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, 2003

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 30,
2004: 1,000

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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SOUTHERN NATURAL GAS COMPANY

TABLE OF CONTENTS

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
Dth = dekatherm
MMcf = million cubic feet
Tcfe = trillion cubic feet equivalent

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 (El Paso) through the
merger of Sonat Inc. with El Paso. Our primary business consists of the
interstate transportation and storage of natural gas. We conduct these business
activities through our natural gas pipeline system, a liquified natural gas
(LNG) receiving terminal, storage facilities, and our 50 percent ownership
interest in Citrus Corp. (Citrus), all of which are discussed below.

The Pipeline Systems. The Southern Natural Gas system consists of
approximately 8,000 miles of pipeline with a design capacity of approximately
3,296 MMcf/d. During 2003, 2002 and 2001, our average throughput was 2,101
BBtu/d, 2,151 BBtu/d and 2,027 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. Since 2001, the Federal Energy
Regulatory Commission (FERC) has approved and we have placed in service our
South System I, North System II and the first two phases of our South System II
expansions. The final phase of our South System II project, which we anticipate
completing by May 2004, will add 138 MMcf/d of capacity along the south mainline
of our system in Alabama, Georgia and South Carolina.

We also have a 50 percent ownership interest in Citrus. This interest was
contributed to us by El Paso in March 2003. Citrus owns 100 percent of Florida
Gas Transmission System, which consists of approximately 4,886 miles of pipeline
with a design capacity of 1,980 MMcf/d. During 2003, 2002, and 2001, average
throughput was 1,963 BBtu/d, 2,004 BBtu/d and 1,616 BBtu/d. This system extends
from South Texas to South Florida. For more information regarding our investment
in Citrus and the Florida Gas Transmission System, see Citrus' audited financial
statements and related notes beginning on page 53 as well as our Part II, Item
8, Financial Statement and Supplementary Data, Note 15.

LNG Terminal. Our wholly owned subsidiary, Southern LNG Inc., owns an LNG
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.
The terminal was placed in service and began receiving deliveries in December
2001. The capacity at the terminal was initially contracted with our affiliate,
El Paso Merchant Energy L.P. (EPME), under a contract that extends through 2023.
This contract was assigned by EPME to a subsidiary of British Gas, BG LNG
Services, LLC in December 2003. In 2003, the FERC approved our plan 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 is estimated
to cost approximately $159 million and has a planned in-service date of February
2006.

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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), a subsidiary of Tennessee Gas Pipeline Company
(TGP), also 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 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, 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 energy 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. Approximately 92 percent of our transportation
revenue is attributable to a capacity reservation (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. 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 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 and our LNG terminalling business is regulated by the
U.S. Coast Guard.

For information regarding Citrus and the Florida Gas Transmission System,
see Citrus' audited financial statements and related notes beginning on page 53.

2

MARKETS AND COMPETITION

We have approximately 270 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 four customers contract for a majority of our firm capacity:

- Atlanta Gas Light Company subscribes to a capacity of 952 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 416 MMcf/d under
contracts that expire beginning in 2008.

- Affiliates of Scana Corporation subscribe to a capacity of 246 MMcf/d
under contracts that expire beginning in 2005 through 2017.

- Southern Company Services subscribes to a capacity of 409 MMcf/d under
contracts that expire beginning in 2010, with the majority expiring in
2018.
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(1) Atlanta Gas Light Company is currently releasing a significant portion
of its firm capacity to a subsidiary of Scana Corporation under terms
allowed by our tariff.

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.

A number of large natural gas consumers are electric utility companies who
use natural gas to fuel electric power generation facilities. Electric power
generation is the fastest growing demand sector 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 potentially 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 efficiency in generation and 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 existing contracts mature at various times and in varying amounts of
throughput capacity. 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.

3

For information regarding Citrus and the Florida Gas Transmission System,
see Citrus' audited financial statements and related notes beginning on page 53.

ENVIRONMENTAL

A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 10, and is incorporated
herein by reference.

EMPLOYEES

As of March 26, 2004, we had approximately 475 full-time employees, none of
whom are subject to a collective bargaining arrangement.

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 10, and is incorporated herein
by reference.

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

None.

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, our stock is not publicly traded.

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.
In March 2003, in connection with El Paso's contribution of its interest in
Citrus to us, 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. No common stock dividends were declared or paid in 2002 or
2001.

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ITEM 6. SELECTED FINANCIAL DATA

The following historical selected financial data should be read together
with Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations and Item 8, Financial Statements and Supplemental Data
included in this Form 10-K. These selected historical results are not
necessarily indicative of results to be expected in the future.

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(1) Charges in 1999 include $90 million of merger-related costs associated with
El Paso's merger with Sonat Inc.

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

Our Management's Discussion and Analysis includes forward-looking
statements that are subject to risks and uncertainties. Actual results may
differ substantially from the statements we make in this section due to a number
of factors that are discussed beginning on page 13.

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 alternative
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

Our management, as well as El Paso's management, uses earnings before
interest and income taxes (EBIT) to assess the operating results and
effectiveness of our business. We define EBIT as net income adjusted for (i)
items that do not impact our income from continuing operations, such as the
impact of accounting changes, (ii) income taxes, (iii) interest and debt expense
and (iv) affiliated interest income. Our business consists of consolidated
operations as well as investments in unconsolidated affiliates. We exclude
interest and debt expense from this measure so that our management can evaluate
our operating results without regard to our financing methods. We believe the
discussion of our results of operations based on EBIT is useful to our investors
because it allows them to more effectively evaluate the operating performance of
both our consolidated business and our unconsolidated investments using the same
performance measure analyzed internally by our management. EBIT may not be
comparable to measurements used by other companies. Additionally, EBIT should be
considered in conjunction with net income and other performance measures such as
operating income or operating cash flow.

6

The following is a reconciliation of our operating income to our EBIT and
our EBIT to our net income for the year ended December 31:

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(1) Throughput volumes include volumes associated with our 50 percent equity
interest in Citrus. Prior period volumes have been restated to reflect our
current year presentation which includes billable transportation throughput
volume for storage injection.

OPERATING RESULTS (EBIT)

Our EBIT for the year ended December 31, 2003 increased $29 million
compared to 2002. During 2003, we placed various phases of our South System I,
South System II and North System II mainline expansions into service which,
combined, contributed $22 million to the increase in EBIT. Revenues from South
System I were higher by $15 million offset by $3 million of operating expenses
and a $1 million reduction in equity allowance for funds used during
construction (equity AFUDC). Revenues from South System II were higher by $5
million and equity AFUDC was higher by $5 million offset by $2 million in higher
operating expenses. Revenues from North System II were $4 million higher offset
by $1 million of higher operating expenses. Also contributing to the increase in
revenues and EBIT is $14 million from the increase in sales of natural gas
volumes that are in excess of our system operating requirements. This increase
was primarily due to higher natural gas prices in 2003. These revenues were
offset by $3 million of increased electricity expenses at various compressor
facilities on our pipeline system. Offsetting the increases in EBIT were higher
accruals in 2003 of $3 million pertaining to estimated liabilities to assess and
remediate our environmental exposure based on ongoing evaluations at our
facilities as well as other changes in our operating revenues and expenses that
individually did not have a material impact on EBIT. Also, we have a gas sales
agreement that requires us to purchase and sell volumes at a rate close to the
market index price. Although the arrangement resulted in variances in both
revenue and expense, there was no material effect on EBIT.

Our EBIT for the year ended December 31, 2002 increased $23 million
compared to 2001. Our Elba Island LNG facility was placed into service following
its recommissioning and began receiving deliveries in December 2001, resulting
in $10 million of the increase in EBIT. Revenues from the project increased $32
million offset by $18 million of operating expenses and a $4 million reduction
in equity AFUDC. We placed our South System I (Phase I) expansion into service
in June 2002, resulting in a $6 million increase in EBIT. This expansion
resulted in an $8 million increase in revenues offset by $1 million in operating
expenses and a reduction of $1 million in equity AFUDC. Also contributing to the
increase in EBIT was a $4 million impact of higher remarketing rates and volumes
in 2002 versus 2001 on seasonal turned-back capacity and a $5 million increase
in equity AFUDC due primarily to the construction of the South System II and
North

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System II expansion projects. Other changes in our individual operating revenue
and expense items did not have a material impact on EBIT. As discussed above, we
have a gas sales agreement that requires us to purchase and sell volumes at a
rate close to the market index price. Although the arrangement resulted in
variances in both revenue and expense, there was no material effect on EBIT.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the year ended December 31, 2003, was $30
million higher than in 2002 primarily due to the issuance in March 2003 of $400
million of 8.875% senior unsecured notes.

Interest and debt expense for the year ended December 31, 2002, was $9
million higher than in 2001. The increase 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, 2003, was $4
million lower than in 2002 due to lower average advances to El Paso under its
cash management program. The average advance balance for the year ended December
31, 2002 of $445 million decreased to $187 million in 2003. The average short
term interest rate increased from 1.9% in 2002 to 2% in 2003.

Affiliated interest income for the year ended December 31, 2002, was $9
million lower than in 2001 due primarily to lower short-term interest rates in
2002, partially offset by increased average advances to El Paso under its cash
management program in 2002. The average short-term interest rate decreased from
4.7% in 2001 to 1.9% in 2002 and average advances to El Paso under its cash
management program were $445 million in 2002 versus $372 million in 2001.

INCOME TAXES

Our effective tax rates were different than the statutory rate of 35
percent for all periods, primarily due to state income taxes and earnings from,
and other adjustments attributable to unconsolidated affiliates where we
anticipate receiving dividends. For a reconciliation of the statutory rate of 35
percent to the effective rates, see Item 8, Financial Statements and
Supplementary Data, Note 4.

OTHER

In the third quarter of 2002, the FERC approved our South System II project
and related compressor facilities. This expansion has a design capacity of 330
MMcf/d. Construction will be completed in three phases. Phase I was placed in
service in September 2003 and Phase IA was placed in service in November 2003.
The targeted in service date for Phase II is May 2004. The South System II
project will increase our firm transportation capacity along our south mainline
to Alabama, Georgia and South Carolina. Current cost estimates are approximately
$242 million, and current expenditures to date as of December 31, 2003 are
approximately $195 million.

On May 31, 2002, we filed with the FERC to expand our Elba Island LNG
facility for estimated capital costs of $159 million. This expansion will
increase the design sendout rate of the facility from 446 MMcf/d to

8

806 MMcf/d. In April 2003, the FERC approved our expansion. Construction
commenced in July 2003 with an in-service date expected to be in February of
2006.

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

Our liquidity needs have been 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, 2003, we had receivables from El
Paso of $153 million as a result of this program. These receivables are due upon
demand; however, we do not anticipate settlement within the next twelve months.
As of December 31, 2003, these receivables were 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. As a
result of recent announcements by El Paso related to a revision of its estimates
of its natural gas and oil reserves, our ability to borrow or recover the
amounts advanced under El Paso's cash management program could be impacted. See
Item 8, Financial Statements and Supplementary Data, Note 2 for a discussion of
these matters. Our cash flows for the years ended December 31 were as follows:

Cash Flows from Operating Activities

Net cash provided by operating activities were $167 million in 2003 versus
$209 million in 2002. This decrease was primarily due to $10 million of customer
deposits received in 2002, higher interest payments of $22 million due to
increased long-term debt in 2003 and higher tax payments of $10 million in 2003.
The remaining decrease is due to the timing of cash payments on accounts
receivable and various fluctuations in working capital components.

Cash Flows from Investing Activities

Net cash used in investing activities in 2003 consisted of $237 million in
capital expenditures, primarily for our pipeline expansions, and $33 million in
affiliated advances. Offsetting this use of cash was $9 million from net
proceeds from disposal of assets.

Cash Flows from Financing Activities

Net cash provided by financing activities in 2003 consisted of net proceeds
from the issuance of $400 million of long-term debt in March 2003, offset by
cash dividends paid of $290 million.

In a series of credit rating agency actions beginning in 2002, and
contemporaneously with downgrades of the senior unsecured indebtedness of El
Paso, our senior unsecured indebtedness was downgraded to below investment grade
and is currently rated B1 by Moody's (with a negative outlook and under review
for a possible downgrade) and B- by Standard & Poor's (with a negative outlook).
These downgrades will increase our external costs of capital and collateral
requirements and could impede our access to capital markets in the future.

9

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 $40
million and $120 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.

CONTRACTUAL OBLIGATIONS

The following table summarizes our contractual obligations as of December
31, 2003, for each of the years presented.

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(1) See Item 8, Financial Statements and Supplementary Data, Note 9. These
amounts reflect our undiscounted obligation.

(2) See Item 8, Financial Statements and Supplementary Data, Note 10. These
amounts reflect our undiscounted obligation.

(3) Other contractual commitments and purchase obligations are defined as
legally enforceable agreements to purchase goods or services that have fixed
or minimum quantities and fixed or minimum variable price provisions, and
detail approximate timing of these underlying obligations.

(4) These are commitments for firm access to storage capacity owned by our
affiliate, Bear Creek.

(5) Includes purchase commitments for natural gas and power.

(6) Includes capital and investment commitments primarily relating to our South
System expansions and to the Elba Island facility expansion.

COMMITMENTS AND CONTINGENCIES

For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 10, which is incorporated
herein by reference.

10

CRITICAL ACCOUNTING POLICIES

Our critical accounting policies are those accounting policies that require
us to make critical accounting estimates in the preparation of our financial
statements.

Asset Impairments. The asset impairment accounting rules require us to
continually monitor our businesses and the business environment to determine if
an event has occurred indicating that a long-lived asset or investment may be
impaired. If an event occurs, which is a determination that involves judgment,
we then assess the expected future cash flows against which to compare the
carrying value of the asset group being evaluated, a process which also involves
judgment. We ultimately arrive at the fair value of the asset which is
determined through a combination of estimating the proceeds from the sale of the
asset, less anticipated selling costs (if we intend to sell the asset), or the
discounted estimated cash flows of the asset based on current and anticipated
future market conditions (if we intend to hold the asset). The assessment of
project level cash flows requires us to make projections and assumptions for
many years into the future for pricing, demand, competition, operating costs,
legal and regulatory issues and other factors and these variables can, and often
do, differ from our estimates. These changes can have either a positive or
negative impact on our impairment estimates. Future changes in the economic and
business environment can impact our original and ongoing assessments of
potential impairments.

Accounting for Environmental Reserves. We accrue for environmental
reserves when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered, and an amount can be reasonably
estimated. Estimates of our liabilities are based on currently available facts,
existing technology and presently enacted laws and regulations taking into
consideration the likely effects of inflation and other societal and economic
factors, and include estimates of associated onsite, offsite and groundwater
technical studies, and legal costs. Actual results may differ from our
estimates, and our estimates can be, and often are, revised in the future,
either negatively or positively, depending upon actual outcomes or changes in
expectations based on the facts surrounding each exposure.

As of December 31, 2003, we had accrued approximately $3 million for
environmental matters. Our accrual represents the most likely outcome can be
reasonably estimated.

Accounting for Postretirement Benefits. Our accruals related to our
postretirement benefits are based on actuarial calculations. In performing these
calculations, our actuaries must use assumptions, including those related to the
return that we expect to earn on our plan assets, discount rates used in
calculating benefit obligations, the cost of health care when benefits are
provided under our plans and other factors.

Actual results may differ from the assumptions included in these actuarial
calculations, and as a result our estimates associated with our postretirement
benefits can be, and often are, revised in the future, with either a negative or
positive effect on the costs we recognize and the accruals we make. The
following table shows the impact of a one percent change in our primary
assumptions used in our actuarial calculations associated with our
postretirement benefits for the year ended December 31, 2003 (in millions):

Our discount rate assumptions reflect the rates of return on the
investments we expect to use to settle our postretirement obligations in the
future. We combined current and expected rates of return on investment grade
corporate bonds to develop the discount rates used in our benefit expense and
obligation estimates as of September 30, 2003.

11

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

As of December 31, 2003, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Based on our
assessment of those standards, we do not believe there are any that could have a
material impact on us.

12

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.

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 such as hydroelectric power;

- price competition;

- drilling activity and supply availability of natural gas;

- expiration and/or turn back of significant contracts;

- service area competition;

- changes in regulation and actions of regulatory bodies;

- credit risk of our customer base;

- increased cost of capital;

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

- adverse general economic conditions; and

- unfavorable movements in 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
13

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:

- competition by other pipelines, including the proposed construction by
other companies of additional pipeline capacity or LNG terminals 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 in the areas we serve;

- 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.

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 a reduction of the volumes transported by our customers, such as
power companies who, depending on the price of fuel, may not dispatch gas fired
power plants. Increased prices could also result in industrial plant shutdowns
or load losses to competitive fuels and local distribution companies' loss of
customer base. 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. If
natural gas prices in the supply basins connected to our pipeline systems are
higher on a delivered basis to our off-system markets than delivered prices from
other natural gas producing regions, our ability to compete with other
transporters may be negatively impacted. 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. Our LNG
terminalling business is also regulated by the U.S. Coast Guard. 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.

14

Further, state agencies and local governments 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, and these amounts
could be material. For additional information, see Item 8, Financial Statements
and Supplementary Data, Note 10.

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.

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

For 2003, contracts with Atlanta Gas Light Company, Southern Company
Services, Alabama Gas Corporation and Scana Corporation represented
approximately 30%, 13%, 13% and 8% 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 13. 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.

15

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 senior unsecured indebtedness of
El Paso has been downgraded to below investment grade, currently rated Caa1 by
Moody's (with a negative outlook and under review for a possible downgrade) and
CCC+ by Standard & Poor's (with a negative outlook). Our senior unsecured
indebtedness is currently rated B1 by Moody's (with a negative outlook and under
review for a possible downgrade) and B- by Standard & Poor's (with a negative
outlook). These downgrades will increase our cost of capital and collateral
requirements, and could impede our access to capital markets. As a result of
these downgrades, El Paso has realized substantial demands on its liquidity.
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.

El Paso has embarked on its 2003 Long-Range Plan that, among other things,
defines El Paso's future businesses, targets significant debt reduction and
establishes financial goals. An inability to meet these objectives could
adversely affect El Paso's liquidity position, and in turn 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,
2003, we have net receivables of approximately $145 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 these matters, see
Item 8, Financial Statements and Supplementary Data, Note 15.

Furthermore, in February 2004, El Paso announced that it had completed a
review of its estimates of natural gas and oil reserves. As a result of this
review, El Paso announced that it was reducing its proved natural gas and oil
reserves by approximately 1.8 Tcfe. El Paso also announced that this reserve
revision would result in a 2003 charge of approximately $1 billion if the full
impact of the revision was taken in that period. In March 2004, El Paso provided
an update and stated that the revisions would likely result in a restatement of
its historical financial statements, the timing and magnitude of which are still
being determined. El Paso has retained a law firm to conduct an internal
investigation, which is ongoing. Also, as a result of the reduction in reserve
estimates, several class action suits have been filed against El Paso and
several of its subsidiaries, but not against us. The reduction in reserve
estimates may also become the subject of an SEC investigation or separate
inquiries by other governmental regulatory agencies. These investigations and
lawsuits may further negatively impact El Paso's credit ratings and place
further demands on its liquidity. See Item 8, Financial Statements and
Supplementary Data, Note 2 for a further discussion of the possible impacts of
this announcement.

OUR SUBSIDIARY MAY BE SUBJECT TO A CHANGE OF CONTROL UNDER CERTAIN
CIRCUMSTANCES.

Our ownership in Bear Creek is pledged as collateral under El Paso's
revolving $3 billion credit facility and approximately $1 billion of other
financing arrangements, including leases, letter's of credit and other
facilities. As a result, Bear Creek's ownership is subject to change if El
Paso's lenders under these facilities exercise rights over their collateral.

16

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.

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.

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.

17

RISKS RELATED TO CITRUS CORP.

FLORIDA GAS TRANSMISSION COMPANY (FGT) DEPENDS SUBSTANTIALLY UPON A SMALL NUMBER
OF CUSTOMERS.

Upon completion of its current expansion, the five most significant
customers on FGT's pipeline system will account for approximately 74% of
contracted capacity, with the two most significant customers, Florida Power &
Light Company, or FP&L, and TECO Energy, Inc., including its subsidiaries Tampa
Electric Company and Peoples Gas System, Inc., being obligated for approximately
39% and 21% of such capacity. Accordingly, failure of one or more of FGT's most
significant customers to pay reservation charges could reduce its revenues
materially and have a material adverse effect on its business, financial
condition and results of operations.

IMPORTANT ACTIONS BY CITRUS AND FGT REQUIRE APPROVAL BY BOTH ENRON CORP. (ENRON)
AND US.

El Paso contributed its 50 percent interest in Citrus to us. Enron owns the
other 50 percent interest. Citrus' organizational documents and FGT's
organizational documents require that "important matters" be approved by both
Enron and us. Important matters include the declaration of dividends and similar
payments, the approval of operating budgets, the incurrence of indebtedness and
the consummation of significant transactions. Consequently, we are dependent on
Enron's agreement to effect any, such actions. Enron's interests with respect to
these important matters could be different from ours and, accordingly, we may be
unable to cause Citrus and FGT to take important actions, such as the payment of
dividends and the sale or acquisition of assets.

CITRUS DEPENDS ON ENRON ENTITIES TO PROVIDE IT WITH MANAGEMENT AND SUPPORT
SERVICES UNDER AN INFORMAL ADMINISTRATIVE SERVICES ARRANGEMENT.

Various Enron entities provide management and support services to Citrus
and its subsidiaries, pursuant to an informal administrative services
arrangement. These services include administration, legal, compliance and
emergency services. The arrangement was originally governed by the provisions of
an operating agreement between an Enron affiliate and Citrus. The term of the
operating agreement expired on June 30, 2001 and has not been extended. However,
the Enron entities have continued to provide their services under an informal
arrangement based on the provisions of the original operating agreement. Under
the arrangement, Citrus and its subsidiaries reimburse the Enron entities for
costs attributable to the operations of Citrus and its subsidiaries.

Although we believe that the Enron entities will continue to perform
management and support services for Citrus and its subsidiaries, and that Citrus
could obtain such services from other sources in a timely and cost effective
manner, Citrus may be unable to obtain such services from other sources on terms
favorable to Citrus in the event the Enron entities stop providing them. Failure
to obtain management and support services in a timely and cost effective manner
could have a material adverse effect on Citrus' business.

THE BLANKET MARKET AUTHORITY OF ONE OF CITRUS' SUBSIDIARIES MAY BE TERMINATED.

On March 26, 2003, the FERC issued an order directing Citrus Trading
Corporation (CTC), a direct subsidiary of Citrus, 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.

ONGOING LITIGATION REGARDING CTC COULD ADVERSELY AFFECT OUR BUSINESS.

In March 2003, CTC filed suit against Duke Energy LNG Sales, Inc. (Duke)
seeking damages for breach of a gas supply contract under which CTC was entitled
to purchase regasified liquefied natural gas. In April 2003, Duke forwarded a
letter to CTC purporting to terminate the contract due to the alleged failure of
CTC to increase the amount of an outstanding letter of credit backstopping its
purchase obligations. On May 1, 2003, CTC notified Duke that Duke was in default
under the contract. CTC subsequently filed an amended complaint, alleging
wrongful contract termination and specifying damages of $185 million. At this

18

time, the outcome of this litigation is not determinable. For further discussion
of these matters, see Item 8, Financial Statements and Supplementary Data, Note
10.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk is exposure to changing interest rates. The table
below shows the carrying value and related weighted average effective interest
rates of our interest bearing securities, by expected maturity dates, and the
fair value of those securities. As of December 31, 2003, 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.

20

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.

21

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)

See accompanying notes.

22

SOUTHERN NATURAL GAS COMPANY

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

See accompanying notes.

23

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN MILLIONS)

See accompanying notes.

24

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.

Regulated Operations

Our natural gas systems and storage 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 currently apply the provisions of
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation. We perform an annual study to assess the
ongoing applicability of SFAS No. 71. The accounting required by SFAS No. 71
differs from the accounting required for businesses that do not apply its
provisions. Transactions that are generally recorded differently as a result of
applying regulatory accounting requirements include capitalizing an equity
return component on regulated capital projects, post retirement employee benefit
plans, and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

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

Materials and Supplies

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

25

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 two 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 regulated 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 the proceeds received, if any, when the asset is sold or
retired.

At December 31, 2003 and 2002, we had approximately $81 million and $126
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 or AFUDC) 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 calculated based on our average cost of debt. Debt
amounts capitalized during the years ended December 31, 2003, 2002 and 2001,
were $3 million, $2 million and $2 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. The equity
amounts capitalized during the years ended December 31, 2003, 2002 and 2001 were
$7 million, $5 million and $5 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 financed construction
are reflected as an increase in the cost of the asset on our balance sheet.

26

Asset Impairments

We evaluate our assets 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, as well as revenues on sales of natural gas and related products, we
record revenues when physical deliveries of natural gas and other commodities
are made at the 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.

Price Risk Management Activities

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

Environmental Costs and Other Contingencies

We record environmental 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.

27

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

2. LIQUIDITY

In February 2004, El Paso announced that it had completed a review of its
estimates of its natural gas and oil reserves. As a result of this review, El
Paso announced that it was reducing its proved natural gas and oil reserves by
approximately 1.8 Tcfe. El Paso also announced that this reserve revision would
result in a 2003 charge of approximately $1 billion if the full impact of the
revision was taken in that period. In March 2004, El Paso provided an update and
stated that the revision would likely result in a restatement of its historical
financial statements, the timing and magnitude of which are still being
determined.

A material restatement of El Paso's prior period financial statements would
result in an "event of default" under El Paso's revolving credit facility and
various other financing transactions; specifically under the provisions of the
facility related to representations and warranties on the accuracy of its
historical financial statements and its debt to total capitalization ratio. El
Paso has received waivers on its revolving credit facility and other financing
transactions that were required to address potential issues related to its
recently announced reserve revisions. Based upon a review of the covenants and
indentures of our outstanding indebtedness, we do not believe that a default on
El Paso's revolving credit facility would constitute an event of default on our
debt securities.

El Paso is a significant potential source of liquidity to us. We
participate in El Paso's cash management program. Under this 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 and
consistently provided cash to El Paso under this program, and as of December 31,
2003, we had a cash advance receivable from El Paso of $153 million, classified
as a non-current asset in our balance sheet. If El Paso were unable to meet its
liquidity needs, we would not have access to this source of liquidity and there
is no assurance that El Paso could repay the entire amounts owed to us. In that
event, we could be required to write-off some amount of these advances, which
could have a material impact on our stockholder's equity. Furthermore, we would
still be required to repay affiliated company payables. Non-cash write-downs
that cause our debt to EBITDA (as defined in our indentures) ratio to fall below
6 to 1 could prohibit us from incurring additional debt. However, this non-cash
equity reduction would not result in an event of default under our existing debt
securities.

Our equity investment in Bear Creek serves as collateral under El Paso's
revolving credit facility and other of El Paso's borrowings. If El Paso's
lenders under this facility or those other borrowings were to exercise their
rights to this collateral, our investment could be liquidated. However, this
liquidation would not constitute an event of default under our existing debt
securities.

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If, as a result of the events described above, El Paso were subject to
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. We believe that claims to
substantively consolidate us with El Paso and/or its other subsidiaries would be
without merit. However, there is no assurance that El Paso and/or its other
subsidiaries or their creditors would not advance such a claim in a bankruptcy
proceeding. If we were to be substantively consolidated in a bankruptcy
proceeding with El Paso and/or its other subsidiaries, there could be a material
adverse effect on our financial condition and our liquidity.

Finally, we have cross-acceleration provisions in our long-term debt that
state that should we incur an event of default under which borrowings in excess
of $10 million are accelerated, our long-term debt could also be accelerated.
The acceleration of our long-term debt would adversely affect our liquidity
position and, in turn, our financial condition.

3. INVESTMENT IN CITRUS

In March 2003, El Paso contributed to us all of its 50 percent ownership
interest in Citrus, a Delaware corporation with a net book value at the time of
contribution of approximately $578 million. Since both the investment in Citrus,
which is accounted for as an equity investment, and our common stock were owned
by El Paso at the time of the contribution, we were required to reflect the
investment in Citrus at its historical cost and include it in our financial
statements for all periods presented. As a result, our financial statements
reflect the contribution of Citrus as though it occurred on January 1, 2001.

4. INCOME TAXES

The following table reflects the components of income tax expense included
in income before cumulative effect of accounting change for each of the three
years ended December 31:

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Our income tax expense included in income before cumulative effect of
accounting change 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:

Under El Paso's tax accrual policy, we are allocated the tax effects
associated with our employees' non-qualified dispositions of employee stock
purchase plan stock, the exercise of non-qualified stock options and the vesting
of restricted stock as well as restricted stock dividends. This allocation
increased taxes payable by $1 million in 2003 and reduced taxes payable by $1
million in 2002 and $3 million in 2001. These tax effects are included in
additional paid-in capital in our balance sheet.

The following are the components of our carryovers as of December 31, 2003:

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(1) $14 million of this amount expires 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 taxes related to our general business credits.

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5. CUMULATIVE EFFECT OF ACCOUNTING CHANGE

On January 1, 2002, we adopted SFAS No. 141, Business Combinations, and
SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that
once SFAS No. 142 is adopted, negative goodwill should be written off as a
cumulative effect of an accounting change. In March 2003, El Paso contributed
its investment in Citrus to us. See Note 3 for a discussion of the accounting
treatment for this transaction. As a result of our ownership in Citrus, which
had negative goodwill associated with El Paso's original investment, we recorded
a pre-tax and after-tax gain of $57 million as a cumulative effect of an
accounting change in our 2002 income statement to reflect the adoption of SFAS
No. 141 and SFAS No. 142.

6. FINANCIAL INSTRUMENTS

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

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

As of December 31, 2003 and 2002, 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.

7. REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and regulatory liabilities as of December 31, 2003
and 2002 are presented below. These balances are presented in our balance sheets
on a gross basis.

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

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

(3) Amounts are included as other non-current liabilities in our balance
sheet.

8. ACCOUNTING FOR HEDGING ACTIVITIES

As of December 31, 2003 and 2002, our equity interest in the value of
Citrus' cash flow hedges included in accumulated other comprehensive loss was an
unrealized loss of $8 million, net of income taxes. This amount will be
reclassified to earnings over the terms of Citrus' outstanding debt. We estimate
that less than $1 million of this unrealized loss will be reclassified from
accumulated other comprehensive loss over the next

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twelve months. For the years ended December 31, 2003, 2002 and 2001, no
ineffectiveness was recorded in earnings on these cash flow hedges.

9. 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: