows:

We have cross-acceleration provisions that, if triggered, could result in
the acceleration of our long-term debt.

In January 2002, we repaid $100 million of our 7.85% notes due 2002. In
February 2002, we issued $300 million aggregate principal amount of 8.0% notes,
due 2032. Proceeds were approximately $297 million, net of issuance costs. In
May 2002, we repaid $100 million of our 8.625% notes due 2002.

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In March 2003, we issued $400 million of unsecured senior notes with an
annual interest rate of 8.875%. The notes mature in 2010. Net proceeds were used
to pay a cash dividend to our parent of approximately $290 million, while $95
million was retained for future capital expenditures.

Other Financing Arrangement

During 1999, El Paso formed Sabine Investors, L.L.C., a wholly owned
limited liability company, and other separate legal entities (collectively,
these are referred to as the Trinity River financing arrangement), for the
purpose of generating funds for El Paso to invest in capital projects and other
assets. The proceeds from the financing transaction were collateralized by
various assets of our parent, including our 50 percent ownership interest in
Bear Creek.

TSC, our affiliate, owns the remaining 50 percent interest in Bear Creek.
Bear Creek has not made any cash dividend distributions since 1999. As a result
of the downgrades of El Paso's credit rating below investment grade, Bear
Creek's cash can be used only for purposes of redeeming the preferred membership
interests that Sabine issued at the time it was formed, and for Bear Creek's
operating needs. Accordingly, until the preferred membership interests were
redeemed in full, we were not able to receive any cash distributions from our
ownership interest in Bear Creek. Bear Creek's estimated operating cash flow for
the year ended December 31, 2002, was $26 million. In March 2003, El Paso
entered into a $1.2 billion two-year term loan and the proceeds were used to
retire the outstanding balance under the Trinity River arrangement.

7. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, we and a number of our affiliates were named defendants
in actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value of
natural gas produced from royalty properties been differently measured,
analyzed, calculated and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the defendants to
adopt allegedly appropriate gas measurement practices. No monetary relief has
been specified in this case. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming, filed June 1997). In May 2001, the court denied the
defendants' motions to dismiss. Discovery is proceeding. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

Will Price (formerly Quinque). We and a number of our affiliates were
named defendants in Quinque Operating Company, et al v. Gas Pipelines and Their
Predecessors, et al, filed in 1999 in the District Court of Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with
prejudgment and postjudgment interest, punitive damages, treble damages,
attorney's fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. Plaintiff's motion for class
certification has been argued and we are awaiting a ruling. Our costs and legal
exposure related to this lawsuit and claims are not currently determinable.

Key. We were named as a defendant in Randall Key v. LAI Contractors, Inc.,
et al., filed in 2002 in the Jefferson County Circuit Court in Jefferson County,
Alabama. The plaintiff, an employee of a contractor, suffered paralysis as a
result of a coupling failure during a pipeline repressuration in May 2002. The
plaintiff is seeking compensatory and punitive damages against us and two other
defendants. We are pursuing
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contribution and indemnity from the contractor or its insurers. Our costs and
legal exposure related to this lawsuit and claims are not currently
determinable.

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

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of December 31, 2002, we had no accruals for our outstanding legal matters.

Environmental Matters

We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of December
31, 2002, we had accrued approximately $4 million for expected remediation costs
and associated onsite, offsite and groundwater technical studies and for related
environmental legal costs, which we anticipate incurring through 2027. Below is
a reconciliation of our environmental remediation liabilities as of December 31,
2001 to our liabilities as of December 31, 2002 (in millions):

In addition, we expect to make capital expenditures for environmental
matters of approximately $5 million in the aggregate for the years 2003 through
2007. These expenditures primarily relate to compliance with clean air
regulations. For 2003, we estimate that our total remediation expenditures will
be approximately $4 million, which primarily will be expended under government
directed clean-up plans.

CERCLA Matters. We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to one active site under the
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or
state equivalents. We are currently evaluating our potential share, if any, of
the remediation costs.

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

Rates and Regulatory Matters

Order No. 637. In February 2000, the FERC issued Order No. 637. Order 637
impacts the way pipelines conduct their operational activities, including how
they release capacity, segment capacity and manage imbalance services,
operational flow orders and pipeline penalties. In July 2001, we filed a
settlement addressing our compliance with Order No. 637 and we received an order
on the settlement from the FERC in April 2002. The FERC approved our settlement,
subject to modifications related to our capacity segmentation proposal, and
rejected our proposed changes to our cash-out mechanism. In response, we sought
a rehearing

30

and have made another compliance filing. We cannot predict the outcome of the
compliance filing or the request for rehearing.

Elba Island. In March 2000, the FERC issued an order which authorized the
recommissioning of our Elba Island LNG receiving terminal near Savannah,
Georgia. In July 2001, the FERC issued a final order approving a modification of
the sendout facilities at the terminal subject to several conditions. In October
2001, we received an initial cargo of LNG in order to test the facilities, and
also applied to increase Elba Island's initial rates to reflect an increase in
capital and expenses, primarily associated with expenditures mandated by the
FERC. In November 2001, the FERC authorized us to commence service, but denied
our request to amend the initial rates, indicating that the increase should be
filed in a separate limited proceeding. In December 2001, we filed the limited
proceeding with the FERC, and received an order accepting the new rates
effective March 1, 2002, subject to refund. On October 10, 2002, the FERC
approved a settlement that permits us to track certain dredging costs but
otherwise preserves the filed rates that became effective on March 1, 2002. In
January 2003, we filed to increase the dredging tracker. The FERC accepted this
increase in an order issued February 26, 2003.

Elba Island LNG Expansion. On May 31, 2002, we applied to expand the Elba
Island LNG terminal based on an agreement for new firm terminalling service we
entered into with Shell NA LNG in December 2001. This expansion adds a new
marine slip, a fourth storage tank with a capacity of 3.3 Bcfe, and new pumps
and vaporizers that increase the design sendout rate from 446 MMcf/d to 806
MMcf/d and the maximum sendout rate from 675 MMcf/d to 1,215 MMcf/d. On November
20, 2002, the FERC issued a Preliminary Determination on Nonenvironmental Issues
authorizing the proposed expansion, subject to completion of a favorable
environmental assessment. Marathon Oil Company filed a request for rehearing on
December 18, 2002, which raised issues concerning the potential adverse impact
of the proposed expansion on existing customers. This application and request
for rehearing remain pending before the FERC.

South System I Expansion. In May 2000, we applied to expand our pipeline
system by 336 million cubic feet per day (MMcf/d), at an estimated cost of $146
million, to serve new power generation loads being sited adjacent to our south
system. We received a certificate order from the FERC in March 2001. In July
2001, the FERC approved an amendment to the South System I Expansion, which
reduced its cost slightly. The first phase of the new facilities was completed
and placed in-service in June 2002. The Alabama Municipal Distributors Group and
others filed appeals of the FERC's orders authorizing this project in the United
States Court of Appeals for the D.C. Circuit; which dismissed the appeal for
want of jurisdiction on December 17, 2002.

South System II Expansion. In October 2001, we applied with the FERC to
expand our south system by 360 MMcf/d at an estimated cost of $246 million, to
serve existing, new and expanded gas-fired electric generation facilities. Two
shippers requested a delay in the commencement of their services and one shipper
requested to reduce service quantity. As a result, in April 2002, we filed an
amendment to the certificate application to reflect these changes. On September
20, 2002, the FERC issued a certificate authorizing the project, as modified.

On November 18, 2002, we filed a petition to amend the September 20 order
to change the construction schedule to three phases and to provide for the joint
ownership of the Port Wenworth meter station. On February 5, 2003, the FERC
denied a request for rehearing of the September 20 order. On February 28, 2003,
the FERC granted our requested amendment. Construction will now be completed in
three phases for this expansion.

Termination of Blanket Marketing Authority. Contemporaneously with our
issuance of notes in March 2003, El Paso contributed its 50% interest in Citrus
Corporation to us. Enron owns the other 50% interest. On March 26, 2003, the
FERC issued an order directing Citrus Trading Corporation (CTC), a direct
subsidiary of Citrus Corporation, to show cause, in a proceeding initiated by
the order, why the FERC should not terminate CTC's blanket marketing
certificates by which CTC is authorized to make sales for resale at negotiated
rates in interstate commerce of natural gas subject to the Natural Gas Act of
1938.

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between
31

interstate pipelines and marketing affiliates to all energy affiliates. The
proposed regulations, if adopted by the FERC, would dictate how we conduct
business and interact with our energy affiliates. In December 2001, we filed
comments with the FERC addressing our concerns with the proposed rules. A public
hearing was held on May 21, 2002, providing an opportunity to comment further on
the NOPR. Following the conference, additional comments were filed by El Paso's
pipelines and others. At this time, we cannot predict the outcome of the NOPR,
but adoption of the regulations in their proposed form would, at a minimum,
place additional administrative and operational burdens on us.

Negotiated Rate NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. We have entered into these transactions
over the years, and the FERC is now reviewing whether negotiated rates should be
capped, whether or not the "recourse rate" (a cost-of-service based rate)
continues to safeguard against a pipeline exercising market power, and other
issues related to negotiated rate programs. On September 25, 2002, El Paso's
pipelines and others filed comments. Reply comments were filed on October 25,
2002. At this time, we cannot predict the outcome of this NOI.

Cash Management NOPR. On August 1, 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary and a non-FERC regulated parent must be in writing, and set forth the
duties and responsibilities of cash management participants and administrators;
the methods of calculating interest and for allocating interest income and
expenses; and the restrictions on deposits or borrowings by money pool members.
The NOPR also requires specified documentation for all deposits into, borrowings
from, interest income from, and interest expenses related to, these
arrangements. Finally, the NOPR proposed that as a condition of participating in
a cash management or money pool arrangement, the FERC regulated entity maintain
a minimum proprietary capital balance of 30 percent, and the FERC regulated
entity and its parent maintain investment grade credit ratings. On August 28,
2002, comments were filed. The FERC held a public conference on September 25,
2002 to discuss the issues raised in the comments. Representatives of companies
from the gas and electric industries participated on a panel and uniformly
agreed that the proposed regulations should be revised substantially and that
the proposed capital balance and investment grade credit rating requirements
would be excessive. At this time, we cannot predict the outcome of this NOPR.

Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting
Release, which was effective immediately. The Accounting Release provides
guidance on how companies should account for money pool arrangements and the
types of documentation that should be maintained for these arrangements.
However, it did not address the proposed requirements that the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent and that the
entity and its parent have investment grade credit ratings. Requests for
rehearing were filed on August 30, 2002. The FERC has not yet acted on the
rehearing requests.

Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. On
January 17, 2003, FERC issued a NOPR proposing to (1) expand the scope of
construction activities authorized under a pipeline's blanket certificate to
allow replacement of mainline facilities; (2) authorize a pipeline to commence
reconstruction of the affected system without a waiting period; and (3)
authorize automatic approval of construction that would be above the normal cost
ceiling. Comments on the NOPR were filed on February 27, 2003. At this time, we
cannot predict the outcome of this rulemaking.

Pipeline Safety Notice of Proposed Rulemaking. On January 28, 2003, the
U.S. Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. We intend to submit
comments on the NOPR, which are due on April 30, 2003. At this time, we cannot
predict the outcome of this rulemaking.

FERC Inquiry. On February 26, 2003, El Paso received a letter from the
Office of the Chief Accountant at the FERC requesting details of its
announcement of 2003 asset sales and plans for ANR
32

Pipeline Company (an El Paso subsidiary) and us to issue a combined $700 million
of long-term notes. The letter requested that El Paso explain how it intended to
use the proceeds from the issuance of the notes and if the notes will be
included in the two regulated companies' capital structure for rate-setting
purposes. Our response to the FERC was filed on March 12, 2003, and we fully
responded to the request.

While the outcome of our outstanding legal matters, environmental matters
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that the outcome of these
matters could impair our debt rating and the credit rating of our parent.
Further, for environmental matters it is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As new information for our outstanding legal matters,
environmental matters and rates and regulatory matters becomes available, or
relevant developments occur, we will review our accruals and make any
appropriate adjustments. The impact of these changes may have a material effect
on our results of operations, our financial position, and on our cash flows in
the period the event occurs.

Capital Commitments and Purchase Obligations

At December 31, 2002, we had capital and investment commitments of $74
million primarily relating to our South System expansion and our North System
expansion projects. Our other planned capital and investment projects are
discretionary in nature, with no substantial capital commitments made in advance
of the actual expenditures. We have entered into unconditional purchase
obligations for products and services totaling $67 million at December 31, 2002.
Our annual obligations under these agreements are $18 million for 2003, $19
million for each of the years 2004 through 2005, $11 million for 2006 and $1
million in total thereafter.

Operating Leases

We lease property, facilities and equipment under various operating leases.
The majority of our total commitments on operating leases is the lease of the
AmSouth Center located in Birmingham, Alabama. Our parent company guarantees all
obligations under this lease agreement. Minimum future annual rental commitments
at December 31, 2002, were as follows:

Rental expense on our operating leases for each of the years ended December
31, 2002, 2001, and 2000 was $4 million, $5 million and $5 million.

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8. RETIREMENT BENEFITS

Pension and Retirement Benefits

El Paso maintains a pension plan to provide benefits determined under a
cash balance formula covering substantially all of its U.S. employees, including
our employees. Prior to January 1, 2000, Sonat Inc., our former parent company,
maintained a pension plan for our employees. On January 1, 2000, following the
merger with El Paso, the Sonat pension plan was merged into El Paso's cash
balance plan. Our employees who were active participants in the Sonat pension
plan on December 31, 1999 receive the greater of cash balance benefits under the
El Paso plan or Sonat plan benefits accrued through December 31, 2004.

El Paso also maintains a defined contribution plan covering its U.S.
employees, including our employees. Prior to May 1, 2002, El Paso matched 75
percent of participant basic contributions up to 6 percent, with matching
contributions being made to the plan's stock fund, which participants could
diversify at any time. After May 1, 2002, the plan was amended to allow for
matching contributions to be invested in the same manner as that of participant
contributions. Effective March 1, 2003, El Paso suspended the matching
contribution. El Paso is responsible for benefits accrued under its plans and
allocates the related costs to its affiliates. See Note 12 for a summary of
transactions with affiliates.

Other Postretirement Benefits

As a result of the early retirement incentive program we offered in
connection with the October 1999 merger of Sonat and El Paso, we accrued costs
associated with curtailment and special termination benefits. Medical benefits
for this closed group of retirees may be subject to deductibles, co-payment
provisions, and other limitations and dollar caps on the amount of employer
costs. El Paso has reserved the right to change these benefits. Employees who
retire on or after June 30, 2000, continue to receive limited postretirement
life insurance benefits. Our postretirement benefit plan costs are prefunded to
the extent these costs are recoverable through rates.

34

The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for other postretirement benefits as of and for the twelve months
ended September 30:

Postretirement benefit obligations are based upon actuarial estimates as
described below:

Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 11.0 percent in 2002, then gradually decreasing to 5.5
percent by the year 2008. Assumed health care cost trends have a significant
effect on the

35

amounts reported for other postretirement benefit plans. A one-percentage point
change in our assumed health care cost trends would have the following effects:

9. COMMON STOCK

On March 7, 2002, our Board of Directors approved and we filed an amended
and restated certificate of incorporation changing our authorized shares of
stock to 1,000 shares of common stock, with a par value of $1 per share. This
action and the reclassification did not impact our total equity. As of December
31, 2001, we had 1,000 authorized and issued shares with a par value of $3.75
per share. In March 2003, we declared and paid a $600 million dividend, $310
million of which was a distribution of outstanding affiliated receivables and
$290 million of which was cash.

10. TRANSACTIONS WITH MAJOR CUSTOMERS

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

- ---------------

(1) In 2000, 2001 and 2002, Atlanta Gas Light Company did not represent
more than 10 percent of our revenue.

(2) A significant portion of revenues received from a subsidiary of Scana
Resources, Inc. resulted from firm capacity released by Atlanta Gas
Light Company under terms allowed by our tariff.

11. SUPPLEMENTAL CASH FLOW INFORMATION

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

12. INVESTMENTS IN AND TRANSACTIONS WITH RELATED PARTIES

We hold investments in various affiliates which are accounted for using the
equity method of accounting. Our equity method investment consists of a 50
percent ownership interest in Bear Creek, a joint venture with TSC, our
affiliate. Bear Creek owns and operates an underground natural gas storage
facility located in Louisiana. The facility has a capacity of 50 Bcf of base gas
and 58 Bcf of working storage. Bear Creek's working storage capacity is
committed equally to the TGP system (an affiliated system), and our pipeline
system under long-term contracts. Our investment in Bear Creek as of December
31, 2002 and 2001, was $128 million and $116 million. We recognized equity
earnings of $12 million in 2002, $14 million in 2001 and $15 million in 2000.
During 1999, our parent formed Sabine River Investors, L.L.C., a wholly owned
limited liability company, and other separate legal entities, for the purpose of
generating funds for El Paso to invest in capital projects and other assets. The
proceeds from the financing transaction were collateralized by assets of

36

El Paso, including our investment in Bear Creek. In March 2003, El Paso entered
into a $1.2 billion two-year term loan and the proceeds were used to retire the
outstanding amount of the financing transaction.

We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of participating affiliates, thus minimizing
total borrowing from outside sources. Our continued participation in the program
may be dependent on any final rule issued by the FERC in connection with its
cash management notice of proposed rulemaking discussed in Note 7. We had
advanced $430 million at December 31, 2002, at a market rate interest which was
1.5%. At December 31, 2001, we had advanced $371 million at a market rate of
interest which was 2.1%. These receivables are due upon demand. As of December
31, 2002, we have classified $61 million as current and the remaining $369
million as non-current receivables from affiliates. In March 2003, we
distributed a dividend of approximately $310 million of our outstanding
affiliated receivables to our parent.

At December 31, 2001, we had accounts receivable from related parties of $1
million. In addition, we had accounts payable to affiliates of $9 million at
December 31, 2002, and $7 million at December 31, 2001. These balances arose in
the normal course of business. We also received $10 million in deposits related
to our Elba Island capacity contracts with an affiliate, El Paso Merchant Energy
L.P. (EPME L.P.) which is included in our balance sheet as deposits on
transportation contracts. These deposits were required as a result of the credit
rating downgrades of El Paso.

During 2001 and 2000, some of our natural gas sales were to EPME L.P. and
we recognized revenues of $43 million and $28 million. In 2002, we recognized
natural gas sales revenue from EPME L.P. of $2 million. In addition, during
2002, EPME L.P. subscribed to all the available capacity at our Elba Island LNG
facility under a contract that extends to 2023. In 2002, we recognized revenue
of $32 million related to this contract. During 2002, 2001 and 2000, we
transported gas for EPME L.P. and recognized transportation revenue of $4
million, $7 million and $16 million. We settled gas imbalance costs with EPME
L.P. for the years ended 2002, and 2001 for $2 million and $6 million and a gain
of $5 million in 2000. These amounts are recorded in operation and maintenance
expense. These activities were entered into in the normal course of our business
and are based on the same terms as non-affiliates.

El Paso allocates a portion of their general and administrative expenses to
us. The allocation of expenses is based upon the estimated level of effort
devoted to our operations and the relative size of our EBIT, gross property and
payroll. For the years ended December 31, 2002, 2001 and 2000 the annual charges
were $41 million, $39 million and $50 million. Beginning in 2001, TGP allocated
payroll and other expenses associated with shared pipeline services to us. The
allocated expenses are based on the estimated level of staff and their expenses
to provide the services. For the years ended December 2002 and 2001, the annual
charges in each year were $5 million. We believe that the allocation methods are
reasonable.

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

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13. CONTRIBUTION OF CITRUS INVESTMENT (UNAUDITED)

In March 2003, we issued $400 million 8.875% senior unsecured notes due
2010. Contemporaneously with this issuance, El Paso contributed to us all of its
50 percent interest in Citrus Corp., a Delaware corporation. Since the
investment and our equity is owned by El Paso, the contribution of the
investment will be accounted for as a transfer between entities under common
control. As a result, we will be required to record this investment in Citrus at
El Paso's historical carrying value at the date of transfer and as though we had
always owned it.

The following table presents the impact of the transfer as if the
contribution had been reflected in our historical financial statements. During
2002, 2001 and 2000, the contribution would not have impacted our reported
revenues or extraordinary items. However, for 2002, we would have recorded $57
million for a cumulative effect of an accounting change.

14. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Financial information by quarter is summarized below:

38

39

REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion, the consolidated financial statements listed in the Index
appearing under Item 15(a)(1) present fairly, in all material respects, the
consolidated financial position of Southern Natural Gas Company and its
subsidiaries ("the Company") at December 31, 2002 and 2001, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the Index appearing under Item
15(a)(2) presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. These financial statements and the financial statement schedule are
the responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audits. We conducted our audits of these statements in accordance
with auditing standards generally accepted in the United States of America,
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama
March 25, 2003

39.1

SCHEDULE II

SOUTHERN NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN MILLIONS)

- ---------------

(1) Payments made for environmental remediation.

40

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

None.

PART III

Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, 'Security Ownership of Management;" and Item
13, "Certain Relationships and Related Transactions," have been omitted from
this report pursuant to the reduced disclosure format permitted by General
Instruction I to Form 10-K.

ITEM 14. CONTROLS AND PROCEDURES

Evaluation of Controls and Procedures. Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls (Internal Controls) within 90 days of the filing date of
this annual report pursuant to Rules 13a-15 and 15d-15 under the Securities
Exchange Act of 1934 (Exchange Act).

Definition of Disclosure Controls and Internal Controls. Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are properly authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

Limitations on the Effectiveness of Controls. Southern Natural Gas'
management, including the principal executive officer and principal financial
officer, does not expect that our Disclosure Controls and Internal Controls will
prevent all errors and all fraud. A control system, no matter how well conceived
and operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of a control
system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Because of the
inherent limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of fraud, if
any, within the company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty, and that
breakdowns can occur because of simple errors or mistakes. Additionally,
controls can be circumvented by the individual acts of some persons, by
collusion of two or more people, or by management override of the controls. The
design of any system of controls also is based in part upon certain assumptions
about the likelihood of future events, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future
conditions. Over time, controls may become inadequate because of changes in
conditions, or the degree of compliance with the policies or procedures may
deteriorate. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected.

No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in
Southern Natural Gas' Internal Controls, or whether Southern Natural Gas had
identified any acts of fraud involving personnel who have a significant role in
Southern Natural Gas' Internal Controls. This information was important both for
the controls evaluation generally and because the principal executive officer
and principal financial officer are required to disclose that information to our
Board and our independent accountants and to report on related matters in this
section of the Annual Report. The principal executive officer and principal
financial officer note that, from the date of the controls evaluation to the
date of this Annual Report, there have been no significant changes in Internal
41

Controls or in other factors that could significantly affect Internal Controls,
including any corrective actions with regard to significant deficiencies and
material weaknesses.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that, subject to the limitations discussed above, the Disclosure Controls are
effective to ensure that material information relating to Southern Natural Gas
and its consolidated subsidiaries is made known to management, including the
principal executive officer and principal financial officer, particularly during
the period when our periodic reports are being prepared.

Officer Certifications. The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included herein, or as Exhibits to this
Annual Report, as appropriate.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:

1. Financial statements.

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

(B) REPORTS ON FORM 8-K.

We filed a current report on Form 8-K, dated March 5, 2003 reporting the
sale of the $400 million of notes.

We filed a current report on Form 8-K, dated March 14, 2003 reporting our
acquisition of an investment in Citrus Corp.

We also furnished information to the SEC in an Item 9 Current Report on
Form 8-K. Item 9 Current Reports on Form 8-K are not considered to be "filed"
for purposes of Section 18 of the Securities and Exchange Act of 1934 and are
not subject to the liabilities of that section, but are furnished to comply with
Regulation FD.

42

SOUTHERN NATURAL GAS COMPANY

EXHIBIT LIST
DECEMBER 31, 2002

Exhibits not incorporated by reference to a prior filing are designated by
an asterisk. All exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

UNDERTAKING.

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

43

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934 as amended, Southern Natural Gas Company has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 27th day of March, 2003.

SOUTHERN NATURAL GAS COMPANY

By /s/ JOHN W. SOMERHALDER II
------------------------------------
John W. Somerhalder II
Chairman of the Board

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

44

CERTIFICATION

I, John W. Somerhalder II, certify that:

1. I have reviewed this annual report on Form 10-K of Southern Natural Gas
Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ JOHN W. SOMERHALDER II
--------------------------------------
John W. Somerhalder II
Chairman of the Board
(Principal Executive Officer)
Southern Natural Gas Company
Date: March 27, 2003

45

CERTIFICATION

I, Greg G. Gruber, certify that:

1. I have reviewed this annual report on Form 10-K of Southern Natural Gas
Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ GREG G. GRUBER
--------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial Officer)
Southern Natural Gas Company
Date: March 27, 2003

46

EXHIBIT INDEX

Exhibits not incorporated by reference to a prior filing are designated by
an asterisk. All exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.