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.

28

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:

29

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:

- ---------------
(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:

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

(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.

- ---------------
(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

31

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:

Our long-term debt contains cross-acceleration provisions, the most
restrictive of which is a $10 million cross-acceleration clause. If triggered,
repayment of our long-term debt, could be accelerated. In addition, under our
indentures, we are subject to a number of restrictions and covenants. The most
restrictive of these include (i) limitations on the incurrence of additional
debt, based on a ratio of debt to EBITDA (as defined in the agreements); (ii)
limitations, in some cases, on transactions with our affiliates; (iii)
limitations on the incurrence of liens; (iv) potential limitations on our
ability to declare and pay dividends; and (v) potential limitations on our
ability to participate in the El Paso cash management program. For the year
ended December 31, 2003, we were in compliance with these covenants.

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 the
remaining proceeds were used for capital expenditures in 2003.

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.

Other Financing Arrangements

In April 2003, El Paso entered into a new $3 billion revolving credit
facility, with a $1.5 billion letter of credit sublimit, which matures on June
30, 2005. El Paso's $1 billion revolving credit facility, which matured in
August 2003, and approximately $1 billion of other El Paso financing
arrangements (including leases, letters of credit and other facilities) were
also amended to conform El Paso's obligations under those arrangements to the $3
billion revolving credit facility. We are not a borrower under El Paso's $3
billion revolving credit facility; however, El Paso's equity in several of its
subsidiaries, including our equity in Bear Creek, collateralizes the credit
facility and the other financing arrangements. See Note 2 for a discussion
regarding El Paso's possible default on the $3 billion revolving credit
facility.

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10. 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
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). Discovery is proceeding. Our costs and legal exposure related to these
lawsuits and claims are not currently determinable.

Key. We were named as a defendant in Randall Key v. LDI Contractors, Inc.,
et al., filed in 2002 in the Circuit Court of Jefferson County, Alabama. The
plaintiff, an employee of a contractor, suffered paralysis as a result of a
coupling failure during a pipeline repressurization in May 2002. The plaintiff
is seeking compensatory and punitive damages against us and two other
defendants. We are pursuing contribution and indemnity from the codefendants and
their insurers. The matter is set for trial in October 2004. Our costs and legal
exposure related to this lawsuit and claims are not currently determinable.

Royalty Claim. In five contract settlements reached in the late 1980s with
Elf Aquitaine (Elf) pertaining to the pricing of gas produced from certain
federal offshore blocks, we indemnified Elf against royalty claims that
potentially could have been asserted by the Minerals Management Service (MMS).
Following its settlements with us, Elf received demands from MMS for royalty
payments related to the settlements. With our approval, Elf protested the
demands for over a decade while trying to reach a settlement with the MMS. Elf,
which is now Total E&P USA (Total), has recently advised us that it is now
renewing efforts to settle claims by the MMS for excess royalties attributable
to price reductions that we achieved in the gas contract settlements in the late
1980s. Total has informed us that the MMS is claiming $10.2 million in
royalties, including $7.3 million of interest, for the five settlements with us
and that Total is proposing to make a settlement offer to MMS. If Total cannot
resolve these claims administratively with MMS, then an appeal can be taken to
the federal courts. We have the right under a pre-existing settlement with our
customers to recover through a surcharge payable by our customers a portion of
the amount ultimately paid to MMS under the royalty indemnity with Total.

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 this information becomes available, or other relevant developments occur, we
will adjust our accrual amounts accordingly. While there are still uncertainties
related to the ultimate costs we may incur, based upon our evaluation and
experience to date, we believe our current reserves are adequate. As of December
31, 2003, we had accrued $1 million for our outstanding legal matters.

Environmental Matters

We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of December
31, 2003, we had accrued approximately $3 million for expected remediation costs
and associated onsite, offsite and groundwater technical studies, which we
anticipate incurring through 2027. Our accrual was based on the

33

most likely outcome that can be reasonably estimated. Below is a reconciliation
of our environmental remediation liabilities as of December 31, 2003 (in
millions):

Balance as of January 1, 2003............................... $ 4
Additions/Adjustments for remediation activities............ 3
Payments for remediation activities......................... (4)
---
Balance as of December 31, 2003............................. $ 3
===

In addition, we expect to make capital expenditures for environmental
matters of approximately $7 million in the aggregate for the years 2004 through
2008. These expenditures primarily relate to compliance with clean air
regulations. For 2004, we estimate that our total remediation expenditures will
be approximately $3 million, which primarily will be expended under government
directed clean-up plans.

Toca Air Permit Violation. In June 2003, we notified the Louisiana
Department of Environmental Quality (LDEQ) that we had discovered possible
compliance issues with respect to operations at our Toca Compressor Station. In
response to a request from the LDEQ, we submitted a report in September 2003
documenting that there had been unpermitted emissions from nine condensate
storage tanks and a tank truck loading station. In December 2003, the LDEQ
issued an order requiring us to correct the existing operating permit and
achieve compliance with federal and state laws and regulations. Our Toca
Compressor Station will invest an estimated $6 million to upgrade the station's
environmental controls by 2005. We filed a revised permit application and a plan
for compliance with the LDEQ in January 2004. The LDEQ has not indicated what,
if any, penalty amount it will assess for this matter.

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 our reserves are
adequate.

Rates and Regulatory Matters

There are several regulatory rules and orders in various stages of
adoption, review and/or implementation, none of which we believe will have a
material impact on us.

While the outcome of our outstanding 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 and accruals related to these
matters.

Other Matters

Enron Bankruptcy. In December 2001, Enron and a number of its
subsidiaries, including Enron North America Corp. (ENA), filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. We had contracts with ENA for, among other things, the
transportation of natural gas. Following the rejection of these contracts by
ENA, we filed a proof of claim totaling $1.9 million with the Bankruptcy Court.
We have fully reserved for the amounts due from ENA.

In addition, we own 50 percent of the outstanding stock of Citrus with
Enron. El Paso and Enron are parties to a Capital Stock Agreement that governs,
among other things, the ownership of capital stock in Citrus. The Capital Stock
Agreement contains restrictions on the transferability of the capital stock of
Citrus. These restrictions include rights of first refusal if either owner
desires to sell its interest in Citrus. Those shares

34

must first be offered to the other stockholder before the shares can be sold or
transferred to a party other than a wholly-owned subsidiary.

On October 31, 2003, Enron filed a motion with the Bankruptcy Court seeking
approval to assign the Capital Stock Agreement to CrossCountry Energy Corp., a
newly created subsidiary which would acquire Enron's stock in Citrus and then be
distributed to Enron's creditors. We objected to the motion on the basis that
(1) we must consent to the assignment and (2) the assignment would effectively
circumvent the transferability restrictions under the Capital Stock Agreement,
including our right of first refusal. The Bankruptcy Court granted the motion on
December 1, 2003.

Duke. On March 7, 2003, CTC, a direct subsidiary of Citrus, filed suit
against Duke Energy LNG Sales, Inc. titled Citrus Trading Corp. v. Duke Energy
LNG Sales, Inc. in the District Court of Harris County, Texas seeking damages
for breach of a gas supply contract.

In April 2003, Duke: (i) sent CTC notice of termination of the gas supply
contract alleging failure of CTC to increase the amount of an outstanding letter
of credit backstopping its purchase obligations; (ii) filed an answer to CTC's
complaint stating among other reasons that CTC had triggered the early
termination and breached the gas supply contract; and (iii) removed the case to
federal court, based on the existence of foreign arbitration with its LNG
supplier, Sonatrading Amsterdam B.V. Sonatrading was alleged to have repudiated
its supply contract with Duke.

In May 2003, CTC: (i) notified Duke that it was in default under the gas
supply contract, demanding cover damages for alternate supplies obtained by CTC;
and (ii) filed a motion to remand the case back to state court. Subsequently,
CTC gave Duke notice of early termination of the gas supply contract.

In August 2003, Duke filed a third-party petition against Sonatrading. In
October 2003, CTC filed an amended complaint, alleging wrongful contract
termination and specifying damages of $185 million. Also in October 2003, Duke
filed various petitions claiming that Sonatrading's breach of contract results
in its being responsible for any damages the court may ultimately find Duke owes
to Citrus. In October 2003, the case was once again removed to federal court. In
November 2003, pursuant to a judicial order, CTC filed an amended complaint
against Duke. We do not expect the ultimate resolution of this matter to have a
material adverse effect on us.

While the outcome of these 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, and adjust our accruals
accordingly. The impact of these changes may have a material effect on our
results of operations, our financial position, and our cash flows in the periods
these events occur.

Capital Commitments and Purchase Obligations

At December 31, 2003, we had capital and investment commitments of $45
million primarily relating to our South System expansion and to the Elba Island
facility expansion. 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 $51 million at December 31, 2003.
Our annual obligations under these agreements are $19 million for each of the
years 2004 through 2005, $11 million for 2006, $1 million for 2007 and $1
million in total thereafter.

35

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
on our operating leases as of December 31, 2003, were as follows:

Rental expense on our operating leases for each of the years ended December
31, 2003, 2002, and 2001 was $3 million, $4 million and $5 million.

11. 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, 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. In March 2003, El Paso suspended the matching contribution.
Effective July 1, 2003, El Paso began making matching contributions again at a
rate of 50 percent of participant basic contributions up to 6 percent. El Paso
is responsible for benefits accrued under its plans and allocates the related
costs to its affiliates.

Other Postretirement Benefits

As a result of our merger with El Paso in October 1999, we offered a
one-time election through an early retirement window for Sonat employees who
were at least age 50 with 10 years of service on December 31, 1999, to retire on
or before June 30, 2000, and keep benefits under Sonat's past retirement medical
and life plans. 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 reserves the right to change these
benefits. Employees who retire after June 30, 2000, continue to receive limited
postretirement life insurance benefits. Our postretirement benefit plan costs
are prefunded to the extent these costs are recoverable through our rates. We
expect to contribute $4 million to our other postretirement benefit plan in
2004.

On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 was signed into law. The benefit obligations and costs
reported below, which include prescription drug coverage, do not reflect the
impact of this legislation. Current accounting standards that are not yet
effective may require changes to previously reported benefit information once
they are finalized.

36

The following table presents 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 (the plan reporting date):

Benefit costs include the following components for the year ended December
31:

Benefit obligations are based on actuarial estimates and assumptions. The
following table details the weighted average assumptions we used for our other
postretirement plan for 2003, 2002 and 2001:

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

(1) The expected return on plan assets is a pre-tax rate (before a tax rate
ranging from 31% to 34% on postretirement benefits) that is primarily based
on an expected risk-free investment return, adjusted for historical risk
premiums and specific risk adjustments associated with our debt and equity
securities. These expected returns were then weighted based on the target
asset allocations of our investment portfolio.

Actuarial estimates for our postretirement benefits plan assumed a weighted
average annual rate of increase in the per capita costs of covered health care
benefits of 10.0 percent in 2003, gradually decreasing to 5.5 percent by the
year 2008. Assumed health care cost trends can have a significant effect on the
amounts

37

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

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

The target allocation for the invested assets is 65% equity/35% fixed
income. In late 2003, we modified our target asset allocations for our
postretirement plan to increase our equity allocation to 65 percent of total
plan assets. As of September 30, 2003, we had not yet adjusted our portfolio's
investments to reflect this change in strategy. Other assets are held in cash
for payment of benefits upon presentment. Any El Paso stock held by the plan is
held indirectly through investments in mutual funds.

The primary investment objective of our plan is to ensure, that over the
long-term life of the plan, an adequate pool of sufficiently liquid assets
exists to support the benefit obligation to participants, retirees and
beneficiaries. In meeting this objective, the plan seeks to achieve a high level
of investment return consistent with a prudent level of portfolio risk.
Investment objectives are long-term in nature covering typical market cycles of
three to five years. Any shortfall in investment performance compared to
investment objectives is the result of general economic and capital market
conditions.

12. COMMON STOCK

As of December 31, 2003 and 2002, we have 1,000 authorized shares of common
stock, with a par value of $1 per share. In March 2003, we declared and paid a
$600 million dividend, $310 million of which was a non-cash distribution of
outstanding affiliated receivables and $290 million of which was cash.

13. TRANSACTIONS WITH MAJOR CUSTOMERS

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

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

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

(2) In 2003, Alabama Gas Corporation did not represent more than 10 percent of
our revenues.

(3) In 2001, 2002 and 2003, Atlanta Gas Light Company did not represent more
than 10 percent of our revenues.

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14. SUPPLEMENTAL CASH FLOW INFORMATION

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

15. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND TRANSACTIONS WITH AFFILIATES

Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates are accounted for using the
equity method of accounting and consist of our equity ownership interests in
Citrus and Bear Creek.

Citrus. In March 2003, El Paso contributed its 50 percent ownership
interest in Citrus to us. Enron owns the other 50 percent. Citrus owns and
operates Florida Gas Transmission, a 4,886 mile regulated pipeline system that
extends from producing regions in Texas to markets in Florida. As of December
31, 2003 and 2002, our investment in Citrus was $650 million and $606 million.
Our investment in Citrus is limited to our ownership of the voting stock of
Citrus, and we have no financial obligations, commitments or guarantees, either
written or oral, to support Citrus.

The ownership agreements of Citrus provide each partner with a right of
first refusal to purchase the ownership interest of the other partner. We have
no obligations, either written or oral, to acquire Enron's ownership interest in
Citrus in the event Enron must sell its interest as a result of its current
bankruptcy proceedings. See Note 10 for further discussion of Enron's bankruptcy
proceedings.

Enron serves as the operator for Citrus. Although Enron filed for
bankruptcy, there have been minimal changes in the operations and management of
Citrus as a result of their bankruptcy. Accordingly, Citrus has continued to
operate as a jointly owned investment, over which we have significant influence,
but not the ability to control.

Citrus has approximately $256 million in current maturities on its
long-term debt due in 2004 which it intends to fund through the utilization of
current working capital, future operating cash flows and the incurrence of
additional indebtedness, if necessary.

Bear Creek. We hold 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, 2003 and 2002, was $138 million and $128 million. Under El
Paso's $3 billion revolving credit facility, our ownership in Bear Creek is
currently pledged as part of the overall collateral for the facility.

39

Summarized income statement and balance sheet information of our
proportionate share of our unconsolidated affiliates for the years ended
December 31, 2003, 2002 and 2001 and as of December 31, 2003 and 2002 are as
follows:

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

(1) The difference between our proportionate share of our equity investments'
net income and our earnings from unconsolidated affiliates reflected in our
income statement and our proportionate share of their net equity and our
overall investment in the balance sheet are due primarily to timing
differences between the estimated and actual equity earnings from our
investments.

Transactions with Affiliates

We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. We had advanced $153 million at
December 31, 2003, at a market rate of interest which was 2.8%. At December 31,
2002, we had advanced $430 million at a market rate of interest which was 1.5%.
These receivables are due upon demand; however, we do not anticipate settlement
within the next twelve months. As of December 31, 2003 and 2002, we classified
$153 million and $369 million as non-current note receivables from affiliates.
See Note 2 for a discussion regarding our participation in and the
collectibility of these receivables.

In March 2003, we distributed dividends from retained earnings totaling
approximately $600 million to our parent including approximately $310 million of
outstanding affiliated receivables and approximately $290 million in cash.

We had accounts payable to affiliates of $8 million at December 31, 2003,
and $9 million at December 31, 2002. These balances arose in the normal course
of our business. As a result of El Paso's credit rating downgrades, we
maintained $10 million as of December 31, 2003 and 2002, in contractual deposits
related to our Elba Island capacity contracts with EPME as discussed below. As a
result of EPME assigning the capacity contracts to a subsidiary of British Gas,
BG LNG Services, LLC in December 2003 and BG Energy Holdings, Ltd., also a
subsidiary of British Gas, providing a parental guarantee, Southern LNG returned
these deposits to EPME in January 2004.

During 2002 and 2001, we sold natural gas to EPME and recognized revenues
of $2 million and $43 million. Natural gas sales to EPME during 2003 were less
than $1 million. During 2002, EPME subscribed to all the available capacity at
our Elba Island facility under a contract that extends to 2023. In 2003 and
2002, we recognized revenues of $28 million and $32 million related to this
contract. EPME assigned this contract to BG LNG Services, LLC in December 2003.
During 2003, 2002 and 2001, we transported gas for EPME and recognized
transportation revenue of $2 million, $4 million and $7 million. We
40

settled gas imbalance costs with EPME for the years ended 2003, 2002 and 2001
for $1 million, $2 million and $6 million. 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, 2003, 2002 and 2001 the annual charges
were $42 million, $41 million and $39 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 31, 2003, 2002 and 2001,
the annual charges were $8 million, $5 million and $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:

16. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Financial information by quarter is summarized below:

41

REPORT OF INDEPENDENT AUDITORS

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, 2003 and 2002, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003 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 did not audit the consolidated financial statements of
Citrus Corp. ("Citrus") for the year ended December 31, 2001. Citrus is an
equity investment of the Company that comprised income of $41 million for the
year ended December 31, 2001. Those statements were audited by other auditors
whose report thereon has been furnished to us, and our opinion expressed herein,
insofar as it relates to the amount included for Citrus, is based solely on the
report of the other auditors. 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.

As discussed in Note 2 to the consolidated financial statements, the
Company's parent, El Paso Corporation, may be in default of covenants contained
in its revolving credit facility and other financing transactions. Such an event
of default could have a material impact on the Company's liquidity. The waivers
have been obtained by El Paso Corporation, however, certain conditions must be
satisfied to continue the effectiveness of the waivers.

As discussed in Note 5, the Company adopted Statement of Financial
Accounting Standards No. 141, Business Combinations, and Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets on January 1,
2002.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama
March 24, 2004

42

SCHEDULE II

SOUTHERN NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN MILLIONS)

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

(1) Primarily payments made for environmental remediation.

43

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

None.

ITEM 9A. 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 over financial reporting (Internal Controls) as of the end
of the period covered by 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
Company's 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. 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. Therefore, 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. Our Disclosure Controls and Internal
Controls are designed to provide such reasonable assurances of achieving our
desired control objectives, and our principal executive officer and principal
financial officer have concluded that our Disclosure Controls and Internal
Controls are effective in achieving that level of reasonable assurance.

No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in
Southern Natural Gas Company's Internal Controls, or whether the company had
identified any acts of fraud involving personnel who have a significant role in
Southern Natural Gas Company's 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's Audit Committee and our independent auditors and to
report on related matters in this section of the Annual Report. The principal
executive officer and principal financial officer note that there has not been
any change in Internal Controls that occurred during the most recent fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, Internal Controls.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that the Disclosure Controls are effective to ensure that material information
relating to Southern Natural Gas Company and its consolidated subsidiaries is
made known to management, including the principal executive officer and
principal financial officer, on a timely basis.

44

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 as Exhibits to this Annual
Report.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of March 26, 2004,
regarding our executive officers and directors. Directors are elected annually
by our parent, and hold office until their successors are elected and duly
qualified. Each executive officer named in the following table has been elected
to serve until his successor is duly appointed or elected or until his earlier
removal or resignation from office.

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

John W. Somerhalder II has been Director and Chairman of the Board of
Southern Natural Gas since January 2000. Mr. Somerhalder has been Executive Vice
President of El Paso since April 2000. He has been Chairman of the Board of
Tennessee Gas Pipeline Company and El Paso Natural Gas Company since January
2000 and Chairman of the Board of ANR Pipeline Company and Colorado Interstate
Gas Company since January 2001. Mr. Somerhalder was President of Tennessee Gas
Pipeline from December 1996 to January 2000. He also served as Senior Vice
President of El Paso from August 1992 to April 1996. He also holds director
and/or officer positions with other of our affiliates.

James C. Yardley has been a Director and President of Southern Natural Gas
since May 1998. He served as Vice President, Marketing and Business Development
from April 1994 to April 1998. Prior to that time, Mr. Yardley served in various
positions with Southern Natural Gas and Sonat Inc. since 1978. He also holds
director and/or officer positions with other of our affiliates.

Greg G. Gruber has been a Director since June 2003 and has been Senior Vice
President and Chief Financial Officer since January 2001 and Treasurer of
Southern Natural Gas since November 2001. Mr. Gruber has served as Senior Vice
President, Chief Financial Officer and Treasurer of our affiliate Tennessee Gas
Pipeline since June 2003. He served as Senior Vice President and Chief Financial
Officer of Tennessee Gas Pipeline from January 2001 to June 2001. Prior to that
time, Mr. Gruber served as Vice President of Tennessee Gas Pipeline from January
1998 to January 2001. He also holds director and/or officer positions with other
of our affiliates.

We are a wholly owned subsidiary of El Paso and rely on El Paso for certain
support services. As a result, we do not have a separate corporate audit
committee or audit committee financial expert. Also, we have not adopted a
separate code of ethics. However, our executives are subject to El Paso's Code
of Business Conduct which is available for your review at El Paso's website,
www.elpaso.com.

ITEM 11. EXECUTIVE COMPENSATION

Our executive officers are compensated by us or TGP, our affiliate, for
their services in such capacities. The following table and narrative text sets
forth information concerning compensation paid by our affiliate to our president
(considered our "chief executive officer") and our two other most highly
compensated executive officers for services rendered to us and our affiliates in
all capacities for services rendered to us during the last three fiscal years.
We did not have any other executive officers other than the named executive
officers at the

45

end of 2003. The table also identifies the principal capacity in which each of
the executives served us at the end of 2003.

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

(1) The amount reflected in this column for Messrs. Somerhalder and Gruber are
amounts charged to us by TGP for the services rendered to us by Messrs.
Somerhalder and Gruber since they divide their time between service to us
and to our affiliates. Our affiliate pays Messrs. Somerhalder's and Gruber's
base salary and charges back an 8 percent allocation to us. The amount
charged back to us is derived by estimating the time and effort involved in
providing services to us. The amount reflected in this column for Mr.
Yardley reflects 100% of his base salary paid by us. Messrs. Somerhalder and
Gruber may also receive stock options, restricted stock, pension plan
benefits and other compensation and benefits from El Paso. Those benefits,
if any, are not charged directly to us and are, therefore, not reflected in
this table and not described elsewhere in this report. However, we do pay
TGP for certain general and administrative costs, which may include the
costs of certain compensation and benefits for officers (including Messrs.
Somerhalder and Gruber) and employees. The amounts reflected in the salary
column for 2003 and 2002 for Messrs. Somerhalder and Gruber include amounts
for El Paso mandated reductions to fund certain charitable organizations.

(2) For fiscal year 2001, El Paso's incentive compensation plans required
executives to receive a substantial part of their annual bonus in shares of
restricted El Paso common stock. The amounts reflected in this column for
Mr. Yardley for 2001 represent a combination of the market value of the
restricted common stock and cash at the time awarded under the applicable El
Paso incentive compensation plan.

(3) The amount reflected for Mr. Yardley in fiscal year 2002 is for a $36,000
perquisite and benefit allowance. Except as noted, the total value of the
perquisites and other personal benefits received by Mr. Yardley in fiscal
years 2003 and 2001 are not included in this column since they were below
the Securities and Exchange Commission's reporting threshold.

(4) For fiscal year 2001, El Paso's incentive compensation plans provided for
and encouraged participants to elect to take the cash portion of their
annual bonus award in shares of restricted common stock. The amount
reflected in this column for 2001 includes the market value of restricted
common stock on the date of grant. The value of the El Paso shares of stock
issued has declined significantly since the date of grant.

(5) For fiscal year 2003, the amount reflected in this column for Mr. Yardley is
the value of shares of restricted stock on the date they vested. These
shares had been reported in a long-term incentive table in El Paso's proxy
statement for the year in which those shares of restricted stock were
originally granted, along with the necessary performance measures necessary
for their vesting. No long-term incentive payouts were made in fiscal years
2002 and 2001. In addition to the amount reflected in this column for 2003,
Mr. Yardley realized $86,340 for the conversion of El Paso stock options
into shares of El Paso common stock.

46

(6) The compensation reflected in this column for fiscal year 2003 includes El
Paso's contributions to the El Paso Retirement Savings Plan and supplemental
company match for the Retirement Savings Plan under the Supplemental
Benefits Plan. Specifically, these amounts for fiscal year 2003 were $4,969
and $3,638 for Mr. Yardley. In addition, for fiscal year 2003 for Mr.
Yardley, the amount in this column includes the value of a special retention
payment in the amount $256,224.

EL PASO PENSION PLAN

Effective January 1, 1997, El Paso amended its pension plan to provide
pension benefits under a cash balance plan formula that defines participant
benefits in terms of a hypothetical account balance.

Effective January 1, 2000, an initial account balance was established for
each Sonat employee who was a participant in the Sonat pension plan (including
Mr. Yardley) on December 31, 1999 due to the merger of Sonat Inc.'s plan into El
Paso's pension plan. Prior to the pension plan merger, Sonat participants
received pension benefits under a plan (the "Prior Sonat Plan") that defined
monthly benefits based on final average earnings and years of service. The
initial account balance was equal to the present value of the Prior Sonat Plan
benefit as of December 31, 1999.

At the end of each calendar quarter, participant account balances are
increased by an interest credit based on 5-Year Treasury bond yields, subject to
a minimum interest credit of 4% per year, plus a pay credit equal to a
percentage of salary and bonus. The pay credit percentage is based on the sum of
age plus service at the end of the prior calendar year according to the
following schedule:

Under El Paso's pension plan and applicable Internal Revenue Code
provisions, compensation in excess of $200,000 cannot be taken into account and
the maximum payable benefit in 2003 was $160,000. Any excess benefits otherwise
accruing under El Paso's pension plan are payable under El Paso's Supplemental
Benefits Plan. Participants may elect to receive benefits in the form of either
a lump sum payment or actuarial equivalent monthly payments over a period of
time not less than five years and not more than the participant's remaining
life.

Participants with a Prior Sonat Plan benefit (including Mr. Yardley) are
provided pension benefits that equal the greater of the cash balance formula
benefit or the Prior Sonat Plan benefit accrued through the earlier of the date
of termination or December 31, 2004. The Prior Sonat Plan benefit is computed as
follows: (2.4% of the participant's average annual earnings during his five
years of highest earnings for each year of pre-92 service (up to a total of 25
years)) minus (2.0% of estimated social security benefit for each year of pre-92
service (up to a total of 25 years)) plus (2.0% of the participant's average
annual earnings during his five years of highest earnings for each year of
post-91 service (up to a total of 30 years)) minus (1.667% of estimated social
security benefit for each year of post-91 service (up to a total of 30 years)).
The result from this Prior Sonat Plan formula cannot exceed 60% of the
participant's average annual earnings during his five years of highest earnings
minus 50% of the estimated social security benefit.

Amounts reported under Salary and Bonus for Mr. Yardley in this Form 10-K
in the Summary Compensation Table approximate earnings as defined under the
pension plan.

Estimated annual benefits payable from the pension plan and Supplemental
Benefits Plan upon retirement at the normal retirement age (age 65) for Mr.
Yardley is reflected below (based on assumptions that Mr. Yardley receives base
salary shown in the Summary Compensation Table with no pay increases,

47

receives 25% of maximum annual bonuses beginning with bonuses earned for fiscal
year 2004, and cash balances are credited with interest at a rate of 4% per
annum):

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

(1) Mr. Yardley's credited service shown is as of December 31, 2004.

BENEFIT PLANS

The following is a description of El Paso benefit plans in which Mr.
Yardley does, or is eligible, to participate. While Messrs. Somerhalder and
Gruber may participate in these plans, because the costs of their participation
are not charged back to us we have not addressed their participation. However,
we do pay TGP for certain general and administrative costs, which may include
the costs of certain compensation and benefits for officers (including Messrs.
Somerhalder and Gruber) and employees. You should refer to El Paso's 2003 annual
report on Form 10-K and proxy statement, when filed, for additional information
on all of El Paso's benefit and equity plans and programs.

Severance Pay Plan. The Severance Pay Plan is a broad-based employee plan
providing severance benefits following a "qualifying termination" for all
salaried employees of El Paso and certain of its subsidiaries.

El Paso Key Executive Severance Protection Plan. This plan, initially
adopted in 1992, provides severance benefits following a "change in control" of
El Paso for certain officers of El Paso and certain of its subsidiaries,
including Mr. Yardley. The benefits of the plan include: (1) an amount equal to
three times the participant's annual salary, including maximum bonus amounts as
specified in the plan; (2) continuation of life and health insurance for an
18-month period following termination; (3) a supplemental pension payment
calculated by adding three years of additional credited pension service; (4)
certain additional payments to the terminated employee to cover excise taxes if
the payments made under the plan are subject to excise taxes on golden parachute
payments; and (5) payment of legal fees and expenses incurred by the employee to
enforce any rights or benefits under the plan. Benefits are payable for any
termination of employment for a participant in the plan within two years of the
date of a change in control, except where termination is by reason of death,
disability, for cause or instituted by the employee for other than "good reason"
(as defined in the plan). A change in control occurs if: (i) any person or
entity becomes the beneficial owner of 20% or more of El Paso's common stock;
(ii) any person or entity (other than El Paso) purchases the common stock by way
of a tender or exchange offer; (iii) El Paso stockholders approve a merger or
consolidation, sale or disposition or a plan of liquidation or dissolution of
all or substantially all of El Paso's assets; or (iv) if over a two year period
a majority of the members of the El Paso Board of Directors at the beginning of
the period cease to be directors. A change in control has not occurred if El
Paso is involved in a merger, consolidation or sale of assets in which the same
stockholders of El Paso before the transaction own 80% of the outstanding common
stock after the transaction is complete. This plan generally may be amended or
terminated at any time, provided that no amendment or termination may impair
participants' rights under the plan or be made following the occurrence of a
change in control. This plan is closed to new participants, unless the El Paso
Board determines otherwise.

El Paso Supplemental Benefits Plan. This plan provides for certain
benefits to officers and key management employees of El Paso and its
subsidiaries. The benefits include: (1) a credit equal to the amount that a
participant did not receive under El Paso's Pension Plan because the Pension
Plan does not consider deferred compensation (whether in deferred cash or
deferred restricted common stock) for purposes of calculating benefits and
eligible compensation is subject to certain Internal Revenue Code limitations;
and (2) a credit equal to the amount of El Paso's matching contribution to El
Paso's Retirement Savings Plan that cannot be made because of a participant's
deferred compensation and Internal Revenue Code limitations. The plan may not be
terminated so long as the Pension Plan and/or Retirement Savings Plan remain in
effect. The management committee of this plan designates who may participate and
also administers the plan. Benefits under El Paso's Supplemental Benefits Plan
are paid upon termination of employment in a lump-sum

48

payment, in annuity or in periodic installments. In the event of a change in
control (as defined under the El Paso Key Executive Severance Protection Plan),
the supplemental pension benefits become fully vested and nonforfeitable.

El Paso Senior Executive Survivor Benefits Plan. This plan provides
certain senior executives (including Mr. Yardley) of El Paso and its
subsidiaries who are designated by the plan administrator with survivor benefit
coverage in lieu of the coverage provided generally for employees under El
Paso's group life insurance plan. The amount of benefits provided, on an
after-tax basis, is two and one-half times the executive's annual salary.
Benefits are payable in installments over 30 months beginning within 31 days
after the executive's death, except that the plan administrator may, in its
discretion, accelerate payments.

EL PASO BENEFITS PROTECTION TRUST AGREEMENT

El Paso maintains a trust for the purpose of funding certain of its
employee benefit plans (including the El Paso Key Executive Severance Protection
Plan). The trust consists of a trustee expense account, which is used to pay the
fees and expenses of the trustee, and a benefit account, which is made up of
three subaccounts and used to make payments to participants and beneficiaries in
the participating plans. The trust is revocable by El Paso at any time before a
"threatened change in control" (which is generally defined to include the
commencement of actions that would lead to a "change in control" (as defined
under the El Paso Key Executive Severance Protection Plan)) as to assets held in
the trustee expense account, but is not revocable (except as provided below) as
to assets held in the benefit account at any time. The trust generally becomes
fully irrevocable as to assets held in the trust upon a threatened change in
control. The trust is a grantor trust for federal tax purposes, and assets of
the trust are subject to claims by El Paso's general creditors in preference to
the claims of plan participants and beneficiaries. Upon a threatened change in
control, El Paso must deliver $1.5 million in cash to the trustee expense
account. Prior to a threatened change in control, El Paso may freely withdraw
and substitute the assets held in the benefit account, other than the initially
funded amount; however, no such assets may be withdrawn from the benefit account
during a threatened change in control period. Any assets contributed to the
trust during a threatened change in control period may be withdrawn if the
threatened change in control period ends and there has been no threatened change
in control. In addition, after a change in control occurs, if the trustee
determines that the amounts held in the trust are less than "designated
percentages" (as defined in the Trust Agreement) with respect to each subaccount
in the benefit account, the trustee must make a written demand on El Paso to
deliver funds in an amount determined by the trustee sufficient to attain the
designed percentages. Following a change in control and if the trustee has not
been requested to pay benefits from any subaccount during a "determination
period" (as defined in the Trust Agreement), El Paso may make a written request
to the trustee to withdraw certain amounts which were allocated to the
subaccounts after the change in control occurred. The trust generally may be
amended or terminated at any time, provided that no amendment or termination may
result, directly or indirectly, in the return of any assets of the benefit
account to El Paso prior to the satisfaction of all liabilities under the
participating plans (except as described above) and no amendment may be made
unless El Paso, in its reasonable discretion, believes that such amendment would
have no material adverse effect on the amount of benefits payable under the
trust to participants. In addition, no amendment may be made after the
occurrence of a change in control which would (i) permit El Paso to withdraw any
assets from the trustee expense account, (ii) directly or indirectly reduce or
restrict the trustee's rights and duties under the trust, or (iii) permit El
Paso to remove the trustee following the date of the change in control.

EL PASO STOCKHOLDER APPROVED PLANS

El Paso 2001 Omnibus Incentive Compensation Plan. This plan provides for
the grant to officers and key employees of El Paso and its subsidiaries of stock
options, stock appreciation rights, limited stock appreciation rights,
performance units and restricted stock. A maximum of 6,000,000 shares in the
aggregate may be subject to awards under this plan. The plan administrator
designates which employees are eligible to participate, the amount of any grant
and the terms and conditions (not otherwise specified in the plan) of such
grant. If a "change in control" (defined in substantially the same manner as
under the El Paso Key Executive Severance Protection Plan) occurs: (1) all
outstanding stock options become fully exercisable; (2) stock

49

appreciation rights and limited stock appreciation rights become immediately
exercisable; (3) designated amounts of performance units become fully vested;
(4) all restrictions placed on awards of restricted common stock automatically
lapse; and (5) the current year's target bonus amount becomes payable for each
officer participating in the plan within 30 days, assuming target levels of
performance were achieved by El Paso and the officer for the year in which the
change in control occurs, or the prior year if target levels have not been
established for the current year, except that no bonus amounts will become
payable in connection with a change in control that results solely from a change
to the Board of Directors of El Paso. The plan generally may be amended or
terminated at any time. Any amendment following a change in control that impairs
participant's rights requires participant consent.

El Paso 1999 Omnibus Incentive Compensation Plan and El Paso 1995 Omnibus
Compensation Plan -- terminated plans. These plans provided for the grant to
eligible officers and key employees of El Paso and its subsidiaries of stock
options, stock appreciation rights, limited stock appreciation rights,
performance units and restricted stock. These plans have been replaced by the El
Paso 2001 Omnibus Incentive Compensation Plan. Although these plans have been
terminated with respect to new grants, certain stock options and shares of
restricted common stock remain outstanding under them. If a "change in control"
of El Paso occurs, all outstanding stock options become fully exercisable and
restrictions placed on restricted common stock lapse. For purposes of the plans,
the term "change in control" has substantially the same meaning given such term
in the El Paso Key Executive Severance Protection Plan.

EL PASO NON-STOCKHOLDER APPROVED PLANS

El Paso Strategic Stock Plan. This plan is an equity compensation plan
that has not been approved by the stockholders. This plan provides for the grant
of stock options, stock appreciation rights, limited stock appreciation rights
and shares of restricted common stock to non-employee members of the El Paso
Board of Directors, officers and key employees of El Paso and its subsidiaries
primarily in connection with El Paso's strategic acquisitions. A maximum of
4,000,000 shares in the aggregate may be subject to awards under this plan. The
plan administrator determines which employees are eligible to participate, the
amount of any grant and the terms and conditions (not otherwise specified in the
plan) of such grant. If a change in control, as defined earlier under the Key
Executive Severance Protection Plan, occurs: (1) all outstanding stock options
become fully exercisable; (2) stock appreciation rights and limited stock
appreciation rights become immediately exercisable; and (3) all restrictions
placed on awards of restricted common stock automatically lapse. The plan
generally may be amended or terminated at any time, provided that no amendment
or termination may impair a participant's current rights under the plan.

El Paso Restricted Stock Award Plan for Management Employees. This plan is
an equity compensation plan which has not been approved by the stockholders. The
plan provides for the granting of restricted shares of El Paso's common stock to
management employees (other than executive officers and directors) of El Paso
and its subsidiaries for specific accomplishments beyond that which are normally
expected and which will have a significant and measurable impact on the
long-term profitability of El Paso. A maximum of 100,000 shares in the aggregate
may be subject to awards under this plan. The plan administrator designates
which employees are eligible to participate, the amount of any grant and the
terms and conditions (not otherwise specified in the plan) of such grant. The
plan generally may be amended or terminated at any time, provided that no
amendment or termination may impair a participant's current rights under the
plan.

El Paso Omnibus Plan for Management Employees. This plan is an equity
compensation plan which has not been approved by the stockholders. This plan
provides for the grant of stock options, stock appreciation rights, limited
stock appreciation rights and shares of restricted common stock to salaried
employees (other than employees covered by a collective bargaining agreement) of
El Paso and its subsidiaries. A maximum of 58,000,000 shares in the aggregate
may be subject to awards under this plan. If a change in control, as defined
earlier under the Key Executive Severance Protection Plan, occurs: (1) all
outstanding stock options become fully exercisable; (2) stock appreciation
rights and limited stock appreciation rights become immediately exercisable; and
(3) all restrictions placed on awards of restricted common stock automatically
lapse. The plan generally may be amended or terminated at any time, provided
that no amendment or termination may impair a participant's current rights under
the plan.
50

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

None of our Common Stock is held by any director or executive officer. No
family relationship exists between any of our directors or executive officers.
The following information relates to the only entity known to us to be the
beneficial owner, as of March 26, 2004, of more than five percent of our voting
securities.

The following table sets forth, as of March 26, 2004, certain information
with respect to the following individuals to the extent they own shares of
common stock of El Paso, our parent.

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

* Less than 1%

(1) The directors and executive officers have the right to acquire the shares of
common stock reflected in this column within 60 days of March 26, 2004,
through the exercise of stock options.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

We are currently a wholly owned subsidiary of El Paso. El Paso owns 100% of
our outstanding stock and has the right to elect all of our directors. We share
office space, personnel, and other administrative services with El Paso. The
costs of such services are allocated by El Paso to us and other affiliates. As
described in Item 11 above, TGP, our affiliate, pays Messrs. Somerhalder's and
Gruber's base salary and charges back an 8 percent allocation to us, and we pay
100% of the costs associated with Mr. Yardley's employment. The amount charged
back to us is derived by estimating the time and effort involved in providing
services to us. In addition, there are other shared personnel that may include
officers who function as both our representatives and those of El Paso and its
subsidiaries. We pay TGP for certain general and administrative costs, which may
include the costs of certain compensation and benefits for officers (including
Messrs. Somerhalder and Gruber) and other employees. Some of these shared
directors, officers and employees own and are awarded from time to time shares,
or options to purchase shares, of El Paso; accordingly, their financial
interests may not always be aligned completely with ours.

Historically, El Paso's and its subsidiaries have contributed certain
assets and ownership interests to us. In March 2003, El Paso contributed its 50
percent ownership interest in Citrus to us. We were required to reflect this
investment in Citrus at its historical cost and include it in our financial
statements for all periods presented. Before we enter into such a transaction,
we determine whether the proposed transaction (i) would comply with the
requirements under our indentures and credit agreements, and (ii) would comply
with substantive law.

A discussion of certain agreements, arrangements and transactions between
or among us and El Paso and its subsidiaries is summarized in Part II, Item 8,
Financial Statements and Supplementary Data, Note 15.

51

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Audit Fees for the years ended December 31, 2003 and 2002 of $640,000
and $470,000 were for professional services rendered by PricewaterhouseCoopers
LLP for the audits of the consolidated financial statements of Southern Natural
Gas Company, the review of documents filed with the Securities and Exchange
Commission, consents, and the issuance of comfort letters. No other
audit-related, tax or other services were provided by our auditors for the years
ended December 31, 2003 and 2002.

We are a wholly owned subsidiary of El Paso and do not have a corporate
audit committee. El Paso's Audit Committee has adopted a pre-approval policy for
audit and non-audit services. For a description of El Paso's pre-approval
policies for audit and non-audit related services, see El Paso Corporation's
proxy statement.

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:

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

(B) REPORTS ON FORM 8-K.

None.

52

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2003, 2002 and 2001
with Report of Independent Auditor

53

CITRUS CORP. AND SUBSIDIARIES

TABLE OF CONTENTS

54

REPORT OF INDEPENDENT AUDITORS

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

In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income, stockholders' equity and cash flows
present fairly, in all material respects, the financial position of Citrus Corp.
and Subsidiaries (the "Company") at December 31, 2003 and 2002, and the results
of their operations and their cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
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

Houston, Texas
March 24, 2004

55

REPORT OF INDEPENDENT AUDITORS

Board of Directors
Citrus Corp.

We have audited the accompanying statements of income, stockholder's equity and
cash flows for the year ended December 31, 2001 of Citrus Corp. and
Subsidiaries. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by arrangement, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the financial statement referred to above present fairly, in all
material respects, the consolidated results of operations and cash flows of
Citrus Corp. and Subsidiaries for the years ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.

/s/ ERNST & YOUNG LLP

March 15, 2002
Birmingham, AL

56

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

The accompanying notes are an integral part of these consolidated financial
statements.
57

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

The accompanying notes are an integral part of these consolidated financial
statements.
58

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

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

The accompanying notes are an integral part of these consolidated financial
statements.
59

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

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

The accompanying notes are an integral part of these consolidated financial
statements.
60

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these consolidated financial
statements.
61

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) REPORTING ENTITY

Citrus Corp. (Citrus), a holding company formed in 1986, owns 100%
of the stock of Florida Gas Transmission Company (Transmission), Citrus
Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI),
collectively the Company. The stock of the Company is owned 50% by El
Paso Citrus Holdings, Inc. (EPCH), a wholly owned subsidiary of Southern
Natural Gas Company (Southern), as transferred by Southern in January
2004, and 50% by Enron Corp. (Enron). Southern's 50% ownership had
previously been contributed by its parent, El Paso Corporation (El Paso)
in March 2003. Pursuant to Enron's filed Plan of Reorganization, Enron
has formed a new operating entity, CrossCountry Energy LLC (CCE), and
intends to contribute its interest in the Company to a new wholly-owned,
direct subsidiary of CCE, CrossCountry Citrus Corp. Although bankruptcy
court approval for the contribution and separation has been received,
certain approvals are still required. These approvals are expected to be
completed in 2004.

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

Trading ceased all trading activities effective the fourth quarter
of 1997, but continues to fulfill its obligations under the remaining
gas purchase and gas sale contracts. Trading buys natural gas primarily
from an affiliate of Southern, El Paso Merchant Energy and sells to
Auburndale Power Partners, LP and Progress Energy Florida, Inc. Trading
is evaluating opportunities to sell or assign its remaining contracts.

CESI primarily provides transportation management and financial
services to customers of Transmission. CESI terminated its O&M business
due to increased insurance costs and pipeline integrity legislation that
affects operators.

In October 2002, and May and July 2003, Transmission and Trading
filed several claims and amendments of claims with the United States
Bankruptcy Court for the Southern District of New York against Enron and
other affiliated bankrupt companies, aggregating $220.6 million. Of
these claims, Transmission has filed claims totaling $68.1 million and
Trading totaling $152.5 million. Transmission and Trading claims
pertaining to contracts rejected by Enron North America Corp. (ENA) are
$29.5 million and $152.3 million, respectively (see Note 14).

(2) SIGNIFICANT ACCOUNTING POLICIES

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

PRINCIPLES OF CONSOLIDATION - The consolidated financial statements
include the accounts of the Company and its wholly owned subsidiaries.
All significant intercompany transactions and accounts have been
eliminated in consolidation.

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

MATERIALS AND SUPPLIES - Materials and supplies are valued at the
lower of cost or market value. Materials transferred out of warehouses
are priced out at average cost.

62

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(2) SIGNIFICANT ACCOUNTING POLICIES (continued)

REVENUE RECOGNITION - Revenues consist primarily of gas
transportation services. Reservation revenues on firm contracted
capacity are recognized ratably over the contract period. For
interruptible or volumetric based services, revenues are recorded upon
the delivery of natural gas to the agreed upon delivery point. Revenues
for all services are generally based on the thermal quantity of gas
delivered or subscribed at a price specified in the contract.
Transmission is subject to FERC regulations and, as a result, revenues
collected may be required to be refunded in a final order in the pending
rate proceeding (see Note 10) or as a result of a rate settlement.
Reserves are established for these potential refunds.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS - The Company engages in
price risk management activities for both trading and non-trading
activities and accounts for these under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities (see Note 4). Instruments
utilized in connection with trading activities are accounted for using
the mark-to-market method and are reflected at fair value as Assets and
Liabilities from Price Risk Management Activities in the Consolidated
Balance Sheets. Earnings from revaluation of price risk management
assets and liabilities are included in Other Income (Expense). Cash flow
hedge accounting is utilized for non-trading purposes to hedge the
impact of interest rate fluctuations. Unrealized gains and losses from
cash flow hedges are recognized according to SFAS No. 133 as other
comprehensive income, and subsequently recognized in earnings in the
same periods as the hedged forecasted transaction affects earnings. In
instances where the hedge no longer qualifies as effective, hedge
accounting is terminated prospectively and the accumulated gain or loss
is recognized in earnings in the same periods during which the hedged
forecasted transaction affects earnings. Where fair value hedge
accounting is appropriate, the offset that is attributed to the risk
being hedged is recorded as an adjustment to the hedged item.

PROPERTY, PLANT AND EQUIPMENT (See Note 11) -- Property, Plant and
Equipment consists primarily of natural gas pipeline and related
facilities. The Company amortizes that portion of its investment in
Transmission and other subsidiaries which is in excess of historical
cost (acquisition adjustment) on a straight-line basis at an annual
composite rate of 1.6% based upon the estimated remaining useful life of
the pipeline system. Transmission has provided for depreciation of
assets net of estimated salvage value, on a straight-line basis, at an
annual composite rate of 1.66%, 1.52%, and 1.53% for 2003, 2002, and
2001, respectively. The overall remaining useful life for Transmission's
assets at December 31, 2003, is 41 years.

Property, Plant and Equipment is recorded at its original cost.
Transmission capitalizes direct costs, such as labor and materials, and
indirect costs, such as overhead, interest and an equity return
component (see following paragraph). Costs of replacements and renewals
of units of property are capitalized. The original costs of units of
property retired are charged to the depreciation reserves, net of
salvage and removal costs. Transmission charges to maintenance expense
the costs of repairs and renewal of items determined to be less than
units of property.

The allowance for funds used during construction consists, in
general, of the net cost of borrowed funds used for construction
purposes and a reasonable rate on other funds when so used (the AFUDC
rate). The allowance is determined by applying the AFUDC rate to the
amount of construction work-in-progress. Capitalization begins at the
time the Company begins the continuous accumulation of costs in a
construction work order on a planned progressive basis and ends when the
facilities are placed in service.

The Company applies the provisions of SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets to account for asset
impairments. Under this standard, an asset is evaluated for impairment
when events or circumstances indicate that a long-lived asset's carrying
63

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(2) SIGNIFICANT ACCOUNTING POLICIES (continued)

value may not be recovered. These events include market declines,
changes in the manner in which an asset was intended to be used,
decisions to sell an asset, and adverse changes in the legal or business
environment such as adverse actions by regulators.

COMPRESSOR OVERHAUL EXPENDITURES - In 2003, Transmission changed
its method of accounting for compressor overhaul costs by adopting a
method of current expense recognition of compressor overhaul costs. This
change was the result of Management's determination that such costs
previously deferred would not be recovered through future tariff rates.
In prior years, such costs were deferred and amortized ratably over the
expected service life of the applicable overhaul item. A remaining
unamortized balance of $7.0 million applicable to the previous method
was expensed in 2003. An additional amount of $6.5 million related to
2003 overhaul costs, which would have been deferred under the previous
methodology, was also expensed.

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

TRADE RECEIVABLES - The Company establishes an allowance for
doubtful accounts on trade receivables based on the expected ultimate
recovery of these receivables. The Company considers many factors
including historical customer collection experience, general and
specific economic trends and known specific issues related to individual
customers, sectors and transactions that might impact collectibility.
Unrecovered trade accounts receivable charged against the allowance for
doubtful accounts were $0.3 and $22.2 million in 2003 and 2002,
respectively.

USE OF ESTIMATES - The preparation of financial statements in
conformity with accounting principles generally accepted in the United
States requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

RECLASSIFICATIONS - Certain reclassifications have been made to the
consolidated financial statements for prior years to conform with the
current year presentations with no impact on reported net income or
stockholders' equity.

64

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3) LONG-TERM DEBT AND OTHER FINANCING ARRANGEMENTS

Long-term debt outstanding at December 31, 2003, and 2002 was as
follows (in thousands):

Annual maturities and sinking fund requirements on long-term debt
outstanding as of December 31, 2003 were as follows (in thousands):

(1) Amortization of the debt premium and swap loss recognized on
financing arrangements.

Transmission's 8.63% Notes are due to be repaid in November 2004 in
the amount of $250 million. Also in 2004, Transmission has due an
additional $6.5 million under its 9.75% Notes. Management intends to
fund this $256.5 million in current maturities through the utilization
of current working capital, future operating cash flows and incurrence
of additional indebtedness. The portion of current obligations due which
are not repaid through current working capital and future operating cash
flows will be refinanced under new borrowing agreements or the
restoration of Transmission's ability to borrow on its $70 million
revolving credit facility (see below). Transmission may incur additional
debt to refinance maturing obligations if the refinancing does not
increase aggregate indebtedness, and thereafter, if Transmission and the
Company's consolidated debt does

65

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3) LONG-TERM DEBT AND OTHER FINANCING ARRANGEMENTS (continued)

not exceed specific debt to total capitalization ratios, as defined.
Incurrence of additional indebtedness to refinance the current
maturities would not result in a debt to capitalization ratio exceeding
these limits.

Citrus has note agreements that contain certain restrictions that,
among other things, limit the incurrence of additional debt, the sale of
assets, the payment of dividends, and maintaining certain restrictive
financial covenants. The agreements relating to Transmission's
promissory notes include, among other things, restrictions as to the
payment of dividends and maintaining certain restrictive financial
covenants. As of December 31, 2003, the Company was in compliance with
both affirmative and restrictive covenants of the note agreements.

All of the debt obligations of Citrus and Transmission have events
of default which contain commonly used cross-default provisions. An
event of default by either Citrus or Transmission on any of their
borrowed money obligations, in excess of certain thresholds which is not
cured within defined grace periods, would cause the other debt
obligations of Transmission and Citrus to be accelerated. As discussed
below, Transmission has obtained a waiver on its revolving credit
facility; however, there are no outstanding borrowings under this
facility which could cause an event of cross-default.

Transmission has a committed revolving credit agreement of $70
million (the "Revolver"), of which none was outstanding at December 31,
2003. The committed amount under this agreement was increased to $210
million in April 2002 then reduced to $70 million in July 2002. Citrus
absolutely and unconditionally guaranteed the obligations of
Transmission under the line of credit agreement. On October 28, 2002,
the Company sought and obtained a 60-day waiver (the "Waiver") of the
requirement of Trading to hedge any open gas contracts within 45 days of
knowledge of such open contracts (see Note 4). The Waiver has been
renewed periodically since it was initially granted. Under the Waiver,
Transmission is prohibited from drawing under the facility, but is
permitted to issue letters of credit, provided they are cash
collateralized (see Note 18).

Transmission has an aggregate of $0.6 million in letters of credit
under the revolving credit agreement. Per the terms of the Waiver, these
issued and outstanding letters of credit are collateralized with cash.
Cash collateral deposits of $2.6 million from Transmission and deposits
totaling $13.8 million from Trading were required in 2002 to support
fully collateralized issued letters of credit (see Note 12).

Citrus also had a line of credit of $30 million. Transmission
absolutely and unconditionally guaranteed the obligations of Citrus
under the line of credit agreement. Citrus terminated this line of
credit in 2002.

Citrus had also entered into a loan sales facility agreement in
2000 with a capacity of $40 million. Transmission had absolutely and
unconditionally guaranteed the obligations of Citrus under these
facilities. Citrus terminated this line of credit in 2002.

Transmission sold $250 million of 144A bonds without registration
rights in July 2002. These notes pay interest of 7% biannually on August
1 and February 1 of each year. The entire principal amount is due July
17, 2012.

In October 2003, Citrus paid the remaining principal of $78.8
million on the 11.100% Note due in 2006 and incurred a $0.7 million
pre-payment expense.

(4) DERIVATIVE INSTRUMENTS

The Company determined that its gas purchase contracts for resale
and related gas sales contracts are derivative instruments and records
these at fair value as price risk management assets
66

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(4) DERIVATIVE INSTRUMENTS (continued)

and liabilities under SFAS No. 133, as amended. The valuation is
calculated using a discount rate adjusted for the Company's borrowing
premium of 250 basis points, which creates an implied reserve for credit
and other related risks. The Company estimated the fair value of all
derivative instruments based on quoted market prices, current market
conditions, estimates obtained from third-party brokers or dealers, or
amounts derived using internal valuation models. In 2003, the Company
changed its method of presenting price risk management assets and
liabilities to reflect the fair market value of specific contracts. In
prior years, the Company presented price risk management assets and
liabilities at the net present value of the expected future cash flows
associated with the respective sales or purchase contracts. The prior
year balances for the price risk management assets and liabilities of
$684.7 million and $627.5 million, respectively, have been reclassified
to conform with the current year presentation. This change in
methodology does not have an impact on the consolidated statements of
income or cash flows. At December 31, 2003 and 2002, under the specific
contracts presentation, the fair value for the price risk management
assets and liabilities was $73.5 million and $105.6 million, and $148.1
million and $79.9 million, respectively. The Company performs a
quarterly revaluation on the carrying balances that is reflected in
current earnings. The impact to earnings from revaluation, mostly due to
price fluctuations and contract status, was a loss of $20.6, $22.9, and
$0.0 million for 2003, 2002, and 2001, respectively.

ENA ceased performing under its purchase and sales contracts with
Trading in December 2001. Subsequent to such date, Trading assumed
responsibility for performance under the respective contracts and
continued to transact business under the terms of these contracts
throughout 2003 and 2002. As a result of the foregoing, Trading has
reported revenues and expenses under such contracts on a gross basis for
the years ended December 31, 2003 and 2002, due to Trading becoming the
primary obligor under such contracts. Prior to 2002, such revenues and
costs were reported net, as a component of Other Income (Expense) in the
statements of income due to ENA bearing the primary obligations of such
contracts.

Prior to the Enron bankruptcy, the principal counterparty to
Trading's gas purchase and sale agreements (as well as swaps) was ENA.
ENA has rejected these contracts in bankruptcy. A pre-petition gas
purchase payable to ENA of $12.4 million was reversed in 2003 when it
was determined that the Company had a right of offset against claims for
pre-petition receivables. Pursuant to an existing operating agreement
(rejected by ENA in 2003 but under which an El Paso affiliate is still
performing), an affiliate of El Paso was required to buy gas, purchased
from a significant third party, that exceeded the requirements of
existing sales contracts. Under this third party contract, gas was
purchased primarily at rates based upon a formula. This gas was then
sold primarily at market rates. On April 16, 2003, the significant third
party supplier terminated the supply contract. Trading currently only
purchases the requirements to fulfill existing sales contracts from
third parties at market rates. As a result of these developments, the
cash flow stream is now dependent on variable pricing, whereas before
Enron's bankruptcy, the cash flow stream was fixed. The quarterly
valuations are based on management's best estimate of the fair value of
the underlying contracts. Changes in the future pricing projections
could lead to material differences in the valuation of the derivative
instruments.

Due to a dispute (see Note 14) during 2003, Duke Energy LNG Sales,
Inc. (Duke) discontinued performance under a natural gas purchase and
supply contract between it and Trading and subsequently terminated the
contract. As a result of this contract termination, during 2003, Trading
discontinued the application of fair market value accounting for this
contract, and wrote off the value of the related price risk management
assets as a charge to Other Income/(Expense) in the accompanying
statement of operations. Pursuant to the terms of the contract and also
during 2003, Trading issued to Duke, the counterparty, a termination
invoice for approximately $187 million. As a
67

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(4) DERIVATIVE INSTRUMENTS (continued)

result of the ongoing litigation regarding this matter, the termination
invoice amount was recognized net of appropriate reserves, as an
offsetting gain to Other Income/(Expense) and as a long term receivable
of $72.5 million in Other Deferred Charges (see Note 12).

During 2001, Transmission entered into an interest rate swap
transaction to hedge the fair value risk associated with $135 million of
existing long-term fixed rate debt. This transaction qualified and was
accounted for as a fair value hedge in accordance with SFAS No. 133.
Fair value recognition of this hedging instrument resulted in $3.2
million being recorded to price risk management liabilities and as an
offset to long-term debt at December 31, 2001. This instrument was
terminated in May 2002 with a fair value loss of $2.6 million being
recorded in long term debt, which is being amortized over the life of
the debt issued as an adjustment to interest expense.

During 2002, Transmission initiated a new swap to hedge interest
rate changes which could occur between the initiation date of the swap
and the issuance date of the July 2002 $250 million note offering. The
aggregate notional amount of this swap was $250 million. This swap was
terminated effective July 18, 2002. The $12.3 million fair value loss at
the termination of the swap agreement was recognized as other
comprehensive loss and is being amortized over the life of the related
debt issue as an adjustment to interest expense.

(5) INCOME TAXES

The principal components of the Company's net deferred income tax
liabilities at December 31, 2003, and 2002 are as follows (in
thousands):

68

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(5) INCOME TAXES (continued)

Total income tax expense for the years ended December 31, 2003,
2002 and 2001 is summarized as follows (in thousands):

The differences between taxes computed at the U.S. federal
statutory rate of 35% and the Company's effective tax rate for the years
ended December 31, 2003, 2002, and 2001 are as follows (in thousands):

The Company has an alternative minimum tax (AMT) credit which can
be used to offset regular income taxes payable in future years. The AMT
credit has an indefinite carry-forward period. For financial statement
purposes, the Company has recognized the benefit of the AMT credit
carry-forward as a reduction of deferred tax liabilities.

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

(6) EMPLOYEE BENEFIT PLANS

The employees of the Company are covered under Enron's employee
benefit plans. Enron maintains the Enron Corp. Cash Balance Plan
("Plan"), which is a noncontributory defined benefit pension plan to
provide retirement income for employees of Enron and its subsidiaries.
Through December 31, 1994, participants in the Enron Corp. Retirement
Plan with five years or more of service were entitled to retirement
benefits in the form of an annuity based on a formula that used a
percentage of final average pay and years of service. In 1995, Enron's
Board of Directors adopted an amendment to and restatement of the
Retirement Plan, changing the plan's name from the Enron Corp.
Retirement Plan to the Enron Corp. Cash Balance Plan. In connection with
a change to the retirement benefit formula, all employees became fully
vested in retirement benefits earned through December 31, 1994. The
formula in place prior to January 1, 1995 was suspended and replaced
with a benefit accrual in the form of a cash balance of 5% of eligible
annual base pay beginning on

69

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(6) EMPLOYEE BENEFIT PLANS (continued)

January 1, 1996. Pension expenses charged to the Company by Enron were
$1.9, $1.7, and $.7 million for 2003, 2002, and 2001, respectively.

Enron initiated steps to terminate the Cash Balance Plan in 2003.
Effective January 1, 2003, Enron suspended the 5% benefit accruals under
the Cash Balance Plan. Each employee's accrued benefit will continue to
be credited with interest based on ten-year Treasury Bond yields.
Because the Company is not part of an Enron "controlled group," as
provided by Section 414(b) and (c) of the Internal Revenue Code of 1986,
as amended, if the Plan were to be terminated or if the Company were to
withdraw from participation in the Plan, the Company would be liable for
only its proportionate share of any under-funding that may exist in the
Plan at the time of such termination or withdrawal. On December 31,
2003, Enron Corp filed a motion with the Bankruptcy Court seeking
authorization to contribute up to $200 million to fully fund and
terminate the Cash Balance Plan and other pension plans of related
debtor companies and affiliates. The Bankruptcy Court approved the
motion on January 29, 2004. On February 5, 2004, Enron's Board of
Directors voted to amend and terminate the Enron Corp. Cash Balance
Plan. The Cash Balance Plan's official termination date is currently set
for May 31, 2004. Before the Plan can be terminated, Enron must comply
with certain federal regulatory requirements, including filing for
necessary approvals and notifying Cash Balance Plan participants of the
Plan termination at least 60 days prior to the termination date. Both
the Pension Benefit Guaranty Corporation ("PBGC") and the Internal
Revenue Service ("IRS") must approve the termination of the Plan (the
IRS needs to determine that the Plan is tax-qualified as of the date of
termination). In 2003, the Company recognized its portion of the
expected Cash Balance Plan settlement by recording a $9.6 million
current liability, and a charge to operating expense. The Company will
seek to recover this expense from its customers through the pending rate
case proceeding. Several creditors, including the PBGC, have filed
objections to Enron's Chapter 11 Plan. The PBGC is arguing that $200
million may be insufficient to fund the plans filed for termination in
Enron's December 31, 2003, motion with the Bankruptcy Court. The
Bankruptcy Court has scheduled a hearing for April 20, 2004, on the
Chapter 11 Plan. Based on the current status of the Cash Balance Plan
settlement and the amount expected to be allocated to the Company as its
proportionate share of the plan's termination liability, the Company
believes this accrual is adequate but not excessive. Although there can
be no assurance that amounts ultimately allocated to and paid by the
Company will not be materially different, we do not believe that the
ultimate resolution of this matter will have a materially adverse effect
on the Company's consolidated financial position or cash flows, but it
could have significant impact on the results of operations in future
periods.

Enron provides certain post-retirement medical, life insurance and
dental benefits to eligible employees and their eligible dependents. The
net periodic post-retirement benefit costs charged to the Company by
Enron were $1.2, $1.3, and $1.2 million for 2003, 2002, and 2001,
respectively. Substantially all of these relate to Transmission and are
being recovered through rates.

Certain retirees of Transmission were covered under a deferred
compensation plan managed and funded by Enron subsidiaries, one
previously sold and the other now in bankruptcy. This matter has been
included as part of the claim filed by Transmission in bankruptcy
against Enron and other affiliated bankrupt companies. Transmission has
not conceded that it has a legal responsibility to fund the obligations
to these certain retirees, but has approved certain payments in the past
in order to avoid litigation. If such obligation were deemed to be a
liability to Transmission, the range of exposure is $0 to approximately
$2.0 million. Transmission does not believe that the ultimate resolution
of this matter will have a materially adverse effect on operating
results, financial position or cash flow.

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(7) MAJOR CUSTOMERS

Revenues from individual third party and affiliate customers
exceeding 10% of total revenues for the years ended December 31, 2003,
2002, and 2001 were approximately as listed below (in millions). Due to
the early adoption of SFAS No. 133, Trading's gas sales transactions for
the period ended December 31, 2001 were not reported as revenues to the
Company. All amounts had been reported net in Other Income (Expense).
Beginning in 2002, the revenues and expenses are reported separately
(see Note 4).

At December 31, 2003, and 2002, the Company had receivables of
approximately $15.1 and $15.4 million from Florida Power & Light
Company. At December 31, 2003, and 2002, the Company had a prepayment of
approximately $0.4 and a receivable of approximately $7.8 million from
El Paso Merchant Energy.

(8) RELATED PARTY TRANSACTIONS

In December 2001, Enron and certain of its subsidiaries filed
voluntary petitions for Chapter 11 reorganization with the U.S.
Bankruptcy Court. The Company was not included in the bankruptcy filing,
and Management believes that the Company will continue to be able to
meet its own operational and administrative service obligations.

The Company incurs certain corporate administrative expenses from
Enron and its affiliates. These services include administrative, legal,
compliance, and pipeline operations emergency services. The arrangement
was historically governed by the provisions of an operating agreement
between an Enron affiliate and the Company which expired on June 30,
2001, and which has not been extended. However, Enron subsidiaries have
continued to provide services under the terms of the original operating
agreement. The Company reimburses the Enron subsidiaries for costs
attributable to the operations of the Company. The Company expensed
approximately $13.0, $14.9, and $13.8 million for these charges for the
years ended December 31, 2003, 2002, and 2001, respectively.

Services provided by bankrupt Enron affiliates are allocated to the
Company pursuant to a Bankruptcy Court ordered allocation methodology.
Under that methodology the Company is obligated to pay allocated
amounts, subject to certain terms and conditions. Consistent with these
terms and conditions, the Company accrues and pays the full amount for
services it receives directly from the bankrupt Enron affiliates.
Indirect Enron service allocations are capped commensurate with 2001
levels. In 2002, the Company was allocated $32.7 million, of which it
paid $2.1 million for indirect services and $10.7 million for direct
services. Enron accepted this settlement in 2003. In 2003, the Company
accrued $2.1 million for indirect services and $9.4 million for direct
services, and has paid a total of $10.1 million, of which $7.5 million
was paid as of December 31, 2003. Final 2003 allocations will not be
completed until mid-2004; however, the Company believes its 2003
accruals reflect reasonable estimates of services received.

The Company provides natural gas sales and transportation services
to Enron and El Paso affiliates at rates equal to rates charged to
non-affiliated customers in the same class of service. Revenues related
to these transportation services were approximately $0.0, $0.4, and $3.4
million from Enron affiliates and $5.3, $5.7, and $3.6 million from El
Paso affiliates for the years ended December 31, 2003, 2002, and 2001,
respectively. The Company's gas sales were approximately

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(8) RELATED PARTY TRANSACTIONS (continued)

$0.0, $0.0, and $343.7 million to Enron affiliates and $9.2, $55.2, and
$14.5 million to El Paso affiliates for the years ended December 31,
2003, 2002, and 2001, respectively. The Company also purchased gas from
affiliates of Enron of approximately $3.7, $0.0, and $216.9 million and
from affiliates of El Paso of approximately $26.9, $19.9, and $100.5
million for the years ended December 31, 2003, 2002, and 2001,
respectively. Transmission also purchased transportation services from
Southern in connection with its Phase III Expansion completed in early
1995. Transmission contracted for firm capacity of 100,000 Mcf/day on
Southern's system for a primary term of 10 years, to be continued for
successive terms of one year each thereafter unless cancelled by either
party, by giving 180 days notice to the other party prior to the end of
the primary term or any yearly extensions thereof. The amount expensed
for these services totaled $6.6, $6.9, and $6.7 million for the years
ended December 31, 2003, 2002, and 2001, respectively.

Effective the fourth quarter of 1997, the operations of the
contracts held by Trading were divided between affiliates of Enron and
El Paso. The fee charged, for services such as scheduling, billing, and
other back office support, is based on a volumetric payment of
$.005/MMBtu, or approximately 50% of the prior arrangement. During 2003,
Trading accrued and paid $0.015 million to El Paso Merchant Energy and
accrued $0.079, and paid $0.243 million, (for all post-petition items)
to ENA, for administrative fees. Under this agreement, Trading was
guaranteed an earnings stream based on all firm long-term contracts in
place at November 1, 1997. The earnings stream now fluctuates due to the
variable pricing currently in effect, the result of ENA rejecting all
aspects of certain agreements in bankruptcy proceedings. As of September
8, 2003, Trading assumed operating responsibilities relating to the
securing of all supply not provided by El Paso Merchant Energy and
scheduling of volumes. See Note 4 for additional details.

The Company either jointly owns or licenses with other Enron
affiliates certain computer and telecommunications equipment and
software that is critical to the conduct of its business. In other
cases, such equipment or software is wholly-owned by such affiliates,
and the Company has no ownership interest or license in or to such
equipment or software. Transmission participated in business
applications that are shared among the Enron pipelines. All
participating pipelines use the same common base system and also have a
custom pipeline-specific component. Each pipeline pays for its custom
development component and shares in the common base system development
costs. There are specific software licenses that were entered into by an
Enron affiliate that entitle Transmission to usage of the software
licenses. Fees for this arrangement are included in the amounts paid for
corporate administrative expenses.

Transmission is a party to a Participation Agreement, dated
effective as of November 1, 2002, with Enron and Enron Net Works to
provide Electronic Data Interchange (EDI) services through an
outsourcing arrangement with EC Outlook. Enron renegotiated an existing
agreement with EC Outlook that lowered the cost of EDI services and that
also provided the means for Transmission to be compliant with the most
recent North American Energy Standards Board (NAESB) EDI standards. The
contract has a termination date of November 30, 2005. Fees for this
arrangement are included in the amounts paid for corporate
administrative expenses.

Transmission has a construction reimbursement agreement with ENA
under which amounts owed to Transmission are delinquent. These
obligations (including post-petition interest which cannot be collected)
total approximately $7.4 million and are included in Transmission's
filed bankruptcy claims. These receivables were fully reserved by
Transmission prior to 2003. Transmission has also filed proofs of claims
regarding other claims against ENA in the bankruptcy proceeding (see
Note 14). In its rate case filed with the FERC (see Note 10),
Transmission has proposed to recover the estimated under-recovery on
this obligation by rolling in the costs of the facilities

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(8) RELATED PARTY TRANSACTIONS (continued)

constructed, less the estimated recovery from ENA, into its rates.
However, Transmission cannot predict the amounts, if any, that it will
collect or the timing of collection.

In addition to the above Transmission claim against ENA, Trading
has filed proofs of claims against ENA totaling $152.3 million for
commodity and financial transactions operable prior to ENA's bankruptcy.
Recovery of certain of these claimed amounts is interrelated with
Trading's gas purchase counterparty litigation and associated Other
Deferred Charge (see Notes 4 and 14).

Transmission entered into a 20-year compression service agreement
with Enron Compression Services Company (ECS) in April 2002. This
agreement requires Transmission to pay ECS to provide electric
horsepower capacity and related horsepower hours to be used to operate
Compressor Station No. 13A, which consists of an electric compressor
unit. Amounts paid to ECS in 2003 and 2002 totaled $2.3 and $1.5 million
respectively. Under related agreements, ECS is required to pay
Transmission an annual lease fee and a monthly operating and maintenance
fee to operate and maintain the facilities. Amounts received from ECS in
2003 and 2002 for these services were $0.4 and $0.3 million,
respectively. A Netting Agreement, dated effective November 1, 2002, was
executed with ECS, providing for the netting of payments due under each
of the O&M, lease, and compression service agreements with ECS.

(9) CASH FLOW STATEMENT RECLASSIFICATION

During 2000, Trading entered into a commodity transaction with an
Enron affiliate as follows. Trading entered into three agreements, each
dated December 1, 2000. Under the first agreement, Trading contracted to
purchase approximately 12 million MMBtu of gas from an Enron affiliate
at $6.65 per MMBtu with payment due by Trading in December 2000. In the
second agreement, Trading contracted to sell 12 million MMBtu of gas to
the same Enron affiliate in December 2000 at $6.67536 per MMBtu, with
payment due from the Enron affiliate in January 2001. In the third
agreement, Trading and the same Enron affiliate exchanged the two 12
million MMBtu gas delivery obligations under the prior two agreements;
Trading was paid an exchange fee of $0.01051 per MMBtu. This third
agreement had the effect of canceling obligations for physical delivery
of gas by Trading and the Enron affiliate to each other under the prior
two agreements, with only the financial obligations remaining. As a
result of these related transactions, Trading paid the Enron affiliate
approximately $80 million in December 2000 and received approximately
$80.4 million in January 2001. In addition, in December 2000 Trading
agreed to pay the same Enron affiliate approximately $20 million in
December instead of January 2001 on an existing gas contract for which
Trading was paid a fee for this early payment. This fee was included in
the total cost of funds to Trading (both for the $80 million arrangement
and the $20 million early payment) that was recovered through the margin
the Enron affiliate agreed to pay Trading under the second agreement and
the exchange fee the Enron affiliate agreed to pay Trading under the
third agreement described above. Trading's favorable cash flow variance
in 2001 resulting from these transactions with the Enron affiliate was
partially offset by higher interest payments and increased income tax
payments in 2001.

In conjunction with the 2003 development and filing of the Enron
bankruptcy plan of reorganization, Enron evaluated selected affiliate
transactions, including the $80 million gas sales, purchase and exchange
agreements between Trading and an Enron affiliate during December 2000
and January 2001, discussed above. The Company originally reflected the
transactions as operating cash flows. Based on an analysis of all
available information from both Trading and Enron, the Company
determined the transactions were in substance a financing for the
benefit of the Enron affiliate and has reclassified the cash flows from
operations to financing.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(10) REGULATORY MATTERS

Transmission's currently effective rates were established pursuant
to a Stipulation and Agreement (Rate Case Settlement) which resolved all
issues in Transmission's Natural Gas Act (NGA) Section 4 rate filing in
FERC Docket No. RP96-366. The Rate Case Settlement, approved by FERC
Order issued September 24, 1997, provided that Transmission could not
file a general rate case to increase its base tariff rates prior to
October 1, 2000 (except in certain limited circumstances) and must file
no later than October 1, 2001, since extended to October 1, 2003
pursuant to the Phase IV settlement discussed below. The Rate Case
Settlement also provided that the rates charged pursuant to
Transmission's Firm Transportation Service (FTS) rate schedule FTS-2
would decrease effective March 1, 1999 and March 1, 2000.

On October 1, 2003, Transmission filed a general rate case,
proposing rate increases for all services, based upon a cost of service
of approximately $165 million for the pre-expansion system and
approximately $342 million for the incremental system. Based on Test
Period reservation and usage determinants, the proposed rate increase
under all Rate Schedules, ignoring the impact of existing rate caps,
negotiated rates, and discounts, would generate approximately $56
million in additional annual transportation revenues for Transmission.
The overall return requested is 11.81%, reflecting an 8.64% cost of debt
and a 14.50% return on common equity, and is based on a capital
structure of 45.92% debt and 54.08% equity. The cost of service for the
pre-expansion system includes an increase in the depreciation rate
applicable to onshore facilities, from 2.13% to 3.00%. In addition,
Transmission has proposed certain revisions to various rate schedules.
Other prospective changes proposed include the change to a traditional
cost-of-service rate design (with straight-line depreciation, as opposed
to variable depreciation under the currently-effective levelized rates)
for the expansion system, a tracker for certain types of significant
capital costs, and compliance with Order No. 637. A number of parties
protested the rates. By order dated October 31, 2003, FERC suspended the
proposed rates for five months (until April 1, 2004); set the tariff
revisions limiting rights to convert FTS-1 service to Small Firm
Transportation Services (SFTS), and setting a minimum volume for No
Notice Transportation Service (NNTS) service for a technical conference;
set all other issues for hearing; accepted the tariff change with regard
to limiting reservation charge credits but only in cases of force
majeure events (thus, in force majeure events, Transmission would only
be required to refund to customers the return and related income tax
components of its rates). Transmission made the required compliance
filing and several customers protested, to which Transmission filed an
answer in opposition. FERC staff has issued its initial position on a
number of issues. At a technical conference held on January 7, 2004,
Transmission agreed to withdraw its NNTS minimum volume proposal,
subject to certain customers withdrawing their nominations. An initial
settlement conference was held on March 11, 2004; the next settlement
conference is set for March 30. In the event a settlement is not
achieved, the hearing is set for August 31, 2004.

On December 1, 1998, Transmission filed an NGA Section 7
certificate application with the FERC in Docket No. CP99-94-000 to
construct 205 miles of pipeline in order to extend the pipeline to Ft.
Myers, Florida and to expand capacity by 272,000 MMBtu/day (Phase IV
Expansion). Expansion costs were estimated at $351 million. Transmission
requested that expansion costs be rolled into the rates applicable to
FTS-2 (Incremental) service. On June 2, 1999, Transmission filed a
Stipulation and Agreement (Phase IV Settlement) which resolved all
non-environmental issues raised in the certificate proceeding and
modified the Rate Case Settlement to provide that Transmission cannot
file a general rate case to increase its base tariff rates prior to
October 1, 2001 (except in certain limited circumstances), and must file
no later than October 1, 2003. The Phase IV Settlement was approved by
the FERC by order issued July 30, 1999, and became effective thirty days
after the date that Transmission accepted an order issued by the FERC
approving the Phase IV Expansion project. On August 23, 1999,
Transmission amended its application on file with the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(10) REGULATORY MATTERS (continued)

FERC to eliminate a portion of the proposed facilities (that would be
delayed until the Phase V Expansion). The amended application reflected
the construction of 139.5 miles of pipeline and an expansion of capacity
in order to provide incremental firm service of 196,405 MMBtu on an
average annual day, with estimated project costs of $262 million. The
Phase IV Expansion was approved by FERC order issued February 28, 2000,
and accepted by Transmission on March 29, 2000. The Phase IV Expansion
was placed in service on April 30, 2001. Total costs through December
31, 2003, were $246 million.

On December 1, 1999, Transmission filed an NGA Section 7
certificate application with the FERC in Docket No. CP00-40-000 to
construct 215 miles of pipeline and 90,000 horsepower of compression and
to acquire an undivided interest in the existing Mobile Bay Lateral
owned by Koch Gateway Pipeline Company (now Gulf South Pipeline Company,
LP), in order to expand the system capacity to provide incremental firm
service to several new and existing customers of 270,000 MMBtu on an
average annual day (Phase V Expansion). Expansion and acquisition costs
were estimated at $437 million. Transmission requested that expansion
costs be rolled into the rates applicable to FTS-2 (Incremental)
service. On August 1, 2000, and September 29, 2000, Transmission amended
its application on file with the FERC to reflect the withdrawal of two
customers, the addition of a new customer and to modify the facilities
to be constructed. The amended application reflected the construction of
167 miles of pipeline and 133,000 horsepower of compression to create
additional capacity to provide 306,000 MMBtu of incremental firm service
on an average annual day. The estimated cost of the revised project is
$462 million. The Phase V Expansion was approved by FERC Order issued
July 27, 2001, and accepted by Transmission on August 7, 2001. Segments
of the Phase V Expansion project were placed in service in December
2001, March 2002, and April 2003, respectively. Total costs through
December 31, 2003, were $417 million.

On November 15, 2001, Transmission filed an NGA Section 7
certificate application with the FERC in Docket No. CP02-27-000 to
construct 33 miles of pipeline and 18,600 horsepower of compression in
order to expand the system to provide incremental firm service to
several new and existing customers of 85,000 MMBtu on an average day
(Phase VI Expansion). Expansion costs were estimated at $105 million.
Transmission requested the expansion costs be rolled into rates
applicable to FTS-2 (Incremental) service. The application was approved
by FERC Order issued on June 13, 2002, and accepted by Transmission on
July 19, 2002. Clarification was granted and a rehearing request of a
landowner was denied by FERC Order of September 3, 2002. The Phase VI
Expansion was completed and placed in service during 2003 with the
exception of the compressor station modifications at stations 12, 15,
and 24. Compressor station modifications at stations 12 and 24 were
completed and placed in-service on January 31, 2004, and February 1,
2004, respectively. Modifications at compressor station 15 are scheduled
to be completed by April 15, 2004. Total costs through December 31,
2003, were $73 million.

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. On July 25, 2003, the FERC issued its
"Modification of Negotiated Rate Policy", in which it determined that it
"will no longer permit the use of gas basis differentials to price
negotiated rate transactions." On August 25, 2003, the Interstate
Natural Gas Association of America (INGAA) filed a request for rehearing
of this ruling. On September 12, 2003, the Commission issued an order
granting rehearing for the purposes of further consideration, thus,
tolling the statutory time in which the FERC is required to act. On
December 18, 2003, the Commission issued orders in two cases,
essentially reversing this ruling for rates that will remain between the
minimum and maximum tariff rates. Transmission has only two negotiated
rate agreements, and both of these are at or below Transmission's
currently effective maximum tariff rates as well as the proposed rates
in the 2003 rate case (see note on rate
75

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(10) REGULATORY MATTERS (continued)

case above). Thus, Transmission does not anticipate its negotiated rate
transactions being impacted by this rulemaking. At this time,
Transmission cannot predict the outcome of this NOI.

On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking
(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. The FERC held a public conference on
September 25, 2002, to discuss the issues raised in 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. On June 26, 2003, the FERC issued an Interim Rule requiring
that cash management agreement be in writing, specify the duties and
responsibilities of the participants, specify the methods for
calculating interest and for allocating interest income and expenses,
and specify any restriction on deposits or borrowing by participants.
Since Transmission does not participate in a cash management pool,
Transmission does not anticipate that this rule will have an impact. The
Interim Rule also required that pipelines notify the FERC when their
proprietary capital ratio drops below 30 percent. In addition, in the
Interim Rule the FERC sought further comments on these requirements. On
October 23, 2003, the FERC issued its Final Rule, which adopted the
requirement of the Interim Rule to file cash management agreements with
the FERC. The Final Rule also required that pipelines must notify the
FERC within 45 days after the end of each calendar quarter if their
proprietary capital ratios drop below or subsequently exceed 30 percent.
In its Final Rule requiring quarterly financial reporting, issued
February 11, 2004, the FERC lifted the requirement to notify the FERC
when proprietary capital drops below or rises above 30 percent.

In 2002, Transmission was subject to an industry wide nonpublic
investigation of the FERC Form 2 (FERC's annual report) focusing on cash
management or transfers between Transmission and Enron or affiliated
companies. By order issued September 8, 2003, the FERC determined that
Transmission was generally in compliance. However, the FERC found that
because Transmission was in a cash management pool during the time of
the audit and because best management practices require a written cash
management plan, Transmission ought to have a written cash management
plan. On October 8, 2003, Transmission sought clarification or, in the
alternative, rehearing of the order that Transmission did not have to
have a written cash management plan at this time because Transmission
was not now participating in a cash management pool. On December 4,
2003, the FERC issued an order granting Transmission's request for
clarification.

In April 2002, FERC and the Department of Transportation, Office of
Pipeline Safety convened a technical conference to discuss how to
clarify, expedite, and streamline permitting and approvals for
interstate pipeline reconstruction in the event of a natural or other
disaster. 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 by INGAA on February 27, 2003. On May
19, 2003 the FERC issued Order
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CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(10) REGULATORY MATTERS (continued)

No. 633, promulgating a final rule that allows pipelines to start
construction to replace mainline facilities without the normal 45-day
notice period when immediate action is required to restore service. This
rule will impact Transmission only in the event of an emergency action.
In such event, Transmission expects that the rule would expedite
replacement or repair of facilities, thereby reducing any service
interruption period.

On November 25, 2003, the FERC issued Order No. 2004 making
significant changes in the Standards of Conduct ("SOC") governing the
relationships between pipelines and Energy Affiliates. The new SOC
applies to a greater number of affiliates, requires more reporting, and
requires appointment of a compliance officer. On December 24, 2003,
INGAA filed a request for rehearing. On January 20, 2004, the Commission
issued an order granting rehearing for the purposes of further
consideration, thus, tolling the statutory time in which the FERC is
required to act. At this time, Transmission cannot predict the final
outcome of the proceeding. On February 9, 2004, Transmission made the
required informational filing with regard to compliance by June 1.
Certain companies plan to seek delay of the implementation to September
2004, in view of the number of pending rehearing and clarification
requests. Transmission believes that the ultimate outcome of this matter
will not have a materially adverse effect on the Company's consolidated
financial position, results of operations or cash flow.

On December 15, 2003, the U.S. Department of Transportation issued
a Final Rule requiring pipeline operators to develop integrity
management programs to comprehensively evaluate their pipelines, and
take measures to protect pipeline segments located in what the
regulation defines as "high consequence areas" ("HCA"). This rule
resulted from the enactment of the Pipeline Safety Improvement Act of
2002, a bill signed into law on December 17, 2002. The rule requires
operators to identify HCAs along their pipelines by December 2004, to
have begun baseline integrity assessments, comprised of in-line
inspection (smart pigging), hydrostatic testing, or direct assessment,
by June 2004. Operators must risk rank their pipeline segments
containing HCAs, and have the highest 50% assessed using one or more of
these methods by December 2007. The balance must be completed by
December 2012. The costs of utilizing these methods typically range from
a few thousand dollars per mile to well over $15,000 per mile. In
addition, some system modifications will be necessary to accommodate the
inspections. Because identification and location of all the HCAs has not
been completed, and because it is impossible to determine the scope of
required remediation activities prior to completion of the assessments
and inspections, the cost of implementing the requirements of this
regulation is impossible to determine at this time. The required
modifications and inspections are estimated to range from approximately
$12-15 million per year, with remediation costs in addition to these
amounts.

On December 29, 2003, the Securities and Exchange Commission
("SEC") denied Enron's outstanding applications for exemption under the
Public Utility Holding Company Act of 1935 ("PUHCA"). Enron applied for
an additional exemption on December 31, 2003. Under PUHCA, the Company
would be a subsidiary of a holding company, but could be eligible for
certain exemptions if such exemptions were applied for by Enron and
approved by the SEC (see Note 18).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(11) PROPERTY, PLANT AND EQUIPMENT

The principal components of the Company's Property, Plant and
Equipment at December 31, 2003, and 2002 are as follows (in thousands):

(12) OTHER DEFERRED CHARGES

The principal components of the Company's other deferred charges at
December 31, 2003, and 2002 are as follows (in thousands):

(1) "Ramp-up" assets is a regulatory asset Transmission was specifically
allowed in the FERC certificates authorizing the Phase IV and V
Expansion projects.

(2) Collateral posted to another party remains the property of the
posting party, unless it defaults on the collateralized obligation.

(3) Balancing tools are a regulatory method by which Transmission
recovers the costs of operational balancing of the pipelines'
system. The balance can be a deferred charge or credit, depending on
timing, rate changes, and operational activities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(13) OTHER DEFERRED CREDITS

The principal components of the Company's other deferred credits at
December 31, 2003, and 2002 are as follows (in thousands):

(1) Related to significant Phase IV, V, and VI expansion projects

(14) COMMITMENTS AND CONTINGENCIES

From time to time, in the normal course of business, the Company is
involved in litigation, claims or assessments that may result in future
economic detriment. The Company evaluates each of these matters and
determines if loss accruals are necessary as required by SFAS No. 5,
Accounting for Contingencies. The Company does not expect to experience
losses that would be materially in excess of the amount accrued at
December 31, 2003.

Transmission and Trading have filed bankruptcy related claims
against Enron and other affiliated bankrupt companies totaling $220.6
million. Transmission's claim includes rejection damages and delinquent
amounts owed under certain transportation agreements, an unpaid
promissory note, and other fees for services and imbalances. Subsequent
to Transmission's filing its claims, ENA's firm transportation
agreements were permanently relinquished to a creditworthy party, which
significantly reduced Transmission's rejection damages. Trading's claim
is for rejection damages on two physical/financial swaps, a gas sales
contract, and on the Operating Agreement, as well as certain delinquent
amounts owed pre-petition. In July, one Enron affiliate, ENA, indicated
that it did not agree with the amount of the claims and wanted to
discuss settlement/resolution. Discussion of possible settlement is
underway.

On March 7, 2003, Trading filed a declaratory order action,
involving a contract between it and Duke. Trading requested that the
court declare that Duke breached the parties' natural gas purchase
contract by failing to provide sufficient volumes of gas to Trading. The
suit seeks damages and a judicial determination that Duke has not
suffered a "loss of supply" under the parties' contract, which could, if
it continued, have given rise to the right of Duke to terminate the
contract at a point in the future. On April 14, 2003, Duke sent Trading
a notice that the contract was terminated as of April 16, 2003 (due to
Trading's alleged failure to timely increase the amount of a letter of
credit); although it disagreed with Duke's position, Trading increased
the letter of credit on April 15. Duke has answered and filed a
counterclaim, arguing that Trading failed to timely increase the amount
of a letter of credit, and that it has breached a "resale restriction"
on the gas. Trading disputes that it has breached the agreement, or that
any event has given rise to a right to terminate by Duke. On April 29,
2003, Duke filed to remove the case to federal court (CA03-CV-1425). On
May 1, 2003, Trading notified Duke that it was in default under the
Agreement, for failure to deliver the base volumes beginning April 17.
However, Duke continued to refuse to perform under the contract. On May
28, 2003, Trading filed a motion to remand the case to state court. On
June 2, 2003, Trading notified Duke that, because Duke had not cured its
default, Trading terminated the agreement effective as of June 5, 2003.
On August 8, 2003, Trading sent its final "termination payment" invoice
to Duke in the amount of $187 million. On July 31, 2003, the federal
court granted Trading's motion

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CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(14) COMMITMENTS AND CONTINGENCIES (continued)

and remanded the case to state court. On August 18, 2003, Duke filed a
Third-Party Petition against Sonatrading and Sonatrach, its Algerian
suppliers ("Sonatrach"), which Trading opposed since, inter alia, even
in the event of a failure to receive supplies from Algeria, Duke was
required to furnish supplies to Trading for a stated period of time. On
October 6, Trading filed its Amended Petition, alleging wrongful
termination and containing the termination damages. In October,
Sonatrach removed the case to federal court and filed a special
appearance challenging jurisdiction. On November 25, 2003, Trading filed
its Second Amended Complaint, alleging, among other things, that Duke
was required to give reasonable notice to Trading to upgrade the letter
of credit, before terminating the contract. On December 5, Duke filed
its answer. Sonatrach's motion to dismiss for lack of jurisdiction was
filed March 2, and Duke's response is due by March 31, 2004. Discovery
is ongoing, and the judge continues to hold informal discovery in an
attempt to resolve the case. On March 8, Trading made demand on
PanEnergy, who, along with Duke is a signatory to the agreement, asking
for PanEnergy to ensure (per the contracts) that Duke has sufficient
assets to pay Trading's claim. Because assurances were not forthcoming,
on March 16, 2004, Trading filed suit against PanEnergy in state court.
On March 23, 2004, Trading filed a motion for Summary Judgment against
Duke, seeking a ruling that Duke was required to provide Trading with
notice before terminating the agreements. This is a disputed matter, and
there can be no assurance as to what amounts, if any, Trading will
ultimately recover. Management believe that the amount ultimately
recovered will not be materially different than the amount recognized at
December 31, 2003, and that the ultimate resolution of this matter will
not have a materially adverse effect on the Company's consolidated
financial position, results of operations or cash flows. Management
further believes that claims made by Duke against the Company with
regard to this matter are without merit and do not constitute a
liability which would require adjustment to or disclosure in the
Company's December 31, 2003, consolidated financial statements in
accordance with SFAS No. 5, Accounting for Contingencies.

In 1999, Transmission entered into an agreement which obligated it
to various natural gas and construction projects includable in its rate
base. This obligation ends July 1, 2004, and Transmission expects to
incur an additional $1.1 million of potentially capitalizable costs
prior to contract expiration.

The Florida Turnpike Authority (FTA) has several turnpike widening
projects in the planning stage, which may, over the next ten years,
impact one or more of Transmission's mainlines co-located in FTA
right-of-way. The most immediate projects are five Sunshine State
Parkway projects, which are proposed to overlap Transmission's
pipelines, for a total of approximately 22 miles. Under certain
conditions, the existing agreement between Transmission and the FTA
calls for the FTA to pay for any new right-of-way needed for the
relocation projects and for Transmission to pay for construction costs.
The actual amount of miles of pipe to be impacted ultimately, and the
relocation cost and/or right-of-way cost, recoverable through rates, is
either undefined at this time, due to the preliminary stage of FTA's
planning process, or the FTA has determined not to require Transmission
to relocate its line. No preliminary estimate of the cost associated
with this potential relocation has been calculated, and it is not
estimable at this time.

(15) CONCENTRATIONS OF CREDIT RISK AND OTHER FINANCIAL INSTRUMENTS

The Company has a concentration of customers in the electric and
gas utility industries. These concentrations of customers may impact the
Company's overall exposure to credit risk, either positively or
negatively, in that the customers may be similarly affected by changes
in economic or other conditions. Credit losses incurred on receivables
in these industries compare favorably to losses experienced in the
Company's receivable portfolio as a whole. The Company also has a
concentra-
80

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(15) CONCENTRATIONS OF CREDIT RISK AND OTHER FINANCIAL INSTRUMENTS
(continued)

tion of customers located in the southeastern United States, primarily
within the state of Florida. Receivables are generally not
collateralized. From time to time, specifically identified customers
having perceived credit risk are required to provide prepayments,
deposits, or other forms of security to the Company. Transmission sought
additional assurances from customers due to credit concerns, and had
customer deposits totaling $8.9 million and $8.2 million and prepayments
of $1.6 million and $2.9 million for 2003 and 2002, respectively. The
Company's management believes that the portfolio of Transmission's
receivables, which includes regulated electric utilities, regulated
local distribution companies and municipalities, is of minimal credit
risk.

The carrying amounts and fair value of the Company's financial
instruments at December 31, 2003, and 2002 are as follows (in
thousands):

The carrying amount of cash and cash equivalents reasonably
approximate their fair value. The fair value of long-term debt is based
upon market quotations of similar debt at interest rates currently
available.

(16) COMPREHENSIVE INCOME

Comprehensive income includes the following (in thousands):

(17) ACCOUNTING PRONOUNCEMENTS

In August 2001, the Financial Accounting Standards Board (FASB)
issued SFAS No. 143, Accounting for Asset Retirement Obligations. This
statement requires companies to record a liability for the estimated
removal costs of assets used in their business where there is a legal
obligation associated with removal. The liability is recorded at its
fair value, with a corresponding asset that is depreciated over the
remaining useful life of the long-lived asset to which the liability
relates. An ongoing expense will also be recognized for changes in the
value of the liability as a result of the passage of time. The
provisions of SFAS No. 143 are effective for fiscal years beginning
after June 15, 2002. The Company adopted SFAS No. 143, beginning January
1, 2003. A comprehensive study was made in 2003 by the Company's
Accounting, Right of Way, Legal, Internal Audit, and Operations
personnel to identify all Asset Retirement Obligations that are
estimable as defined in

81

CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(17) ACCOUNTING PRONOUNCEMENTS (continued)

SFAS No. 143, and it has been determined that the adoption of this
standard did not have a financial statement impact at this time. The
Company will continue to monitor these requirements on an annual basis
in future.

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities. This statement will require
recognition of costs associated with exit or disposal activities when
they are incurred rather than when a commitment is made 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 initiated after January 1, 2003. SFAS No. 146 has not had an
impact on the Company's financial position or results of operations.

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 or
modified after December 31, 2002, 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 FIN No. 45 has not had an impact on the
Company's financial position or results of operations, it will impact
any guarantees the Company issues in the future.

(18) SUBSEQUENT EVENTS

On February 6, 2004, Enron filed two form U1's with the SEC,
proposing a set of conditions under which Enron would register as a
holding company under PUHCA. Among other things, Enron sought an
exemption for the Company under Rule 16 of the SEC's PUHCA Rules and
Regulations (17 CFR sec.250.16, "Exemption of Non-Utility Subsidiaries
and Affiliates") (The "Exemption"). On March 9, 2004, Enron amended its
form U1 application filings, withdrew its application for exemption
filed on December 31, 2003, and filed a form U5A, registering as a
public utility holding company under PUHCA. Also on March 9, 2004, the
SEC issued orders approving the applications made on the amended form
U1's and the U5A, including approval of the application for the
Exemption. The result of these proceedings has reconfirmed the Company's
exemptions.

On January 28, 2004, the Company extended the Waiver (see Note 3).
However, due to the unresolved exemption status of Enron under PUHCA
(see Note 10), Transmission agreed to further limit its rights under the
Revolver by restricting its right to issue new letters of credit. At
this time, Transmission cannot draw under the Revolver, nor can it issue
new letters of credit.

82

SOUTHERN NATURAL GAS COMPANY

EXHIBIT LIST
DECEMBER 31, 2003

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.

83

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized on the 30th day of
March, 2004.

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, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:

84

SOUTHERN NATURAL GAS COMPANY

EXHIBIT INDEX
DECEMBER 31, 2003

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.